1
Filed Pursuant to Rule 424(b)(3)
Registration No. 333-48584
PROSPECTUS
[TRITON LOGO]
TRITON ENERGY LIMITED
OFFER TO EXCHANGE UP TO
$300,000,000 8 7/8% SENIOR NOTES DUE 2007
FOR
$300,000,000 8 7/8% SENIOR NOTES DUE 2007
THAT HAVE BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933
TERMS OF THE EXCHANGE OFFER
- We are offering to exchange up to $300,000,000 of our outstanding 8 7/8%
Senior Notes due 2007 for new notes with substantially identical terms
that have been registered under the Securities Act and are freely
tradable.
- We will exchange all outstanding notes that you validly tender and do not
validly withdraw before the exchange offer expires for an equal principal
amount of new notes.
- The exchange offer expires at 5:00 p.m., New York City time, on December
7, 2000, unless extended. We do not currently intend to extend the
exchange offer.
- Tenders of outstanding notes may be withdrawn at any time prior to the
expiration of the exchange offer.
- The exchange of outstanding notes for new notes will not be a taxable
event for U.S. federal income tax purposes.
TERMS OF THE NEW 8 7/8% SENIOR NOTES OFFERED IN THE EXCHANGE OFFER
MATURITY
- The new notes will mature on October 1, 2007.
INTEREST
- Interest on the new notes is payable on April 1 and October 1 of each
year, beginning April 1, 2001.
- Interest will accrue from October 4, 2000.
REDEMPTION
- We may redeem some or all of the new notes at any time on or after
October 1, 2004.
- We may also redeem up to $105 million of the new notes using the proceeds
of certain equity offerings completed before October 1, 2003.
CHANGE OF CONTROL
- If we experience a change of control, we must offer to purchase the new
notes.
RANKING
- The new notes are unsecured. The new notes rank equally with all of our
other existing and future senior unsecured debt and senior to all of our
existing and future subordinated debt.
PORTAL
- We expect that the new notes will be eligible for trading in the PORTAL
market.
SEE "RISK FACTORS" ON PAGE 13 FOR A DISCUSSION OF FACTORS YOU SHOULD
CONSIDER BEFORE INVESTING IN THE NEW NOTES.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS
PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
The date of this prospectus is November 8, 2000
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This prospectus is part of a registration statement we filed with the
Securities and Exchange Commission. In making your investment decision, you
should rely only on the information contained in this prospectus and in the
accompanying letter of transmittal. We have not authorized anyone to provide you
with any other information. If you receive any unauthorized information, you
must not rely on it. We are not making an offer to sell these securities in any
state where the offer is not permitted. You should not assume that the
information contained in this prospectus is accurate as of any date other than
the date on the front cover of this prospectus.
---------------------
TABLE OF CONTENTS
PAGE
----
Prospectus Summary.......................................... 1
Risk Factors................................................ 13
Exchange Offer.............................................. 21
Use of Proceeds............................................. 31
Capitalization.............................................. 32
Selected Consolidated Historical Financial Data............. 33
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 35
Business.................................................... 45
Management.................................................. 59
Certain Relationships and Transactions...................... 62
Description of Other Indebtedness........................... 64
Description of New Notes.................................... 66
Tax Considerations.......................................... 110
Book-Entry; Delivery and Form............................... 111
Plan of Distribution........................................ 112
Legal Matters............................................... 114
Experts..................................................... 114
Enforceability of Civil Liabilities Against Foreign
Persons................................................... 114
Where You Can Find More Information......................... 115
Incorporation by Reference.................................. 115
Certain Definitions......................................... 116
Index to Financial Statements............................... F-1
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PROSPECTUS SUMMARY
This summary may not contain all the information that may be important to
you. You should read this entire prospectus, including the financial data and
related notes, and the documents to which we have referred you before making an
investment decision. You should carefully consider the information set forth
under "Risk Factors." In addition, certain statements include forward-looking
information which involves risks and uncertainties. See "Disclosure Regarding
Forward-Looking Information."
Unless this prospectus otherwise indicates or the context otherwise
requires, the terms "we," "our," "us," "Triton" or the "Company" as used in this
prospectus refer to Triton Energy Limited and its subsidiaries. We have defined
certain technical terms used in this prospectus in the glossary that is included
at the end of this prospectus.
THE COMPANY
GENERAL
We are an international oil and gas exploration and production company. Our
core operating areas and oil and gas reserves are located in Colombia,
Equatorial Guinea and Malaysia-Thailand. We explore for oil and gas in these
areas, as well as in southern Europe, Africa and the Middle East. We believe
that our acreage portfolio offers significant opportunity for growth and
diversifies our exposure to any one region. Since 1989, we have discovered three
major fields through our exploration program which has allowed us to grow and
diversify our reserve base. For the latest twelve months ended June 30, 2000 we
had revenues of $293.1 million and EBITDA of $212.4 million.
We have achieved substantial growth in proved reserves, production,
revenues and EBITDA over the past five years. Our proved reserves increased from
139.4 MMboe in 1995 to 265 MMboe at December 31, 1999. We also increased
production over this time period from 7.2 MMboe in 1995 to 12.5 MMboe in 1999.
Oil and gas revenues and EBITDA also have grown significantly, increasing from
$106.8 million and $57.9 million, respectively, in 1995 to $247.9 million and
$160.9 million in 1999. At December 31, 1999, our future net revenue from proved
reserves had an estimated pre-tax present value (discounted at 10%) of $1,945
million. Oil comprised 64% of our proved reserves while natural gas comprised
36%. At December 31, 1999, approximately 35% of our proved reserves were
classified as proved developed.
Net proved reserves at December 31, 1999, were:
PROVED DEVELOPED PROVED UNDEVELOPED TOTAL PROVED
-------------------------- --------------------------- ---------------------------
OIL GAS BOE OIL GAS BOE OIL GAS BOE
(MBBLS) (MMCF) (MMBOE) (MBBLS) (MMCF) (MMBOE) (MBBLS) (MMCF) (MMBOE)
------- ------ ------- ------- ------- ------- ------- ------- -------
Colombia(1).............. 91,803 11,566 93,731 33,712 -- 33,712 125,515 11,566 127,443
Malaysia-Thailand(2)..... -- -- -- 13,223 553,862 105,533 13,223 553,862 105,533
Equatorial Guinea........ -- -- -- 32,033 -- 32,033 32,033 -- 32,033
------ ------ ------ ------ ------- ------- ------- ------- -------
Total............ 91,803 11,566 93,731 78,968 553,862 171,278 170,771 565,428 265,009
====== ====== ====== ====== ======= ======= ======= ======= =======
- ---------------
(1) Includes liquids to be recovered from Empresa Colombiana de Petroleos, the
Colombian national oil company, as reimbursement for pre-commerciality
expenditures and excludes reserves attributable to the Liebre field, which
was sold in 2000.
(2) As of December 31, 1999, gas sales had not yet commenced. The proved gas
reserves are calculated using the base price in the gas sales agreement of
$2.30. The base price is subject to annual adjustments based on various
indices. We cannot assure you what the actual price will be when gas sales
commence.
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CORE OIL AND GAS PROPERTIES
Colombia
Cusiana and Cupiagua Fields
We hold a 12% interest in the Santiago de Las Atalayas, Tauramena and Rio
Chitamena contract areas, covering approximately 66,000, 36,300 and 6,700 acres,
respectively. The areas are located approximately 160 kilometers (100 miles)
northeast of Bogota in the Andean foothills of the Llanos Basin area in eastern
Colombia. Our net revenue interest is approximately 9.6% after governmental
royalties. Gross production from the Cusiana and Cupiagua fields has reached
over 500 million barrels of oil since production commenced, and averaged
approximately 430,000 BOPD during 1999. Based on a revised production forecast
we received in September 2000 from the operator, we expect that average gross
oil production for these fields in 2000 will be approximately 334,000 BOPD and
will be approximately 270,000 to 280,000 BOPD in 2001.
Recetor Contract Area
In 1999, we acquired a 20% interest in the Recetor contract area, covering
approximately 70,215 acres, subject to certain government royalties. Ecopetrol
has the right to acquire up to a 50% interest in the Recetor contract area, pro
rata from each participant, upon declaration of commerciality. This area is
located adjacent to and north of the Santiago de Las Atalayas contract area and
includes an extension of the Cupiagua field. In January 2000, we and our working
interest partners completed the Liria YD-2 well on the extension of the Cupiagua
field in the Recetor contract area. The well reached a total depth of 16,953
feet and is producing into the Cupiagua central processing facility. Currently
one drilling rig is operating in the Recetor contract area. We expect at least
two additional wells to be drilled in the Recetor contract area in 2001.
Equatorial Guinea
We have an interest in production-sharing contracts covering two contiguous
offshore blocks, Blocks F and G, with the Republic of Equatorial Guinea. The
contracts give us the right to explore and develop an area covering
approximately 1.3 million acres located offshore and southwest of the town of
Bata in water depths of up to 5,200 feet. We are the operator and have an 85%
interest in Blocks F and G, subject to a 5% carried participating interest held
by the government. In October 1999, we announced the discovery of the Ceiba oil
field, located on Block G. We recently completed a 3-D seismic survey covering
1.025 million acres in Blocks F and G that identified a number of what we
believe to be highly attractive prospects for exploration and exploitation. Our
acreage, which is equal to approximately 260 Gulf of Mexico blocks, offers us
the potential for significant continued growth.
We are implementing an accelerated appraisal and development program with
two drilling rigs to enable early production from the Ceiba field. The field is
located in approximately 2,200 to 2,600 feet of water, approximately 22 miles
off the continental coast of Africa. Our first production from the field is
scheduled for the end of 2000. The current plan of development provides for
initial or phase one production of 52,000 BOPD, although we cannot assure you
that actual production will be at this level. We have contracted for a FPSO
vessel that we expect to provide storage for up to two MMbbls of oil and initial
processing capacity of up to 60,000 BOPD from a single production unit. We can
add production capacity cost effectively through the installation of additional
processing units. We also plan to drill up to six exploration wells by the
middle of 2001, the first of which we spudded on October 2, 2000.
Malaysia-Thailand
We own a 25% interest in Block A-18 of the Malaysia-Thailand Joint
Development Area in the Gulf of Thailand. We and our partners have discovered
eight natural gas fields -- known as the Bulan, Bumi, Bumi East, Cakerawala,
Samudra, Senja, Suriya and Wira fields. In October 1999, we and the other
parties to the production-sharing contract for Block A-18 executed a gas sales
agreement providing for the sale of the first phase of gas to Malaysia.
Construction has begun with first production scheduled to
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commence by June 30, 2002. Our share of the capital costs for the first phase of
the exploration and development is being funded by BP Amoco p.l.c.
COMPETITIVE STRENGTHS
We believe that we have certain strengths that provide us with significant
competitive advantages, including the following:
- Proven Growth Record. Over the past five years, on a compound annual
basis, we have increased reserves by 18%, production by 15% and EBITDA by
29%. We expect continued growth as a result of the development of the
first phase of the Ceiba field and Block A-18.
- Diversified International Portfolio. We have diversified our core areas
beyond our initial interest in the Cusiana and Cupiagua fields in
Colombia to include the Gulf of Thailand and West Africa. First
production from phase one development of the Ceiba field in Equatorial
Guinea is expected by the end of 2000 and first production from Block
A-18 in the Gulf of Thailand is scheduled to begin by June 30, 2002. We
believe these three core areas will diversify our exposure to technical,
geological and political risks in any one region while increasing the
stability of our production and cash flow.
- Extensive Exploitation and Exploration Potential. Our core properties
contain large oil and gas fields in various stages of development. The
size of these fields and our extensive acreage holdings afford us the
potential to significantly increase our reserves, production and cash
flow. In Colombia we are focused on full exploitation of the Cusiana and
Cupiagua fields and development of our Recetor concession. We believe
considerable development potential remains on Block A-18, although we
will need to negotiate additional phases of gas deliveries under the
existing gas sales agreement. Capitalizing on our recent success in
Equatorial Guinea, we have accelerated our drilling program to begin to
pursue full development of the Ceiba field and further exploration of our
concession.
- Experienced Management. Our management team and technical staff have an
average of 20 years of experience in the oil and gas industry. We have
been very successful in identifying, acquiring, exploring and developing
international oil and gas properties as evidenced by our record in
Colombia, Equatorial Guinea and Malaysia-Thailand.
BUSINESS STRATEGY
The key elements of our strategy are as follows:
- Exploit Existing Core Asset Base. We are focused on continuing to exploit
our existing core asset base utilizing technical solutions to accelerate
production and maximize reserve recovery in order to increase our returns
on invested capital. This is demonstrated by our experience with the
Ceiba field, with production expected to commence within 15 months after
our initial discovery well via a sub-sea development program tied back to
an FPSO vessel.
- Capitalize on Extensive Exploration Opportunities. Our growth has
primarily been a result of our successful exploration program. We are
committed to continuing to pursue an active exploration program to
capitalize on the experience we have gained and our extensive prospect
inventory. In Equatorial Guinea we have acquired and processed 1 million
acres of 3-D seismic data and have identified approximately 40 leads or
prospects. We expanded our drilling program in Equatorial Guinea via the
addition of a second drilling rig and are planning to drill up to six
exploration wells by the middle of 2001, the first of which we spudded on
October 2, 2000. Our recently announced farm-in in Gabon, which has
similar geologic characteristics to our Equatorial Guinea concession,
reflects our desire to utilize the knowledge and experience from
Equatorial Guinea to expand our activities in West Africa.
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- Maintain a Low Cost Structure. We have lowered our operating costs
significantly, both in absolute terms and on a boe basis, over the last
two years. General and administrative expenses before capitalization have
been reduced from $47 million, or $3.83 per boe, in 1998 to $31 million,
or $2.02 per boe, in 1999. Operating costs have been reduced from $74
million, or $5.97 per boe, in 1998 to $68 million, or $4.50 per boe, in
1999. We plan to maintain a low cost structure to maximize cash flow and
earnings.
- Maintain Financial Flexibility. We have undertaken a number of steps
since mid 1998 to strengthen our financial position and improve our
financial flexibility. In August 1998, we sold one half of our interest
in Block A-18 to ARCO for $150 million and financing of all costs on the
block up to $377 million or until first gas production from a gas field.
In September 1998, we sold $350 million in 8% Convertible Preference
Shares, substantially all of which was sold to HM4 Triton, L.P., a
limited partnership controlled by Thomas O. Hicks and Hicks, Muse, Tate &
Furst Incorporated. As a result of these activities and increased
financial discipline, we have increased our liquidity and diversified our
capital base. These actions enabled us to pursue an aggressive
exploration and development schedule in Equatorial Guinea. We are
committed to maintaining the financial flexibility we have established in
order to pursue exploration and development activities and to take
advantage of other opportunities that may arise.
RECENT DEVELOPMENTS
Gross production from the Cusiana and Cupiagua fields averaged
approximately 331,000 BOPD during the third quarter of 2000. Based on a revised
production forecast we received in September 2000 from the operator, we expect
that average gross production for the fields will be approximately 334,000 BOPD
for the year, and approximately 270,000 to 280,000 BOPD in 2001.
In September 2000, we surrendered our interest in our Aitoloakarnania
onshore lease in Greece after drilling two dry holes, and we expect to record a
writedown of approximately $19 million ($17 million net of tax) in the third
quarter of 2000.
In September 2000, we announced that the Ceiba-6 well offshore Equatorial
Guinea would be plugged and abandoned, having not encountered oil and gas. The
Ceiba-6 well was a significant step-out well located outside and southeast of
the Ceiba field.
PRINCIPAL EXECUTIVE OFFICES AND CONTACT INFORMATION
Our principal executive offices are located at Caledonian House, Jennett
Street, P.O. Box 1043, George Town, Grand Cayman, Cayman Islands, and our
telephone number is (345) 949-0050.
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THE EXCHANGE OFFER
On October 4, 2000, we completed a private offering of the old notes. We
entered into a registration rights agreement with the initial purchasers in the
private offering in which we agreed to deliver to you this prospectus and to use
our reasonable best efforts to complete the exchange offer within 210 days after
the date we issued the old notes.
Exchange Offer............. We are offering to exchange new notes for old
notes.
Expiration Date............ The exchange offer will expire at 5:00 p.m. New
York City time, on December 7, 2000, unless we
decide to extend it.
Condition to the Exchange
Offer.................... The registration rights agreement does not require
us to accept old notes for exchange if the exchange
offer or the making of any exchange by a holder of
the old notes would violate any applicable law or
interpretation of the staff of the Securities and
Exchange Commission. A minimum aggregate principal
amount of old notes being tendered is not a
condition to the exchange offer.
Procedures for Tendering
Old
Notes.................... To participate in the exchange offer, you must
complete, sign and date the letter of transmittal,
or a facsimile of the letter of transmittal, and
transmit it together with all other documents
required by the letter of transmittal, including
the old notes that you wish to exchange, to The
Chase Manhattan Bank, as exchange agent, at the
address indicated on the cover page of the letter
of transmittal. In the alternative, you can tender
your old notes by following the procedures for
book-entry transfer described in this prospectus.
If your old notes are held through The Depository
Trust Company and you wish to participate in the
exchange offer, you may do so through the automated
tender offer program of The Depository Trust
Company. If you tender under this program, you will
agree to be bound by the letter of transmittal that
we are providing with this prospectus as though you
had signed the letter of transmittal.
If a broker, dealer, commercial bank, trust company
or other nominee is the registered holder of your
old notes, we urge you to contact that person
promptly to tender your old notes in the exchange
offer.
For more information on tendering your old notes,
please refer to the sections in this prospectus
entitled "Exchange Offer -- Terms of the Exchange
Offer," "-- Procedures for Tendering" and "-- Book
Entry Transfer."
Guaranteed Delivery
Procedures............... If you wish to tender your old notes and you cannot
get your required documents to the exchange agent
on time, you may tender your old notes according to
the guaranteed delivery procedures described in
"Exchange Offer -- Guaranteed Delivery Procedures."
Withdrawal of Tenders...... You may withdraw your tender of old notes at any
time prior to the expiration date. To withdraw, you
must have delivered a written or facsimile
transmission notice of withdrawal to the exchange
agent at its address indicated on the cover page of
the letter of transmittal before 5:00 p.m. New York
City time on the expiration date of the exchange
offer.
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Acceptance of Old Notes and
Delivery of New Notes.... If you fulfill all conditions required for proper
acceptance of old notes, we will accept any and all
old notes that you properly tender in the exchange
offer on or before 5:00 p.m. New York City time on
the expiration date. We will return any old note
that we do not accept for exchange to you without
expense as promptly as practicable after the
expiration date. We will deliver the new notes as
promptly as practicable after the expiration date
and acceptance of the old notes for exchange.
Please refer to the section in this prospectus
entitled "Exchange Offer -- Terms of the Exchange
Offer."
Fees and Expenses.......... We will bear all expenses related to the exchange
offer. Please refer to the section in this
prospectus entitled "Exchange Offer -- Fees and
Expenses."
Use of Proceeds............ The issuance of the new notes will not provide us
with any new proceeds. We are making this exchange
offer solely to satisfy our obligations under our
registration rights agreement. Please refer to the
sections entitled "Use of Proceeds" and
"Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity
and Capital Requirements" for a discussion of our
use of the proceeds from the issuance of the old
notes.
Consequences of Failure to
Exchange Old Notes....... If you do not exchange your old notes in this
exchange offer, you will no longer be able to
require us to register the old notes under the
Securities Act of 1933 except in the limited
circumstances provided under our registration
rights agreement. In addition, you will not be able
to resell, offer to resell or otherwise transfer
the old notes unless we have registered the old
notes under the Securities Act of 1933, or unless
you resell, offer to resell or otherwise transfer
them under an exemption from the registration
requirements of, or in a transaction not subject
to, the Securities Act of 1933.
U.S. Federal Income Tax
Considerations........... The exchange of new notes for old notes in the
exchange offer will not be taxable event for U.S.
federal income tax purposes. Please read "Tax
Considerations."
Exchange Agent............. We have appointed The Chase Manhattan Bank as
exchange agent for the exchange offer. You should
direct questions and requests for assistance,
requests for additional copies of this prospectus
or the letter of transmittal and requests for the
notice of guaranteed delivery to the exchange agent
addressed as follows: The Chase Manhattan Bank,
Corporate Trust -- Securities Window, 55 Water
Street, Room 234 -- North Building, New York, New
York 10041, Attn: Edwina Osborne. Eligible
institutions may make requests by facsimile at
212-638-7375.
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TERMS OF THE NEW NOTES
The new notes will be identical to the old notes except that the new notes
are registered under the Securities Act of 1933 and will not have restrictions
on transfer, registration rights or provisions for additional interest and will
contain different administrative terms. The new notes will evidence the same
debt as the old notes, and the same indenture will govern the new notes and the
old notes.
The following summary contains basic information about the new notes and is
not intended to be complete. It does not contain all the information that is
important to you. For a more complete understanding of the new notes, please
refer to the section of this document entitled "Description of New Notes."
References to "Triton," the "Company," "us," "we," and "our" in this section of
the summary refer only to Triton Energy Limited and do not include our
subsidiaries.
Issuer..................... Triton Energy Limited.
Notes Offered.............. $300 million aggregate principal amount of 8 7/8%
Senior Notes due 2007.
Maturity................... October 1, 2007.
Interest on the New
Notes...................... Annual Rate 8.875%.
Interest Payment Dates..... April 1 and October 1 of each year, commencing on
April 1, 2001.
Sinking Fund............... None.
Optional Redemption........ On or after October 1, 2004, we may redeem some or
all of the new notes at the redemption prices
listed in the section entitled "Description of New
Notes -- Optional Redemption." We may not redeem
the new notes before October 1, 2004, except that
at any time on or before October 1, 2003, we may
redeem up to $105 million of the new notes with the
proceeds of offerings of common equity at a
redemption price equal to 108.875%, together with
accrued and unpaid interest, so long as $195
million of the new notes remain outstanding after
each permitted redemption made with equity
proceeds.
We may redeem all, but not fewer than all, of the
new notes at their principal amount, plus accrued
and unpaid interest, in the event of certain
changes affecting tax laws, as described under
"Description of New Notes -- Redemption for Changes
in Withholding Taxes."
Change of Control.......... Upon the occurrence of a change of control, you
will have the right to require us to repurchase all
or a portion of your new notes at a price equal to
101% of the principal amount, together with any
accrued and unpaid interest to the date of
purchase.
Ranking.................... The new notes rank equally in right of payment with
all our existing and future unsecured senior debt
and are senior in right of payment to all our
future subordinated debt. Because we are a holding
company that conducts all our operations through
subsidiaries, the new notes will be effectively
subordinated to all obligations of our
subsidiaries. As of June 30, 2000, on a pro forma
basis to give effect to the offering of old notes
and the application of the proceeds thereof, our
outstanding senior indebtedness would have been
approximately $509 million, none of which would
have been secured, and our subsidiaries would have
had approximately $91 million of total liabilities
(consisting of $9 million of Export-Import Bank
supported bank indebtedness and $82 million of
other liabilities, including accounts payable). The
indenture that will govern the new notes
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permits us to incur a significant amount of senior
indebtedness. Our subsidiaries may also have other
liabilities, including contingent liabilities. The
new notes will not be guaranteed by any of our
subsidiaries.
Specified Covenants........ The indenture governing the new notes will contain,
among other things, limitations on our ability and
the ability of our subsidiaries to:
- borrow money;
- pay dividends on stock, redeem stock or redeem
subordinated debt;
- make investments;
- use assets as security in other transactions;
- create liens;
- enter into sale and leaseback transactions;
- sell assets;
- sell capital stock of subsidiaries;
- guarantee other indebtedness;
- enter into agreements that restrict dividends
from subsidiaries;
- merge or consolidate;
- enter into transactions with affiliates; and
- enter into different lines of business.
For the period during which the new notes receive
an investment grade rating by either Standard &
Poor's Ratings Services or Moody's Investors
Service, Inc. and no default or event of default
has occurred and is continuing under the indenture
governing the new notes, we and our subsidiaries
will not be required to comply with certain of the
covenants, but we and our subsidiaries will be
required to continue to comply with the covenants
restricting our ability to create liens, enter into
sale and leaseback transactions and merge or
consolidate.
Transfer Restrictions;
Absence of
a Public Market for the
Notes.................... The new notes generally will be freely
transferable, but will also be new securities for
which there will not initially be a market. There
can be no assurance as to the development or
liquidity of any market for the new notes. We
expect that the new notes will be eligible for
trading in the PORTAL market. We do not intend to
apply for a listing of the new notes on any
securities exchange or any automated dealer
quotation system.
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SUMMARY HISTORICAL FINANCIAL DATA
The following table sets forth certain of our consolidated historical
financial data. You should read the historical data in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and our historical consolidated financial statements and notes
included elsewhere in this prospectus. The historical results are not
necessarily indicative of our future results.
SIX MONTHS
ENDED JUNE 30, YEAR ENDED DECEMBER 31,
----------------- ------------------------------------------------
2000 1999 1999 1998 1997 1996 1995
-------- ------ ------- ------- -------- ------- -------
(DOLLARS IN MILLIONS, EXCEPT PER UNIT AMOUNTS)
STATEMENTS OF OPERATIONS:
REVENUES:
Oil and gas sales......................... $ 154.0 $108.8 $ 247.9 $ 160.9 $ 145.4 $ 129.8 $ 106.9
Other operating revenues.................. -- -- -- 67.7 4.1 4.2 0.6
-------- ------ ------- ------- -------- ------- -------
154.0 108.8 247.9 228.6 149.5 134.0 107.5
-------- ------ ------- ------- -------- ------- -------
COSTS AND EXPENSES:
Operating................................. 31.3 38.2 68.1 73.5 51.4 36.7 35.3
General and administrative................ 10.3 9.8 23.6 26.7 28.6 25.9 25.7
Depreciation, depletion and
amortization............................ 27.4 30.6 61.4 58.8 36.8 25.6 23.2
Writedown of assets....................... -- -- -- 328.6 -- 43.0 --
Special charges........................... -- 1.2 2.9 18.3 -- -- --
-------- ------ ------- ------- -------- ------- -------
69.0 79.8 156.0 505.9 116.8 131.2 84.2
-------- ------ ------- ------- -------- ------- -------
OPERATING INCOME (LOSS)................... 85.0 29.0 91.9 (277.3) 32.7 2.8 23.3
Interest income........................... 4.8 5.2 10.6 3.2 5.2 6.7 8.0
Interest expense, net..................... (8.9) (11.9) (22.7) (23.2) (23.9) (15.9) (24.1)
Other income (expense), net............... (0.5) 0.2 (3.6) 58.7 2.9 27.3 9.4
-------- ------ ------- ------- -------- ------- -------
(4.6) (6.5) (15.7) 38.7 (15.8) 18.1 (6.7)
-------- ------ ------- ------- -------- ------- -------
Earnings (loss) from continuing
operations before income taxes and
extraordinary
item.................................. 80.4 22.5 76.2 (238.6) 16.9 20.9 16.6
Income tax expense (benefit).............. 25.1 9.7 28.6 (51.1) 11.3 (2.9) 10.1
-------- ------ ------- ------- -------- ------- -------
55.3 12.8 47.6 (187.5) 5.6 23.8 6.5
Discontinued operations................... -- -- -- -- -- -- (3.8)
-------- ------ ------- ------- -------- ------- -------
Earnings (loss) before extraordinary
item.................................. 55.3 12.8 47.6 (187.5) 5.6 23.8 2.7
Extraordinary item -- extinguishment of
debt.................................... -- -- -- -- (14.5) (1.2) --
-------- ------ ------- ------- -------- ------- -------
Net earnings (loss)..................... 55.3 12.8 47.6 (187.5) (8.9) 22.6 2.7
Accumulated dividends on preference
shares.................................. 14.7 14.0 28.7 3.1 0.4 1.0 0.8
-------- ------ ------- ------- -------- ------- -------
Earnings (loss) applicable to ordinary
shares................................ $ 40.6 $ (1.2) $ 18.9 $(190.6) $ (9.3) $ 21.6 $ 1.9
======== ====== ======= ======= ======== ======= =======
STATEMENT OF CASH FLOWS DATA:
Cash flows from operating activities...... $ 66.2 $ 49.8 $ 116.5 $ 1.5 $ (97.4) $ 80.7 $ 149.1
Cash flows from investing activities...... $ (163.1) $(46.5) $(118.5) $ 84.2 $ (212.7) $(105.5) $(159.8)
Cash flows from financing activities...... $ (10.0) $190.8 $ 170.1 $ (80.1) $ 313.4 $ (13.0) $ 38.9
OTHER FINANCIAL DATA:
EBITDA(a)................................. $ 116.9 $ 65.4 $ 160.9 $ 54.9 $ 74.4 $ 87.2 $ 57.9
EBITDA to interest expense................ 6.0x 3.4x 4.2x 1.1x 1.4x 1.8x 1.3x
Ratio of earnings to fixed charges(b)..... 4.6x 1.8x 2.6x -- -- -- 1.1x
BALANCE SHEET DATA (AT END OF PERIOD):
Working capital (deficit)................. $ 58.3 $182.1 $ 161.3 $ (21.6) $ (115.2) $(182.2) $ 85.6
Property, plant and equipment, net........ 582.9 571.0 524.2 470.9 835.5 676.8 524.4
Total assets.............................. 1,015.7 937.7 974.5 754.3 1,098.0 914.5 824.2
Long-term debt, including current
maturities(c)........................... 409.2 418.0 413.5 427.5 573.7 416.6 402.5
Shareholders' equity...................... 514.6 444.6 463.1 223.8 296.6 300.6 246.0
- ---------------
(a) EBITDA consists of consolidated net earnings (loss), plus interest expense,
income taxes, depreciation expense, amortization of intangibles,
exploration and abandonment expense and other non-cash charges reducing
consolidated net earnings (loss) to the extent deducted in calculating
consolidated net earnings (loss). Net earnings associated with barrels
delivered in connection with our forward oil sale in May 1995 have not been
deducted in the calculation of EBITDA. EBITDA is not a measure determined
pursuant to generally accepted accounting principles, or GAAP, nor is it an
alternative to GAAP income.
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(b) For purposes of computing the ratio of earnings to fixed charges, earnings
consist of consolidated earnings (loss) from continuing operations before
income taxes and extraordinary items, excluding undistributed equity
earnings of affiliates whose debt is not guaranteed, plus fixed charges.
Fixed charges consists of interest expense on indebtedness and capitalized
interest, plus amortization of debt issuance costs, discounts and premiums,
plus that portion of rental expense which is deemed to be representative of
an interest factor. Earnings were inadequate to cover fixed charges for the
years ended December 31, 1998, 1997, and 1996 by $261.8 million, $8.9
million, and $6.3 million, respectively. Without nonrecurring items,
earnings would have been inadequate to cover fixed charges for the years
ended December 31, 1998, 1997, and 1995 by $39.4 million, $15.2 million,
and $9.9 million, respectively.
(c) Includes current maturities totaling $9.1 million and $9.0 million at June
30, 2000 and 1999, respectively, and $9.0 million, $14.0 million, $130.4
million, $199.6 million, and $1.3 million at December 31, 1999, 1998, 1997,
1996, and 1995, respectively.
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SUMMARY RESERVE AND PRODUCTION DATA
The following table sets forth certain of our consolidated historical
reserve and operating data. You should read the historical data in conjunction
with our historical consolidated financial statements and notes included
elsewhere in this prospectus. The historical results are not necessarily
indicative of our future results.
YEAR ENDED DECEMBER 31,
--------------------------------
1999 1998 1997
-------- -------- ----------
(DOLLARS IN MILLIONS, EXCEPT PER
UNIT AMOUNTS)
ESTIMATED PROVED RESERVES (AT END OF PERIOD):
Oil (MBbls)............................................... 170,827 143,344 175,799
Gas (MMcf)................................................ 565,428 582,596 1,238,419
Oil equivalents (MBOE).................................... 265,065 240,443 382,202
Percent Oil................................................. 64% 60% 46%
Percent proved developed.................................... 35% 37% 22%
FUTURE NET CASH FLOWS BEFORE INCOME TAXES (AT END OF
PERIOD):
Undiscounted.............................................. $ 3,648 $ 1,607 $ 3,577
Discounted................................................ $ 1,945 $ 669 $ 1,280
RESERVE ADDITIONS (MBOE):
Acquisitions.............................................. 3,280 N/A N/A
Extensions, discoveries and revisions..................... 33,887 (12,263) 80,477
-------- -------- ----------
Total additions..................................... 37,167 (12,263) 80,477
======== ======== ==========
COSTS INCURRED:
Acquisitions.............................................. $ 6.4 $ .5 $ 3.1
Exploration and development costs......................... 117.6 153.8 154.3
-------- -------- ----------
Total costs incurred................................ $ 124.0 $ 154.3 $ 157.4
======== ======== ==========
UNIT FINDING COST (PER BOE)(A).............................. $ 3.34 $ N/M $ 1.96
SIX MONTHS
ENDED JUNE 30, YEAR ENDED DECEMBER 31,
--------------- --------------------------------------------
2000 1999 1999 1998 1997 1996 1995
------ ------ ------- ------- ------ ------ ------
PRODUCTION:
Oil (MBbls)(b)...................................... 5,474 6,390 12,469 9,979 5,776 5,987 6,303
Gas (MMcf).......................................... 220 215 459 503 802 2,517 5,312
Total (MBOE)(b)............................... 5,511 6,426 12,546 10,063 5,910 6,407 7,188
AVERAGE SALES PRICE PER UNIT(C):
Oil (per Bbl)(d).................................... $24.65 $13.72 $ 15.95 $ 12.31 $17.54 $19.61 $16.60
Gas (per Mcf)....................................... $ 1.25 $ .87 $ .88 $ .99 $ 1.15 $ 1.69 $ 1.64
BOE................................................. $24.55 $13.68 $ 15.89 $ 12.27 $17.37 $19.42 $16.19
EXPENSES PER BOE:
Production costs, including production taxes........ $ 5.04 $ 5.03 $ 4.50 $ 5.97 $ 6.47 $ 5.77 $ 6.28
Depletion........................................... $ 4.21 $ 3.71 $ 3.80 $ 4.07 $ 3.67 $ 2.84 $ 2.81
AVERAGE RESERVE LIFE (YEARS)(E)....................... N/A N/A 21.1 23.9 64.7 51.4 20.3
- ---------------
(a) Finding cost is calculated by dividing each year's costs incurred by the
same year's reserve additions. Finding costs are not provided for 1998,
since reserve additions were negative.
(b) Includes Ecopetrol reimbursement barrels and excludes .8 million and 1.5
million barrels of oil produced and delivered for the six months ended June
30, 2000 and 1999, respectively, and 3.1 million, 3.1 million, 2.5 million,
.7 million and .4 million barrels of oil produced and delivered for the
years ended December 31, 1999, 1998, 1997, 1996 and 1995, respectively, in
connection with our forward oil sale in May 1995.
(c) Includes barrels delivered under the forward oil sale through March 2000,
which were recognized in oil and gas sales at $11.56 per barrel upon
delivery.
(d) Includes natural gas liquids and condensate.
(e) Average reserve life is calculated by dividing each year's total reserve by
such year's production.
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RISK FACTORS
You should carefully consider the risk factors beginning on page 13 of this
prospectus, as well as the information included or incorporated by reference in
this prospectus, before participating in the exchange offer. In addition, please
read "Disclosure Regarding Forward-Looking Information" below, where we describe
additional uncertainties associated with our business and the forward-looking
statements included in this prospectus.
DISCLOSURE REGARDING FORWARD-LOOKING INFORMATION
Some statements in this prospectus and the documents we refer you to, as
well as written and oral statements made from time to time by us and our
representatives in reports, filings with the Securities and Exchange Commission,
news releases, conferences, teleconferences, web postings or otherwise, may be
deemed to be "forward-looking statements" within the meaning of Section 27A of
the Securities Act, Section 21E of the Securities Exchange Act of 1934 and the
Private Securities Litigation Reform Act of 1995. This information is subject to
the "Safe Harbor" provisions of those statutes. Forward-looking statements
include statements concerning Triton's and management's plans, objectives,
goals, strategies and future operations and performance and the assumptions
underlying these forward-looking statements. We use the words "anticipates,"
"estimates," "expects," "believes," "intends," "plans," "may," "will," "should"
and similar expressions to identify forward-looking statements. These statements
include information regarding:
- drilling schedules;
- expected or planned production capacity;
- our interpretation of seismic data;
- future production of the Cusiana and Cupiagua fields in Colombia,
including the Recetor license;
- future production of the Ceiba field in Equatorial Guinea, including
volumes and timing of first production;
- the acceleration of our exploration, appraisal and development activities
in Equatorial Guinea;
- the completion of development and the commencement of production in
offshore Malaysia-Thailand;
- our capital budget, future capital requirements and our ability to meet
our future capital needs;
- our ability to realize our deferred tax asset;
- the level of future expenditures for environmental costs;
- the outcome of regulatory and litigation matters; and
- proved oil and gas reserves and discounted future net cash flows
therefrom.
We base these statements on our current expectations. These statements
involve a number of risks and uncertainties, including those described in the
context of the forward-looking statements, as well as those presented in "Risk
Factors" below. Actual results and developments could differ materially from
those expressed in or implied by these statements. We are not obligated to
update or revise any forward-looking statements, whether as a result of new
information, future events or otherwise.
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RISK FACTORS
In deciding whether to participate in the exchange offer, you should
consider the following risks. You should consider carefully these risks along
with the other information in this document and the documents to which we have
referred you.
RISKS RELATED TO OUR BUSINESS
Oil prices significantly impact our operating results.
Currently, we derive substantially all of our revenues and operating cash
flow from the sale of oil produced in Colombia. In general, we sell our oil
production at prices based on the market price of oil on the date of sale,
although from time to time we may sell production in advance at contractually
fixed prices and we may enter into hedging transactions. The market price for
oil historically has been volatile. For example, during 1999, WTI oil prices
fluctuated between a low price of $11.37 per barrel and a high price of $27.07
per barrel, and was $32.54 per barrel as of November 3, 2000. Decreases in oil
and natural gas prices will adversely affect our revenues, results of
operations, and cash flows.
If we determine that exploration results on one or more properties do not
justify continuing to carry their capitalized costs, we may write down the
properties' carrying value and incur a charge to earnings and a reduction in
shareholders' equity.
We follow the full cost method of accounting for exploration and
development of oil and gas reserves. Under this method of accounting, all of our
costs related to acquisition, holding and initial exploration of licenses in
countries where we do not have any proved reserves are initially capitalized. We
then periodically make assessments of these licenses for impairment on a
country-by-country basis. Based on our evaluation of drilling results, seismic
data and other information we deem relevant, we may write down the carrying
value of the oil and gas licenses in that country. A writedown constitutes a
charge to earnings that does not impact our cash flow from operating activities,
but it does reduce our shareholders' equity. For example, in September 2000, we
surrendered our interest in an onshore lease in Greece after drilling two dry
holes and we expect to record a write down of about $19 million ($17 million net
of tax) in the third quarter of 2000. In addition, in the second quarter of
1998, we recorded a $77.3 million ($72.6 million, net of tax) writedown of
unevaluated oil and gas properties relating to our operations in China, Ecuador,
Guatemala and other countries, and a corresponding reduction in shareholders'
equity. We expect to complete our contractual obligations in Greece, Italy,
Madagascar, and Oman over the next 12 months. If in the course of our
exploration activities in any one or more of these countries, we determine that
continuing to explore for hydrocarbons there is not justified, we may record a
writedown during this period for any one of our cost pools related to these
countries. Due to the unpredictable nature of exploration activities, we cannot
predict the amount and time of impairment writedowns.
If oil and gas prices decrease below specified levels, we may write down the
carrying values of properties with proved reserves and incur a charge to
earnings and a reduction in shareholders' equity.
We may also write down the carrying value of properties where we have
proved reserves as a result of the "full cost ceiling limitation" prescribed by
the Securities and Exchange Commission. Under the full cost ceiling limitation,
we must write down the carrying value of properties in any country where we have
proved reserves to the extent that the net capitalized costs of the properties,
less related deferred income taxes, exceeds the amount given by the following
formula:
(1) the estimated future net revenues from the properties, discounted
at 10%; plus
(2) unevaluated costs not being amortized; plus
(3) the lower of cost or estimated fair value of unproved properties
being amortized; minus
(4) income tax effects related to differences between the financial
statement basis and tax basis of oil and gas properties.
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The discounted future net revenues from the properties is determined based
on the selling price of oil or gas as of the end of the accounting period, or
when results of operations for that period are determined. For example, as a
result of a decline in oil prices in 1998, we wrote down the carrying value of
our evaluated oil and gas properties in Colombia by $105.4 million ($68.5
million, net of tax) in June 1998, and $135.6 million ($115.9 million, net of
tax) in December 1998, because of the full cost ceiling limitation. To calculate
the Securities and Exchange Commission full cost ceiling limitation, we used a
net price of approximately $13 per barrel as of June 30, 1998, and $11 per
barrel as of December 31, 1998.
Substantially all of our operations are in foreign countries and we are
subject to political, economic and other uncertainties.
We conduct substantially all of our exploration and production operations,
and derive substantially all of our revenues, outside the United States,
including Colombia, Equatorial Guinea, Malaysia-Thailand, Gabon, Greece, Italy,
Madagascar and Oman. Operations in foreign countries, particularly the oil and
gas business, are subject to political, economic and other uncertainties, which
include:
- the risk of expropriation, nationalization, war, revolution, border
disputes, renegotiation or modification of existing contracts, import,
export and transportation regulations and tariffs;
- taxation policies, including royalty and tax increases and retroactive
tax claims;
- exchange controls, currency fluctuations and other uncertainties arising
out of foreign government sovereignty over our international operations;
- laws and policies of the United States affecting foreign trade, taxation
and investment; and
- the possibilities of being subjected to the exclusive jurisdiction of
foreign courts in connection with legal disputes and the inability to
subject foreign persons to the jurisdiction of courts in the United
States.
Countries in Latin America and Africa, as well as other regions, have had a
history of political and economic instability. This instability could result in
new governments or the adoption of new policies that might assume a hostile
attitude toward foreign investment. In an extreme case, such a change could
result in the termination of our contract rights and expropriation of our
assets.
Our drilling operations are subject to certain other risks which could cause
us to delay or cease our drilling.
Numerous risks affect drilling activities, including the risk of drilling
non-productive wells or dry holes. The cost of drilling, completing and
operating wells and of installing production facilities and pipelines is often
uncertain. Also, our drilling could delay or cease because of any of the
following:
- title problems;
- weather conditions;
- noncompliance with or changes in governmental requirements or
regulations;
- shortage or delays in the delivery or availability of equipment; and
- failure to obtain permits for our operations in a timely manner.
Drilling oil and gas wells could involve blowouts, hurricanes, environmental
and other operating hazards.
The nature of the oil and gas business involves operating hazards such as
well blowouts, explosions, uncontrollable flows of oil, gas or well fluids,
pollution, earthquakes, formations with abnormal pressures, labor disruptions,
fires, releases of toxic gas and other environmental hazards and risks. Any of
these operating hazards could result in substantial losses.
14
17
In addition, we may be liable for environmental damages caused by previous
owners of properties we have purchased. As a result, we could incur substantial
liabilities to third parties or governmental entities. The payment of these
amounts could reduce or eliminate the funds available for exploration,
development or acquisitions.
In accordance with customary industry practices, we maintain insurance
against some, but not all, of these risks and losses. If an event occurs that is
not fully covered by insurance, it could result in a financial loss and reduce
our resources for capital expenditures. In addition, we cannot be sure that
insurance will continue to be available, or that insurance will continue to be
available at premium levels that justify its purchase.
Guerrilla activity in Colombia could disrupt our operations.
Our Colombia operation is currently responsible for substantially all of
our revenues and operating cash flow. From time to time, guerrilla activity in
Colombia has disrupted the operation of oil and gas projects. The guerrilla
activity has increased over the last few years, causing delays in the
development of our fields in Colombia. Their activity has from time to time
slowed our ability to put workers in the field, and they have made attempts to
disrupt the flow of production through the pipeline. BP Amoco, as operator of
the fields, and we and the Colombian government have taken steps to maintain
security and favorable relations with the local population. These steps have
included the hiring of security to patrol our facilities, and programs to
provide local communities with health and educational assistance. We expect that
we will be required to continue these steps throughout the term of our interest
there. We cannot assure you that these attempts to reduce or prevent guerrilla
activity will be successful or that guerrilla activity will not disrupt
operations in the future.
Colombia could be denied certification as a country making progress in
stemming the production and transit of illegal drugs, which could heighten the
risks of our operations there.
Colombia is among several nations whose progress in stemming the production
and transit of illegal drugs is subject to annual certification by the President
of the United States. Although the President has granted Colombia certification
in 2000, Colombia was denied certification in two recent years and only received
a national interest waiver for one of those years. We cannot assure you that, in
the future, Colombia will receive certification or a national interest waiver.
If the United States does not grant Colombia certification, or a national
interest waiver, in the future, several adverse consequences could result,
including the following:
- all bilateral aid, except anti-narcotics and humanitarian aid, would be
suspended;
- the Export-Import Bank of the United States and the Overseas Private
Investment Corporation would not approve financing for new projects in
Colombia;
- U.S. representatives at multilateral lending institutions would be
required to vote against all loan requests from Colombia (although their
votes would not constitute vetoes); and
- the President of the United States and Congress would retain the right to
apply future trade sanctions.
Each of these consequences could result in adverse economic consequences in
Colombia and could further heighten the political and economic risks associated
with our operations there.
We have experienced unexpected production declines in Colombia.
Gross production from the Cusiana and Cupiagua fields averaged
approximately 430,000 BOPD during 1999 and approximately 331,000 BOPD during the
third quarter of 2000. Based on a revised production forecast we received in
September 2000 from the operator, we expect that average gross production for
the fields will be approximately 334,000 BOPD for the year. The operator has
recommended certain actions to offset the decline in production in 2001, such as
work overs and water
15
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flood projects, that would result in an expected production rate of
approximately 270,000 to 280,000 BOPD in 2001. We cannot assure you that these
attempts to offset the decline in production will be successful. These declines
in gross production levels have been greater than the operator and our engineers
projected. We cannot assure you that any attempts to increase production will be
successful or that the Colombia fields will not continue to experience
significantly less production than we and our engineers projected. As a result
of the greater than expected decline in production from the Colombia fields, we
expect that proved reserves at year end 2000 attributable to the fields will be
decreased by more than the amount that would be attributable to production
during the year.
Estimates of our reserves and future net revenues may be unreliable.
Numerous uncertainties exist in estimating quantities of proved reserves
and future net revenues from those reserves. The estimates of proved reserves
and related future net revenues provided in this prospectus are based on various
assumptions, which may be inaccurate. Actual future production, oil and gas
prices, revenues, taxes, capital expenditures, operating expenses, geologic
success and quantities of recoverable oil and gas reserves may vary
substantially from those assumed in the estimates and could materially affect
the estimated quantities and future net revenues of proved reserves set forth in
this prospectus. In addition, we may be subject to downward or upward revisions
based on production performance, purchases or sales of properties, results of
future development, prevailing oil and gas prices and other factors. Therefore,
you should not construe these estimates as estimates of the current market value
of our proved reserves.
Our property in Equatorial Guinea is in the development stage and we may not
be able to meet our targets for first production or production levels, or for
increased levels of production in future phases.
Based on discussions held to date with development contractors, we are
targeting first oil production to occur by year-end 2000, and the plan of
development, as currently approved by the government, provides for initial or
phase-one production of about 52,000 BOPD. We are highly dependent on third
party contractors, including the company constructing, maintaining and operating
the FPSO vessel. Our ability to meet our targets is subject to the timely
drilling and completion of development wells and the timely performance by the
development contractors of their commitments. We cannot assure you that we will
meet these targets. Any phases of production beyond the initial or phase-one
production level from the Ceiba field will depend on a successful delineation
and appraisal program, including interpretation of seismic data and the drilling
of successful appraisal wells. We cannot assure you that we will be successful
in our efforts to increase production from the Ceiba field through appraisal.
Our growth in Equatorial Guinea is dependent on our ability to discover
additional oil or gas fields, and we have a limited time in which to explore.
Under the terms of our production sharing contracts, we have the right to
continue to explore the remaining acreage on our blocks in Equatorial Guinea for
three additional one-year periods, provided that the we commit to drill at least
two exploration wells during that year. Under the current terms of the
contracts, we were required to relinquish 30% of each contract's original area
in April 2000, and an additional 20% of the remaining contract area by the end
of April 2002, provided that we will not be required to surrender an area that
includes a commercial field or a discovery that has not then been declared
commercial. We cannot assure you that we will be successful in discovering
additional oil or gas fields.
We have been negotiating with the Republic of Equatorial Guinea to retain
the 30% of the original area that were required to relinquish in April 2000.
There is a high degree of risk that these negotiations will be unsuccessful. We
can designate the area or areas to be surrendered, provided that, where
possible, each area must be of sufficient size and convenient shape to permit
petroleum operations. We have informed the Republic of Equatorial Guinea that,
if required, we would relinquish those areas of the blocks that we consider to
be the least prospective. We cannot assure you that the government would agree
that this relinquishment meets the terms of the contract.
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19
Sales of gas from our property in Malaysia-Thailand could be delayed by an
environmental impact assessment, and we may have to pay compensation to BP
Amoco and we may not receive incentive payments from BP Amoco if delays occur.
The agreement for the sale of natural gas production from Block A-18 of the
Malaysia-Thailand Joint Development Area contemplates that sales will begin by
June 30, 2002. However, the buyers may delay their obligation to purchase the
gas if they do not receive approval of an environmental impact assessment for
the pipeline and processing facilities they plan to construct. A lengthy
approval process, or significant opposition to the project, could delay
construction and the commencement of gas sales. We cannot assure you that the
buyers will receive approval of the environmental impact assessment or if they
do receive approval, when that approval will occur. It is possible that if the
environmental impact assessment process does result in a significant delay, the
buyers could seek an alternate route for the delivery of the gas. We cannot
assure you as to when any such alternate route could be completed or when gas
sales could commence.
When we sold one half of our interest in Block A-18 to BP Amoco in 1998, BP
Amoco agreed to pay the future exploration and development costs attributable to
our collective interest in Block A-18, up to $377 million or until first
production from a gas field. BP Amoco also agreed to pay us specified incentive
payments if the requisite criteria were met. The first $65 million in incentive
payments is conditioned upon having the production facilities for the sale of
gas from Block A-18 completed by June 30, 2002. If the facilities are completed
after June 30, 2002 but before June 30, 2003, the incentive payment would be
reduced to $40 million. A lengthy environmental approval process, or
unanticipated delays in construction of the facilities, could result in our
receiving a reduced incentive payment or possibly the complete loss of the first
incentive payment. In addition, we have agreed to share with BP Amoco some of
the risk that the environmental approval might be delayed by agreeing to pay to
BP Amoco $1.25 million per month for each month, if applicable, that the first
gas sales are delayed beyond the 30-month period following the award of the
engineering, procurement and construction contract for the project in March
2000. Our obligation is capped at 24 months of these payments or $30 million.
Environmental liabilities could adversely affect our financial condition.
The oil and gas business is subject to environmental hazards, such as oil
spills, gas leaks and ruptures and discharges of toxic substances or gases.
These environmental hazards could expose us to material liabilities for property
damages, personal injuries or other environmental harm, including costs of
investigating and remediating contaminated properties. A variety of stringent
federal, state and foreign laws and regulations govern the environmental aspects
of our business. Such laws and regulations impose strict requirements for, among
other things, well creation, operation and abandonment, waste management, land
reclamation, financial assurance under the Oil Pollution Act of 1990, and
controlling air and water emissions from our production operations and gas
treatment and processing plants. Any noncompliance with these laws and
regulations could subject us to material civil or criminal penalties or other
liabilities. Our compliance with these laws may, from time to time, result in
increased costs to our operations, a decrease in production and have an affect
on our costs of acquisitions.
We do not believe that our environmental risks are materially different
from those of comparable companies in the oil and gas industry. We cannot
provide you any assurance however, that environmental laws will not, in the
future, cause a decrease in our production or processing or cause an increase in
our costs of production, development, exploration or processing. Pollution and
similar environmental risks generally are not fully insurable.
RISKS RELATED TO THE EXCHANGE OFFER AND THE NEW NOTES
If you do not properly tender your old notes, you will continue to hold
unregistered old notes and your ability to transfer old notes will be
adversely affected.
We will only issue new notes in exchange for old notes that you timely and
properly tender. Therefore, you should allow sufficient time to endure timely
delivery of the old notes and you should
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carefully follow the instructions on how to tender your old notes. Neither we
nor the exchange agent are required to tell you of any defects or irregularities
with respect to your tender of old notes.
If you do not exchange your old notes for new notes pursuant to the
exchange offer, the old notes you hold will continue to be subject to the
existing transfer restrictions. In general, you may not offer or sell the old
notes except under an exemption from, or in a transaction not subject to, the
Securities Act of 1933 and applicable state securities laws. We do not plan to
register old notes under the Securities Act of 1933. Further, if you continue to
hold any old notes after the exchange offer is consummated, you may have trouble
selling them because there will be fewer old notes outstanding.
If an active trading market does not develop for the new notes, you may be
unable to sell the new notes or to sell the new notes at a price that you deem
sufficient.
The new notes will be new securities for which there currently is no
established trading market. Although we will register the new notes under the
Securities Act of 1933, we do not intend to apply for listing of the new notes
on any securities exchange or for quotation of the new notes in any automated
dealer quotation system. In addition, although the initial purchasers of the old
notes have informed us that they intend to make a market in the new notes after
the exchange offer, the initial purchasers may stop making a market at any time.
Finally, if a large number of holders of old notes do not tender old notes or
tender old notes improperly, the limited amount of new notes that would be
issued and outstanding after we consummate the exchange offer could adversely
affect the development of a market for these new notes.
Our ability to satisfy our debt obligations, including the new notes, will
depend upon our future growth, our operating performance and our ability to
successfully implement our business strategy.
Our business requires substantial capital. As a result, we now have and,
after the exchange offer will continue to have, substantial amounts of
outstanding debt, interest expense and principal repayment obligations under our
credit facilities and the new notes. At June 30, 2000, as adjusted for the
offering of the old notes and the application of the estimated net proceeds
therefrom, our total debt would have been approximately $509 million on a
consolidated basis. At June 30, 2000, as adjusted to give effect to the offering
of the old notes and the application of the estimated net proceeds therefrom, we
would have had $4.6 million of debt maturing in 2000, $4.6 million maturing in
2001 and zero maturing in 2002, in each case excluding amounts payable under
credit facilities that, provided conditions are met, permit them to be
reborrowed beyond those dates. Subject to the limitations contained in our
credit facility, the indentures governing our 8 3/4% Senior Notes due April 15,
2002 and our 9 1/4% Senior Notes due April 15, 2005, the indenture governing the
new notes and our shareholders agreement with HM4 Triton, L.P., we and our
subsidiaries may incur substantial additional debt to finance our acquisitions,
investments, projects and capital expenditures.
Our existing and future debt could have important consequences to new note
holders, such as
- making it more difficult for us to satisfy our obligations with respect
to the new notes and our other debt;
- limiting our ability to use operating cash flow in other areas of our
business because we must dedicate a substantial portion of these funds to
fund debt service;
- limiting our ability to obtain additional financing to fund our strategy,
working capital, capital expenditures, debt service requirements or for
other purposes;
- limiting our ability to react to changing market conditions, changes in
our industry and adverse economic conditions; and
- increasing our vulnerability to interest rate increases because
borrowings under our credit facility are at variable interest rates.
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Our ability to pay interest on the new notes and to satisfy our other debt
obligations will depend in part on our future growth, our future operating
performance, the successful implementation of our business strategy and our
ability to refinance our debt when necessary. Each of these factors depends on
economic, financial, competitive and other factors beyond our control. If we do
not generate sufficient cash from future operations to make scheduled payments
on the new notes or to meet our other obligations, we will need to refinance our
debt, reduce or delay capital expenditures, obtain additional financing, sell
assets or liquidate Triton. In the past, we have borrowed under various credit
facilities to meet interest obligations, and we may borrow to meet interest
obligations in the future as well. We cannot assure you that our business will
generate sufficient cash flow, or that we will be able to obtain adequate
funding, to satisfy our debt service requirements over the term of the new
notes. The new notes will not be secured by any of our assets. Please read
"Management's Discussion and Analysis of Financial Conditions and Results of
Operations -- Liquidity and Capital Requirements" and "Description of Other
Indebtedness."
Restrictions in our debt agreements and in our shareholders agreement with HM4
Triton, L.P. could limit our growth and our ability to respond to changing
conditions.
The terms of our debt agreements, the indenture governing our 8 3/4% Senior
Notes due April 15, 2002 and our 9 1/4% Senior Notes due April 15, 2005, the
indenture governing the new notes and our shareholders agreement with HM4
Triton, L.P. contain a number of significant covenants. These covenants will
limit our ability to, among other things:
- incur debt above certain levels;
- pay dividends, redeem or repurchase our shares or our 8 3/4% Senior Notes
due April 15, 2002 and our 9 1/4% Senior Notes due April 15, 2005 or make
other distributions;
- make certain investments;
- use assets as security in other transactions;
- enter into transactions with affiliates;
- merge, issue certain securities or enter into certain other business
combination transactions;
- dispose of certain asset sale proceeds;
- create certain liens;
- extend credit;
- sell or discount receivables;
- sell assets comprising more than 50% of our market value;
- enter into certain leases; and
- enter into speculative derivative positions.
A breach of any of these covenants could result in a default under our debt
agreements. A default, if not waived, could result in acceleration of our
indebtedness, in which case the debt would become immediately due and payable.
If this occurs, we may not be able to repay our debt or borrow sufficient funds
to refinance it. Even if new financing is available, it may not be on terms that
are acceptable to us. Please read "Description of Other Indebtedness" and
"Description of New Notes -- Events of Default and Remedies."
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We are a holding company, so our ability to satisfy our debt obligations,
including the new notes, will depend in large part on cash flows made
available from our subsidiaries. Those distributions may be subject to
substantial restrictions.
We are a holding company and conduct substantially all our operations
through our subsidiaries. Substantially all of our assets consist of equity in
our subsidiaries. Our ability to make payments on the new notes will depend on
our receiving sufficient funds from our current and future subsidiaries. Our
subsidiaries are separate legal entities and, because they will not guarantee
the new notes, they will have no obligation to make payments on the new notes or
to make funds available for that purpose.
Their ability to distribute funds to us in the form of dividends,
management fees and expense reimbursements, principal, interest, loans or
otherwise is restricted, and may in the future be restricted, by the terms of
their subsidiary financing arrangements and regulatory schemes. Subject to
restrictions described in this prospectus, the indenture governing the new notes
permits us or our subsidiaries to incur additional secured debt or to pledge
assets to secure new and existing debt. Under certain circumstances, the
indenture also permits us and our subsidiaries to agree with the lenders to
limit the ability of our subsidiaries to make distributions, loans, other
payments or asset transfers to us. In the event of bankruptcy proceedings
affecting a subsidiary, to the extent we are recognized as a creditor of that
subsidiary, our claim would still be subordinate to any security interest in or
other lien on any assets of that subsidiary and to any of its debt and other
obligations that are senior to the payment of the new notes.
The new notes will be effectively subordinated to our future secured debt and
structurally subordinated to the existing and future debt of our subsidiaries.
The new notes will not be secured by any of our assets or the assets of our
subsidiaries. As a result, the new notes will be effectively subordinated to any
of our secured debt to the extent of the security. For example, if we were to
pledge some of our assets to secure debt and we were subsequently to become
insolvent, our secured lenders generally would be entitled to exercise remedies
available to secured lenders with respect to pledged assets.
Further, our subsidiaries will not guarantee the new notes. As a result,
the new notes will be structurally subordinated to the current and future debt
of our subsidiaries. Regardless of whether a subsidiary pledges assets to secure
its debt, if we became insolvent or were liquidated, creditors of our
subsidiaries would generally be entitled to payment of their claims from the
assets of those subsidiaries before any remaining assets are made available to
us for payment on the new notes, except to the extent that we may have a claim
as a creditor to our subsidiaries.
Although the occurrence of specific change of control events affecting us will
permit you to require us to repurchase your new notes, we may not be able to
repurchase your new notes.
Upon the occurrence of specific change of control events affecting us, you
will have the right to require us to repurchase your new notes at 101% of their
principal amount, plus accrued and unpaid interest and liquidated damages. Our
ability to repurchase your new notes upon such change of control event would be
limited by our access to funds at the time and the terms of our debt agreements.
Upon a change of control event, we may be required immediately to repay the
outstanding principal, any accrued interest on and any other amounts owed by us
under our credit facility. The source of funds for these repayments would be our
available cash or cash generated from other sources. However, we cannot assure
you that we will have sufficient funds available upon a change of control event
to make any required repurchases of tendered new notes. Please read "Description
of New Notes -- Change of Control."
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EXCHANGE OFFER
PURPOSE AND EFFECT OF THE EXCHANGE OFFER
In connection with the issuance of the old notes, we entered into a
registration rights agreement. Under the registration rights agreement, we
agreed to:
- use our reasonable best efforts to file a registration statement with the
Securities and Exchange Commission for an exchange of the new notes for
the old notes under the Securities Act of 1933 and to keep such
registration statement effective until the closing of such exchange
offer;
- use our reasonable best efforts to cause the exchange offer to be
consummated within 210 days following the original issuance of the old
notes;
- keep the exchange offer open for acceptance for a period of not less than
20 business days after the date notice thereof is mailed to holders of
the old notes, or longer if required by applicable law; and
- accept for exchange all old notes duly tendered and not validly withdrawn
in the exchange offer in accordance with the terms of the exchange offer
registration statement and letter of transmittal.
As soon as practicable after the exchange offer registration statement
becomes effective, we will offer eligible holders of the old notes the
opportunity to exchange their old notes for new notes registered under the
Securities Act of 1933. Holders are eligible if they are not prohibited by any
law or policy of the Securities and Exchange Commission from participating in
this exchange offer. The new notes will be substantially identical to the old
notes except that the new notes will not contain terms with respect to transfer
restrictions, registration rights or additional interest.
Under limited circumstances, we agreed to use our reasonable best efforts
to cause the Securities and Exchange Commission to declare effective a shelf
registration statement for the resale of the old notes. We also agreed to use
our reasonable best efforts to cause the Securities and Exchange Commission to
keep the shelf registration statement effective for up to two years after its
effective date (or one year from the effective date of the shelf registration
statement if the registration statement is filed upon the request of an initial
purchaser, as described in the third bullet point below). The circumstances
include if:
- we are not permitted to effect the exchange offer as contemplated by the
registration rights agreement because of any change in law or applicable
interpretations of the law by the staff of the Securities and Exchange
Commission;
- any old notes validly tendered pursuant to the exchange offer are not
exchanged for new notes within 210 days after October 4, 2000;
- any initial purchaser of the old notes so requests with respect to old
notes that are not eligible to be exchanged for new notes in the exchange
offer;
- any applicable law or interpretations do not permit any holder of old
notes to participate in the exchange offer; or
- any holder of old notes that participates in the exchange offer does not
receive freely transferable new notes in exchange for tendered old notes.
Under the registration rights agreement, additional interest accrues on the
old notes at a rate of $0.192 per week per $1,000 principal amount of old notes
in the following circumstances:
- the exchange offer registration statement is not declared effective on or
prior to the 180th day after October 4, 2000;
- the exchange offer is not consummated on or prior to the 210th day after
October 4, 2000;
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- a shelf registration statement, if required, is not filed on or before
the date on which such registration statement is required to be filed or
declared effective on or prior to the 180th day after it is required to
be filed; or
- the exchange offer registration statement or shelf registration statement
ceases to be effective after being declared effective without being
succeeded within 30 days by an additional registration statement filed
and declared effective.
Upon the effectiveness of the exchange offer registration statement, the
consummation of the exchange offer, the effectiveness of a shelf registration
statement, or the effectiveness of a succeeding registration statement, as the
case may be, the interest rate borne by the notes from the date of such
effectiveness or consummation, as the case may be, is reduced to the original
interest rate. However, if after any such reduction in interest rate, a
different event specified in the four clauses above occurs, the interest rate
may again be increased pursuant to the foregoing provisions.
To exchange your old notes for transferable new notes in the exchange
offer, you will be required to make the following representations:
- any new notes will be acquired in the ordinary course of your business;
- you have no arrangement or understanding with any person or entity to
participate in the distribution of the new notes;
- you are not engaged in and do not intend to engage in the distribution of
the new notes;
- if you are a broker-dealer that will receive new notes for your own
account in exchange for old notes, you acquired those notes as a result
of market-making activities or other trading activities and you will
deliver a prospectus, as required by law, in connection with any resale
of such new notes; and
- you are not our "affiliate," as defined in Rule 405 of the Securities Act
of 1933.
In addition, we may require you to provide information to be used in
connection with the shelf registration statement to have your old notes included
in the shelf registration statement and benefit from the provisions regarding
additional interest described in the preceding paragraphs. A holder who sells
old notes under the shelf registration statement generally will be required to
be named as a selling securityholder in the related prospectus and to deliver a
prospectus to purchasers. Such a holder will also be subject to the civil
liability provisions under the Securities Act of 1933 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 indemnification obligations.
The description of the registration rights agreement contained in this
section is a summary only. For more information, you should review the
provisions of the registration rights agreement that we filed with the
Securities and Exchange Commission as an exhibit to the registration statement
of which this prospectus is a part.
RESALE OF NEW NOTES
Based on no action letters of the Securities and Exchange Commission staff
issued to third parties, we believe that new notes may be offered for resale,
resold and otherwise transferred by you without further compliance with the
registration and prospectus delivery provisions of the Securities Act of 1933
if:
- you are not our "affiliate" within the meaning of Rule 405 under the
Securities Act of 1933;
- such new notes are acquired in the ordinary course of your business; and
- you do not intend to participate in the distribution of such new notes.
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The Securities and Exchange Commission, however, has not considered the
exchange offer for the new notes in the context of a no action letter, and the
Securities and Exchange Commission may not make a similar determination as in
the no action letters issued to these third parties.
If you tender in the exchange offer with the intention of participating in
any manner in a distribution of the new notes, you
- cannot rely on such interpretations by the Securities and Exchange
Commission staff; and
- must comply with the registration and prospectus delivery requirements of
the Securities Act of 1933 in connection with a secondary resale
transaction.
Unless an exemption from registration is otherwise available, any security
holder intending to distribute new notes should be covered by an effective
registration statement under the Securities Act of 1933. This registration
statement should contain the selling security holder's information required by
Item 507 of Regulation S-K under the Securities Act of 1933. This prospectus may
be used for an offer to resell, resale or other retransfer of new notes only as
specifically described in this prospectus. Only broker-dealers that acquired the
old notes as a result of market-making activities or other trading activities
may participate in the exchange offer. Each broker-dealer that receives new
notes for its own account in exchange for old notes, where such old notes were
acquired by such 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 the new notes. Please read the section captioned
"Plan of Distribution" for more details regarding the transfer of new notes.
TERMS OF THE EXCHANGE OFFER
Subject to the terms and conditions described in this prospectus and in the
letter of transmittal, we will accept for exchange any old notes properly
tendered and not withdrawn prior to the expiration date. We will issue new notes
in principal amount equal to the principal amount of old notes surrendered under
the exchange offer. Old notes may be tendered only for new notes and only in
integral multiples of $1,000.
The exchange offer is not conditioned upon any minimum aggregate principal
amount of old notes being tendered for exchange.
As of the date of this prospectus, $300,000,000 aggregate principal amount
of the old notes are outstanding. This prospectus and the letter of transmittal
are being sent to all registered holders of old notes. There will be no fixed
record date for determining registered holders of old notes entitled to
participate in the exchange offer.
We intend to conduct the exchange offer in accordance with the provisions
of the registration rights agreement, the applicable requirements of the
Securities Act of 1933 and the Securities Exchange Act of 1934 and the rules and
regulations of the Securities and Exchange Commission. Old notes that the
holders thereof do not tender for exchange in the exchange offer will remain
outstanding and continue to accrue interest. These old notes will be entitled to
the rights and benefits such holders have under the indenture relating to the
notes and the registration rights agreement.
We will be deemed to have accepted for exchange properly tendered old notes
when we have given oral or written notice of the acceptance to the exchange
agent and complied with the applicable provisions of the registration rights
agreement. The exchange agent will act as agent for the tendering holders for
the purposes of receiving the new notes from us.
If you tender old notes in the exchange offer, you will not be required to
pay brokerage commissions or fees or, subject to the letter of transmittal,
transfer taxes with respect to the exchange of old notes. We will pay all
charges and expenses, other than certain applicable taxes described below, in
connecting with the exchange offer. It is important that you read the section
labeled "--Fees and Expenses" for more details regarding fees and expenses
incurred in the exchange offer.
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We will return any old notes that we do not accept for exchange for any
reason without expense to their tendering holder as promptly as practicable
after the expiration or termination of the exchange offer.
EXPIRATION DATE
The exchange offer will expire at 5:00 p.m. New York City time on December
7, 2000, unless, in our sole discretion, we extend it.
EXTENSIONS, DELAYS IN ACCEPTANCE, TERMINATION OR AMENDMENT
We expressly reserve the right, at any time or various times, to extend the
period of time during which the exchange offer is open. We may delay acceptance
of any old notes by giving oral or written notice of such extension to their
holders. During any such extensions, all old notes previously tendered will
remain subject to the exchange offer, and we may accept them for exchange.
In order to extend the exchange offer, we will notify the exchange agent
orally or in writing of any extension. We will notify the registered holders of
old notes of the extension no later than 9:00 a.m., New York City time, on the
business day after the previously scheduled expiration date.
If any of the conditions described below under "-- Conditions to the
Exchange Offer" have not been satisfied, we reserve the right, in our sole
discretion
- to delay accepting for exchange any old notes,
- to extend the exchange offer, or
- to terminate the exchange offer,
by giving oral or written notice of such delay, extension or termination to the
exchange agent. Subject to the terms of the registration rights agreement, we
also reserve the right to amend the terms of the exchange offer in any manner.
Any such delay in acceptance, extension, termination or amendment will be
followed as promptly as practicable by oral or written notice thereof to the
registered holders of old notes. If we amend the exchange offer in a manner that
we determine to constitute a material change, we will promptly disclose such
amendment by means of a prospectus supplement. The supplement will be
distributed to the registered holders of the old notes. Depending upon the
significance of the amendment and the manner of disclosure to the registered
holders, we will extend the exchange offer if the exchange offer would otherwise
expire during such period.
CONDITIONS TO THE EXCHANGE OFFER
We will not be required to accept for exchange, or exchange any new notes
for, any old notes if the exchange offer, or the making of any exchange by a
holder of old notes, would violate applicable law or any applicable
interpretation of the staff of the Securities and Exchange Commission.
Similarly, we may terminate the exchange offer as provided in this prospectus
before accepting old notes for exchange in the event of such a potential
violation.
In addition, we will not be obligated to accept for exchange the old notes
of any holder that has not made to us the representations described under
"-- Purpose and Effect of the Exchange Offer," "-- Procedures for Tendering" and
"Plan of Distribution" and such other representations as may be reasonably
necessary under applicable Securities and Exchange Commission rules, regulations
or interpretations to allow us to use an appropriate form to register the new
notes under the Securities Act of 1933.
We expressly reserve the right to amend or terminate the exchange offer,
and to reject for exchange any old notes not previously accepted for exchange,
upon the occurrence of any of the conditions to the
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exchange offer specified above. We will give oral or written notice of any
extension, amendment, non-acceptance or termination to the holders of the old
notes as promptly as practicable.
These conditions are for our sole benefit, and we may assert them or waive
them in whole or in part at any time or at various times in our sole discretion.
If we fail at any time to exercise any of these rights, this failure will not
mean that we have waived our rights. Each such right will be deemed an ongoing
right that we may assert at any time or at various times.
In addition, we will not accept for exchange any old notes tendered, and
will not issue new notes in exchange for any such old notes, if at such time any
stop order has been threatened or is in effect with respect to the registration
statement of which this prospectus constitutes a part or the qualification of
the indenture relating to the notes under the Trust Indenture Act of 1939.
PROCEDURES FOR TENDERING
How to Tender Generally
Only a holder of old notes may tender such old notes in the exchange offer.
To tender in the exchange offer, a holder must:
- complete, sign and date the letter of transmittal, or a facsimile of the
letter of transmittal;
- have the signature on the letter of transmittal guaranteed if the letter
of transmittal so requires; and
- mail or deliver such letter of transmittal or facsimile to the exchange
agent prior to the expiration date; or
- comply with the automated tender offer program procedures of The
Depository Trust Company, or DTC, described below.
In addition, either:
- the exchange agent must receive old notes along with the letter of
transmittal;
- the exchange agent must receive, prior to the expiration date, a timely
confirmation of book-entry transfer of such old notes into the exchange
agent's account at DTC according to the procedure for book-entry transfer
described below or a properly transmitted agent's message; or
- the holder must comply with the guaranteed delivery procedures described
below.
To be tendered effectively, the exchange agent must receive any physical
delivery of the letter of transmittal and other required documents at its
address indicated on the cover page of the letter of transmittal. The exchange
agent must receive such documents prior to the expiration date.
The tender by a holder that is not withdrawn prior to the expiration date
will constitute an agreement between the holder and us in accordance with the
terms and subject to the conditions described in this prospectus and in the
letter of transmittal.
THE METHOD OF DELIVERY OF OLD NOTES, THE LETTER OF TRANSMITTAL AND ALL
OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT YOUR ELECTION AND RISK.
RATHER THAN MAIL THESE ITEMS, WE RECOMMEND THAT YOU USE AN OVERNIGHT OR HAND
DELIVERY SERVICE. IN ALL CASES, YOU SHOULD ALLOW SUFFICIENT TIME TO ASSURE
DELIVERY TO THE EXCHANGE AGENT BEFORE THE EXPIRATION DATE. YOU SHOULD NOT SEND
THE LETTER OF TRANSMITTAL OR OLD NOTES TO US. YOU MAY REQUEST YOUR BROKERS,
DEALERS, COMMERCIAL BANKS, TRUST COMPANIES OR OTHER NOMINEES TO EFFECT THE ABOVE
TRANSACTIONS FOR YOU.
How to Tender if You Are a Beneficial Owner
If you beneficially own old notes that are registered in the name of a
broker, dealer, commercial bank, trust company or other nominee and you wish to
tender those notes, you should contact the registered holder promptly and
instruct it to tender on your behalf. If you are a beneficial owner and wish to
tender
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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 registered holder of old
notes.
The transfer of registered ownership may take considerable time and may not
be completed prior to the expiration date.
Signatures and Signature Guarantees
You must have signatures on a letter of transmittal or a notice of
withdrawal (as described below) guaranteed by a member firm of a registered
national securities exchange or of the National Association of Securities
Dealers, Inc., a commercial bank or trust company having an office or
correspondent in the United States, or an "eligible guarantor institution"
within the meaning of Rule 17Ad-15 under the Securities Exchange Act of 1934. In
addition, such entity must be a member of one of the recognized signature
guarantee programs identified in the letter of transmittal. Signature guarantees
are not required, however, if the notes are tendered:
- by a registered holder who has not completed the box entitled "Special
Issuance Instructions" or "Special Delivery Instructions" on the letter
of transmittal;
- for the account of a member firm of a registered national securities
exchange or of the National Association of Securities Dealers, Inc., a
commercial bank or trust company having an office or correspondence in
the United States, or an eligible guarantor institution.
When You Need Endorsements or Bond Powers
If the letter of transmittal is signed by a person other than the
registered holder of any old notes, the old notes must be endorsed or
accompanied by a properly completed bond power. The bond power must be signed by
the registered holder as the registered holder's name appears on the old notes.
A member firm of a registered national securities exchange or of the National
Association of Securities Dealers, Inc., a commercial bank or trust company
having an office or correspondent in the United States, or an eligible guarantor
institution must guarantee the signature on the bond power.
If the letter of transmittal or any old notes or bond powers are signed by
trustees, executors, administrators, guardians, attorneys-in-fact, officers of
corporations or others acting in a fiduciary or representative capacity, those
persons should so indicate when signing. Unless waived by us, they should also
submit evidence satisfactory to us of their authority to deliver the letter of
transmittal.
Tendering Through DTC's Automated Tender Offer Program
The exchange agent and DTC have confirmed that any financial institution
that is a participant in DTC's system may use DTC's automated tender offer
program to tender. Participants in the program may, instead of physically
completing and signing the letter of transmittal and delivering it to the
exchange agent, transmit their acceptance of the exchange offer electronically.
They may do so by causing DTC to transfer the old notes to the exchange agent in
accordance with its procedures for transfer. DTC will then send an agent's
message to the exchange agent.
The term "agent's message" means a message transmitted by DTC, received by
the exchange agent and forming part of the book-entry confirmation, to the
effect that:
- DTC has received an express acknowledgment from a participant in its
automated tender offer program that is tendering old notes that are the
subject of such book-entry confirmation;
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- such participant has received and agrees to be bound by the terms of the
letter of transmittal or, in the case of an agent's message relating to
guaranteed delivery, that such participant has received and agrees to be
bound by the applicable notice of guaranteed delivery; and
- the agreement may be enforced against such participant.
Determinations Under the Exchange Offer
We will determine in our sole discretion all questions as to the validity,
form, eligibility, time of receipt, acceptance of tendered old notes and
withdrawal of tendered old notes. Our determination will be final and binding.
We reserve the absolute right to reject any old notes not properly tendered or
any old notes our acceptance of which would, in the opinion of our counsel, be
unlawful. We also reserve the right to waive any defect, irregularities or
conditions of tender as to particular old notes. Our interpretation of the terms
and conditions of the exchange offer, including the instructions in the letter
of transmittal, will be final and binding on all parties. Unless waived, all
defects or irregularities in connection with tenders of old notes must be cured
within such time as we shall determine. Although we intend to notify holders of
defects or irregularities with respect to tenders of old notes, neither we, the
exchange agent nor any other person will incur any liability for failure to give
such notification. Tenders of old notes will not be deemed made until such
defects or irregularities have been cured or waived. Any old notes received by
the exchange agent that are not properly tendered and as to which the defects or
irregularities have not been cured or waived will be returned to the tendering
holder, unless otherwise provided in the letter of transmittal, as soon as
practicable following the expiration date.
When We Will Issue New Notes
In all cases, we will issue new notes for old notes that we have accepted
for exchange under the exchange offer only after the exchange agent timely
receives:
- old notes or a timely book-entry confirmation of such old notes into the
exchange agent's account at DTC; and
- a properly completed and duly executed letter of transmittal and all
other required documents or a properly transmitted agent's message.
Return of Old Notes Not Accepted or Exchanged
If we do not accept any tendered old notes for exchange or if old notes are
submitted for a greater principal amount than the holder desires to exchange,
the unaccepted or non-exchanged old notes will be returned without expense to
their tendering holder. In the case of old notes tendered by book-entry transfer
in the exchange agent's account at DTC according to the procedures described
below, such non-exchanged old notes will be credited to an account maintained
with DTC. These actions will occur as promptly as practicable after the
expiration or termination of the exchange offer.
Your Representations to Us
By signing or agreeing to be bound by the letter of transmittal, you will
represent to us that, among other things:
- any new notes that you receive will be acquired in the ordinary course of
your business;
- you have no arrangement or understanding with any person or entity to
participate in the distribution of the new notes;
- you are not engaged in and do not intend to engage in the distribution of
the new notes;
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- if you are a broker-dealer that will receive new notes for your own
account in exchange for old notes, you acquired those notes as a result
of market-making activities or other trading activities and you will
deliver a prospectus, as required by law, in connection with any resale
of such new notes; and
- you are not our "affiliate," as defined in Rule 405 of the Securities Act
of 1933.
BOOK-ENTRY TRANSFER
The exchange agent will establish an account with respect to the old notes
at DTC for purposes of the exchange offer promptly after the date of this
prospectus. Any financial institution participating in DTC's system may make
book-entry delivery of old notes by causing DTC to transfer such old notes into
the exchange agent's account at DTC in accordance with DTC's procedures for
transfer. Holders of old notes who are unable to deliver confirmation of the
book-entry tender of their old notes into the exchange agent's account at DTC or
all other documents required by the letter of transmittal to the exchange agent
on or prior to the expiration date must tender their old notes according to the
guaranteed delivery procedures described below.
GUARANTEED DELIVERY PROCEDURES
If you wish to tender your old notes but your old notes are not immediately
available or you cannot deliver your old notes, the letter of transmittal or any
other required documents to the exchange agent or comply with the applicable
procedures under DTC's automated tender offer program prior to the expiration
date, you may tender if:
- the tender is made through a member firm of a registered national
securities exchange or of the National Association of Securities Dealers,
Inc., a commercial bank or trust company having an office or
correspondent in the United States, or an eligible guarantor institution,
- prior to the expiration date, the exchange agent receives from such
member firm of a registered national securities exchange or of the
National Association of Securities Dealers, Inc., commercial bank or
trust company having a office or correspondent in the United States, or
eligible guarantor institution either a properly completed and duly
executed notice of guaranteed delivery by facsimile transmission, mail or
hand delivery or a properly transmitted agent's message and notice of
guaranteed delivery:
- setting forth your name and address, the registered number(s) of your
old notes and the principal amount of old notes tendered,
- stating that the tender is being made thereby, and
- guaranteeing that, within three (3) New York Stock Exchange trading days
after the expiration date, the letter of transmittal or facsimile
thereof, together with the old notes or a book-entry confirmation, and
any other documents required by the letter of transmittal will be
deposited by the eligible guarantor institution with the exchange agent,
and
- the exchange agent receives such properly completed and executed letter
of transmittal or facsimile thereof, as well as all tendered old notes in
proper form for transfer or a book-entry confirmation, and all other
documents required by the letter of transmittal, within three (3) New
York Stock Exchange trading days after the expiration date.
Upon request to the exchange agent, a notice of guaranteed delivery will be
sent you if you wish to tender your old notes according to the guaranteed
delivery procedures described above.
WITHDRAWAL OF TENDERS
Except as otherwise provided in this prospectus, you may withdraw your
tender at any time prior to the expiration date.
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For a withdrawal to be effective:
- the exchange agent must receive a written notice of withdrawal at the
address indicated on the cover page of the letter of transmittal or
- you must comply with the appropriate procedures of DTC's automated tender
offer program system.
Any notice of withdrawal must:
- specify the name of the person who tendered the old notes to be
withdrawn, and
- identify the old notes to be withdrawn, including the principal amount of
such old notes.
If old notes have been tendered under the procedure for book-entry transfer
described above, any notice of withdrawal must specify the name and number of
the account at DTC to be credited with withdrawn old notes and otherwise comply
with the procedures of DTC.
We will determine all questions as to the validity, form, eligibility and
time of receipt of notice of withdrawal. Our determination shall be final and
binding on all parties. We will deem any old notes so withdrawn not to have been
validly tendered for exchange for purposes of the exchange offer.
Any old notes that have been tendered for exchange but that are not
exchanged for any reason will be returned to their holder without cost to the
holder. In the case of old notes tendered by book-entry transfer into the
exchange agent's account at DTC according to the procedures described above,
such old notes will be credited to an account maintained with DTC for the old
notes. This return or crediting will take place as soon as practicable after
withdrawal, rejection of tender or termination of the exchange offer. You may
retender properly withdrawn old notes by following one of the procedures
described under "-- Procedures for Tendering" above at any time on or prior to
the expiration date.
FEES AND EXPENSES
We will bear the expenses of soliciting tenders. The principal solicitation
is being made by mail; however, we may make additional solicitation by
telegraph, telephone or in person by our officers and regular employees and
those of our affiliates.
We have not retained any dealer-manager in connection with the exchange
offer and will not make any payments to broker-dealers or others soliciting
acceptances of the exchange offer. We will, however, pay the exchange agent
reasonable and customary fees for its services and reimburse it for its related
reasonable out-of-pocket expenses.
We will pay the cash expenses to be incurred in connection with the
exchange offer. They include:
- Securities and Exchange Commission registration fees;
- fees and expenses of the exchange agent and trustee;
- accounting and legal fees and printing costs; and
- related fees and expenses.
TRANSFER TAXES
We will pay all transfer taxes, if any, applicable to the exchange of old
notes under the exchange offer. The tendering holder, however, will be required
to pay any transfer taxes, whether imposed on the registered holder or any other
person, if:
- certificates representing old notes for principal amounts not tendered or
accepted for exchange are to be delivered to, or are to be issued in the
name of, any person other than the registered holder of old notes
tendered;
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- tendered old notes are registered in the name of any person other than
the person signing the letter of transmittal; or
- a transfer tax is imposed for any reason other than the exchange of old
notes under the exchange offer.
If satisfactory evidence of payment of any transfer taxes payable by a note
holder is not submitted with the letter of transmittal, the amount of such
transfer taxes will be billed directly to that tendering holder.
CONSEQUENCES OF FAILURE TO EXCHANGE
If you do not exchange new notes for your old notes under the exchange
offer, you will remain subject to the existing restrictions on transfer of the
old notes. In general, you may not offer or sell the old notes unless they are
registered under the Securities Act of 1933, or if the offer or sale is exempt
from the registration under the Securities Act of 1933 and applicable state
securities laws. Except as required by the registration rights agreement, we do
not intend to register resales of the old notes under the Securities Act of
1933.
ACCOUNTING TREATMENT
We will record the new notes in our accounting records at the same carrying
value as the old notes. This carrying value is the aggregate principal amount of
the old notes, as reflected in our accounting records on the date of exchange.
Accordingly, we will not recognize any gain or loss for accounting purposes in
connection with the exchange offer.
OTHER
Participation in the exchange offer is voluntary, and you should carefully
consider whether to accept. You are urged to consult your financial and tax
advisors in making your own decision on what action to take.
We may in the future seek to acquire untendered old notes in open market or
privately negotiated transactions, through subsequent exchange offers or
otherwise. We have no present plans to acquire any old notes that are not
tendered in the exchange offer or to file a registration statement to permit
resales of any untendered old notes.
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USE OF PROCEEDS
The exchange offer is intended to satisfy our obligations under the
registration rights agreement. We will not receive any cash proceeds from the
issuance of the new notes in the exchange offer. In consideration for issuing
the new notes as contemplated by this prospectus, we will receive old notes in a
like principal amount. The form and terms of the new notes are identical in all
respects to the form and terms of the old notes, except the new notes do not
include certain transfer restrictions. Old notes surrendered in exchange for the
new notes will be retired and cancelled and will not be reissued. Accordingly,
the issuance of the new notes will not result in any increase in our outstanding
indebtedness.
We received approximately $294 million from the offering of the old notes,
after deducting the initial purchasers' discounts and the expenses of that
offering. We used approximately $207 million of these net proceeds to redeem all
of our outstanding 8 3/4% Senior Notes due 2002 which were called for redemption
after the closing of the offering of the old notes. We will use the remaining
net proceeds to fund our future capital expenditure plans as well as for general
corporate purposes. Pending use for these purposes, we will invest the net
proceeds in AAA rated money-market funds.
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CAPITALIZATION
The following table sets forth, as of June 30, 2000, our consolidated
historical capitalization and consolidated as adjusted capitalization
reflecting:
- our application of the net proceeds from the old notes, including the
redemption of all of the 8 3/4% Senior Notes due 2002; and
- the exchange of the old notes for the new notes.
You should read this table in conjunction with our consolidated financial
statements and notes thereto included elsewhere in this prospectus.
AT JUNE 30, 2000
-----------------------
ACTUAL AS ADJUSTED
--------- -----------
(IN THOUSANDS)
Cash and equivalents........................................ $ 79,251 $ 166,351
========= ==========
Long-term debt:(1)
Revolving credit agreement................................ $ -- $ --
Term credit facility...................................... 9,026 9,026
Senior notes due 2002..................................... 199,959 --
Senior notes due 2005..................................... 200,000 200,000
Notes offered hereby...................................... -- 300,000
Other..................................................... 221 221
--------- ----------
Total long-term debt.............................. 409,206 509,247
--------- ----------
Shareholders' equity:
5% preference shares, stated value $34.41(2).............. 6,375 6,375
8% preference shares, stated value $70.00................. 362,944 362,944
Ordinary shares, par value $0.01.......................... 364 364
Additional paid-in capital................................ 529,601 529,601
Accumulated deficit(3).................................... (382,211) (389,280)
Accumulated other non-owner changes in shareholders'
equity................................................. (2,451) (2,451)
--------- ----------
Total shareholders' equity........................ 514,622 507,553
--------- ----------
Total capitalization.............................. $ 923,828 $1,016,800
========= ==========
- ---------------
(1) Includes current maturities of long-term debt of $9.1 million.
(2) These shares have been called for redemption with a redemption date of
October 31, 2000.
(3) The as adjusted accumulated deficit reflects the estimated extraordinary
loss of $7.1 million we expect to realize by redeeming the 8 3/4% Senior
Notes due 2002.
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SELECTED CONSOLIDATED HISTORICAL FINANCIAL DATA
We have provided in the table below our selected consolidated historical
financial data. The financial information for each of the years in the five-year
period ended December 31, 1999 has been derived from our audited financial
statements. The financial information for the six-month periods ended June 30,
2000 and June 30, 1999 has been derived from our unaudited financial statements.
You should read the following financial information in conjunction with our
consolidated financial statements and related notes that are included elsewhere
in this prospectus.
SIX MONTHS
ENDED JUNE 30, YEAR ENDED DECEMBER 31,
----------------- -----------------------------------------------
2000 1999 1999 1998 1997 1996 1995
-------- ------ ------- ------- ------- ------- -------
(IN MILLIONS, EXCEPT PER UNIT AMOUNTS)
STATEMENTS OF OPERATIONS:
REVENUES:
Oil and gas sales..................................... $ 154.0 $108.8 $ 247.9 $ 160.9 $ 145.4 $ 129.8 $ 106.9
Other operating revenues.............................. -- -- -- 67.7 4.1 4.2 0.6
-------- ------ ------- ------- ------- ------- -------
154.0 108.8 247.9 228.6 149.5 134.0 107.5
-------- ------ ------- ------- ------- ------- -------
COSTS AND EXPENSES:
Operating............................................. 31.3 38.2 68.1 73.5 51.4 36.7 35.3
General and administrative............................ 10.3 9.8 23.6 26.7 28.6 25.9 25.7
Depreciation, depletion and amortization.............. 27.4 30.6 61.4 58.8 36.8 25.6 23.2
Writedown of assets................................... -- -- -- 328.6 -- 43.0 --
Special charges....................................... -- 1.2 2.9 18.3 -- -- --
-------- ------ ------- ------- ------- ------- -------
69.0 79.8 156.0 505.9 116.8 131.2 84.2
-------- ------ ------- ------- ------- ------- -------
OPERATING INCOME (LOSS)................................. 85.0 29.0 91.9 (277.3) 32.7 2.8 23.3
Interest income....................................... 4.8 5.2 10.6 3.2 5.2 6.7 8.0
Interest expense, net................................. (8.9) (11.9) (22.7) (23.2) (23.9) (15.9) (24.1)
Other income (expense), net........................... (0.5) 0.2 (3.6) 58.7 2.9 27.3 9.4
-------- ------ ------- ------- ------- ------- -------
(4.6) (6.5) (15.7) 38.7 (15.8) 18.1 (6.7)
-------- ------ ------- ------- ------- ------- -------
Earnings (loss) from continuing operations before
income taxes and extraordinary item............... 80.4 22.5 76.2 (238.6) 16.9 20.9 16.6
Income tax expense (benefit).......................... 25.1 9.7 28.6 (51.1) 11.3 (2.9) 10.1
-------- ------ ------- ------- ------- ------- -------
55.3 12.8 47.6 (187.5) 5.6 23.8 6.5
Discontinued operations............................... -- -- -- -- -- -- (3.8)
-------- ------ ------- ------- ------- ------- -------
Earnings (loss) before extraordinary item........... 55.3 12.8 47.6 (187.5) 5.6 23.8 2.7
Extraordinary item -- extinguishment of debt.......... -- -- -- -- (14.5) (1.2) --
-------- ------ ------- ------- ------- ------- -------
Net earnings (loss)................................. 55.3 12.8 47.6 (187.5) (8.9) 22.6 2.7
Accumulated dividends on preference shares............ 14.7 14.0 28.7 3.1 0.4 1.0 0.8
-------- ------ ------- ------- ------- ------- -------
Earnings (loss) applicable to ordinary shares... $ 40.6 $ (1.2) $ 18.9 $(190.6) $ (9.3) $ 21.6 $ 1.9
======== ====== ======= ======= ======= ======= =======
Average ordinary shares outstanding................... 36.1 36.5 36.1 36.6 36.5 35.9 35.1
======== ====== ======= ======= ======= ======= =======
BASIC EARNINGS (LOSS) PER ORDINARY SHARE:
Continuing operations................................. $ 1.13 $(0.03) $ 0.52 $ (5.21) $ 0.14 $ 0.64 $ 0.16
Discontinued operations............................... -- -- -- -- -- -- (0.11)
Extraordinary item.................................... -- -- -- -- (0.40) (0.03) --
-------- ------ ------- ------- ------- ------- -------
Net earnings (loss)............................. $ 1.13 $(0.03) $ 0.52 $ (5.21) $ (0.26) $ 0.61 $ 0.05
======== ====== ======= ======= ======= ======= =======
DILUTED EARNINGS (LOSS) PER ORDINARY SHARE:
Continuing operations................................. $ 0.94 $(0.03) $ 0.52 $ (5.21) $ 0.14 $ 0.62 $ 0.16
Discontinued operations............................... -- -- -- -- -- -- (0.11)
Extraordinary item.................................... -- -- -- -- (0.39) (0.03) --
-------- ------ ------- ------- ------- ------- -------
Net earnings (loss)............................. $ 0.94 $(0.03) $ 0.52 $ (5.21) $ (0.25) $ 0.59 $ 0.05
======== ====== ======= ======= ======= ======= =======
STATEMENT OF CASH FLOWS DATA:
Cash flows from operating activities.................... $ 66.2 $ 49.8 $ 116.5 $ 1.5 $ (97.4) $ 80.7 $ 149.1
Cash flows from investing activities.................... $ (163.1) $(46.5) $(118.5) $ 84.2 $(212.7) $(105.5) $(159.8)
Cash flows from financing activities.................... $ (10.0) $190.8 $ 170.1 $ (80.1) $ 313.4 $ (13.0) $ 38.9
OTHER FINANCIAL DATA:
EBITDA(a)............................................... $ 116.9 $ 65.4 $ 160.9 $ 54.9 $ 74.4 $ 87.2 $ 57.9
EBITDA to interest expense.............................. 6.0x 3.4x 4.2x 1.1x 1.4x 1.8x 1.3x
Ratio of earnings to fixed charges(b)................... 4.6x 1.8x 2.6x -- -- -- 1.1x
BALANCE SHEET DATA (AT END OF PERIOD):
Working capital (deficit)............................... $ 58.3 $182.1 $ 161.3 $ (21.6) $(115.2) $(182.2) $ 85.6
Property, plant and equipment, net...................... 582.9 571.0 524.2 470.9 835.5 676.8 524.4
Total assets............................................ 1,015.7 937.7 974.5 754.3 1,098.0 914.5 824.2
Long-term debt, including current maturities(c)......... 409.2 418.0 413.5 427.5 573.7 416.6 402.5
Shareholders' equity.................................... 514.6 444.6 463.1 223.8 296.6 300.6 246.0
33
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- ---------------
(a) EBITDA consists of consolidated net earnings (loss), plus interest expense,
income taxes, depreciation expense, amortization of intangibles,
exploration and abandonment expense and other non-cash charges reducing
consolidated net earnings to the extent deducted in calculating
consolidated net earnings (loss). Net earnings associated with barrels
delivered in connection with our forward oil sale in May 1995 have not been
deducted in the calculation of EBITDA. EBITDA is not a measure determined
pursuant to generally accepted accounting principles, or GAAP, nor is it an
alternative to GAAP income.
(b) For purposes of computing the ratio of earnings to fixed charges, earnings
consist of consolidated earnings (loss) from continuing operations before
income taxes and extraordinary items, excluding undistributed equity
earnings of affiliates whose debt is not guaranteed, plus fixed charges.
Fixed charges consists of interest expense on indebtedness and capitalized
interest, plus amortization of debt issuance costs, discounts and premiums,
plus that portion of rental expense which is deemed to be representative of
an interest factor. Earnings were inadequate to cover fixed charges for the
years ended December 31, 1998, 1997, and 1996 by $261.8 million, $8.9
million, and $6.3 million, respectively. Without nonrecurring items,
earnings would have been inadequate to cover fixed charges for the years
ended December 31, 1998, 1997, and 1995 by $39.4 million, $15.2 million,
and $9.9 million, respectively.
(c) Includes current maturities totaling $9.1 million and $9.0 million at June
30, 2000 and 1999, respectively, and $9.0 million, $14.0 million, $130.4
million, $199.6 million, and $1.3 million at December 31, 1999, 1998, 1997,
1996, and 1995, respectively.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion and analysis in conjunction with
our financial information and our consolidated financial statements and notes to
those statements included in this prospectus. The following information contains
forward-looking statements. For a discussion of limitations inherent in
forward-looking statements, see "Disclosure Regarding Forward-Looking
Information" in this prospectus on page 12.
LIQUIDITY AND CAPITAL REQUIREMENTS
Cash and equivalents totaled $79.3 million at June 30, 2000 and $186.3
million at December 31, 1999. Working capital was $58.3 million at June 30, 2000
and $161.3 million at December 31, 1999.
The following summary table reflects cash flows for the six months ended
June 30, 2000 (in thousands):
Net cash provided (used) by operating activities............ $ 66,189
Net cash provided (used) by investing activities............ $(163,070)
Net cash provided (used) by financing activities............ $ (10,011)
Operating Activities
Cash flows provided by operating activities for the six months ended June
30, 2000, benefited from a higher average realized oil price. The higher
realized oil price was partially offset by a decrease in production from the
Cusiana and Cupiagua fields in Colombia. Gross production from the Cusiana and
Cupiagua fields averaged approximately 430,000 BOPD during 1999 and
approximately 331,000 BOPD during the third quarter of 2000. Based on a revised
production forecast we received in September 2000 from the operator, we expect
average gross production for the fields in 2000 will be approximately 334,000
BOPD for the year.
In May 1995, we sold oil forward to a third party for a lump sum payment,
which required us to deliver to the purchaser a fixed amount of production each
month until its expiration in March 2000. We have recognized as revenue about
$11.56 per barrel delivered under the forward oil sale. We completed the
deliveries at the end of the first quarter of 2000, at which time we were
delivering 254,136 barrels per month. Because we no longer are required to
deliver those barrels to the purchaser under the forward oil sale, during the
three months ended June 30, 2000, we were able to sell all of our production at
the higher market price, although we did hedge the price of some of our
production.
Investing Activities
Capital expenditures and other capital investments were $74.4 million for
the six months ended June 30, 2000, primarily for development of the Ceiba field
in Equatorial Guinea and for development of the Cusiana and Cupiagua fields in
Colombia. $9.9 million of that amount was capitalized interest.
In May 2000, we acquired from an unrelated third party, for $88.8 million
in cash, the shares of Triton Pipeline Colombia, Inc. Triton Pipeline Colombia's
sole asset is its 9.6% equity interest in the Colombian pipeline company,
Oleoducto Central S.A. ("OCENSA"). OCENSA is a Colombian company we formed with
Ecopetrol, BP Amoco, TotalFinaElf, IPL Enterprises (Colombia) Inc. and TCPL
International Investments Inc. and owns and operates the pipeline and port
facilities that transport and handle crude oil from the Cusiana and Cupiagua
fields to the Caribbean port of Covenas. We had sold Triton Pipeline Colombia to
the third party in February 1998.
Financing Activities
We repaid borrowings of $4.5 million during the six months ended June 30,
2000, and $14.5 million during the six months ended June 30, 1999. We paid cash
dividends totaling $14.7 million on preference
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shares during the six months ended June 30, 2000 and $2.9 million during the six
months ended June 30, 1999. During the six months ended June 30, 1999, we also
paid dividends on preference shares in additional preference shares totaling
$13.7 million. Proceeds from issuances of ordinary shares under our stock
compensation plans totaled $10.9 million for the six months ended June 30, 2000.
Future Capital Needs
We are implementing an accelerated appraisal and development program to
enable early production from the Ceiba field in Equatorial Guinea. Our target
for first production from the field is by the end of 2000. We have contracted
for a FPSO vessel that we expect to provide storage for up to two MMbbls of oil
and initial processing capacity of up to 60,000 BOPD from a single production
unit. We can add production capacity cost effectively through the installation
of additional processing units. We currently plan to use the Sedco 700
semisubmersible rig to complete four Ceiba wells as production wells, and to
drill and complete additional development wells and water injection wells for
development of the Ceiba field. We also intend to procure equipment for a
water-injection facility for future secondary oil recovery. We have submitted a
revised work program and budget to the government of Equatorial Guinea for
approval. In addition to our plans for accelerated appraisal and development of
the Ceiba field, we expect to use Global Marine's R.F. Bauer drillship to drill
up to six exploration wells in Equatorial Guinea through the middle of 2001, the
first of which we spudded on October 2, 2000.
The accelerated appraisal and development program for Equatorial Guinea, as
well as exploration wells, will require significant capital outlays commencing
this year. For internal planning purposes, our revised capital spending program
for the year ending December 31, 2000, is approximately $256 million, excluding
capitalized interest and acquisitions. The $256 million comprises approximately
$187 million for exploration and development activities in Equatorial Guinea
($42.3 million incurred through June 30), $58 million for the Cusiana and
Cupiagua fields in Colombia, including our interest in Recetor ($17.4 million
incurred through June 30), and $11 million for exploration activities in other
parts of the world ($4.8 million incurred through June 30).
In October 2000, we issued the old notes and received approximately $294
million in net proceeds, after deducting the initial purchasers' discounts and
the expenses of that offering. Upon receiving the proceeds from issuing the old
notes, we called for redemption our outstanding 8 3/4 Senior Notes due 2002,
which will require the payment to the holders of approximately $207 million. The
redemption date was November 3, 2000. We expect that our results of operations
for the quarter ending December 31, 2000, will include an extraordinary expense
of approximately $7 million associated with the redemption of the 8 3/4% Senior
Notes due 2002. The indenture governing the new notes contains various
restrictive covenants including covenants that limit our ability to borrow money
or guarantee other indebtedness, grant liens on our assets, make investments,
use assets as security in other transactions, pay dividends on stock, enter into
sale and leaseback transactions, sell assets, and sell capital stock of
subsidiaries. The indenture provides that we may not incur additional debt
unless at the time of the incurrence our consolidated earnings before interest,
depreciation, depletion, amortization and income taxes to interest expense as
these terms are defined in the indenture, is at least 2.5 to 1. Notwithstanding
this limit, the indenture does permit us to incur certain indebtedness even if
we do not meet this limitation. For example, we can incur indebtedness to
financial institutions, such as the credit agreement described in the next
paragraph, in an amount up to $250 million or the amount obtained by adding $100
million to 20% of the our adjusted net tangible assets, whichever is greater.
In February 2000, we entered into an unsecured two-year revolving credit
facility with a group of banks, which matures in February 2002. The credit
facility gives us the right to borrow from time to time up to the amount of the
borrowing base determined by the banks, not to exceed $150 million. The credit
facility contains various restrictive covenants, including covenants that
require us to maintain a ratio of earnings before interest, depreciation,
depletion, amortization and income taxes to net interest expense of at least 2.5
to 1 on a trailing four quarters basis. The restrictive covenants also prohibit
us from permitting net debt to exceed the product of 3.75 times our earnings
before interest, depreciation, depletion, amortization and income taxes on a
trailing four quarters basis. As of the date of this prospectus, we had
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39
no borrowings outstanding under this facility. As a result of the issuance of
the old notes and the redemption of our 8 3/4% Senior Notes due 2002, the
borrowing base was adjusted to $50 million, subject to any future
redetermination of the borrowing base as provided in the agreement.
In April 1997, we issued $400 million aggregate face value of senior
indebtedness to refinance other indebtedness. The senior indebtedness consisted
of $200 million face amount of 8 3/4% Senior Notes due April 15, 2002 (the "2002
Notes"), at 99.942% of the principal amount (resulting in $199.9 million
aggregate net proceeds) and $200 million face amount of 9 1/4% Senior Notes due
April 15, 2005 (the "2005 Notes" and, together with the 2002 Notes, the "Senior
Notes"), at 100% of the principal amount, for total aggregate net proceeds of
$399.9 million before deducting transaction costs of approximately $1 million.
Interest on the Senior Notes is payable semi-annually on April 15 and
October 15. The Senior Notes are redeemable at any time at our option, in whole
or in part, and contain certain covenants limiting the incurrence of certain
liens, sale/leaseback transactions, and mergers and consolidations.
In November 1995, one of our subsidiaries signed an unsecured term credit
facility with a bank supported by a guarantee issued by the Export-Import Bank
of the United States for $45 million, which matures in January 2001. Principal
and interest payments are due semi-annually on January 15 and July 15, and
borrowings bear interest at LIBOR plus .25%, adjusted on a semi-annual basis. At
June 30, 2000, we had outstanding borrowings of about $9 million under the
facility.
We expect to fund our 2000 capital spending with a combination of some or
all of the following: cash flow from operations, cash, including the net
proceeds from the sale of the old notes, and our committed bank credit facility.
At June 30, 2000, we had guaranteed the performance of a total of $11.4
million in future exploration expenditures to be incurred through September 2001
in various countries. A total of approximately $6 million of the exploration
expenditures are included in the 2000 capital spending program related to a
commitment for two onshore exploratory wells in Greece which were dry holes.
These commitments are backed primarily by unsecured letters of credit.
RESULTS OF OPERATIONS
Sales volumes and average prices realized were as follows:
SIX MONTHS ENDED
JUNE 30,
-----------------
2000 19999
------- -------
Sales volumes:
Oil (MBbls), excluding forward oil sale................... 5,474 6,390
Forward oil sale (MBbls delivered)........................ 762 1,525
------ ------
Total............................................. 6,236 7,915
====== ======
Gas (MMcf)................................................ 220 215
Weighted average price realized:
Oil (per Bbl)(1).......................................... $24.65 $13.72
Gas (per Mcf)............................................. $ 1.25 $ 0.87
- ---------------
(1) Includes the effect of barrels delivered under the forward oil sale, if
applicable, that were recognized at $11.56 per barrel.
Six Months Ended June 30, 2000, Compared with Six Months Ended June 30, 1999
Oil and Gas Sales
Oil and gas sales in 2000 totaled $154 million, a 42% increase from the
prior year due to higher average realized oil prices. This increase was
partially offset by lower production. The average realized oil
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40
price increased $10.93 per barrel, or 80%, resulting in an increase in revenues
of $68.2 million, compared with the same period in 1999. Oil production,
including production related to barrels delivered under the forward oil sale,
decreased 21% in 2000, compared with the prior-year, resulting in a revenue
decrease of $23.1 million. Gross production from the fields averaged
approximately 331,000 BOPD during the third quarter of 2000. Based on a revised
production forecast we received in September 2000 from the operator, we expect
average gross production for the fields will be approximately 334,000 BOPD for
the year.
We have entered into financial and commodity market transactions intended
primarily to reduce risk associated with changing oil prices. For the six months
ended June 30, 2000, our oil sales were approximately $13.4 million less than if
we had not entered into those transactions. Looking forward, we have hedged the
WTI price on a portion of our remaining 2000 oil production and our 2001
production. See "Quantitative and Qualitative Disclosures about Market Risk"
below.
In May 1995, we sold oil forward to a third party for a lump sum payment,
which required us to deliver to the purchaser a fixed amount of production each
month until its expiration in March 2000. We have recognized as revenue about
$11.56 per barrel delivered under the forward oil sale. We completed the
deliveries at the end of the first quarter of 2000, at which time we were
delivering 254,136 barrels per month. Because we no longer are required to
deliver those barrels to the purchaser under the forward oil sale, during the
three months ended June 30, 2000, we were able to sell all of our production at
the higher market price, although we did hedge the price of some of our
production.
Costs and Expenses
Operating expenses decreased $6.9 million in 2000 primarily due to lower
pipeline tariffs. On an oil-equivalent barrel basis, operating expenses were
$5.04 in 2000 and $5.03 in 1999. One component of operating expenses is the
tariff OCENSA charges us to transport our oil through its pipeline. Pipeline
tariffs totaled $17 million, or $2.76 per barrel, in 2000 and $26 million, or
$3.44 per barrel, in 1999. After we acquired Triton Pipeline Colombia in 2000,
we elected to cancel the dividend we would receive as an owner of OCENSA shares
to reduce our tariff. The tariff OCENSA charges us, as well as the other owners
of OCENSA, is the amount OCENSA estimates it needs to recoup the total capital
cost of the project, amortized over a 15-year period; its operating expenses for
the year, which include all Colombian taxes; its interest expense; and the
dividend it must pay to any shareholder that has elected to receive a dividend.
OCENSA charges other shippers of crude oil a premium tariff on a per-barrel
basis, and OCENSA uses the revenues from those tariffs to reduce the tariff it
charges us and its other shareholders.
Depreciation, depletion and amortization decreased $3.3 million, primarily
due to lower production volumes, including barrels delivered under the forward
oil sale.
General and administrative expense before capitalization increased $1.2
million, to $15.2 million in 2000. Capitalized general and administrative costs
were $4.8 million in 2000 and $4.2 million in 1999.
Interest Expense
Gross interest expense totaled $18.7 million for 2000 and $18.8 million for
1999, while capitalized interest for 2000 increased $3 million to $9.9 million.
Income Taxes
Current taxes increased to $20 million in 2000 from $2.6 million in 1999
due to higher pretax income from Colombian operations. During 2000, tax expense
was lower by approximately $5.8 million due to the amortization of deferred
income resulting from anticipated utilization of net operating losses of an
entity that we acquired in 1999. The income tax provisions included deferred tax
expense of $5.1 million for 2000 and $7.2 million for 1999.
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Year Ended December 31, 1999, Compared with Year Ended December 31, 1998
Oil and Gas Sales
Oil and gas sales in 1999 totaled $247.9 million, a 54% increase from 1998,
due to higher average realized oil prices and higher production. The average
realized oil price was $15.95 and $12.31 in 1999 and 1998, respectively, an
increase of 30% for 1999, resulting in higher revenues of $56.4 million compared
to 1998. Total revenue barrels, including production related to barrels
delivered under the forward oil sale, totaled 15.5 million barrels in 1999, an
increase of 19%, compared to the prior year, resulting in an increase in
revenues of $30.7 million. The increased production was primarily due to the
start-up during the second half of 1998 of two new 100,000 BOPD oil-production
units at the Cupiagua central processing facility.
As a result of financial and commodity market transactions settled during
the year ended December 31, 1999, our risk management program resulted in lower
oil sales of approximately $19.8 million than if we had not entered into such
transactions. See "Quantitative and Qualitative Disclosures about Market Risk"
below.
Gain on Sale of Oil and Gas Assets
In August 1998, we sold to a subsidiary of ARCO for $150 million, one-half
of the shares of the subsidiary through which we owned our 50% share of Block
A-18 in the Malaysia-Thailand Joint Development Area. The sale resulted in a
gain of $63.2 million. In December 1998, we sold our Bangladesh subsidiary for
$4.5 million and recorded a gain of the same amount.
Operating Expenses
Operating expenses, which include field operating expenses, pipeline
tariffs and production taxes, decreased $5.4 million in 1999. On an oil
equivalent-barrel basis, operating expenses were $4.50 and $5.97 in 1999 and
1998, respectively. We pay lifting costs, production taxes and transportation
costs to the Colombian port of Covenas for barrels to be delivered under the
forward oil sale. Operating expenses on an oil equivalent-barrel basis were
lower primarily due to higher production volumes. OCENSA pipeline tariffs
totaled $42.1 million and $49.9 million in 1999 and 1998, respectively. Pipeline
tariffs for 1999 were lower primarily due to a non-recurring credit issued by
OCENSA in February 2000 totaling $4.2 million. The credit resulted from OCENSA's
compliance with a Colombian government decree in December 1999 that reduced its
1999 noncash expenses. OCENSA imposes a tariff on shippers from the Cusiana and
Cupiagua fields (the "Initial Shippers"), which is estimated to recoup: the
total capital cost of the project over a 15-year period; its operating expenses,
which include all Colombian taxes; interest expense; and the dividend to be paid
by OCENSA to its shareholders. Any shippers of crude oil who are not Initial
Shippers are assessed a premium tariff on a per-barrel basis, and OCENSA will
use revenues from such tariffs to reduce the Initial Shippers' tariff.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization increased $2.5 million, primarily
due to higher production volumes, including barrels delivered under the forward
oil sale. Off-setting the effect of higher production, full cost ceiling test
writedowns taken during 1998 reduced the per barrel depletion in 1999.
General and Administrative Expenses
General and administrative expense before capitalization decreased $16.6
million from $47.2 million in 1998 to $30.6 million in 1999, while
capitalization general and administrative costs were $6.9 million and $20.6
million in 1999 and 1998, respectively. General and administrative expenses, and
the portion capitalized, decreased as a result of restructuring activities
undertaken during the second half of 1998 and in March 1999.
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Writedown of Assets
In June and December 1998, the carrying amount of our evaluated oil and gas
properties in Colombia was written down by $105.4 million ($68.5 million, net of
tax) and $135.6 million ($115.9 million, net of tax), respectively, through
application of the full cost ceiling limitation as prescribed by the Securities
and Exchange Commission, principally as a result of a decline in oil prices. No
adjustments were made to our reserves in Colombia as a result of the decline in
prices. The Securities and Exchange Commission ceiling test was calculated using
the June 30, and December 31, 1998, WTI oil prices of $14.18 per barrel and
$12.05 per barrel, respectively, that, after a differential for Cusiana crude
delivered at the port of Covenas in Colombia, resulted in a net price of
approximately $13 per barrel and $11 per barrel, respectively.
During 1998, we evaluated the recoverability of our approximate 6.6%
investment in a Colombian pipeline company, Oleoducto de Colombia S.A. ("ODC"),
which is accounted for under the cost method. Based on an analysis of the future
cash flows expected to be received from ODC, we expensed the carrying value of
our investment totaling $10.3 million.
In July 1998, we commenced a plan to restructure our operations, reduce
overhead costs and substantially scale back exploration-related expenditures.
The plan contemplated the closing of foreign offices in four countries, the
elimination of approximately 105 positions, or 41% of the worldwide workforce,
and the relinquishment or other disposal of several exploration licenses.
In conjunction with the plan to restructure operations and scale back
exploration-related expenditures in 1998, we assessed our investments in
exploration licenses and determined that certain investments were impaired. As a
result, unevaluated oil and gas properties and other assets totaling $77.3
million ($72.6 million, net of tax) were expensed. The writedown included $27.2
million and $22.5 million related to exploration activity in Guatemala and
China, respectively. The remaining writedowns related to our exploration
projects in certain other areas of the world.
Special Charges
As a result of the restructuring, we recognized special charges of $15
million during the third quarter of 1998 and $3.3 million during the fourth
quarter of 1998 for a total of $18.3 million. Of the $18.3 million in special
charges, $14.5 million related to the reduction in workforce, and represented
the estimated costs for severance, benefit continuation and outplacement costs,
which will be paid over a period of up to two years according to the severance
formula. From July 1998 through December 31, 1999, we paid $13.1 million in
severance, benefit continuation and outplacement costs. A total of $2.1 million
of special charges related to the closing of foreign offices, and represented
the estimated costs of terminating office leases and the write-off of related
assets. The remaining special charges of $1.7 million primarily related to the
write-off of other surplus fixed assets resulting from the reduction in
workforce. At December 31, 1999, all of the positions had been eliminated, all
designated foreign offices had closed and all licenses had been relinquished,
sold, or their commitments renegotiated. During the fourth quarter of 1999, we
reversed $.7 million of the accrual associated with the completion of
restructuring activities. The remaining liability related to the restructuring
activities undertaken in 1998 was $1 million at December 31, 1999.
In March 1999, we accrued special charges of $1.2 million related to an
additional 15% reduction in the number of employees resulting from our
continuing efforts to reduce costs. The special charges consisted of $1 million
for severance, benefit continuation and outplacement costs and $.2 million
related to the write-off of surplus fixed assets. From March 1999 through
December 31, 1999, we paid $.9 million in severance, benefit continuation and
outplacement costs. At December 31, 1999, the remaining liability related to the
restructuring activities undertaken in 1999 was $.1 million.
In September 1999, we recognized special charges totaling $2.4 million
related to the transfer of our working interest in Ecuador to a third party.
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Gain on Sale of Triton Pipeline Colombia
In February 1998, we sold Triton Pipeline Colombia to an unrelated third
party for $100 million. Net proceeds were approximately $97.7 million. The sale
resulted in a gain of $50.2 million.
Interest Expense
Gross interest expense for 1999 and 1998 totaled $37.2 million and $46.4
million, respectively, while capitalized interest for 1999 decreased $8.7
million to $14.5 million. The decrease in capitalized interest is primarily due
to the writedown of unevaluated oil and gas properties in June 1998 and a sale
of 50% of our Block A-18 project in August 1998.
Other Income (Expense), Net
Other income (expense), net, included a foreign exchange gain (loss) of
($2.7 million) and $2.1 million in 1999 and 1998, respectively. During 1999 and
1998, we recorded gains of $6.2 million and $.4 million, respectively,
representing the change in the fair value of the call options purchased in
anticipation of a forward oil sale. In addition, during 1999 and 1998, we
recorded an expense of $6.9 million and $3.3 million, respectively, in other
income (expense), net, related to the net payments made under and the change in
the fair value of the equity swap entered into in conjunction with the sale of
Triton Pipeline Colombia. In 1999 and 1998, we recorded loss provisions of $2.3
million and $.8 million, respectively, for certain legal matters. In 1998, we
recognized gains of $7.6 million on the sale of corporate assets in addition to
the ARCO and Triton Pipeline Colombia transactions.
Income Taxes
Statement of Financial Accounting Standards No. 109 ("SFAS 109"),
"Accounting of Income Taxes," requires that we make projections about the timing
and scope of certain future business transactions in order to estimate
recoverability of deferred tax assets primarily resulting from the expected
utilization of net operating loss carryforwards ("NOLs"). Changes in the timing
or nature of actual or anticipated business transactions, projections and income
tax laws can give rise to significant adjustments to our deferred tax expense or
benefit that may be reported from time to time. For these and other reasons,
compliance with SFAS 109 may result in significant differences between tax
expense for income statement purposes and taxes actually paid.
Current taxes related to our Colombian operations were $20.8 million and
$4.4 million in 1999 and 1998, respectively. The income tax provision for 1999
included a foreign deferred tax expense totaling $9.2 million compared with a
foreign deferred tax benefit of $57 million in 1998. The benefit recognized in
1998 primarily resulted from the writedown of oil and gas properties.
Additionally, the income tax provision included a deferred tax benefit in the
United States totaling $1.4 million, compared with an expense of $1.5 million in
1998.
At December 31, 1999, we had U.S. NOLs of approximately $450.2 million
compared with NOLs of approximately $415.6 million at December 31, 1998. The
NOLs expire from 2000 to 2020. At December 31, 1999, our Colombian operations
and other foreign operations had NOLs and other credit carryforwards totaling
$57.4 million and $40.7 million, respectively, that will expire between 2001 and
2004.
During 1999, we acquired the Colombian entity of our former partner in the
El Pinal field. In addition to the working interest in the El Pinal field, the
acquired entity has tax basis and NOLs totaling approximately $40 million,
included in total foreign NOLs above, which we expect to utilize in 2000. At
December 31, 1999, the tax affected amount of the tax basis and NOLs ($14.2
million) was included in current assets as a deferred tax asset. In addition, we
recorded deferred income of $10.6 million, representing the difference between
the value of the deferred tax asset and the purchase price. During 2000, the
deferred tax asset and the deferred income will be reduced as the tax basis and
NOLs are utilized.
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We recorded a U.S. deferred tax asset of $88.2 million, net of a valuation
allowance of $72.9 million, at December 31, 1999. The valuation allowance was
primarily attributable to management's assessment of the utilization of NOLs in
the U.S., the expectation that other tax credits will expire without being
utilized, and certain temporary differences will reverse without a benefit to
us. The minimum amount of future taxable income necessary to realize the U.S.
deferred tax asset is approximately $252 million. Although there can be no
assurance we will achieve such levels of income, management believes the
deferred tax asset will be realized through income from its operations.
Year Ended December 31, 1998, Compared with Year Ended December 31, 1997
Oil and Gas Sales
Oil and gas sales in 1998 totaled $160.9 million, an 11% increase from
1997, due to higher production, which was partially offset by significantly
lower average realized oil prices. Total revenue barrels, including production
related to barrels delivered under the forward oil sale, totaled 13 million
barrels in 1998, an increase of 58%, compared to the prior year, resulting in an
increase in revenues of $84.2 million. The increased production was primarily
due to the start-up in late 1997 of two new 80,000 BOPD oil-production units at
the Cusiana central processing facility. In addition, two 100,000 BOPD
oil-production units at the Cupiagua central processing facility began
production during the second half of 1998. The average realized oil price was
$12.31 and $17.54 in 1998 and 1997, respectively, a decrease of 30% for 1998,
resulting in lower revenues of $68.3 million compared to 1997. The lower average
realized oil price resulted from a significant decrease in the 1998 average WTI
oil price.
Gain on Sale of Oil and Gas Assets
In August 1998, we sold to a subsidiary of ARCO for $150 million, one-half
of the shares of the subsidiary through which we owned our 50% share of Block
A-18 in the Malaysia-Thailand Joint Development Area. The sale resulted in a
gain of $63.2 million. In December 1998, we sold our Bangladesh subsidiary for
$4.5 million and recorded a gain of the same amount.
In June 1997, we sold our Argentine subsidiary for cash proceeds of $4.1
million and recognized a gain of $4.1 million.
Operating Expenses and Depreciation, Depletion and Amortization
Operating expenses increased $22.2 million in 1998, and depreciation,
depletion and amortization increased $22 million, primarily due to higher
production volumes, including barrels delivered under the forward oil sale. Our
operating costs per oil equivalent-barrel were $5.97 and $6.47 in 1998 and 1997,
respectively. Operating expenses on a per equivalent-barrel basis were lower
primarily due to higher production volumes and a decrease in production taxes of
$7.8 million. Beginning in 1998, no production taxes were assessed on production
from the Cusiana field. These improvements to operating costs were partially
offset by an increase in OCENSA pipeline tariffs which totaled $49.9 million or
$4.08 per barrel, and $28.7 million or $3.69 per barrel, in 1998 and 1997,
respectively. The OCENSA pipeline expansion was completed at the end of 1997. At
such time, the full cost of the pipeline was included in the tariff computation,
which was the primary contributor to the higher 1998 tariffs.
General and Administrative Expenses
General and administrative expense before capitalization decreased $13.8
million to $47.2 million in 1998, while capitalized general and administrative
costs were $20.6 million and $32.4 million in 1998 and 1997, respectively.
General and administrative expenses, and the portion capitalized, decreased as a
result of restructuring activities undertaken in the third quarter of 1998 to
reduce overhead costs and exploration expenses.
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Interest Expense
Gross interest expense for 1998 and 1997 totaled $46.4 million and $49.7
million, respectively, while capitalized interest for 1998 decreased $2.6
million to $23.2 million. The decrease in capitalized interest is primarily due
to the writedown of unevaluated property totaling $73.9 million in June 1998 and
a sale of 50% of our Block A-18 project in August 1998.
Other Income (Expense), Net
Other income (expense), net, included foreign exchange gains of $2.1
million and $9.5 million in 1998 and 1997, respectively, primarily related to
noncash adjustments to deferred tax liabilities in Colombia associated with
devaluation of the Colombian peso versus the U.S. dollar. In 1998 and 1997, we
recognized gains of $7.6 million and $1.4 million, respectively, on the sale of
corporate assets. During 1998 and 1997, we recorded a gain (loss) of $.4 million
and ($9.7 million), respectively, representing the change in the fair value of
the call options purchased in anticipation of a forward oil sale. In addition,
during 1998, we recorded an expense of $3.3 million in other income (expense),
net, related to the net payments made under and the change in the fair value of
the equity swap entered into in conjunction with the sale of Triton Pipeline
Colombia.
Income Taxes
The income tax provision for 1998 included a foreign deferred tax benefit
totaling $57 million compared with a foreign deferred tax expense of $16 million
in 1997. The benefit recognized in 1998 primarily resulted from the writedown of
oil and gas properties. Additionally, the income tax provision included deferred
tax expense in the United States totaling $1.5 million, compared with a benefit
of $7.9 million in 1997. Current taxes related to our Colombian operations were
$4.4 million and $3.4 million in 1998 and 1997, respectively.
Extraordinary Item
In May and June 1997, we completed a tender offer and consent solicitation
with respect to our Senior Subordinated Discount Notes due November 1, 1997
("1997 Notes") and 9 3/4% Senior Subordinated Discount Notes due December 31,
2000 ("9 3/4% Notes") that resulted in the retirement of the 1997 Notes and
substantially all of the 9 3/4% Notes. Our results of operations for 1997
included an extraordinary expense of $14.5 million, net of a $7.8 million tax
benefit, associated with the extinguishment of the 1997 Notes and 9 3/4% Notes.
The remainder of the 9 3/4% Notes were retired in 1998.
EXPLORATION OPERATIONS
We follow the full cost method of accounting for exploration and
development of oil and gas reserves. Under this method of accounting, all of our
costs related to acquisition, holding and initial exploration of licenses in
countries where we do not have any proved reserves are initially capitalized. We
then periodically make assessments of these licenses for impairment on a
country-by-country basis. Based on our evaluation of drilling results, seismic
data and other information we deem relevant, we may write down the carrying
value of the oil and gas licenses in that country. A writedown constitutes a
charge to earnings that does not impact our cash flow from operating activities,
but it does reduce our shareholders' equity. For example, in September 2000, we
surrendered our interest in an onshore lease in Greece, after drilling two dry
holes and we expect to record a write down of about $19 million ($17 million net
of tax) in the third quarter of 2000. In addition, in the second quarter of
1998, we recorded a $77.3 million ($72.6 million, net of tax) writedown of
unevaluated oil and gas properties relating to our operations in China, Ecuador,
Guatemala and other countries, and a corresponding reduction in shareholders'
equity. We expect to complete our contractual obligations in Greece, Italy,
Madagascar, and Oman over the next 12 months. If in the course of our
exploration activities in any one or more of these countries, we determine that
continuing to explore for hydrocarbons there is not justified, we may record a
writedown
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during this period of any one of our cost pools related to these countries. Due
to the unpredictable nature of exploration activities, we cannot predict the
amount and time of impairment writedowns.
ENVIRONMENTAL MATTERS
The oil and gas business is subject to environmental hazards, such as oil
spills, gas leaks and ruptures and discharges of toxic substances or gases.
These environmental hazards could expose us to material liabilities for property
damages, personal injuries or other environmental harm, including costs of
investigating and remediating contaminated properties. A variety of stringent
federal, state and foreign laws and regulations govern the environmental aspects
of our business. Such laws and regulations impose strict requirements for, among
other things, well creation, operation and abandonment, waste management, land
reclamation, financial assurance under the Oil Pollution Act of 1990, and
controlling air and water emissions from our production operations and gas
treatment and processing plants. Any noncompliance with these laws and
regulations could subject us to material civil or criminal penalties or other
liabilities. Our compliance with these laws may, from time to time, result in
increased costs to our operations, a decrease in production and have an affect
on our costs of acquisitions.
We do not believe that our environmental risks are materially different
from those of comparable companies in the oil and gas industry. We cannot
provide you any assurance however, that environmental laws will not, in the
future, cause a decrease in our production or processing or cause an increase in
our costs of production, development, exploration or processing. Pollution and
similar environmental risks generally are not fully insurable.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This Statement was amended in June 2000 by
SFAS No. 138 "Accounting for Certain Derivative Instruments and Certain Hedging
Activities -- an Amendment of SFAS No. 133." The new statements establish
accounting and reporting standards for derivative instruments and for hedging
activities. The standards will require us to recognize all derivatives as either
assets or liabilities in the balance sheet and measure those instruments at fair
value. The requisite accounting for changes in the fair value of a derivative
will depend on the intended use of the derivative and the resulting designation.
We must adopt the statements effective January 1, 2001. Based on our outstanding
derivatives contracts, the impact of adopting this standard would not have a
material adverse effect on our operations or consolidated financial condition.
However, we cannot give you any assurance as to what the impact will be at the
time we adopt the statements, because the impact will depend on our derivatives
activities at the time of adoption.
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
Our oil sales are normally priced with reference to a defined benchmark,
such as WTI light sweet crude oil traded on the New York Mercantile Exchange.
The price we actually receive will vary from the benchmark depending on quality
and location differentials. As a matter of policy, from time to time we use
financial market transactions with creditworthy counterparties to reduce risk
associated with the pricing of our oil sales. The policy is structured to
underpin our planned revenues and results of operations. We cannot assure you
that our use of financial market transactions will not result in losses. We do
not enter into financial market transactions for trading purposes.
We have entered into oil price swaps with creditworthy counterparties to
establish a weighted average WTI benchmark price of $30.23 per barrel on an
aggregate of 1.5 million barrels of production during the period from July
through December 2000. As a result, to the extent the average monthly WTI price
exceeds $30.23, we will pay the counterparties the difference between the
average monthly WTI price and $30.23, and to the extent that the average monthly
WTI price is below $30.23, the counterparties will pay us the difference between
the average monthly WTI price and $30.23. In addition, we have entered into
option contracts for an aggregate of 300,000 barrels of production during the
period from July through
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September 2000. As a result, to the extent the monthly average WTI exceeds
$28.43 per barrel, we will pay the counterparty the difference between the
average WTI and $28.43, and to the extent WTI is at or below $22.00, the
counterparty will pay us $2.00 per barrel.
Also, we have entered into option contracts for an aggregate of 900,000
barrels of production during the period from January through June 2001. As a
result, to the extent the monthly average WTI exceeds $35.48 per barrel, we will
pay the counterparty the difference between the average WTI and $35.48 per
barrel, and to the extent WTI is at or below $27.00, the counterparty will pay
us $3.00 per barrel.
BUSINESS
We are an international oil and gas exploration and production company. Our
core operating areas and oil and gas reserves are located in Colombia,
Equatorial Guinea and Malaysia-Thailand. We explore for oil and gas in these
areas, as well as in southern Europe, Africa and the Middle East. We believe
that our acreage portfolio offers significant opportunity for growth and
diversifies our exposure to any one region. Since 1989, we have discovered three
major fields through our exploration program which has allowed us to grow and
diversify our reserve base.
OIL AND GAS PROPERTIES
Through various subsidiaries and affiliates, we have participating
interests in exploration licenses in Colombia, Equatorial Guinea, Block A-18 of
the Malaysia-Thailand Joint Development Area in the Gulf of Thailand, Gabon,
Greece, Italy, Madagascar and Oman. All of our proved reserves are located in
Colombia, offshore Equatorial Guinea and in the Gulf of Thailand. Our Colombia
operation is currently responsible for substantially all of our revenues and
operating cash flow.
The following is intended to describe our interests in these licenses and
our recent operations over these licenses. Many of our interests are owned with
partners. References in this discussion to "we" and "us" sometimes refer to
Triton and its partners in a given area.
Colombia
We hold a 12% interest in the Santiago de Las Atalayas ("SDLA"), Tauramena
and Rio Chitamena contract areas, covering approximately 66,000, 36,300 and
6,700 acres, respectively. The areas are located approximately 160 kilometers
(100 miles) northeast of Bogota in the Andean foothills of the Llanos Basin area
in eastern Colombia.
Our partners in these areas are Empresa Colombiana De Petroleos
("Ecopetrol"), the Colombian national oil company, with a 50% interest, and
subsidiaries of BP Amoco and TotalFina EIF SA, each with a 19% interest. BP
Amoco is the operator. Our net revenue interest is approximately 9.6% after
governmental royalties. We have an agreement with one of our original
co-investors that entitles that party to .36% of our net revenue if it pays its
proportionate share of related costs.
Contract Terms
The SDLA license gives BP Amoco, TotalFinaElf and us the right to produce
oil and gas from the contract area through the year 2010. The Tauramena license
gives BP Amoco, TotalFinaElf and us the right to produce oil and gas from the
contract area through the year 2016. The Rio Chitamena license gives BP Amoco,
TotalFinaElf and us the right to produce oil and gas from the contract area
through the year 2015 or 2019, depending on contract interpretation.
In July 1994, BP Amoco, TotalFinaElf, Ecopetrol and Triton agreed to a
procedure for developing the Cusiana field. Until the expiration of the SDLA
association contract in 2010, oil and gas produced from the unified area will be
owned by the parties according to their percentage interests in each contract
area.
In the first quarter of 2005, the parties will have an independent
determination of the original barrels of oil equivalent of petroleum in place
under the unified area and under each association contract made.
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Then a "tract factor" will be calculated for each association contract. Each
tract factor will be the amount of original barrels of oil equivalent in place
under the particular association contract as a percentage of the total original
barrels of oil equivalent under the unified area. Each party's unified area
interest during the second period (commencing from the expiration of the SDLA
association contract in 2010) and during the final period (commencing from the
termination of the second association contract to termination) will be the
aggregate of that party's interest in each remaining association contract
multiplied by the tract factor for each such contract.
Recent Operating Activity
Cusiana Field
In the Cusiana Field, from January 2000 through August 2000 we completed an
additional three wells, bringing the total completions to date to 48 producing
wells, 13 gas injection wells and four water injection wells. The gas injection
wells recycle to the Mirador formation most of the gas that is associated with
the oil production to increase the oil recoverable during the life of the field.
The water injection wells inject the field's produced water into the Barco and
Guadalupe formations for disposal and pressure maintenance. There are currently
two drilling rigs operating in the Cusiana Field, and we expect that one
additional well will be completed during 2000 and two additional wells in 2001.
Cupiagua Field
In the Cupiagua Field, from January 2000 through August 2000 we completed
an additional six wells, bringing the total completions to date to 30 producing
wells and eight gas injection wells. There are currently three drilling rigs
operating in the Cupiagua Field on the SDLA contract area to drill production,
water and gas injection wells, and we expect that three wells will be completed
during 2000 and three additional wells in 2001.
Recetor Contract Area
In 1999, we acquired a 20% interest in the Recetor contract area, covering
approximately 70,215 acres, subject to certain government royalties. Ecopetrol
has the right to acquire up to a 50% interest in the Recetor contract area, pro
rata from each participant, upon declaration of commerciality. This area is
located adjacent to and north of the SDLA contract area and includes an
extension of the Cupiagua field. Our partners in this area are BP Amoco, with a
63.3% interest, and Inaquimicas, with a 16.7% interest. BP Amoco is the
operator. The contract provides BP Amoco, Inaquimicas and us the right to
produce oil and gas from the Recetor contract area through the year 2017.
In January 2000, our working interest partners and we completed the Liria
YD-2 well on the extension of the Cupiagua field in the Recetor contract area.
The well reached total depth of 16,953 feet and is producing into the Cupiagua
central processing facility. Ecopetrol granted commerciality on a limited area.
Currently one drilling rig is operating in the Recetor contract area. We expect
that at least two additional wells will be drilled in the Recetor contract area
in 2001.
Production Facilities and Pipelines
We have completed the production facilities in the Cusiana and Cupiagua
fields. The components of the Cusiana central processing facility consist of a
long term test facility, four early production units, and two 80,000 BOPD
production trains. The production capacity of the Cusiana central processing
facility is approximately 320,000 BOPD. Currently, the Cusiana central
processing facility cannot handle more than about 1,400 MMcf of gas per day.
This limitation constrains the amount of oil that can be produced because gas
and oil are produced at the same time.
The components of the Cupiagua central processing facility consist of two
100,000 BOPD production trains. The gas handling capacity of the Cupiagua
central processing facility is approximately 1,300 MMcf of gas per day.
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49
We transport the oil and condensate produced from the Cusiana and Cupiagua
fields to the Caribbean port of Covenas through the 832-kilometer (520-mile)
pipeline system operated by OCENSA. OCENSA also transports oil produced by other
parties from other fields in Colombia.
Gross production from the Cusiana and Cupiagua fields averaged
approximately 430,000 BOPD during 1999 and approximately 331,000 BOPD during the
third quarter of 2000. Based on a revised production forecast we received in
September 2000 from the operator, we expect that average gross production for
the fields will be approximately 334,000 BOPD for the year. The operator has
recommended certain actions to offset the decline in production in 2001, such as
work overs and water flood projects, that would result in an expected production
rate of approximately 270,000 to 280,000 BOPD in 2001. We cannot assure you that
these attempts to offset the decline in production will be successful. These
declines in gross production levels have been greater than the operator and our
engineers projected. We cannot assure you that any attempts to increase
production will be successful or that the Colombia fields will not continue to
experience significantly less production than we and our engineers projected. As
a result of the greater than expected decline in production from the Colombia
fields, we expect that proved reserves at year end 2000 attributable to the
fields will be decreased by more than the amount that would be attributable to
production during the year.
Equatorial Guinea
We have an interest in production-sharing contracts covering two contiguous
blocks (Blocks F and G) with the Republic of Equatorial Guinea. The contracts
became effective in April 1997 and were amended in October 2000. In October
1999, we announced the discovery of the Ceiba oil field, located on Block G
offshore the Republic of Equatorial Guinea. The field is located in
approximately 2,200 to 2,600 feet of water, approximately 22 miles off the
continental coast.
The contracts give us the right to explore and develop an area covering
approximately 1.3 million acres located offshore and southwest of the town of
Bata in water depths of up to 5,200 feet. We are the operator and Energy Africa
Equatorial Guinea Limited is our partner. Our contract interest is 85% and
Energy Africa's contract interest is 15%, subject to a 5% carried participating
interest held by the government.
Contract Terms
Currently, our remaining commitments under the production-sharing contracts
for the contract year ending April 2001 are to drill at least one exploration
well, and a second exploration well contingent upon our identifying an
additional structure we believe is a drillable prospect. We can extend the
exploration period of each contract for three additional one-year periods if we
agree to certain operational commitments for those periods, including the
drilling of at least one exploration well, and a second exploration well
contingent upon our identifying an additional structure we believe is a
drillable prospect. The contracts require us to relinquish 30% of each
contract's original area in April 2000, and an additional 20% of the remaining
contract area by the end of April 2002, provided that we will not be required to
surrender an area that includes a commercial field or a discovery that has not
then been declared commercial. We can designate the area or areas to be
surrendered, provided that, where possible, each area must be of sufficient size
and convenient shape to permit petroleum operations. We have been negotiating
with the Republic of Equatorial Guinea to retain the 30% of the original area
that we were required to relinquish in April 2000.
The contracts provide that if there is a commercial discovery of an oil or
gas field on a block, the contract will remain in existence as to that field for
a period of 30 years, in the case of oil, or 40 years, in the case of gas, from
the date the Ministry of Mines and Energy approves the discovery as commercial.
Any further discoveries of formations that underlie or overlie that field, or
other deposits found within the extension of that field, will be included with
that field and be subject to the original 30 or 40 year term, as applicable. The
Ministry approved the Ceiba field as commercial in December 1999.
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50
Under the terms of the production-sharing contracts, the Republic of
Equatorial Guinea is entitled to a royalty as to each field. In the case of an
oil field, the royalty is based on average daily production, and is determined
as follows:
RATES OF DAILY PRODUCTION OF A FIELD
(CALCULATED ON AN INCREMENTAL BASIS OF CRUDE OIL) ROYALTY PER TRANCHE
- ------------------------------------------------- -------------------
From 0 to 30,000 Barrels.................................... 11%
Above 30,000 to 60,000 Barrels.............................. 12%
Above 60,000 to 80,000 Barrels.............................. 14%
Above 80,000 to 100,000 Barrels............................. 15%
More than 100,000 Barrels................................... 16%
In the case of a gas field, the royalty is 10% of all the natural gas in
the field.
After making the royalty payments, we and Energy Africa will be allocated
up to 70% of the remaining production to recover our capital costs. The
government of Equatorial Guinea's 5% carried participating interest does not
entitle the government to receive any of the proceeds for cost recovery. After
the allocation of production toward the payment of the royalty and cost
recovery, the production sharing contracts entitle the Republic of Equatorial
Guinea to receive a share of production based on cumulative production,
determined as follows:
CONTRACTORS' SHARE OF
CUMULATIVE PRODUCTION GOVERNMENT SHARE OF REMAINING
(IN MILLIONS OF BARRELS) REMAINING PRODUCTION PRODUCTION
- ------------------------ -------------------- ---------------------
From 0 to 200...................................... 20% 80%
Above 200 to 350................................... 30% 70%
Above 350 to 450................................... 40% 60%
Above 450 to 550................................... 50% 50%
More than 550...................................... 60% 40%
The government of Equatorial Guinea's 5% carried participating interest
entitles it to receive 5% of the production allocated to the contractors in the
preceding table. As a result, we would receive 80.75% of the remaining
production and Energy Africa would receive 14.25%.
In addition, as any new field is discovered, the contractors must make a
production payment to the government in the amount of $750,000 when the Ministry
of Mines and Energy approves the discovery as commercial. The contractors must
pay the government certain production bonuses if and when production from a
field, including the Ceiba field, averages certain levels for the first time,
determined as follows:
AVERAGE PRODUCTION PER DAY PRODUCTION BONUS
-------------------------- ----------------
30,000...................................................... $4 million
60,000...................................................... 3 million
100,000..................................................... 4 million
These production bonuses would be added to the capital costs the
contractors are entitled to recover.
Recent Operating Activity
In October 1999, we announced an oil discovery in the Ceiba field, Block G,
and confirmed the significance of the discovery with the Ceiba-2 appraisal well.
On test, the Ceiba-1 well flowed 12,401 BOPD of 30 degree oil from one zone over
an interval of 160 feet. Test results were constrained by the capacity of
surface testing equipment. Analysis of wireline logs and core data indicate a
gross oil column of 742 feet in the well with net oil-bearing pay of 314 feet in
four zones. The Ceiba-1 well was drilled to a total depth of approximately 9,700
feet in approximately 2,200 feet of water, located 22 miles off the continental
coast.
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51
The Ceiba-2 well was drilled approximately one mile to the southwest and
342 feet down-dip of the Ceiba-1 discovery well. The well encountered net
oil-bearing pay of 300 feet in a single, continuous column. In addition, the
well confirmed the oil-water contact found in Ceiba-1, and demonstrated lateral
reservoir continuity and connectivity. The well is located 22 miles off the
continental coast and was drilled to a total depth of 8,744 feet in 2,347 feet
of water. We elected not to flow test the well based on wireline logs, extensive
coring and pressure data, as well as Ceiba-1 flow-test results.
In June 2000, we reported that the Ceiba-3 development well confirmed the
primary reservoir found in the Ceiba-1 and Ceiba-2 wells and encountered a
deeper, similar-quality oil reservoir. Ceiba-3 penetrated 256 feet of net
oil-bearing pay based on the analysis of drilling, coring, wireline logging and
samples. The new additional reservoir has an oil-water contact about 60 feet
deeper than the oil-water contact found in the first two wells drilled in the
Ceiba field. Located 22 miles off the continental coast of Equatorial Guinea on
Block G, the Ceiba-3 well was drilled to a total depth of 9,695 feet in 2,165
feet of water. The well is approximately one mile northeast and 282 feet downdip
of the Ceiba-1 discovery well and confirms the extension of the Ceiba field to
the north.
In June 2000, we reported that the Ceiba-4 development well confirmed the
oil pool found in the Ceiba-1, -2 and -3 wells. Ceiba-4 penetrated 269 feet of
net oil-bearing pay in three zones based on the analysis of drilling, coring,
wireline logging and samples. The Ceiba-4 well confirmed the southern extension
of the field, validating lateral reservoir continuity and connectivity in the
oil reservoir tested in the Ceiba-1 discovery well and confirmed in Ceiba-2 and
Ceiba-3. The Ceiba-4 well results support a deeper field oil-water contact than
originally interpreted. Located 22 miles off the continental coast of Equatorial
Guinea on Block G, the Ceiba-4 well was drilled to a total depth of 8,957 feet
in 2,431 feet of water. The well is approximately one mile southwest and 207
feet downdip of the Ceiba-2 appraisal well.
In July 2000, we reported that the Ceiba-5 appraisal well confirmed the
primary oil pool found in the Ceiba-1, -2, -3 and -4 wells, and encountered a
deeper pool with an additional high-quality reservoir not seen in any of the
previous Ceiba wells. Ceiba-5 penetrated 243 feet of net oil-bearing pay in
three zones based on the analysis of drilling, wireline logging, downhole
pressure measurements and rock/fluid samples. The new oil pool has an oil-water
contact 328 feet below the oil-water contact of the primary Ceiba pool. Drilled
on the western flank of the Ceiba structure, the Ceiba-5 well validated the
lateral reservoir continuity and connectivity of the field's primary oil pool to
the northwest. Located 23 miles off the continental coast of Equatorial Guinea
on Block G, the Ceiba-5 well was drilled to a total depth of 9,187 feet in 2,622
feet of water. The well is approximately 1.75 miles northwest of the Ceiba-3
development well.
In September 2000, we reported that the Ceiba-6 well would be plugged and
abandoned, having not encountered oil and gas. The Ceiba-6 well was a step-out
well located outside and southeast of the Ceiba Field approximately 2.5 miles
south of the Ceiba-4 well, and was drilled to a total depth of 10,388 feet.
In addition, we have renegotiated and extended into 2001 the contracts for
the two rigs we have been using in the field. We have contracted with Global
Marine's R.F. Bauer drillship to drill six wells, and have an option to use the
drillship to drill an additional six wells. We currently plan for the drillship
to drill up to six additional exploration wells, taking us through the middle of
2001. We spudded the first exploration well on October 2, 2000. In addition, we
have contracted to have the Sedco 700 semisubmersible rig complete four Ceiba
wells, and have committed to continue to use the rig for one year after these
completions. After the Sedco 700 rig completes the four initial production wells
in the Ceiba field, we expect to then use the rig to drill and complete
additional development wells and water injection wells for development of the
Ceiba field. As of September 25, 2000, the rig had completed the Ceiba-4 well,
and is now completing the Ceiba-1, -2 and -3 wells.
We have acquired a 1,025,000-acre (4,200 square kilometer) 3D seismic
survey, out of the total 1.3 million acres, to assist in delineating the extent
of the Ceiba field, identify drilling locations for the appraisal/production
wells, and better define other exploration prospects on the blocks. We are in
the process of evaluating the data.
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Plan of Development
We are implementing an accelerated appraisal and development program with
two drilling rigs to enable early production from the Ceiba field. Our first
production from the field is scheduled for end of 2000. The current plan of
development provides for initial or phase one production of 52,000 BOPD,
although we cannot assure you that actual production will be at this level. We
have contracted for an FPSO vessel that we expect to provide storage for up to
two million barrels of oil and initial processing capacity of up to 60,000 BOPD
from a single production unit. We selected an FPSO-based development concept to
allow for accelerated development of the Ceiba field. We can add production
capacity cost effectively through the installation of additional processing
units. As part of this initial phase of development, four sub-sea production
wells are scheduled to be completed and connected through flow lines to the FPSO
vessel. We believe that due to transportation and preliminary assays of the
quality of the crude oil, the oil from the Ceiba field will sell at a discount
to Brent crude.
Malaysia-Thailand
In Block A-18 of the Malaysia-Thailand Joint Development Area in the Gulf
of Thailand, we and our partners have discovered eight natural gas
fields -- known as the Bulan, Bumi, Bumi East, Cakerawala, Samudra, Senja,
Suriya, and Wira fields. We own our interest through a one-half interest in a
company that holds a 50% contract interest in a production sharing contract
covering Block A-18. BP Amoco owns the other half of the shares of the company.
The operator is Carigali-Triton Operating Company Sdn. Bhd., a company owned by
us and BP Amoco, through our jointly owned company, and Petronas Carigali (JDA)
Sdn. Bhd., a subsidiary of the Malaysian national oil company.
The contract area, which encompasses approximately 731,000 acres, had been
the subject of overlapping claims between Malaysia and Thailand. The two
countries established the Malaysia-Thailand Joint Authority to administer the
development of the Joint Development Area. In April 1994, we entered into a
production-sharing contract with the Malaysia-Thailand Joint Authority and
Carigali. We previously held a license from Thailand that covered part of the
Joint Development Area.
Contract Terms
The term of the contract is 35 years, subject to possible relinquishment of
certain areas and subject to the treaty between Malaysia and Thailand creating
the Malaysia-Thailand Joint Authority remaining in effect. The contract gives us
the right to explore for oil and gas for the first eight years of the contract.
If we discover a natural gas field (not associated with crude oil), we must
submit to the Malaysia-Thailand Joint Authority a development plan for the
field. If the Malaysia-Thailand Joint Authority accepts the development plan, we
can then hold that gas field without production for an additional five-year
period, but not beyond the tenth anniversary of the contract. We then have a
five-year period from the Malaysia-Thailand Joint Authority's acceptance of the
development plan to develop the field, and have the right to produce gas from
the field for approximately 20 years (or until the termination of the contract,
if earlier). We are required to drill two exploratory wells before April 2002.
If we discover an oil field, we would have the right to produce oil from
the field for 25 years (or until the termination of the contract, if earlier).
We would have to relinquish any areas not developed and producing within
the periods provided.
As oil and gas are produced, the Malaysia-Thailand Joint Authority is
entitled to a 10% royalty. A portion of each unit of production is considered
"cost oil" or "cost gas" and will be allocated to the contractors to the extent
of their recoverable costs, with the balance considered "profit oil" or "profit
gas" to be divided 50% to the Malaysia-Thailand Joint Authority and 50% to the
contractors (i.e., 25% to Carigali and 25% to the company we own jointly with BP
Amoco). The portion that will be considered "cost gas" for production from the
Cakerawala and Bulan fields is a maximum of 60%. The Cakerawala and Bulan fields
are the fields planned for first-phase development. The portion that will be
considered "cost gas" for production from the other fields is a maximum of 50%.
There is an additional royalty
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attributable to Triton's and BP Amoco's joint interest equal to 0.75% of Block
A-18 production. Tax rates imposed by the Malaysia-Thailand Joint Authority on
behalf of the governments of Malaysia and Thailand are 0% for the first eight
years of production, 10% for the next seven years of production and 20% for any
remaining production.
Our agreements with BP Amoco require BP Amoco to pay the future exploration
and development costs attributable to our collective interest in Block A-18, up
to $377 million or until first production from a gas field. Once gas production
starts, or once BP Amoco has paid $377 million, whichever occurs first, we and
BP Amoco would each pay 50% of our share of exploration and development costs.
Under our agreements with BP Amoco, once production commences and "cost oil" or
"cost gas" is allocated to the contractors for their recoverable costs under the
production-sharing contract, we will recover our investment in recoverable costs
in the project first, and then BP Amoco will recover its investment in
recoverable costs. We have estimated our recoverable costs to be approximately
$100 million.
Gas Sales Agreement
In October 1999, we and the other parties to the production-sharing
contract for Block A-18 executed a gas sales agreement providing for the sale of
the first phase of gas to Malaysia. The sales agreement provides for gas
deliveries over a term concurrent with the production-sharing contract and
contemplates initial deliveries of 195 MMcf per day for the first six months of
the agreement, and 390 MMcf per day for a period of twenty years. The sales
agreement includes a take-or-pay provision that specifies that the buyers must
take a minimum of 90% of the annual daily contract quantity and the sellers must
be able to deliver a maximum of 110% of the daily contract quantity. Delivery is
made at the offshore production platform.
The price for gas will be adjusted annually for changes in the U.S.
Consumer Price Index, the Producer Price Index for Oil Field and Gas Field
Machinery and Tools, and medium fuel oil (180 CST) in Singapore. The price is
calculated annually and will apply to sales over the succeeding twelve months.
All calculations and payments are in U.S. dollars. The base price is $2.30 per
mmbtu. To give the buyers incentive to accelerate the timing of the delivery of
the gas, the sales agreement gives the buyers a discount of 5% after 500 Bcf has
been delivered and a discount of 10% after an aggregate of 1.3 Tcf has been
delivered.
The sales agreement provides that the initial delivery date will be a date
to be agreed upon by the sellers and the buyers between April 1, 2002 and June
30, 2002. If the parties do not agree on a date for initial delivery, the
agreement provides that the date will be deemed to be June 30, 2002.
By the first delivery date, the sellers will be required to have completed
the facilities necessary to meet its delivery obligations. The Malaysia-Thailand
Joint Authority had previously approved the field development plan for the
Cakerawala field in December 1997. Carigali-Triton Operating Company, the
operator, has begun field development work and has awarded several contracts for
long lead-time equipment, including CO(2) removal, structural steel,
refrigeration, power generation and gas compression. In March 2000,
Carigali-Triton Operating Company awarded the contract for engineering,
procurement and construction of three wellhead platforms, a production platform
with living quarters platform, a riser platform and a floating storage and
off-loading vessel for oil and condensate. The initial development plan calls
for 35 development wells.
The buyers currently do not have in place facilities necessary to transport
and process the gas. While it is not a requirement of the sales agreement, the
buyers anticipate constructing pipeline and processing facilities onshore
Thailand to accept deliveries of the gas. The sales agreement does recognize
that the buyers' downstream facilities will require that certain environmental
approvals be obtained before the buyers' facilities can be constructed. The
agreement provides that, if a delay in obtaining the necessary environmental
approvals results in a delay of the completion of the buyers' downstream
facilities, this will be treated as a force majeure event and will excuse the
buyers from their take or pay obligations for the length of the delay. We cannot
give you any assurance as to when the environmental approvals will be
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obtained, and a lengthy approval process, or significant opposition to the
project, could delay construction and the commencement of gas sales.
When we sold one half of our interest in Block A-18 to BP Amoco in 1998, BP
Amoco agreed to pay the future exploration and development costs attributable to
our collective interest in Block A-18, up to $377 million or until first
production from a gas field. BP Amoco also agreed to pay us specified incentive
payments if the requisite criteria were met. The first $65 million in incentive
payments is conditioned upon having the production facilities for the sale of
gas from Block A-18 completed by June 30, 2002. If the facilities are completed
after June 30, 2002 but before June 30, 2003, the incentive payment would be
reduced to $40 million. A lengthy environmental approval process, or
unanticipated delays in construction of the facilities, could result in our
receiving a reduced incentive payment or possibly the complete loss of the first
incentive payment.
Notwithstanding a possible future delay in the buyers' environmental
approvals process, in order to meet the June 30, 2002 deadline, the sellers are
committed to, or will be required to commit to, significant expenditures,
including the engineering, procurement and construction contract. Although BP
Amoco is committed to pay all development costs associated with Block A-18 up to
$377 million, we have agreed to provide some compensation to BP Amoco in the
event that gas sales are delayed by agreeing to pay to BP Amoco $1.25 million
per month for each month, if applicable, that first gas sales are delayed beyond
30 months following the award of the engineering, procurement and construction
contract for the project in March 2000. Our obligation is capped at 24 months of
these payments.
Gabon
In July 2000, we agreed to acquire a 38% interest in the Tolo and Otiti
blocks offshore Gabon. Our partners in the two blocks are Australia-based Broken
Hill Proprietary Company Limited, the operator, and Sasol, a South African
company. The agreement is subject to approval by the government of Gabon. We
expect to drill an exploration well in first half of 2001, subject to rig
availability.
Greece
We have an 88% interest in the Gulf of Patraikos contract area. Hellenic
Petroleum, the national oil company of Greece, has the remaining 12% interest.
The Gulf of Patraikos contract provides a primary exploration term expiring in
September 2001. We have a commitment of 2,000 kilometers (1,250 miles) of new 2D
seismic and the drilling of one exploratory well for a total expenditure of not
less than $13.5 million. We have completed our commitments for the seismic data
and we plan to drill the commitment well in 2001.
We had an interest in the Aitoloakarnania onshore contract area. During
2000, we completed our commitments for this area, including the drilling of two
commitment wells, which were dry holes. In September 2000, we surrendered our
interest in the area.
Italy
We have a 47% interest in each of the DR71 and DR72 licenses covering
approximately 369,400 acres. The license areas are located in the Adriatic Sea
located 45 kilometers (28 miles) offshore the city of Brindisi. Our partner is
Enterprise Oil Italiana, S.p.A., the operator, with a 53% interest. During 1998,
we drilled the Giove-1 well. The well was drilled to a total depth of 3,458 feet
but was prematurely abandoned due to a gas blowout and mechanical failure. We
drilled a replacement well, Giove-2, to a total depth of 4,285 feet and
encountered oil and gas. We will need to do additional work to evaluate the
commercial potential of the licenses.
In 1998, we acquired a 20% interest in the FR33AG offshore license. ENI
S.p.A. is the operator, with a 50% interest, and Enterprise holds the remaining
30% interest. The license provides a primary exploration term expiring in
September 2004 with a commitment of 250 km (156 miles) of new 2D seismic and the
drilling of one exploratory well.
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In the southern Apennine Mountains, we have an interest in three contiguous
licenses, Fosso del Lupo, Valsinni and Masseria de Sole, covering approximately
58,000 acres in the Matera province. We are the operator of these licenses and
we have a 50% interest. Our partner is BP Amoco, which holds the remaining 50%
interest. The licenses provide a primary exploration term expiring in August
2002 and were amended in 1999 to provide a combined work commitment of
approximately 50 kilometers (31 miles) of new 2D seismic and the drilling of one
exploratory well. We acquired the 50 kilometers of seismic data in 1999. BP
Amoco has indicated it wishes to withdraw from these licenses.
Madagascar
We are a party to a production-sharing contract with the Office of National
Mines and Strategic Industries in Madagascar for the Ambilobe Block, covering
approximately 4.3 million acres. The block is located directly offshore from
Ambilobe in water depths of up to 11,500 feet. We have acquired approximately
3,000 kilometers (1,875 miles) of 2D seismic.
Oman
We are a party to a production sharing contract for Block 40, covering
approximately 1.3 million acres located offshore in the Straits of Hormuz. The
contract provides an exploration term expiring in June 2001 with a commitment of
the drilling of one exploratory well. We are the operator with a 50% contract
interest and Atlantis Holding Norway AS is our partner with a 50% interest.
We have completed the reprocessing and interpretation of 4,083 kilometers
(2,546 miles) of existing 2D seismic, and completed the acquisition of a 620
square kilometer 3D seismic survey in January 2000. We are processing and
interpreting this data and expect to drill an exploratory well in 2001.
RESERVES
The following table sets forth a summary of our estimated proved oil and
gas reserves at December 31, 1999, and is based on separate estimates of our net
proved reserves prepared by:
- the independent petroleum engineers, DeGolyer and MacNaughton, with
respect to the proved reserves in the Cusiana and Cupiagua fields in
Colombia,
- the independent petroleum engineers, Netherland, Sewell & Associates,
Inc., with respect to the proved reserves in the Ceiba field in
Equatorial Guinea, and
- the internal petroleum engineers of the operating company,
Carigali-Triton Operating Company, with respect to the proved reserves in
Malaysia-Thailand on Block A-18 in the Gulf of Thailand.
Net proved reserves at December 31, 1999, were:
PROVED DEVELOPED PROVED UNDEVELOPED TOTAL PROVED
-------------------------- --------------------------- ---------------------------
OIL GAS BOE OIL GAS BOE OIL GAS BOE
(MBBLS) (MMCF) (MMBOE) (MBBLS) (MMCF) (MMBOE) (MBBLS) (MMCF) (MMBOE)
------- ------ ------- ------- ------- ------- ------- ------- -------
Colombia(1)............. 91,803 11,566 93,731 33,712 -- 33,712 125,515 11,566 127,443
Malaysia-Thailand(2).... -- -- -- 13,223 553,862 105,533 13,223 553,862 105,533
Equatorial Guinea....... -- -- -- 32,033 -- 32,033 32,033 -- 32,033
------ ------ ------ ------ ------- ------- ------- ------- -------
Total........... 91,803 11,566 93,731 78,968 553,862 171,278 170,771 565,428 265,009
====== ====== ====== ====== ======= ======= ======= ======= =======
- ---------------
(1) Includes liquids to be recovered from Ecopetrol as reimbursement for
precommerciality expenditures and excludes reserves attributable to the
Liebre field which was sold in 2000.
(2) As of December 31, 1999, gas sales had not yet commenced. The proved gas
reserves are calculated using the base price in the gas sales agreement of
$2.30. The base price is subject to annual adjustments based on various
indices. We cannot assure you that the actual price when gas sales commence
will be the same as the price we used in our assumptions.
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We do not file estimates of total proved net oil or gas reserves with, or
include estimates of total proved net oil or gas reserves in any report to, any
United States authority or agency.
OIL AND GAS OPERATIONS
Production and Sales
The following table sets forth the net quantities of oil and gas we
produced during 1999, 1998 and 1997. If during these three years we acquired or
sold a property or a subsidiary, the information in the tables includes
production and sales information relating to the property or subsidiary only
during the times we owned it.
GAS PRODUCTION
OIL PRODUCTION(1) ------------------
------------------------- YEAR ENDED
YEAR ENDED DECEMBER 31, DECEMBER 31,
------------------------- ------------------
1999 1998 1997 1999 1998 1997
------- ------ ------ ---- ---- ----
Colombia(2)........................................ 12,469 9,979 5,776 459 503 802
- ---------------
(1) Includes natural gas liquids and condensate.
(2) Includes Ecopetrol reimbursement barrels and excludes 3.1 million, 3.1
million and 2.5 million barrels of oil produced and delivered for the years
ended December 31, 1999, 1998 and 1997, respectively, in connection with a
forward oil sale in May 1995.
The following tables summarize for 1999, 1998 and 1997: (i) the average
sales price per barrel of oil and per Mcf of natural gas; (ii) the average sales
price per equivalent barrel of production; (iii) the depletion cost per
equivalent barrel of production; and (iv) the production cost per equivalent
barrel of production:
AVERAGE SALES PRICE AVERAGE SALES PRICE
PER BARREL OF OIL(1) PER MCF OF GAS
------------------------ ------------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
------------------------ ------------------------
1999 1998 1997 1999 1998 1997
------ ------ ------ ------ ------ ------
Colombia(4).................................. $15.95 $12.31 $17.54 $0.88 $0.99 $1.15
PER EQUIVALENT BARREL(2)
------------------------------------------------------------------------
AVERAGE SALES PRICE DEPLETION(3) PRODUCTION COST
------------------------ --------------------- ---------------------
YEAR ENDED YEAR ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31,
------------------------ --------------------- ---------------------
1999 1998 1997 1999 1998 1997 1999 1998 1997
------ ------ ------ ----- ----- ----- ----- ----- -----
Colombia(4)................... $15.89 $12.27 $17.37 $3.80 $4.07 $3.67 $4.50 $5.97 $6.47
- ---------------
(1) Includes natural gas liquids and condensate.
(2) Natural gas has been converted into equivalent barrels of oil based on six
Mcf of natural gas per barrel of oil.
(3) Includes depreciation calculated on the unit of production method for
support equipment and facilities.
(4) Includes barrels delivered under the forward oil sale which are recorded at
$11.56 per barrel upon delivery. Excludes the full cost ceiling limitation
writedown in 1998 totaling $241 million.
COMPETITION
We encounter strong competition from major oil companies (including
government-owned companies), independent operators and other companies for
favorable oil and gas concessions, licenses, production-sharing contracts and
leases, drilling rights and markets. Additionally, the governments of certain
countries in which we operate may, from time to time, give preferential
treatment to their nationals. The oil and gas industry as a whole also competes
with other industries in supplying the energy
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and fuel requirements of industrial, commercial and individual consumers. We
believe that the principal means of competition in the sale of oil and gas are
product availability, price and quality.
MARKETS
We generally sell our crude oil, natural gas, condensate and other oil and
gas products to other oil and gas companies, government agencies and other
industries. We do not believe that the loss of any single customer or sales
contract would have a long-term material, adverse effect on the our revenues or
oil and gas operations.
In Colombia, our oil production is exported through the Caribbean port of
Covenas where it is sold at prices based on United States prices, adjusted for
quality and transportation. The oil produced from the Cusiana and Cupiagua
fields is transported to the export terminal by pipeline.
ACREAGE
The following table shows the total gross and net developed and undeveloped
oil and gas acreage we held at December 31, 1999. "Gross" refers to the total
number of acres in an area in which we hold an interest without adjustment to
reflect the actual percentage interest we hold. "Net" acreage is adjusted for
working interests owned by other parties.
"Developed" acreage is acreage spaced or assignable to productive wells.
"Undeveloped" acreage is acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas, regardless of whether such acreage contains proved reserves.
DEVELOPED UNDEVELOPED
ACREAGE ACREAGE(1)
----------- -------------
GROSS NET GROSS NET
----- --- ----- -----
(IN THOUSANDS)
Colombia.................................................... 109 13 106 50
Equatorial Guinea(2)........................................ -- -- 1,306 1,110
Malaysia-Thailand........................................... -- -- 731 183
Greece...................................................... -- -- 1,060 933
Italy....................................................... -- -- 499 217
Oman........................................................ -- -- 1,322 661
Madagascar.................................................. -- -- 4,300 4,300
--- -- ----- -----
Total............................................. 109 13 9,324 7,454
=== == ===== =====
- ---------------
(1) Our interests in certain of this acreage may expire if not developed at
various times in the future pursuant to the terms of the leases, licenses,
concessions, contracts, permits or other agreements under which it was
acquired.
(2) We are negotiating to retain 30% of this acreage that we were required to
relinquish in April 2000.
DRILLING ACTIVITY
In this section, when we refer to "gross" wells, we mean every well drilled
in an area in which we hold any interest. When we refer to "net" wells, we mean
the gross number of wells drilled adjusted for our percentage interest in the
area.
At December 31, 1999, we held working interests in 80 productive wells on a
gross basis, and 9.86 wells on a net basis. All of the productive wells we
participated in were in Colombia. Productive wells include 17 gross (2.04 net)
gas-injection wells and two gross (.24 net) water-injection wells.
The following tables set forth the results of the oil and gas well drilling
activity on a gross basis for wells in which we held an interest during 1999,
1998 and 1997. If during these three years we acquired or
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sold a property or a subsidiary, the information in the tables includes
production and sales information relating to the property or subsidiary only
during the times we owned it.
GROSS EXPLORATORY WELLS
PRODUCTIVE(1) DRY TOTAL
------------------ ------------------ ------------------
YEAR ENDED YEAR ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31,
------------------ ------------------ ------------------
1999 1998 1997 1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ---- ---- ---- ----
Colombia............................. -- 1 1 1 -- 1 1 1 2
Equatorial Guinea.................... 2 -- -- -- -- -- 2 -- --
Malaysia-Thailand.................... -- 2 5 -- -- -- -- 2 5
Italy................................ -- -- -- -- 2 -- -- 2 --
Guatemala............................ -- -- -- -- -- 1 -- -- 1
China................................ -- -- -- -- 1 -- -- 1 --
Ecuador.............................. -- -- -- -- -- 1 -- -- 1
Tunisia.............................. -- -- -- -- 1 -- -- 1 --
-- -- -- -- -- -- -- -- --
Total...................... 2 3 6 1 4 3 3 7 9
== == == == == == == == ==
GROSS DEVELOPMENT WELLS
PRODUCTIVE(1) DRY TOTAL
------------------ ------------------ ------------------
YEAR ENDED YEAR ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31,
------------------ ------------------ ------------------
1999 1998 1997 1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ---- ---- ---- ----
Colombia............................. 14 13 18 -- -- -- 14 13 18
Malaysia-Thailand.................... -- -- -- -- -- -- -- -- --
Equatorial Guinea.................... -- -- -- -- -- -- -- -- --
-- -- -- -- -- -- -- -- --
Total...................... 14 13 18 -- -- -- 14 13 18
== == == == == == == == ==
- ---------------
(1) A productive well is producing or capable of producing oil and/or gas in
commercial quantities. Multiple completions have been counted as one well.
Any well in which one of the multiple completions is an oil completion is
classified as an oil well.
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The following tables set forth the results of drilling activity on a net
basis for wells in which we held an interest during 1999, 1998 and 1997. If
during these three years we acquired or sold a property or a subsidiary, the
information in the tables includes production and sales information relating to
the property or subsidiary only during the times we owned it.
NET EXPLORATORY WELLS
PRODUCTIVE(1) DRY TOTAL
------------------ ------------------ ------------------
YEAR ENDED YEAR ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31,
------------------ ------------------ ------------------
1999 1998 1997 1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ---- ---- ---- ----
Colombia(2)....................... -- 0.12 0.12 0.50 -- 0.50 0.50 0.12 0.62
Equatorial Guinea................. 1.70 -- -- -- -- -- 1.70 -- --
Malaysia-Thailand(3).............. -- 1.00 2.50 -- -- -- -- 1.00 2.50
Italy............................. -- -- -- -- 0.80 -- -- 0.80 --
Guatemala......................... -- -- -- -- -- 0.60 -- -- 0.60
China............................. -- -- -- -- 0.50 -- -- 0.50 --
Ecuador........................... -- -- -- -- -- 0.55 -- -- 0.55
Tunisia........................... -- -- -- -- 0.50 -- -- 0.50 --
---- ---- ---- ---- ---- ---- ---- ---- ----
Total................... 1.70 1.12 2.62 0.50 1.80 1.65 2.20 2.92 4.27
==== ==== ==== ==== ==== ==== ==== ==== ====
NET DEVELOPMENT WELLS
PRODUCTIVE(1) DRY TOTAL
------------------ ------------------ ------------------
YEAR ENDED YEAR ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31,
------------------ ------------------ ------------------
1999 1998 1997 1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ---- ---- ---- ----
Colombia(2)........................ 1.68 1.56 2.16 -- -- -- 1.68 1.56 2.16
Malaysia-Thailand.................. -- -- -- -- -- -- -- -- --
Equatorial Guinea.................. -- -- -- -- -- -- -- -- --
---- ---- ---- -- -- -- ---- ---- ----
Total.................... 1.68 1.56 2.16 -- -- -- 1.68 1.56 2.16
==== ==== ==== == == == ==== ==== ====
- ---------------
(1) A productive well is producing or capable of producing oil and/or gas in
commercial quantities. Multiple completions have been counted as one well.
Any well in which one of the multiple completions is an oil completion is
classified as an oil well.
(2) Adjusted to reflect the national oil company participation at commerciality
for the Cusiana and Cupiagua fields.
(3) The interest in the wells drilled in 1998 was not reduced to take into
account the sale of our interest in Block A-18 to BP Amoco because the sale
occurred after the drilling of the wells.
OTHER PROPERTIES
We lease office space, other facilities and equipment under various
operating leases expiring through 2005. Total rental expense was $1.3 million,
$2.1 million and $2 million for the years ended December 31, 1999, 1998 and
1997, respectively. At December 31, 1999, the minimum payments required under
terms of the leases are as follows 2000 -- $1.5 million; 2001 -- $1.6 million;
2003 -- $1.6 million; 2004 -- $1.6 million; and thereafter $1 million.
EMPLOYEES
At November 3, 2000, we employed approximately 150 full-time employees.
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LITIGATION
In July through October 1998, eight lawsuits were filed against Triton and
Thomas G. Finck and Peter Rugg, in their capacities as officers of Triton. The
lawsuits were filed in the United States District Court for the Eastern District
of Texas, Texarkana Division, and have been consolidated and are styled In re:
Triton Energy Limited Securities Litigation. The consolidated complaint alleges
violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5
promulgated thereunder in connection with disclosures concerning our properties,
operations, and value relating to a prospective sale in 1998 of us or of all or
a part of our assets. The lawsuits seek recovery of an unspecified amount of
compensatory damages, fees and costs. We have filed a motion to dismiss the
claims, which is pending.
We believe our disclosures have been accurate and intend to vigorously
defend these actions. There can be no assurance that the litigation will be
resolved in our favor. An adverse result could have a material adverse effect on
our financial position or results of operations.
In November 1999, a lawsuit was filed against us, one of our subsidiaries
and Thomas G. Finck, Peter Rugg and Robert B. Holland, III, in their capacities
as officers of Triton, in the District Court of the State of Texas for Dallas
County. The lawsuit is styled Aaron Sherman, et al. vs. Triton Energy
Corporation et al. and, as amended, alleges as causes of action fraud, negligent
misrepresentation and violations of the Texas Securities fraud statutes in
connection with our 1996 reorganization as a Cayman Islands corporation and
disclosures concerning our prospective sale of all or a substantial part of our
assets announced in March 1998. In its most recent filling, the plaintiffs
asserted actual damages of up to $10 million and sought punitive damages of up
to $50 million. We have filed various motions to dispose of the lawsuit on the
grounds that the plaintiffs do not have standing and have not plead causes of
action cognizable in law. The court has dismissed all claims of certain
plaintiffs and some claims of the remaining plaintiffs for failure to plead
viable causes of action. The Court has entered an order for proceedings in
connection with further examination of plaintiffs' claims.
In August 1997, we were sued in the Superior Court of the State of
California for the County of Los Angeles, by David A. Hite, Nordell
International Resources Ltd., and International Veronex Resources, Ltd. The
action was removed to the United States District Court for the Central District
of California. We and the plaintiffs were adversaries in a 1990 arbitration
proceeding in which the interest of Nordell International Resources Ltd. in the
Enim oil field in Indonesia was awarded to us (subject to a 5% net profits
interest for Nordell) and Nordell was ordered to pay us nearly $1 million. The
arbitration award was followed by a series of legal actions by the parties in
which the validity of the award and its enforcement were at issue. As a result
of these proceedings, the award was ultimately upheld and enforced. The current
suit alleges that the plaintiffs were damaged in amounts aggregating $13 million
primarily because of our prosecution of various claims against the plaintiffs as
well as our alleged misrepresentations, infliction of emotional distress, and
improper accounting practices. The suit seeks specific performance of the
arbitration award, damages for alleged fraud and misrepresentation in accounting
for Enim field operating results, an accounting for Nordell's 5% net profit
interest, and damages for emotional distress and various other alleged torts.
The suit seeks interest, punitive damages and attorneys fees in addition to the
alleged actual damages. In August 1998, the district court dismissed all claims
asserted by the plaintiffs other than claims for malicious prosecution and abuse
of the legal process, which the court held could not be subject to a motion to
dismiss. The abuse of process claim was later withdrawn, and the damages sought
were reduced to approximately $700,000 (not including punitive damages). The
lawsuit was tried and the jury found in favor of the plaintiffs and assessed
compensatory damages against us in the amount of approximately $700,000 and
punitive damages in the amount of approximately $11 million. We believe we have
acted appropriately and we have appealed the verdict. Enforcement of the
judgment was stayed without a bond pending the outcome of the appeal.
During the quarter ended September 30, 1995, the United States
Environmental Protection Agency ("EPA") and Justice Department advised us that
one of our domestic oil and gas subsidiaries, as a potentially responsible party
for the clean-up of the Monterey Park, California, Superfund site operated by
Operating Industries, Inc., could agree to contribute approximately $2.8 million
to settle its alleged liability
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for certain remedial tasks at the site. The offer did not address responsibility
for any groundwater remediation. Our subsidiary was advised that if it did not
accept the settlement offer, it, together with other potentially responsible
parties, may be ordered to perform or pay for various remedial tasks. After
considering the cost of possible remedial tasks, its legal position relative to
potentially responsible parties and insurers, possible legal defenses and other
factors, our subsidiary declined to accept the offer. In October 1997, the EPA
advised us that the estimated cost of the clean-up of the site would be
approximately $217 million to be allocated among the 280 known operators. Our
subsidiary's share would be approximately $1 million based upon a volumetric
allocation, but there can be no assurance that any allocation of liability to
the subsidiary would be made on a volumetric basis. No proceeding has been
brought in any court against us or our subsidiary in this matter.
In addition to the matters described above, we are also subject to
litigation that is incidental to our business.
MANAGEMENT
Our Articles of Association currently provide for a board of directors
divided into three classes of nearly equal size, designated as Class I, Class II
and Class III. Directors are elected to serve three-year terms. Our Board of
Directors elects our executive officers annually. There are no family
relationships among our executive officers. The following table sets forth
certain information regarding our directors and executive officers at November
6, 2000:
SERVED WITH
TRITON
NAME AGE POSITION WITH TRITON SINCE
- ---- --- -------------------- -----------
James C. Musselman.................. 52 President and Chief Executive 1998
Officer
A.E. Turner, III.................... 52 Senior Vice President and Chief 1994
Operating Officer
W. Greg Dunlevy..................... 45 Senior Vice President and Chief 1993
Financial Officer
Brian Maxted........................ 43 Senior Vice President, Exploration 1994
Marvin Garrett...................... 44 Vice President, Production 1994
Sheldon R. Erikson.................. 59 Director, Class III 1995
Jack D. Furst....................... 41 Director, Class I 1998
John R. Huff........................ 54 Director, Class II 1998
Thomas O. Hicks..................... 54 Director, Class II 1998
Fitzgerald S. Hudson................ 76 Director, Class III 1992
Michael E. McMahon.................. 52 Director, Class I 1993
C. Lamar Norsworthy................. 55 Director, Class III 1998
C. Richard Vermillion, Jr. ......... 55 Director, Class I 1998
J. Otis Winters..................... 68 Director, Class I 1998
Mr. Musselman was elected as a director in May 1998, and was elected Chief
Executive Officer in October 1998. Mr. Musselman has served as Chairman,
President and Chief Executive Officer of Avia Energy Development, LLC, a private
company engaged in gas processing and drilling, since September 1994. From June
1991 to September 1994, Mr. Musselman was the President and Chief Executive
Officer of Lone Star Jockey Club, LLC, a company formed to organize a horse
racetrack facility in Texas.
Mr. Turner was elected Senior Vice President and Chief Operating Officer in
March 1999, and prior to that served as Senior Vice President, Operations, since
March 1994. From 1988 to February 1994, Mr. Turner served in various positions
with British Gas Exploration & Production, Inc., including Vice President and
General Manager of operations in Africa and the Western Hemisphere from October
1993.
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Mr. Dunlevy has served as Senior Vice President and Chief Financial Officer
since September 2000. Mr. Dunlevy joined Triton in 1993 as Vice President,
Investor Relations and became Treasurer in July 1998. He became Vice President,
Finance in March 2000.
Mr. Maxted has served as Senior Vice President, Exploration since September
2000. He served as Vice President, Exploration, since January 1998, and prior to
that served as Exploration Manager of Carigali-Triton Operating Company where he
led exploration activities in the Gulf of Thailand from 1994 to 1998. From 1979
to 1994, Mr. Maxted was employed by British Petroleum in various capacities,
including Exploration Manager, Colombia from 1990 to 1992 and License Manager,
Norway from 1992 to 1994.
Mr. Garrett has served as Vice President, Production, since December 1999,
and prior to that served in various capacities within our Operations Department
since August 1994, including most recently as Director, Operations. Prior to
joining Triton in August 1994, Mr. Garrett served in various positions with
British Gas Exploration and Production, Inc., including General Manager and
Managing Director of Zaafarana Joint Operating Company in Cairo, Egypt.
Mr. Erikson has served as a director of the Company since 1995. Mr. Erikson
has served as Chairman, President and Chief Executive Officer of Cooper Cameron
Corporation, a petroleum and industrial equipment company, since January 1995
and has served as a director of that corporation since March 1995. Mr. Erikson
was the Chairman of the Board from 1988 to 1995, and President and Chief
Executive Officer from 1987 to 1995, of The Western Company of North America, an
oil and gas service company. Mr. Erikson is also a director of Layne Christensen
Company and Spinnaker Exploration Company.
Mr. Furst has served as a director of the Company since October 1998. Mr.
Furst is a Partner of Hicks Muse. From 1987 to May 1989, Mr. Furst was a vice
president and subsequently a partner of Hicks & Haas Incorporated. Mr. Furst
also serves as a director of American Tower Corporation, Cooperative Computing,
Inc., Globix Corporation, Hedstrom Corporation, Hedstrom Holdings, Inc., Home
Interiors & Gifts, Inc., International Wire Group, LLS Corp. and Viasystems
Group, Inc.
Mr. Huff has served as a director of the Company since 1995. Mr. Huff has
served as President and Chief Executive Officer of Oceaneering International,
Inc., a company providing engineering and intervention services primarily for
underwater operations, since August 1986, and as Chairman of Oceaneering
International, Inc. since 1990. Mr. Huff is also a director of BJ Services
Company and Suncor Corp.
Mr. Hicks has served as Chairman of the Board of Directors of the Company
since October 1998. Mr. Hicks has served as Chairman of the Board and Chief
Executive Officer of Hicks Muse since 1989. Hicks Muse is a private investment
firm located in Dallas, New York, St. Louis, Mexico City and London,
specializing in strategic investments, leveraged acquisitions and
recapitalizations. From 1984 to May 1989, Mr. Hicks was Co-Chairman of the Board
and Co-Chief Executive Officer of Hicks & Haas Incorporated, a Dallas-based
private investment firm. Mr. Hicks also serves as a director of AMFM Inc.,
Cooperative Computing, Inc., Home Interiors & Gifts, Inc., International Home
Foods, Inc., Lamar Advertising Company, LIN Holdings Corp., LIN Television
Corporation, Mumm Perrier-Jouet, Regal Cinemas, Inc., Sybron International
Corporation, Teligent, Inc. and Viasystems Group, Inc.
Mr. Hudson has served as a director of the Company since 1992. Mr. Hudson's
principal occupation since 1991 has been his position as general partner of
Hudson Group Partners, a family investment partnership. From 1990 to 1991 Mr.
Hudson was Chairman of the construction division of Willis Corroon, an insurance
brokerage firm.
Mr. McMahon has served as a director of the Company since 1993. Mr. McMahon
has served as a partner in RockPort Partners LLC, a merchant banking company,
since June 1998. From July 1997 to June 1998, Mr. McMahon was a Managing
Director of Chase Securities, Inc., and from October 1994 until July 1997, Mr.
McMahon was a Managing Director of Lehman Brothers. Prior to joining Lehman
Brothers, Mr. McMahon had been a partner in Aeneas Group, Inc., a subsidiary of
Harvard Management
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Company, Inc., since January 1993. Harvard Management Company, Inc. is a private
investment company responsible for managing the endowment fund of Harvard
University. Mr. McMahon was primarily responsible for the fund's energy and
commodities investments. Mr. McMahon also serves as a director of Spinnaker
Exploration Company.
Mr. Norsworthy has served as a director of the Company since 1998. Mr.
Norsworthy has served as Chairman of the Board and Chief Executive Officer of
Holly Corporation, an independent refiner of petroleum and petroleum
derivatives, since 1979 and also served as President of that corporation from
1988 to 1995.
Mr. Vermillion has served as a director of the Company since October 1998.
Mr. Vermillion has served as Chairman of Gammaloy Holdings L.P., an oilfield
service firm, since February 1996, and as a principal of MV Partners, a private
investment firm, since June 1995. From October 1993 to June 1995, Mr. Vermillion
was a Managing Director of Donaldson Lufkin & Jenrette, an investment banking
firm.
Mr. Winters has served as a director of the Company since October 1998. Mr.
Winters also served as a director of the Company from September 1993 to May
1996. Mr. Winters was co-founder of PWS Group (formerly known as Pate, Winters &
Stone, Inc.), a consulting firm, in 1989. Since 1989 he has served as Chairman
of that company. Mr. Winters also serves as a director of Dynegy, Inc., AMFM,
Inc. and Panja Corporation.
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CERTAIN RELATIONSHIPS AND TRANSACTIONS
TRANSACTIONS WITH HM4 TRITON, L.P. AND ITS AFFILIATES
In August 1998, we entered into a Shareholders Agreement with HM4 Triton,
L.P. and a Financial Advisory Agreement (the "Financial Advisory Agreement") and
a Monitoring and Oversight Agreement (the "Monitoring Agreement") with Hicks,
Muse & Co. Partners, L.P. ("Hicks Muse Partners"). Messrs. Hicks and Furst are
owners of the general partner of Hicks Muse Partners.
The Shareholders Agreement provides that, subject to the following
paragraph, so long as our entire Board of Directors consists of ten members, HM4
Triton, L.P. (and its designated transferees, collectively) may designate four
nominees for election to the Board and we are obligated to cause HM4 Triton,
L.P.'s designees to be nominated for election.
The right of HM4 Triton, L.P. (and its designated transferees) to designate
nominees for election to our Board of Directors will be reduced if the number of
Ordinary Shares (assuming conversion of any 8% Convertible Preference Shares
into Ordinary Shares) held by HM4 Triton, L.P. and its affiliates is reduced as
set forth below:
OWNERSHIP OF ORDINARY SHARES (INCLUDING 8% CONVERTIBLE NUMBER OF DIRECTORS ENTITLED TO BE
PREFERENCE SHARES ON AN AS CONVERTED BASIS) (APPROX.) DESIGNATED FOR NOMINATION
- ------------------------------------------------------ ----------------------------------
$$14.8 million........................................... 4
<14.8 million, but $9.9 million.......................... 3
<9.9 million, but > 4.9 million.......................... 2
<4.9 million, but > 197,500.............................. 1
<197,500................................................. 0
So long as HM4 Triton, L.P. is entitled to designate one nominee for
director, we are required to cause at least one HM4 Triton, L.P. director to be
a member of each committee of the Board of Directors.
In the Shareholders Agreement, we also agreed that, so long as HM4 Triton,
L.P. and its affiliates continue to hold at least approximately 9.9 million
Ordinary Shares (assuming conversion of any 8% Convertible Preference Shares
held by HM4 Triton, L.P. and its affiliates into Ordinary Shares), or shares
representing in the aggregate at least 10% of the outstanding Ordinary Shares
(assuming the conversion or exchange of all of our outstanding convertible or
exchangeable securities), we would not take certain actions without the consent
of HM4 Triton, L.P. Some of the actions that would require HM4 Triton, L.P.'s
consent are listed below:
- amending our Articles of Association or the terms of the 8% Convertible
Preference Shares with respect to the voting powers, rights or
preferences of the holders of 8% Convertible Preference Shares,
- entering into a merger or similar business combination transaction, or
effecting a reorganization, recapitalization or other transaction
pursuant to which a majority of the outstanding Ordinary Shares or any 8%
Convertible Preference Shares are exchanged for securities, cash or other
property,
- authorizing, creating or modifying the terms of any securities that would
rank equal to or senior to the 8% Convertible Preference Shares,
- selling assets comprising more than 50% of our market value,
- paying dividends on our Ordinary Shares or other shares ranking junior to
the 8% Convertible Preference Shares,
- incurring certain levels of debt, and
- commencing a tender offer or exchange for any of our Ordinary Shares.
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In the Shareholders Agreement, we have granted to HM4 Triton, L.P. and
persons to whom it transfers its shares certain rights to require us to file a
registration statement with the Securities and Exchange Commission to permit
them to freely sell the 8% Convertible Preference Shares and Ordinary Shares
they then own (together, the "Registrable Shares"). The Shareholders Agreement
provides that one or more holders of Registrable Shares may (subject to
customary "black-out" periods) require us to effect up to five registrations
under the Securities Act if the Registrable Shares proposed to be sold represent
more than 20% of the then outstanding Registrable Shares. The Shareholders
Agreement also provides certain "piggyback" registration rights to the holders
of Registrable Shares whenever we propose to register an offering of any of its
capital stock under the Securities Act (including on behalf of any of our
shareholders other than a holder of Registrable Shares), subject to certain
exceptions. In addition, the Shareholders Agreement contains customary
provisions regarding the payment of holders' expenses relating to offerings by
us in connection with the exercise of registration rights and regarding
indemnification of us and the holders of Registrable Shares for certain
securities law violations.
The Financial Advisory Agreement designates Hicks Muse Partners as our
exclusive financial advisor in connection with any Sale Transaction (defined
below) unless Hicks Muse Partners and we agree to retain an additional financial
advisor in connection with any particular Sale Transaction. The Financial
Advisory Agreement requires us to pay a fee to Hicks Muse Partners in connection
with any Sale Transaction (unless our Chief Executive Officer elects not to
retain a financial advisor) in an amount equal to the lesser of (i) the fees
then charged by first-tier investment banking firms for similar advisory
services rendered in similar transactions or (ii) 1.5% of the Transaction Value
(as defined in the Financial Advisory Agreement); provided that the fee will be
divided equally between Hicks Muse Partners and any additional financial advisor
that we and Hicks Muse Partners agree will be retained by us with respect to any
such transaction. A "Sale Transaction" is defined as any merger, sale of
securities representing a majority of our combined voting power, sale of our
assets representing more than 50% of the total market value of the assets of
Triton and its subsidiaries or other similar transaction. We are also required
to reimburse Hicks Muse Partners for reasonable disbursements and out-of-pocket
expenses Hicks Muse Partners incurs in connection with its advisory services.
Pursuant to the Monitoring Agreement, Hicks Muse Partners provides
financial oversight and monitoring services as requested by us and we pay to
Hicks Muse Partners an annual fee of $500,000, payable in quarterly
installments. In addition, we are obligated to reimburse Hicks Muse Partners for
reasonable disbursements and out-of-pocket expenses incurred by Hicks Muse
Partners or its affiliates for our account or in connection with the performance
of its services.
The Financial Advisory and Monitoring Agreements will remain in effect
until the earlier of (i) September 30, 2008 or (ii) the date on which HM4
Triton, L.P. and its affiliates cease to beneficially own at least 5% of our
outstanding Ordinary Shares (determined after giving effect to the conversion of
all 8% Convertible Preference Shares held by HM4 Triton, L.P. and its
affiliates). We have agreed to indemnify Hicks Muse Partners with respect to
liabilities incurred as a result of Hicks Muse Partners' performance of services
for us pursuant to the Financial Advisory Agreement and the Monitoring
Agreement.
We are also required to provide directors' and officers' liability
insurance coverage for HM4 Triton, L.P. and its affiliates with respect to any
claims brought against them relating to any act or omission of any director of
us in his or her capacity as a director of us. We are required to maintain this
coverage for so long as HM4 Triton, L.P. is entitled to nominate any members of
our Board of Directors.
In April 1999, we sold to HMTF Operating L.P., an entity affiliated with
Hicks Muse and Messrs. Hicks and Furst, our interest in a hunting facility in
Texas and related facilities for $900,000 and recognized a gain of $400,000. The
purchase price was derived through negotiation between representatives of us and
Hicks Muse and was approved by the disinterested members of our Board of
Directors.
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TRANSACTIONS WITH COOPER CAMERON CORPORATION AND OCEANEERING INTERNATIONAL, INC.
Both Cooper Cameron Corporation ("Cooper Cameron") and Oceaneering
International, Inc. ("Oceaneering") were winning bidders to provide services as
subcontractors in connection with our offshore drilling program in Equatorial
Guinea. Cooper Cameron will provide certain subsea equipment and related
services and we expect that the amounts to be paid under Cooper Cameron's
current contracts will amount to approximately $74 million, of which we expect
to pay approximately $45 million during 2000. Oceaneering also will provide
certain subsea equipment and related services, and we expect that the amounts to
be paid under Oceaneering's current contracts will amount to approximately $12
million during 2000 based on the planned drilling program. Mr. Erikson is the
Chairman, President and Chief Executive Officer of Cooper Cameron, and Mr. Huff
is the Chairman, President and Chief Executive Officer of Oceaneering.
DESCRIPTION OF OTHER INDEBTEDNESS
SENIOR NOTES
In April 1997, we issued $400 million aggregate face value of senior
indebtedness to refinance other indebtedness. The senior indebtedness consisted
of $200 million face amount of 8 3/4% Senior Notes due April 15, 2002 (the "2002
Notes"), at 99.942% of the principal amount (resulting in $199.9 million
aggregate net proceeds) and $200 million face amount of 9 1/4% Senior Notes due
April 15, 2005 (the "2005 Notes" and, together with the 2002 Notes, the "Senior
Notes"), at 100% of the principal amount, for total aggregate net proceeds of
$399.9 million before deducting transaction costs of approximately $1 million.
Interest on the Senior Notes is payable semi-annually on April 15 and
October 15. The Senior Notes are redeemable at any time at our option, in whole
or in part, and contain certain covenants limiting the incurrence of certain
liens, sale/leaseback transactions, and mergers and consolidations. On October
4, 2000, we called all of the 2002 Notes for redemption at a redemption price
per note equal to $1,038.40. The redemption date for the 2002 Notes was November
3, 2000.
TERM CREDIT FACILITY
In November 1995, one of our subsidiaries signed an unsecured term credit
facility with a bank supported by a guarantee issued by the Export-Import Bank
of the United States for $45 million, which matures in January 2001. Principal
and interest payments are due semi-annually on January 15 and July 15, and
borrowings bear interest at LIBOR plus .25%, adjusted on a semi-annual basis. At
June 30, 2000, we had outstanding borrowings of about $9 million under the
facility.
REVOLVING CREDIT FACILITY
In February 2000, we entered into an unsecured two-year revolving credit
facility with a group of banks, which matures in February 2002. The credit
facility gives us the right to borrow from time to time up to the amount of the
borrowing base determined by the banks, not to exceed $150 million. The credit
facility contains various restrictive covenants, including covenants that
require us to maintain a ratio of earnings before interest, depreciation,
depletion, amortization and income taxes to net interest expense of at least 2.5
to 1, and that prohibit us from permitting net debt to exceed the product of
3.75 times our earnings before interest, depreciation, depletion, amortization
and income taxes, in each case, on a trailing four quarters basis. As of the
date of this prospectus, we had no borrowings outstanding under the credit
facility. As a result of the issuance of the old notes and the redemption of our
2002 Notes, the amount of the borrowing base was adjusted to $50 million,
subject to any future redetermination of the borrowing base as provided in the
agreement. We can borrow two different types of loans under the credit facility,
excluding letters of credit: Eurodollar loans and non-Eurodollar loans. Any
Eurodollar amounts outstanding under the credit facility will bear interest at a
rate per annum ranging from LIBOR plus 2.25% to LIBOR plus 3%, depending upon
the amount of the credit facility utilized and the credit rating of our
outstanding
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senior, unsecured, non-guaranteed or enhanced, long-term indebtedness. All
outstanding non-Eurodollar amounts will incur interest at the rate per annum
equal to the sum of (a) the greatest of (1) the prime rate, (2) the base CD rate
plus 1%, and (3) the federal funds effective rate plus 1/2 of 1% and (b) 1.25%
to 2.00%, depending upon the amount of the credit facility utilized and the
credit rating of our outstanding senior, unsecured, non-guaranteed or enhanced,
long-term indebtedness.
GUARANTEES
At June 30, 2000, we had guaranteed the performance of a total of $11.4
million in future exploration expenditures to be incurred through September 2001
in various countries. A total of approximately $6 million of the exploration
expenditures are included in the 2000 capital spending program related to a
commitment of two onshore exploratory wells in Greece which were dry holes.
These commitments are backed primarily by unsecured letters of credit.
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DESCRIPTION OF NEW NOTES
The form and terms of the new notes are the same as the form and terms of
the old notes, except that the new notes have been registered under the
Securities Act of 1933, will not bear legends restricting the transfer thereof,
will not be entitled to registration rights under our registration rights
agreement, and will not contain provisions relating to additional interest. We
will issue the new notes under the indenture dated as of October 4, 2000 between
us and The Chase Manhattan Bank, as trustee. The following description is a
summary of the material provisions of the indenture. We urge you to read the
indenture because it defines your rights as holders of the new notes. The terms
of the new notes include those stated in the indenture and those made part of
the indenture by reference to the Trust Indenture Act of 1939. You may obtain a
copy of the indenture from us.
You can find the definitions of certain terms used in this description
under the subheading "Certain Definitions." In this description, references to
"we," "us," "our," and "the Company" refer only to Triton Energy Limited and not
to any of its subsidiaries. As used in this section, the term "notes" refers to
both old notes and the new notes.
The old notes and the new notes will constitute a single class of debt
securities under the indenture. If the exchange offer is consummated, holders of
old notes who do not exchange new notes for their old notes will vote together
with holders of the new notes for all relevant purposes under the indenture.
Accordingly, in determining whether the required holders have given any notice,
consent or waiver or taken any other action permitted under the indenture, any
old notes that remain outstanding after the exchange offer will be aggregated
with the new notes, and the holders of the old notes and the new notes will vote
together as a single class. All references in this prospectus to specified
percentages in aggregate principal amount of the notes that are outstanding
means, at any time after the exchange offer is consummated, the percentages in
aggregate principal amount of the old notes and the new notes then outstanding.
GENERAL
The Notes. The notes:
- are general unsecured, senior obligations of the Company;
- are limited to an aggregate principal amount of $500 million, of which
$300 million was issued in the offering of the old notes;
- mature on October 1, 2007;
- will be issued in denominations of $1,000 and integral multiples of
$1,000;
- will be represented by one or more registered notes in global form, but
in certain circumstances may be represented by notes in definitive form.
See "Book-Entry, Delivery and Form";
- rank equally in right of payment to all existing and future Senior
Indebtedness of the Company;
- rank senior in right of payment to all existing and future subordinated
debt of the Company, if any; and
- are expected to be eligible for trading in the PORTAL market.
Interest. Interest on the notes will:
- accrue at the rate of 8.875% per annum;
- accrue from the date of issuance or the most recent interest payment
date;
- be payable in cash semi-annually in arrears on April 1 and October 1,
commencing on April 1, 2001;
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- be payable to the holders of record on the March 15 and September 15
immediately preceding the related interest payment dates; and
- be computed on the basis of a 360-day year comprised of twelve 30-day
months.
Payments on the Notes
Principal of, premium, if any, and interest on the notes will be payable,
and the notes may be exchanged or transferred, at the office or agency of the
Company in the Borough of Manhattan, The City of New York (which initially will
be the corporate trust office of the trustee in New York, New York), except
that, at the option of the Company, payment of interest may be made by check
mailed to the address of the holders as such address appears in the Company's
securities register maintained by the registrar. Payment of principal of,
premium, if any, and interest on, notes in global form registered in the name of
or held by the depositary or its nominee will be made in immediately available
funds to the depositary or its nominee, as the case may be, as the registered
holder of such global note. No service charge will be made for any registration
of transfer or exchange of notes, but the Company may require payment of a sum
sufficient to cover any transfer tax or other similar governmental charge
payable in connection therewith.
Paying Agent and Registrar
The Chase Manhattan Bank, as trustee, will initially act as paying agent
and registrar. The Company may change the paying agent or registrar without
prior notice to the holders of the notes, and the Company or any of its
Restricted Subsidiaries may act as paying agent or registrar.
Transfer and Exchange
A holder may transfer or exchange notes in accordance with the indenture.
The registrar and the trustee may require a holder, among other things, to
furnish appropriate endorsements and transfer documents and the Company may
require a holder to pay any taxes and fees required by law or permitted by the
indenture. The Company is not required to transfer or exchange any note selected
for redemption. Also, the Company is not required to transfer or exchange any
note for a period of 15 days before a selection of notes to be redeemed.
The registered holder of a note will be treated as the owner of it for all
purposes.
Issuance of Additional Notes
We may issue up to $200.0 million aggregate principal amount of additional
notes having terms and conditions identical to the notes (the "additional
notes"), subject to compliance with the covenants contained in the indenture and
the Senior Debt Agreements. Any additional notes will be part of the same issue
as the notes, will vote on all matters with the notes and will be treated,
together with the new notes and the old notes, as a single class of securities
under the indenture. Unless the context otherwise requires, references in this
prospectus to the old notes or to the new notes do not include the additional
notes. Additional notes are not being offered by means of this prospectus.
OPTIONAL REDEMPTION
Except as described below, the notes are not redeemable until October 1,
2004. On and after October 1, 2004, the Company may, at its option, redeem all
or a part of the notes from time to time upon not less than 30 nor more than 60
days' notice, at the following redemption prices (expressed as a percentage of
principal amount) plus accrued and unpaid interest thereon, if any, to the
applicable redemption date (subject to the right of holders of record on the
relevant record date to receive interest
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due on the relevant interest payment date), if redeemed during the twelve-month
period beginning on October 1 of the years indicated below:
YEAR PERCENTAGE
- ---- ----------
2004..................................................... 104.438%
2005..................................................... 102.219%
2006 and thereafter...................................... 100.000%
Prior to October 1, 2003, the Company may on any one or more occasions
redeem up to 35% of the original principal amount of the notes with the Net Cash
Proceeds of one or more Equity Offerings at a redemption price of 108.875% of
the principal amount thereof, plus accrued and unpaid interest, if any, 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 that
(1) at least 65% of the original principal amount of the notes remains
outstanding after each such redemption; and
(2) the redemption occurs within 120 days after the closing of such
Equity Offering. Pending the application of the Net Cash Proceeds of any
Equity Offering to redeem notes in accordance with the provisions of this
paragraph, the Company or its Restricted Subsidiaries may temporarily repay
Senior Indebtedness with those Net Cash Proceeds.
In the case of any partial redemption, selection of the notes for
redemption will be made by the trustee in compliance with the requirements of
the principal national securities exchange, if any, on which the notes are
listed or, if the notes are not listed, then on a pro rata basis, by lot or by
such other method as the trustee in its sole discretion will deem to be fair and
appropriate, although no note of $1,000 in original principal amount or less
will be redeemed in part. If any note is to be redeemed in part only, the notice
of redemption relating to such note will 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.
RANKING AND SUBORDINATION
The notes will be structurally subordinated to the liabilities of the
Subsidiaries of the Company. At June 30, 2000, on a pro forma basis to give
effect to this offering of notes and the application of the proceeds thereof:
- outstanding Senior Indebtedness would have been approximately $509
million, none of which would have been secured; and
- Restricted Subsidiaries would have had approximately $91 million of total
liabilities (consisting of $9 million of Export-Import Bank supported
bank indebtedness and $82 million of other liabilities, including
accounts payable).
Although the indenture will limit the amount of indebtedness that the
Company and its Restricted Subsidiaries may incur, such indebtedness of the
Company may be substantial and all of it may be Senior Indebtedness.
The notes will in all respects rank equally with all other Senior
Indebtedness of the Company. Unsecured Indebtedness is not deemed to be
subordinate or junior to secured Indebtedness merely because it is unsecured.
CHANGE OF CONTROL
If a Change of Control occurs, each holder of a note will have the right to
require the Company to repurchase all or any part (equal to $1,000 or an
integral multiple thereof) of such holder's notes at a
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purchase price in cash equal to 101% of the principal amount of the notes plus
accrued and unpaid interest, if any, to the date of purchase (subject to the
right of holders of record on the relevant record date to receive interest due
on the relevant interest payment date).
Within 90 days following the date the Company becomes aware that any Change
of Control has occurred, the Company will mail a notice (the "Change of Control
Offer") 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 the Company to purchase such holder's notes at a purchase
price in cash equal to 101% of the principal amount thereof plus accrued
and unpaid interest, if any, to the date of purchase (subject to the right
of holders of record on a record date to receive interest on the relevant
interest payment date) (the "Change of Control Payment");
(2) the repurchase date (which shall be no earlier than 30 days nor
later than 60 days from the date such notice is mailed) (the "Change of
Control Payment Date"); and
(3) the procedures determined by the Company, consistent with the
indenture, that a holder must follow in order to have its notes
repurchased.
On the Change of Control Payment Date, the Company will, to the extent
lawful:
(1) accept for payment all notes or portions thereof (equal to $1,000
or an integral multiple thereof) properly tendered pursuant to the Change
of Control Offer;
(2) deposit with the paying agent an amount equal to the Change of
Control Payment in respect of all notes or portions thereof so tendered;
and
(3) deliver or cause to be delivered to the trustee the notes so
accepted together with an Officers' Certificate stating the aggregate
principal amount of Notes or portions thereof being purchased by the
Company.
The paying agent will promptly mail to each holder of notes so tendered the
Change of Control Payment for such notes, and the trustee will promptly
authenticate and mail (or cause to be transferred by book entry) to each holder
a new note equal in principal amount to any unpurchased portion of the notes
surrendered, if any; provided that each such new note will be in a principal
amount of $1,000 or an integral multiple thereof.
If the Change of Control Payment Date is on or after an interest record
date and on or before the related interest payment date, any accrued and unpaid
interest, if any, will be paid to the Person in whose name a note is registered
at the close of business on such record date, and no additional interest will be
payable to holders who tender pursuant to the Change of Control Offer.
The Change of Control provisions described above will be applicable whether
or not any other provisions of the indenture are applicable. Except as described
above with respect to a Change of Control, the indenture does not contain
provisions that permit the holders to require that the Company repurchase or
redeem the notes in the event of a takeover, recapitalization or similar
transaction. As a result, the provisions of the indenture would not necessarily
afford holders of the notes protection in the event of a highly leveraged
transaction, reorganization, restructuring, merger or similar transaction
involving the Company that may adversely affect the holders.
The Company will not be required to make a Change of Control Offer upon a
Change of Control if a third party makes the Change of Control Offer in the
manner, at the times and otherwise in compliance with the requirements set forth
in the indenture applicable to a Change of Control Offer made by the Company and
purchases all notes validly tendered and not withdrawn under such Change of
Control Offer.
The Company will comply, to the extent applicable, with the requirements of
Section 14(e) of the Securities Exchange Act of 1934 and any other securities
laws or regulations in connection with the
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repurchase of notes pursuant to this covenant. To the extent that the provisions
of any securities laws or regulations conflict with provisions of the indenture,
the Company will comply with the applicable securities laws and regulations and
will not be deemed to have breached its obligations described in the indenture
by virtue thereof.
The Company's ability to repurchase notes pursuant to a Change of Control
Offer may be limited by a number of factors. The occurrence of certain of the
events that constitute a Change of Control may constitute a default under the
Senior Debt Agreements. In addition, certain events that may constitute a change
of control under the Senior Debt Agreements and cause a default thereunder may
not constitute a Change of Control under the Indenture. Future Indebtedness of
the Company and its Subsidiaries may also contain prohibitions of certain events
that would constitute a Change of Control or require such Indebtedness to be
repurchased upon a Change of Control. Moreover, the exercise by the holders of
their right to require the Company to repurchase the notes could cause a default
under such Indebtedness, even if the Change of Control itself does not, due to
the financial effect of such repurchase on the Company. Finally, the Company's
ability to pay cash to the holders upon a repurchase may be limited by the
Company's then existing financial resources. There can be no assurance that
sufficient funds will be available when necessary to make any required
repurchases.
The Change of Control provisions described above may deter certain mergers,
tender offers and other takeover attempts involving the Company by increasing
the capital required to effectuate such transactions. The definition of "Change
of Control" includes a disposition of all or substantially all of the property
and assets of the Company and its Restricted Subsidiaries taken as a whole to
any Person. Although there is a limited body of case law interpreting the phrase
"substantially all," there is no precise established definition of the phrase
under applicable law. Accordingly, in certain circumstances there may be a
degree of uncertainty as to whether a particular transaction would involve a
disposition of "all or substantially all" of the property or assets of a Person.
As a result, it may be unclear as to whether a Change of Control has occurred
and whether a holder of notes may require the Company to make an offer to
repurchase the notes as described above.
ADDITIONAL AMOUNTS
The Company is required to make all its payments under or with respect to
the notes free and clear of and without withholding or deduction for or on
account of any present or future tax, duty, levy, impost, assessment or other
governmental charge (including penalties, interest and other liabilities related
thereto) (hereinafter "Taxes") imposed or levied by or on behalf of the
government of the Cayman Islands or any political subdivision or any authority
or agency therein or thereof having power to tax, or within any other
jurisdiction in which we are organized or are otherwise resident for tax
purposes or any jurisdiction from or through which payment is made (each a
"Relevant Taxing Jurisdiction"), unless the Company is required to withhold or
deduct Taxes by law or by the interpretation or administration thereof.
If the Company is so required to withhold or deduct any amount for or on
account of Taxes imposed by a Relevant Taxing Jurisdiction from any payment made
under or with respect to the notes, the Company will be required to pay such
additional amounts ("Additional Amounts") as may be necessary so that the net
amount received by each holder (including Additional Amounts) after such
withholding or deduction will not be less than the amount such holder would have
received if such Taxes had not been withheld or deducted; provided, however,
that the foregoing obligation to pay Additional Amounts does not apply to:
- any Taxes that would not have been so imposed but for the existence of
any present or former connection between the relevant holder (or between
a fiduciary, settlor, beneficiary, member or shareholder of, or possessor
of power over the relevant holder, if the relevant holder is an estate,
nominee, trust or corporation) and the Relevant Taxing Jurisdiction
(other than the mere receipt of such payment or the ownership or holding
outside of the Cayman Islands of such note but including, without
limitation, such relevant holder (or such fiduciary, settlor,
beneficiary, member or shareholder or possessor) being or having been a
citizen or resident thereof or being or having been
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present or engaged in a trade or business therein or having or having had
a permanent establishment therein);
- any estate, inheritance, gift, sales, excise, transfer, personal property
tax or similar tax, assessment or governmental charge;
- any tax, assessment or other governmental charge that is imposed or
withheld by reason of the failure by the holder or the beneficial owner
of the note to comply with a request (x) to provide information,
documents or other evidence concerning the nationality, residence or
identity of the holder or such beneficial owner or (y) to make and
deliver any declaration or other similar claim (other than a claim for
refund of a tax, assessment or other governmental charge withheld by the
Company) or satisfy any information or reporting requirements, which, in
the case of (x) or (y), is required or imposed by a statute, treaty,
regulation or administrative practice of the taxing jurisdiction as a
precondition to exemption from all or part of such tax, assessment or
other governmental charge;
- any tax, assessment or other governmental charge that is payable
otherwise than by withholding from payment of principal of, premium, if
any, or interest on such note; or
- any tax, assessment or governmental charge that would not have been
imposed but for the presentation of a note for payment in the Cayman
Islands or any political subdivision thereof or therein, unless such note
could not have been presented elsewhere, nor will we pay Additional
Amounts (a) if the payment could have been made without such deduction or
withholding if the beneficiary of the payment had presented the note for
payment within 30 days after the date on which such payment or such note
became due and payable or the date on which payment thereof is duly
provided for, whichever is later (except to the extent that the holder
would have been entitled to Additional Amounts had the note been
presented on the last day of such 30-day period), (b) if, at the election
of the relevant holder, the payment of principal of (or premium, if any,
on) or interest on such note could have been made through another paying
agent without such deduction or withholding, or (c) with respect to any
payment of principal of (or premium, if any, on) or interest on such note
to any holder who is a fiduciary or partnership or limited liability
company that is treated as a partnership for U.S. federal income tax
purposes or any person other than the sole beneficial owner of such
payment, to the extent that a beneficiary or settlor with respect to such
fiduciary, a member of such a partnership or limited liability company
that is treated as a partnership for U.S. federal income tax purposes or
the beneficial owner of such payment would not have been entitled to the
Additional Amounts had such beneficiary, settlor, member or beneficial
owner been the actual holder of such note.
Upon request, the Company will provide the trustee with official receipts
or other documentation satisfactory to the trustee evidencing the payment of the
Taxes with respect to which Additional Amounts are paid.
Whenever in the indenture there is mentioned, in any context:
(1) the payment of principal;
(2) purchase prices in connection with a purchase of notes;
(3) interest; or
(4) any other amount payable on or with respect to any of the notes,
such reference shall be deemed to include payment of Additional Amounts as
described under this heading to the extent that, in such context, Additional
Amounts are, were or would be payable in respect thereof.
The Company will pay any present or future stamp, court or documentary
taxes or any other excise or property taxes, charges or similar levies and other
duties (including interest and penalties) that arise in any jurisdiction from
the execution, delivery, enforcement or registration of the notes, the indenture
or any
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other document or instrument in relation thereof, or the receipt of any payments
with respect to the notes, excluding such taxes, charges or similar levies
imposed by any jurisdiction outside of the Cayman Islands or the United States
(or any political subdivision or taxing authority of either jurisdiction), the
jurisdiction of incorporation of any successor of the Company, any jurisdiction
through which payment is made or in which a paying agent is located or any
jurisdiction in which the Company is organized or engaged in business for tax
purposes, and the Company will agree to indemnify the holders for any such taxes
paid by such holders.
The obligations described under this heading will survive any termination,
defeasance or discharge of the indenture and will apply mutatis mutandis to any
jurisdiction in which any successor Person to the Company is organized or any
political subdivision or taxing authority or agency thereof or therein.
For a discussion of Cayman Islands withholding taxes applicable to payments
under or with respect to the notes, see "Tax Considerations -- Certain Cayman
Islands Tax Consequences."
REDEMPTION FOR CHANGES IN WITHHOLDING TAXES
The Company is entitled to redeem the notes, at its option, at any time as
a whole but not in part, upon not less than 30 nor more than 60 days' notice, at
100% of the principal amount thereof, plus accrued and unpaid interest (if any)
to the date of redemption (subject to the right of holders of record on the
relevant record date to receive interest due on the relevant interest payment
date), in the event the Company has become or would become obligated to pay, on
the next date on which any amount would be payable with respect to the notes,
any Additional Amounts as a result of:
(1) a change in or an amendment to the laws (including any regulations
or rulings promulgated thereunder) of the Cayman Islands (or any political
subdivision or taxing authority thereof or therein) which change or
amendment is announced or becomes effective on or after the date of this
prospectus; or
(2) any change in or amendment to any official position regarding the
application or interpretation of such laws, regulations or rulings, or any
execution of or amendment to, any treaty or treaties affecting taxation to
which such jurisdiction (or such political subdivision or taxing authority)
is a party, which change or amendment is announced or becomes effective on
or after the date of this prospectus
and the Company cannot avoid such obligation by taking reasonable measures
available to it.
Before the Company publishes or mails notice of redemption of the notes as
described above, the Company will deliver to the trustee an Officers'
Certificate to the effect that the Company cannot avoid its obligation to pay
Additional Amounts by taking reasonable measures available to it. The Company
will also deliver an opinion of independent legal counsel of recognized standing
stating that the Company would be obligated to pay Additional Amounts as a
result of a change in tax laws or regulations or the application or
interpretation of such laws or regulations.
CERTAIN COVENANTS
Set forth below are summaries of certain covenants contained in the
indenture. During any period of time that the notes have an Investment Grade
Rating from either of the Rating Agencies, the Company and the Restricted
Subsidiaries will not be subject to the following provisions of the indenture:
- "-- Limitation on Indebtedness,"
- "-- Limitation on Restricted Payments,"
- "-- Limitation on Restrictions on Distributions from Restricted
Subsidiaries,"
- "-- Limitation on Sale of Assets and Subsidiary Stock,"
- "-- Limitation on Affiliate Transactions,"
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- "-- Limitation on Sale of Capital Stock of Restricted Subsidiaries,"
- "-- SEC Reports,"
- "-- Limitation on Lines of Business,"
- "-- Payments for Consent" and
- paragraph (3) of "-- Merger and Consolidation"
(collectively, the "Suspended Covenants"), provided that if upon the receipt by
the notes of an Investment Grade Rating by such Rating Agency, a Default or
Event of Default has occurred and is continuing under the Indenture, the Company
will continue to be subject to the Suspended Covenants until such time that no
Default or Event of Default is continuing. In the event that the Company and the
Restricted Subsidiaries are not subject to the Suspended Covenants for any
period of time as a result of the preceding sentence and, subsequently, one or
both of the Rating Agencies withdraws its ratings or downgrades the ratings
assigned to the notes below the required Investment Grade Ratings so that the
notes do not have an Investment Grade Rating from either Rating Agency, then the
Company and the Restricted Subsidiaries will thereafter again be subject to the
Suspended Covenants and compliance with the Suspended Covenants with respect to
Restricted Payments made after the time of such withdrawal or downgrade will be
calculated in accordance with the terms of the covenant described below under
"-- Limitation on Restricted Payments" as though such covenant had been in
effect during the entire period of time from the date the notes are issued.
Limitation on Indebtedness
(a) The Company will not, and will not permit any of its Restricted
Subsidiaries to, Incur any Indebtedness; provided, however, that the Company may
Incur Indebtedness if on the date thereof the Consolidated Coverage Ratio for
the Company and its Restricted Subsidiaries is at least 2.50 to 1.00.
(b) Paragraph (a) of this covenant will not prohibit the incurrence of the
following Indebtedness:
(1) Indebtedness Incurred pursuant to the Senior Credit Agreement,
including any amendment, modification, supplement, extension, restatement,
replacement (including replacement after the termination of such Senior
Credit Agreement), restructuring, increase, renewal, or refinancing thereof
from time to time in one or more agreements or instruments; provided,
however, that, after giving effect to any such Incurrence, the aggregate
principal amount of such Indebtedness then outstanding does not exceed the
greater of (i) $250 million and (ii) an amount equal to the sum of (a)
$100.0 million and (b) 20% of Adjusted Consolidated Net Tangible Assets
determined as of the date of the Incurrence of such Indebtedness;
(2) Indebtedness owed to and held by the Company or a Restricted
Subsidiary; provided, however, that any subsequent issuance or transfer of
any Capital Stock which results in any such Restricted Subsidiary ceasing
to be a Restricted Subsidiary or any subsequent transfer of such
Indebtedness (other than to the Company or a Restricted Subsidiary) shall
be deemed, in each case, to constitute the Incurrence of such Indebtedness
by the obligor thereon;
(3) the old notes and any new notes;
(4) Indebtedness of the Company and any Restricted Subsidiary
outstanding on the Issue Date;
(5) Indebtedness of a Restricted Subsidiary Incurred and outstanding
on or prior to the date on which such Subsidiary was acquired by the
Company (other than Indebtedness Incurred in connection with, or to provide
all or any portion of the funds or credit support utilized to consummate,
the transaction or series of related transactions pursuant to which such
Subsidiary became a Subsidiary or was acquired by the Company); provided,
however, that at the time such Restricted Subsidiary is acquired by the
Company, the Company would have been able to Incur $1.00
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of additional Indebtedness pursuant to the first paragraph of this covenant
after giving effect to the Incurrence of such Indebtedness pursuant to this
clause (5);
(6) Refinancing Indebtedness in respect of Indebtedness Incurred
pursuant to paragraph (a) of this covenant or pursuant to clause (3), (4),
(5) or this clause (6);
(7) Hedging Obligations of the Company or any Restricted Subsidiary
consisting of Interest Rate Agreements directly related to Indebtedness
permitted to be Incurred pursuant to the Indenture;
(8) Non-Recourse Debt of any Unrestricted Subsidiary;
(9) Indebtedness in respect of bid, performance, reimbursement or
surety obligations issued by or for the account of the Company or any
Restricted Subsidiary in the ordinary course of business, including
Guarantees and letters of credit functioning as or supporting such bid,
performance, reimbursement or surety obligations (in each case other than
for an obligation for money borrowed);
(10) Indebtedness of the Company or any Restricted Subsidiary
consisting of obligations in respect of purchase price adjustments,
indemnities or Guarantees of the same or similar matters in connection with
the acquisition or disposition of Property;
(11) Indebtedness of the Company or any Restricted Subsidiary under
Commodity Agreements and Currency Agreements entered into in the ordinary
course of business for the purpose of limiting risks that arise in the
ordinary course of business of the Company and its Restricted Subsidiaries;
(12) Any Guarantee by the Company or a Subsidiary of the Company of
Indebtedness Incurred pursuant to the paragraph (a) of this covenant or
pursuant to clause (1), (2), (3), (4), (7), (9), (10), (11) or (13) or
pursuant to clause (6) to the extent the Refinancing Indebtedness Incurred
thereunder directly or indirectly Refinances Indebtedness Incurred pursuant
to the first paragraph of this covenant or pursuant to clauses (3) or (4);
(13) Indebtedness in an aggregate principal amount which, when taken
together with all other Indebtedness of the Company outstanding on the date
of such Incurrence (other than Indebtedness permitted by clauses (1)
through (12) above and (14) below or paragraph (a) of this covenant) does
not exceed $50 million (which amount may, but need not, be incurred under
the Senior Credit Agreement); and
(14) Indebtedness incurred by a Restricted Subsidiary in an aggregate
principal amount which, taken together with all other Indebtedness of
Restricted Subsidiaries outstanding on the date of such Incurrence, does
not exceed $50 million (which amount may, but need not, be incurred under
the Senior Credit Agreement).
(c) For purposes of determining compliance with this covenant, in the event
that an item of proposed Indebtedness meets the criteria of more than one of the
categories of Indebtedness described in the paragraphs (a) and (b) of this
covenant, the Company may, in its sole discretion,
(i) at the time the proposed Indebtedness is incurred, classify all or
a portion of that item of Indebtedness on the date of its Incurrence under
either paragraph (a) of this covenant or under any category in paragraph
(b) of this covenant,
(ii) reclassify at a later date all or a portion of that or any other
item of Indebtedness as being or having been Incurred in any manner that
complies with this covenant, and
(iii) elect to comply with this covenant and the applicable
definitions in any order.
(d) The amount of Indebtedness of any Person at any date will be
(i) the lesser of (A) the outstanding principal amount of all
unconditional obligations described above, as such amount would be
reflected on a balance sheet prepared in accordance with GAAP, and (B) the
actual outstanding principal amount of all such obligations;
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(ii) the accreted value of that Indebtedness, in the case of any
Indebtedness issued with original issue discount; and
(iii) the principal amount of that Indebtedness, together with any
interest on that Indebtedness that is more than 30 days past due, in the
case of any other Indebtedness.
(e) Accrual of interest, accrual of dividends, the accretion of accreted
value, the payment of interest in the form of additional Indebtedness and the
payment of dividends in the form of additional shares of Preferred Stock will
not be deemed to be an incurrence of Indebtedness for purposes of this covenant.
(f) In addition, the Company will not permit any of its Unrestricted
Subsidiaries to Incur any Indebtedness or issue any shares of Disqualified
Stock, other than Non-Recourse Debt. If at any time an Unrestricted Subsidiary
becomes a Restricted Subsidiary, any Indebtedness of such Subsidiary shall be
deemed to be Incurred by a Restricted Subsidiary of the Company as of such date
(and, if such Indebtedness is not permitted to be Incurred as of such date under
this "Limitation on Indebtedness" covenant, the Company shall be in Default of
this covenant).
(g) For purposes of determining compliance with any U.S. dollar-denominated
restriction on the Incurrence of Indebtedness, the U.S. dollar-equivalent
principal amount of Indebtedness denominated in a foreign currency shall be
calculated based on the relevant currency exchange rate in effect on the date
such Indebtedness was Incurred, in the case of term Indebtedness, or first
committed, in the case of revolving credit Indebtedness; provided that if such
Indebtedness is Incurred to refinance other Indebtedness denominated in a
foreign currency, and such refinancing would cause the applicable U.S.
dollar-dominated restriction to be exceeded if calculated at the relevant
currency exchange rate in effect on the date of such refinancing, such U.S.
dollar-dominated restriction shall be deemed not to have been exceeded so long
as the principal amount of such refinancing Indebtedness does not exceed the
principal amount of such Indebtedness being refinanced. Notwithstanding any
other provision of this covenant, the maximum amount of Indebtedness that the
Company may Incur pursuant to this covenant shall not be deemed to be exceeded
solely as a result of fluctuations in the exchange rate of currencies. The
principal amount of any Indebtedness incurred to refinance other Indebtedness,
if Incurred in a different currency from the Indebtedness being refinanced,
shall be calculated based on the currency exchange rate applicable to the
currencies in which such Refinancing Indebtedness is denominated that is in
effect on the date of such refinancing.
Limitation on Restricted Payments.
The Company will not, and will not permit any of its Restricted
Subsidiaries, directly or indirectly, to:
(1) declare or pay any dividend or make any distribution on or in
respect of its Capital Stock (including any payment in connection with any
merger or consolidation involving the Company or any of its Restricted
Subsidiaries) except:
(a) dividends or distributions payable in Capital Stock of the
Company (other than Disqualified Stock) or in options, warrants or other
rights to purchase such Capital Stock of the Company; and
(b) dividends or distributions payable to the Company or a
Restricted Subsidiary of the Company (and if such Restricted Subsidiary
is not a Wholly-Owned Subsidiary, to its other holders of common Capital
Stock on a pro rata basis);
(2) purchase, redeem, retire or otherwise acquire or retire for value
any Capital Stock of the Company or any direct or indirect parent of the
Company held by Persons other than the Company or a Restricted Subsidiary
of the Company (other than in exchange for Capital Stock of the Company
(other than Disqualified Stock));
(3) purchase, repurchase, redeem, defease or otherwise acquire or
retire for value, prior to scheduled maturity, scheduled repayment or
scheduled sinking fund payment, any Subordinated
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Obligations (other than the purchase, repurchase or other acquisition of
Subordinated Obligations purchased in anticipation of satisfying a sinking
fund obligation, principal installment or final maturity, in each case due
within one year of the date of purchase, repurchase or acquisition); or
(4) make any Restricted Investment in any Person;
(any such dividend, distribution, purchase, redemption, repurchase, defeasance,
other acquisition, retirement or Restricted Investment referred to in clauses
(1) through (4) shall be referred to herein as a "Restricted Payment"), if at
the time the Company or such Restricted Subsidiary makes such Restricted
Payment:
(a) a Default shall have occurred and be continuing (or would
result therefrom); or
(b) the Company is not able to incur an additional $1.00 of
Indebtedness pursuant to the first paragraph under the "Limitation on
Indebtedness" covenant after giving effect to such Restricted Payment;
or
(c) the aggregate amount of such Restricted Payment and all other
Restricted Payments declared or made subsequent to the Issue Date would
exceed the sum of (without duplication):
(i) 50% of Consolidated Net Income for the period (treated as
one accounting period) from the beginning of the first fiscal quarter
commencing after the date of the Indenture to the end of the most
recent fiscal quarter ending prior to the date of such Restricted
Payment for which financial statements are in existence (or, in case
such Consolidated Net Income is a deficit, minus 100% of such
deficit);
(ii) 100% of the aggregate Net Cash Proceeds, plus the fair
market value of the assets less any related liabilities as determined
by the Board of Directors of the Company in good faith (such
determination to be accompanied by a fairness opinion or appraisal
issued by an accounting, appraisal or investment banking firm of
national standing if such fair market value is estimated to exceed
$50 million), received by the Company from the issue or sale of its
Capital Stock (other than Disqualified Stock) (including, without
limitation, in a merger, consolidation, acquisition of Property or
any other form of transaction involving the issue or sale of its
Capital Stock (other than Disqualified Stock)) or other capital
contributions (including, without limitation, through the merger or
consolidation of a Person with and into the Company not involving the
issuance or delivery of securities or other consideration by the
Company to the holders of such Person's Capital Stock) subsequent to
the Issue Date (other than Net Cash Proceeds received from an
issuance or sale of such Capital Stock to a Subsidiary of the Company
or an employee stock ownership plan, option plan or similar trust to
the extent such sale to an employee stock ownership plan, option plan
or similar trust is financed by loans from or guaranteed by the
Company or any Restricted Subsidiary unless such loans have been
repaid with cash on or prior to the date of determination);
(iii) the amount by which Indebtedness of the Company is reduced
on the Company's balance sheet upon the conversion or exchange (other
than by a Subsidiary of the Company) subsequent to the Issue Date of
any Indebtedness of the Company for Capital Stock (other than
Disqualified Stock) of the Company (less the amount of any cash, or
the fair market value of other property as determined by the Board of
Directors in good faith, distributed by the Company upon such
conversion or exchange); and
(iv) amount equal to the net reduction in Restricted Investments
made by the Company or any of its Restricted Subsidiaries in any
Person resulting from:
(A) repurchases or redemptions of such Restricted
Investments by such Person, proceeds realized upon the sale of
such Restricted Investment to an unaffiliated purchaser,
repayments of loans or advances or other transfers of assets
(including by
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way of dividend or distribution) by such Person to the Company or
any Restricted Subsidiary of the Company; or
(B) the redesignation of Unrestricted Subsidiaries as
Restricted Subsidiaries (valued in each case as provided in the
definition of "Investment") not to exceed, in the case of any
Unrestricted Subsidiary, the amount of Investments previously
made by the Company or any Restricted Subsidiary in such
Unrestricted Subsidiary, which amount in each case under this
clause (iv) was included in the calculation of the amount of
Restricted Payments; provided, however, that no amount will be
included under this clause (iv) to the extent it is already
included in Consolidated Net Income.
The provisions of the preceding paragraph will not prohibit:
(1) any purchase or redemption of Capital Stock or Subordinated
Obligations of the Company made by exchange for, or out of the proceeds of
the substantially concurrent sale of, Capital Stock of the Company (other
than Disqualified Stock and other than Capital Stock issued or sold to a
Subsidiary or an employee stock ownership plan or similar trust to the
extent such sale to an employee stock ownership plan or similar trust is
financed by loans from or guaranteed by the Company or any Restricted
Subsidiary unless such loans have been repaid with cash on or prior to the
date of determination); provided, however, that (a) such purchase or
redemption will be excluded in subsequent calculations of the amount of
Restricted Payments and (b) the Net Cash Proceeds from such sale will be
excluded from clause (c)(ii) of the preceding paragraph;
(2) any purchase or redemption of Subordinated Obligations of the
Company made by exchange for, or out of the proceeds of the substantially
concurrent sale of, Subordinated Obligations of the Company that qualifies
as Refinancing Indebtedness; provided, however, that such purchase or
redemption will be excluded in subsequent calculations of the amount of
Restricted Payments;
(3) so long as no Default or Event of Default has occurred and is
continuing, any purchase or redemption of Subordinated Obligations from Net
Available Cash to the extent permitted under "-- Limitation on Sales of
Assets and Subsidiary Stock" below; provided, however, that such purchase
or redemption will be excluded in subsequent calculations of the amount of
Restricted Payments;
(4) dividends paid within 60 days after the date of declaration if at
such date of declaration such dividend would have complied with this
provision; provided, however, that such dividends will be included in
subsequent calculations of the amount of Restricted Payments;
(5) so long as no Default or Event of Default has occurred and is
continuing, the declaration and payment of dividends to holders of any
class or series of Disqualified Stock of the Company issued in accordance
with the terms of the Indenture to the extent such dividends are included
in the definition of "Consolidated Interest Expense"; provided that the
payment of such dividends will be excluded from subsequent calculations of
Restricted Payments;
(6) repurchases of Capital Stock deemed to occur upon the exercise of
stock options if such Capital Stock represents a portion of the exercise
price thereof; provided, however, that such repurchases will be excluded
from subsequent calculations of the amount of Restricted Payments;
(7) payments by the Company to fund the payment by a Holding Company
of audit, accounting, legal or other similar expenses, to pay franchise or
other similar taxes and to pay other corporate overhead expenses, so long
as such dividends are paid as and when needed by its respective direct or
indirect Holding Company and so long as the aggregate amount of payments
pursuant to this clause (7) does not exceed $1.0 million in any calendar
year; provided, however, that such payments will be excluded from
subsequent calculations of the amount of Restricted Payments;
(8) payments by the Company to repurchase, or to enable a Holding
Company to repurchase, Capital Stock or other securities from employees or
independent contractors of the Company or a
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Holding Company in an aggregate amount not to exceed $3.0 million in any
calendar year; provided, however, that such payments will be excluded from
subsequent calculations of the amount of Restricted Payments;
(9) payments by the Company to redeem or repurchase, or to enable a
Holding Company to redeem or repurchase, stock purchase or similar rights
granted by the Company or a Holding Company with respect to its Capital
Stock in an aggregate amount not to exceed $500,000; provided, however,
that such payments will be excluded from subsequent calculations of the
amount of Restricted Payments;
(10) payments of the Company to Hicks Muse Partners in accordance with
the terms of the Financial Advisory Agreement and the Monitoring and
Oversight Agreement, as in effect on the Issue Date; provided, however,
that such payments will be excluded from subsequent calculations of the
amount of Restricted Payments;
(11) payments, not to exceed $200,000 in the aggregate, to enable the
Company or a Holding Company to make cash payments to holders of its
Capital Stock in lieu of the issuance of fractional shares of its Capital
Stock; provided, however, that such payments will be excluded from
subsequent calculations of the amount of Restricted Payments;
(12) payments under contractual obligations to employees of the
Company or any Restricted Subsidiary to repurchase up to 2,000,000 of their
shares of Capital Stock of the Company in connection with a change of
control of the Company of a nature similar to a Change in Control;
provided, however, that such payments will be included in subsequent
calculations of the amount of Restricted Payments; and
(13) Restricted Payments in an amount not to exceed $50 million;
provided, however, that such payments will be included in subsequent
calculations of the amount of Restricted Payments.
The amount of all Restricted Payments (other than cash) shall be the fair
market value on the date of such Restricted Payment of the asset(s) or
securities proposed to be paid, transferred or issued by the Company or such
Restricted Subsidiary, as the case may be, pursuant to such Restricted Payment.
The fair market value of any cash Restricted Payment shall be its face amount
and any non-cash Restricted Payment shall be determined conclusively by the
Board of Directors acting in good faith whose resolution with respect thereto
shall be delivered to the trustee, such determination to be accompanied by a
fairness opinion or appraisal issued by an accounting, appraisal or investment
banking firm of national standing if such fair market value is estimated to
exceed $50 million.
Limitation on Liens.
The Company will not, and will not permit any of its Restricted
Subsidiaries to, create or permit to exist any Liens upon any Principal Property
or any shares of stock or Indebtedness of any Restricted Subsidiary that owns or
leases any Principal Property (whether such Principal Property, shares of stock
or Indebtedness are now owned or hereafter acquired) unless all payments due
under the indenture with respect to the notes are secured on an equal and
ratable basis with the obligations so secured until such time as such
obligations are no longer secured by a Lien. The preceding sentence will not
require the Company to secure the notes if the Liens consist of either (a)
Permitted Liens or (b) Liens securing indebtedness described in the last
sentence of the next paragraph.
Limitation on Sale/Leaseback Transactions.
Neither the Company nor any of its Restricted Subsidiaries will enter into
any Sale/Leaseback Transaction with respect to any Principal Property unless
either (a) the Company or such Restricted Subsidiary would be entitled, pursuant
to the provisions of the indenture, to incur Indebtedness secured by a Lien on
the property to be leased without equally and ratably securing the notes
pursuant to the covenant described above in "Limitation on Liens," or (b) the
Company, within six months after the
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effective date of such transaction, applies to the voluntary defeasance or
retirement of its funded debt an amount equal to the Attributable Indebtedness
of such transaction. Notwithstanding the foregoing limitations on Liens and
Sale/Leaseback Transactions, the Company and its Restricted Subsidiaries may
issue, assume, or guarantee Indebtedness secured by a Lien without securing the
Notes, or may enter into Sale/Leaseback Transactions without defeasing or
retiring funded debt, or enter into a combination of such transactions, if the
sum of the principal amount of all such Indebtedness and the Attributable
Indebtedness of all such Sale/Leaseback Transactions does not at any time exceed
15% of Adjusted Consolidated Net Tangible Assets.
Limitation on Restrictions on Distributions from Restricted Subsidiaries.
The Company will not, and will not permit any Restricted Subsidiary to,
create or otherwise cause or permit to exist or become effective any consensual
encumbrance or consensual restriction on the ability of any Restricted
Subsidiary to:
(1) pay dividends or make any other distributions on its Capital Stock
or pay any Indebtedness or other obligations owed to the Company or any
Restricted Subsidiary;
(2) make any loans or advances to the Company or any Restricted
Subsidiary; or
(3) transfer any of its property or assets to the Company or any
Restricted Subsidiary.
The preceding provisions will not prohibit:
(i) any encumbrance or restriction pursuant to an agreement in effect
at or entered into on the Issue Date (including, without limitation, the
Indenture and the Senior Debt Agreements in effect on such date);
(ii) any encumbrance or restriction with respect to a Restricted
Subsidiary pursuant to an agreement effecting a refinancing of Indebtedness
Incurred pursuant to an agreement referred to in clause (i) of this
paragraph or this clause (ii) or contained in any amendment to an agreement
referred to in clause (i) of this paragraph or this clause (ii); provided,
however, that the encumbrances and restrictions with respect to such
Restricted Subsidiary contained in any such agreement or amendment are no
less favorable in any material respect to the Holders of the notes than the
encumbrances and restrictions contained in such agreements referred to in
clause (i) of this paragraph on the Issue Date;
(iii) in the case of clause (3) of the first paragraph of this
covenant, any encumbrance or restriction:
(a) that restricts in a customary manner the subletting, assignment
or transfer of any property or asset that is subject to a lease,
license, joint operating agreement, area of mutual interest agreement,
production sharing contract, transportation agreement or similar
contract, or the assignment or transfer of any such contract;
(b) contained in mortgages, pledges or other security agreements
permitted under the Indenture securing Indebtedness of the Company or a
Restricted Subsidiary to the extent such encumbrances or restrictions
restrict the transfer of the property subject to such mortgages, pledges
or other security agreements; or
(c) pursuant to customary provisions restricting dispositions of
real property interests set forth in any reciprocal easement agreements
of the Company or any Restricted Subsidiary;
(d) arising or agreed to in the ordinary course of business and
that does not, individually or in the aggregate, detract from the value
of property or assets of the Company or any of its Restricted
Subsidiaries in any manner material to the Company or any such
Restricted Subsidiary as determined in good faith by senior management
or the Board of Directors of the Company;
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(iv) purchase money obligations for property acquired in the ordinary
course of business that impose encumbrances or restrictions of the nature
described in clause (3) of the first paragraph of this covenant on the
property so acquired;
(v) any restriction with respect to a Restricted Subsidiary (or any of
its property or assets) imposed pursuant to an agreement entered into for
the direct or indirect sale or disposition of all or substantially all the
Capital Stock or assets of such Restricted Subsidiary (or the property or
assets that are subject to such restriction) pending the closing of such
sale or disposition;
(vi) encumbrances or restrictions arising or existing by reason of
applicable law or any applicable rule, regulation or order;
(vii) customary provisions with respect to the distribution of assets
or property in joint venture agreements;
(viii) any encumbrance or restriction with respect to such Restricted
Subsidiary pursuant to an agreement relating to any Indebtedness or
Preferred Stock issued by such Restricted Subsidiary on or prior to the
date on which such Restricted Subsidiary became a Restricted Subsidiary or
was acquired by the Company and outstanding on such date, other than
Indebtedness or Preferred Stock issued as consideration in, or to provide
all or any portion of the funds or credit support utilized to consummate,
the transaction or series of related transactions pursuant to which such
Restricted Subsidiary became a Restricted Subsidiary of the Company or was
acquired by the Company;
(ix) restrictions relating to Subsidiary Preferred Stock that require
that due and payable dividends thereon be paid in full prior to dividends
on such Restricted Subsidiary's common stock; and
(x) any agreement or charter provision evidencing Indebtedness or
Capital Stock permitted under the Indenture; provided, however, that the
provisions relating to such encumbrance or restriction contained in such
agreement or charter provision are not less favorable to the Company in any
material respect as determined in good faith by the Board of Directors of
the Company than the provisions relating to such encumbrance or restriction
contained in the Indenture.
Limitation on Sales of Assets and Subsidiary Stock.
The Company will not, and will not permit any of its Restricted
Subsidiaries to, make any Asset Disposition unless:
(1) the Company or such Restricted Subsidiary receives consideration
at the time of such Asset Disposition at least equal to the fair market
value, as determined in good faith by the Board of Directors (including as
to the value of all non-cash consideration), of the shares and assets
subject to such Asset Disposition;
(2) at least 75% of the consideration thereof received by the Company
or such Restricted Subsidiary, as the case may be, is in the form of cash
or Cash Equivalents, Additional Assets (the value of which shall be
determined conclusively by the Board of Directors acting in good faith,
such determination to be accompanied by a fairness opinion or appraisal
issued by an accounting, appraisal or investment banking firm of national
standing if such fair market value is estimated to exceed $50 million) or
any combination thereof ("Permitted Consideration"); provided, however,
that the Company and its Restricted Subsidiaries shall be permitted to
receive Property (the value of which shall be determined conclusively by
the Board of Directors acting in good faith, such determination to be
accompanied by a fairness opinion or appraisal issued by an accounting,
appraisal or investment banking firm of national standing if such fair
market value is estimated to exceed $50 million) other than Permitted
Consideration, so long as the aggregate fair market value, as so
determined, of all such Property other than Permitted Consideration
received from Asset Dispositions and held by the Company and the Restricted
Subsidiaries at any one time shall not exceed 10% of Adjusted Consolidated
Net Tangible Assets; and
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(3) an amount equal to 100% of the Net Available Cash from such Asset
Disposition is applied by the Company or such Restricted Subsidiary, as the
case may be:
(a) first, to the extent the Company or any Restricted Subsidiary,
as the case may be, elects (or is required by the terms of any Senior
Indebtedness), to prepay, repay or purchase Senior Indebtedness or
Indebtedness (other than any Preferred Stock) of a Restricted Subsidiary
(in each case other than Indebtedness owed to the Company or an
Affiliate of the Company) within 360 days from the later of the date of
such Asset Disposition or the receipt of such Net Available Cash;
provided, however, that, in connection with any prepayment, repayment or
purchase of Indebtedness pursuant to this clause (a), the Company or
such Restricted Subsidiary will retire such Indebtedness and will cause
the related commitment (if any) to be permanently reduced in an amount
equal to the principal amount so prepaid, repaid or purchased; provided
that, prior to such retirement, the Company or its Restricted
Subsidiaries may temporarily repay Senior Indebtedness with the Net
Available Cash; and
(b) second, to the extent of the balance of such Net Available Cash
after application in accordance with clause (a), to the extent the
Company or such Restricted Subsidiary elects, to invest in Additional
Assets within 360 days from the later of the date of such Asset
Disposition or the receipt of such Net Available Cash; provided that,
prior to such investment, the Company or its Restricted Subsidiaries may
temporarily repay Senior Indebtedness with the Net Available Cash.
Any Net Available Cash from Asset Sales that are not applied or invested as
provided in the preceding paragraph will be deemed to constitute "Excess
Proceeds." On the 361(st) day after the later of the Asset Disposition or the
receipt of the Net Available Cash, if the aggregate amount of Excess Proceeds
exceeds $10.0 million, the Company will be required to make an offer ("Asset
Sale Offer") to all holders of notes and to the extent required by the terms
thereof, to all holders of other Senior Indebtedness outstanding with similar
provisions requiring the Company to make an offer to purchase such Senior
Indebtedness with the proceeds from any Asset Disposition ("Pari Passu Notes"),
to purchase the maximum principal amount of notes and any such Pari Passu Notes
to which the Asset Sale Offer applies that may be purchased out of the Excess
Proceeds, at an offer price in cash in an amount equal to 100% of the principal
amount thereof (or the accreted value of any such Pari Passu Notes, if they were
issued at a discount) plus accrued and unpaid interest to the date of purchase,
in accordance with the procedures set forth in the Indenture or the agreements
governing the Pari Passu Notes, as applicable. To the extent that the aggregate
amount of notes and Pari Passu Notes so validly tendered and not properly
withdrawn pursuant to an Asset Sale Offer is less than the Excess Proceeds, the
Company may use any remaining Excess Proceeds for general corporate purposes,
subject to the other covenants contained in the Indenture. If the aggregate
principal amount of notes surrendered by holders thereof and other Pari Passu
Notes (or the accreted value of any such Pari Passu Notes, if they were issued
at a discount) surrendered by holders or lenders thereof, collectively, exceeds
the amount of Excess Proceeds, the Trustee shall select the notes and Pari Passu
Notes to be purchased on a pro rata basis on the basis of the aggregate
principal amount of tendered notes and Pari Passu Notes (or the accreted value
of any such Pari Passu Notes, if they were issued at a discount). Upon
completion of such Asset Sale Offer, the amount of Excess Proceeds shall be
reset at zero.
The Asset Sale Offer will remain open for a period of 20 Business Days
following its commencement, except to the extent that a longer period is
required by applicable law (the "Asset Sale Offer Period"). No later than five
Business Days after the termination of the Asset Sale Offer Period (the "Asset
Sale Purchase Date"), the Company will purchase the principal amount of notes
and Pari Passu Notes required to be purchased pursuant to this covenant (the
"Asset Sale Offer Amount") or, if less than the Asset Sale Offer Amount has been
so validly tendered, all notes and Pari Passu Notes validly tendered in response
to the Asset Sale Offer.
If the Asset Sale Purchase Date is on or after an interest record date and
on or before the related interest payment date, any accrued and unpaid interest
will be paid to the Person in whose name a note is
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registered at the close of business on such record date, and no additional
interest will be payable to holders who tender notes pursuant to the Asset Sale
Offer.
On or before the Asset Sale Purchase Date, the Company will, to the extent
lawful, accept for payment, on a pro rata basis to the extent necessary, the
Asset Sale Offer Amount of Notes and Pari Passu Notes or portions thereof so
validly tendered and not properly withdrawn pursuant to the Asset Sale Offer, or
if less than the Asset Sale Offer Amount has been validly tendered and not
properly withdrawn, all notes and Pari Passu Notes so validly tendered and not
properly withdrawn. The Company will deliver to the trustee an Officers'
Certificate stating that such notes or portions thereof were accepted for
payment by the Company in accordance with the terms of this covenant and, in
addition, the Company will deliver all certificates and notes required, if any,
by the agreements governing the Pari Passu Notes. The Company or the paying
agent, as the case may be, will promptly (but in any case not later than five
Business Days after the termination of the Asset Sale Offer Period) mail or
deliver to each tendering holder of notes or holder or lender of Pari Passu
Notes, as the case may be, an amount equal to the purchase price of the notes or
Pari Passu Notes so validly tendered and not properly withdrawn by such holder
or lender, as the case may be, and accepted by the Company for purchase, and the
Company will promptly issue a new note, and the trustee, upon delivery of an
Officers' Certificate from the Company will authenticate and mail or deliver
such new note to such holder, in a principal amount equal to any unpurchased
portion of the note surrendered. In addition, the Company will take any and all
other actions required by the agreements governing the Pari Passu Notes. Any
note not so accepted will be promptly mailed or delivered by the Company to the
holder thereof. The Company will publicly announce the results of the Asset Sale
Offer on the Asset Sale Purchase Date.
For the purposes of this covenant, the following will be deemed to be cash:
(1) the assumption by the transferee of Indebtedness (other than
Subordinated Obligations or Disqualified Stock) of the Company or
Indebtedness (other than Preferred Stock) of any Restricted Subsidiary of
the Company and the release of the Company or such Restricted Subsidiary
from all liability on such Indebtedness in connection with such Asset
Disposition (in which case the Company will, without further action, be
deemed to have applied such deemed cash to Indebtedness in accordance with
clause (a) above); and
(2) securities, notes or other obligations received by the Company or
any Restricted Subsidiary of the Company from the transferee that are
promptly converted by the Company or such Restricted Subsidiary into cash.
The Company will 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 the indenture. To the
extent that the provisions of any securities laws or regulations conflict with
provisions of this covenant, the Company will comply with the applicable
securities laws and regulations and will not be deemed to have breached its
obligations under the indenture by virtue thereof.
Limitation on Affiliate Transactions.
The Company will not, and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, enter into or conduct any transaction
(including the purchase, sale, lease or exchange of any property or the
rendering of any service) with any Affiliate of the Company (an "Affiliate
Transaction") unless:
(1) the terms of such Affiliate Transaction are no less favorable to
the Company or such Restricted Subsidiary, as the case may be, in any
material respect than those that could be obtained in a comparable
transaction at the time of such transaction in arm's-length dealings with a
Person who is not such an Affiliate;
(2) in the event such Affiliate Transaction involves an aggregate
amount in excess of $5.0 million, the terms of such transaction have been
approved by a majority of the members of the Board of Directors of the
Company and by a majority of the members of such Board having no
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personal stake in such transaction, if any (and such majority or
majorities, as the case may be, determines that such Affiliate Transaction
satisfies the criteria in clause (1) above); and
(3) in the event such Affiliate Transaction involves an aggregate
amount in excess of $15.0 million, the Company has received a written
opinion from an independent investment banking firm of nationally
recognized standing that such Affiliate Transaction is not materially less
favorable than those that might reasonably have been obtained in a
comparable transaction at such time on an arms-length basis from a Person
that is not an Affiliate.
The preceding paragraph will not apply to:
(1) any Restricted Payment (other than a Restricted Investment)
permitted to be made pursuant to the covenant described under "Limitation
on Restricted Payments";
(2) any issuance of securities, or other payments, awards or grants in
cash, securities or otherwise pursuant to, or the funding of, employment
arrangements, stock options and stock ownership plans and other reasonable
fees, compensation, benefits and indemnities paid or entered into by the
Company or its Restricted Subsidiaries in the ordinary course of business
to or with officers, directors or employees of the Company and its
Restricted Subsidiaries;
(3) loans or advances to officers, directors and employees in the
ordinary course of business of the Company or any of its Restricted
Subsidiaries;
(4) any transaction (i) between the Company and a Restricted
Subsidiary, (ii) between the Company and a joint venture or similar entity
which would constitute an Affiliate Transaction solely because the Company
or Restricted Subsidiary owns an equity interest in or otherwise controls
such Restricted Subsidiary, joint venture or similar entity or (iii)
between Restricted Subsidiaries or a Restricted Subsidiary and a joint
venture or similar entity described in this clause (4);
(5) the payment of reasonable and customary fees to, and indemnity
provided on behalf of, officers, directors or employees of the Company or
any Restricted Subsidiary of the Company;
(6) the performance of obligations of the Company or any of its
Restricted Subsidiaries under the terms of any agreement to which the
Company or any of its Restricted Subsidiaries is a party on the Issue Date,
as these agreements may be amended, modified or supplemented from time to
time; provided, however that any future amendment, modification or
supplement entered into after the Issue Date will be permitted to the
extent that its terms are not more disadvantageous to the holders of the
notes than the terms of the agreements in effect on the Issue Date;
(7) transactions with suppliers or purchasers or sellers of goods or
services, in each case in the ordinary course of business and otherwise in
compliance with the terms of the Indenture, which are fair to the Company
or its Restricted Subsidiaries, in the good faith determination of the
Board of Directors of the Company or the senior management thereof and are
on terms (taken as a whole) at least as favorable as might reasonably have
been obtained at such time from an unaffiliated party; and
(8) commercially reasonable payments by the Company or any of its
Restricted Subsidiaries to Hicks Muse or its Affiliates made for any
financial advisory, financing, underwriting or placement services or in
respect of other investment banking activities, including, without
limitation, in connection with acquisitions or divestitures which payments
are approved by a majority of the Board of Directors of the Company in good
faith.
Limitation on Sale of Capital Stock of Restricted Subsidiaries.
The Company will not, and will not permit any Restricted Subsidiary of the
Company to, transfer, convey, sell, lease or otherwise dispose of any Voting
Stock of any Restricted Subsidiary or to issue any of
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the Voting Stock of a Restricted Subsidiary (other than, if necessary, shares of
its Voting Stock constituting directors' qualifying shares) to any Person
except:
(1) to the Company or a Wholly-Owned Subsidiary; or
(2) in compliance with the covenant described under "-- Limitation on
Sales of Assets and Subsidiary Stock" and immediately after giving effect
to such transfer, conveyance, sale, lease, other disposition or issuance,
such Restricted Subsidiary either continues to be a Restricted Subsidiary
or if such Restricted Subsidiary would no longer be a Restricted
Subsidiary, then the Investment would have been permitted to be made under
the "-- Limitation on Restricted Payments" covenant as if made on the date
of such transfer, conveyance, sale, lease, other disposition or issuance.
Notwithstanding the preceding paragraph, the Company may sell all the
Voting Stock of a Restricted Subsidiary as long as the Company complies with the
terms of the covenant described under "-- Limitation on Sales of Assets and
Subsidiary Stock."
SEC Reports.
Notwithstanding that the Company may not be subject to the reporting
requirements of Section 13 or 15(d) of the Exchange Act, to the extent permitted
by the Exchange Act, the Company will file with the Securities and Exchange
Commission, and provide the trustee and the holders of the notes with, the
annual reports and the information, documents and other reports (or copies of
such portions of any of the foregoing as the Securities and Exchange Commission
may by rules and regulations prescribe) that are specified in Sections 13 and
15(d) of the Exchange Act within the time periods specified therein. In the
event that the Company is not permitted to file such reports, documents and
information with the Securities and Exchange Commission pursuant to the Exchange
Act, the Company will nevertheless provide such Exchange Act information to the
trustee and the holders of the notes as if the Company were subject to the
reporting requirements of Section 13 or 15(d) of the Exchange Act within the
time periods specified therein.
Merger and Consolidation.
The Company will not consolidate with or merge with or into, or convey,
transfer or lease all or substantially all its assets to, any Person, unless:
(1) the resulting, surviving or transferee Person, if other than the
Company (the "Successor Company"), will be a corporation, partnership,
trust or limited liability company organized and existing under the laws of
the United States of America, any State thereof or the District of Columbia
or the Cayman Islands and the Successor Company (if not the Company) will
expressly assume, by supplemental indenture, executed and delivered to the
trustee, in form reasonably satisfactory to the trustee, all the
obligations of the Company under the notes and the indenture;
(2) immediately after giving effect to such transaction (and treating
any Indebtedness that becomes an obligation of the Successor Company or any
Subsidiary of the Successor Company as a result of such transaction as
having been Incurred by the Successor Company or such Subsidiary at the
time of such transaction), no Default or Event of Default shall have
occurred and be continuing;
(3) immediately after giving effect to such transaction, either (a)
the Successor Company would be able to Incur at least an additional $1.00
of Indebtedness pursuant to the first paragraph of the "Limitation on
Indebtedness" covenant or (b) the Consolidated Coverage Ratio for the
Successor Company would not be less than the Consolidated Coverage Ratio of
the Company immediately prior to the transaction; and
(4) the Company shall have delivered 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)
comply with the Indenture.
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For purposes of this covenant, the sale, lease, conveyance, assignment,
transfer, or other disposition of all or substantially all of the properties and
assets of one or more Restricted Subsidiaries of the Company, which properties
and assets, if held by the Company instead of such Restricted Subsidiaries,
would constitute all or substantially all of the properties and assets of the
Company and its Restricted Subsidiaries on a consolidated basis, shall be deemed
to be the transfer of all or substantially all of the properties and assets of
the Company.
The Successor Company will succeed to, and be substituted for, and may
exercise every right and power of, the Company under the Indenture, but, in the
case of a lease of all or substantially all its assets, the Company will not be
released from the obligation to pay the principal of and interest on the notes.
Although there is a limited body of case law interpreting the phrase
"substantially all," there is no precise established definition of the phrase
under applicable law. Accordingly, in certain circumstances there may be a
degree of uncertainty as to whether a particular transaction would involve "all
or substantially all" of the property or assets of a Person.
Notwithstanding the preceding clause (3), (x) any Restricted Subsidiary of
the Company may consolidate with, merge into or transfer all or part of its
properties and assets to the Company and the Company may consolidate with, merge
into or transfer all or part of its properties and assets to any Restricted
Subsidiary and (y) the Company may merge with an Affiliate incorporated solely
for the purpose of reincorporating the Company in another jurisdiction to
realize tax or other benefits.
Limitation on Lines of Business.
The Company will not, and will not permit any Restricted Subsidiary to,
engage in any business other than a Related Business.
Payments for Consent.
Neither the Company nor any of its Restricted Subsidiaries will, directly
or indirectly, pay or cause to be paid any consideration, whether by way of
interest, fees or otherwise, to any holder of any notes for or as an inducement
to any consent, waiver or amendment of any of the terms or provisions of the
Indenture or the Notes unless such consideration is offered to be paid or is
paid to all holders of the notes that consent, waive or agree to amend in the
time frame set forth in the solicitation documents relating to such consent,
waiver or agreement.
EVENTS OF DEFAULT
Each of the following is an Event of Default:
(1) default in any payment of interest or additional interest (as
required by the registration rights agreement) on any note when due,
continued for 30 days, whether or not such payment is prohibited by the
provisions described under "Ranking and Subordination";
(2) default in the payment of principal of or premium, if any, on any
note when due at its Stated Maturity, upon optional redemption, upon
required repurchase, upon declaration or otherwise, whether or not such
payment is prohibited by the provisions described under "Ranking and
Subordination";
(3) failure by the Company to comply with its obligations under
"Certain Covenants -- Merger and Consolidation";
(4) failure by the Company to comply for 30 days after notice with any
of its obligations under the covenants described under "Change of Control"
above or under the covenants described under "Certain Covenants" above (in
each case, other than a failure to purchase notes which will constitute an
Event of Default under clause (2) above and other than a failure to comply
with "Certain Covenants -- Merger and Consolidation" which is covered by
clause (3));
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(5) failure by the Company to comply for 60 days after notice with its
other agreements contained in the indenture;
(6) default under any mortgage, indenture or instrument under which
there may be issued or by which there may be secured or evidenced any
Indebtedness for money borrowed by the Company or any of its Restricted
Subsidiaries (or the payment of which is guaranteed by the Company or any
of its Restricted Subsidiaries), other than Indebtedness owed to the
Company or a Restricted Subsidiary, whether such Indebtedness or guarantee
now exists, or is created after the date of the indenture, which default:
(a) is caused by a failure to pay principal of, or interest or
premium, if any, on such Indebtedness prior to the expiration of the
grace period provided in such Indebtedness ("payment default"); or
(b) results in the acceleration of such Indebtedness prior to its
maturity (the "cross acceleration provision");
and, in each case, the principal amount of any such Indebtedness,
together with the principal amount of any other such Indebtedness under
which there has been a payment default or the maturity of which has been
so accelerated, aggregates $15.0 million or more;
(7) certain events of bankruptcy, insolvency or reorganization of the
Company or a Significant Subsidiary or group of Restricted Subsidiaries
that, taken together (as of the latest audited consolidated financial
statements for the Company and its Restricted Subsidiaries), would
constitute a Significant Subsidiary (the "bankruptcy provisions"); or
(8) failure by the Company or any Significant Subsidiary or group of
Restricted Subsidiaries that, taken together (as of the latest audited
consolidated financial statements for the Company and its Restricted
Subsidiaries), would constitute a Significant Subsidiary to pay final and
nonappealable judgments in aggregate principal amount in excess of $15.0
million (net of any amounts that a reputable and creditworthy insurance
company has acknowledged liability for in writing), which judgments are not
paid, discharged or stayed for a period of 60 days after becoming final and
nonappealable (the "judgment default provision").
However, a default under clauses (4) and (5) of this paragraph will not
constitute an Event of Default until the trustee or the holders of 25% in
principal amount of the outstanding notes notify the Company of the default and
the Company does not cure such default within the time specified in clauses (4)
and (5) of this paragraph after receipt of such notice.
If an Event of Default (other than an Event of Default described in clause
(7) above) occurs and is continuing, the trustee by notice to the Company, or
the holders of at least 25% in principal amount of the outstanding notes by
notice to the Company and the trustee, may, and the trustee at the request of
such holders shall, declare the principal of, premium, if any, and accrued and
unpaid interest, if any, on all the notes to be due and payable. Upon such a
declaration, such principal, premium and accrued and unpaid interest will be due
and payable immediately. In the event of a declaration of acceleration of the
notes because an Event of Default described in clause (6) under "Events of
Default" has occurred and is continuing, the declaration of acceleration of the
notes shall be automatically annulled if the event of default or payment default
triggering such Event of Default pursuant to clause (6) shall be remedied or
cured by the Company or a Restricted Subsidiary of the Company or waived by the
holders of the relevant Indebtedness within 20 days after the declaration of
acceleration with respect thereto and if (1) the annulment of the acceleration
of the notes would not conflict with any judgment or decree of a court of
competent jurisdiction and (2) all existing Events of Default, except nonpayment
of principal, premium or interest on the notes that became due solely because of
the acceleration of the notes, have been cured or waived. If an Event of Default
described in clause (7) above occurs and is continuing, the principal of,
premium, if any, and accrued and unpaid interest on all the notes will become
and be immediately due and payable without any declaration or other act on the
part of the trustee or any holders. The holders of a
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majority in principal amount of the outstanding notes may waive all past
defaults (except with respect to nonpayment of principal, premium or interest)
and rescind any such acceleration with respect to the notes and its consequences
if (1) rescission would not conflict with any judgment or decree of a court of
competent jurisdiction and (2) all existing Events of Default, other than the
nonpayment of the principal of, premium, if any, and interest on the notes that
have become due solely by such declaration of acceleration, have been cured or
waived.
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, premium, if any, or interest when due, no holder may pursue any
remedy with respect to the indenture or the notes unless:
(1) such holder has previously given the trustee notice that an Event
of Default is continuing;
(2) holders of at least 25% in principal amount of the outstanding
notes have requested the trustee to pursue the remedy;
(3) such holders have offered the trustee reasonable security or
indemnity against any loss, liability or expense;
(4) the trustee has not complied with such request within 60 days
after the receipt of the request and the offer of security or indemnity;
and
(5) the holders of a majority in principal amount of the outstanding
notes have not given the trustee a direction that, in the opinion of the
trustee, is 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 or that would involve the trustee in personal liability. Prior
to taking any action under the Indenture, the trustee will be entitled to
indemnification satisfactory to it in its sole discretion against all losses and
expenses caused by taking or not taking such action.
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, premium, if any, or interest on any note, the trustee may
withhold notice if and so long as a committee of trust officers of the trustee
in good faith determines that withholding notice is in the interests of the
holders. In addition, the Company is required to deliver to the trustee, within
120 days after the end of each fiscal year, a certificate indicating whether the
signers thereof know of any Default that occurred during the previous year. The
Company also is required to deliver to the trustee, within 30 days after the
occurrence thereof, written notice of any events which would constitute certain
Defaults, their status and what action the Company is taking or proposes to take
in respect thereof.
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 without limitation, consents obtained in connection with
a purchase of, or tender offer or exchange offer for, notes) and, subject to
certain exceptions, any past default or compliance with any provisions may be
waived with the consent of the holders of a majority in principal amount of the
notes then outstanding (including, without limitation, consents obtained in
connection with a purchase of, or tender offer or exchange offer for, notes).
However,
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without the consent of each holder of an outstanding note affected, no amendment
may, among other things:
(1) reduce the amount of notes whose holders must consent to an
amendment;
(2) reduce the stated rate of or extend the stated time for payment of
interest on any note;
(3) reduce the principal of or extend the Stated Maturity of any note;
(4) reduce the premium payable upon the redemption or repurchase of
any note or, after the Company's obligation to purchase notes arises under
the indenture, change the time at which any note may be redeemed or
repurchased as described above under "Change of Control," "Certain
Covenants -- Limitation on Sales of Assets and Subsidiary Stock" or any
similar provision, whether through an amendment or waiver of provisions in
the covenants, definition or otherwise;
(5) make any note payable in money other than that stated in the note;
(6) impair the right of any holder to receive payment of, premium, if
any, principal of and interest on such holder's notes on or after the due
dates therefor or to institute suit for the enforcement of any payment on
or with respect to such holder's notes; or
(7) make any change in the amendment provisions which require each
holder's consent or in the waiver provisions.
Without the consent of any holder, the Company and the trustee may amend
the indenture to:
(1) cure any ambiguity, omission, defect or inconsistency;
(2) provide for the assumption by a successor corporation,
partnership, trust or limited liability company of the obligations of the
Company under the indenture;
(3) provide for uncertificated notes in addition to or in place of
certificated Notes (provided that the uncertificated notes are issued in
registered form for purposes of Section 163(f) of the Code, or in a manner
such that the uncertificated notes are described in Section 163(f)(2)(B) of
the Code);
(4) add Guarantees with respect to the notes;
(5) secure the notes;
(6) add to the covenants of the Company for the benefit of the holders
or surrender any right or power conferred upon the Company;
(7) make any change that does not adversely affect the rights of any
holder in any material respect; or
(8) comply with any requirement of the Securities and Exchange
Commission 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. After an amendment under the
Indenture becomes effective, the Company is required to mail to the holders a
notice briefly describing such amendment. However, the failure to give such
notice to all the holders, or any defect therein, will not impair or affect the
validity of the amendment.
DEFEASANCE
The Company at any time may terminate all its obligations under the notes
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.
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The Company at any time may terminate its obligations under covenants
described under "Certain Covenants" (other than "Merger and Consolidation"), the
operation of the cross-default upon a payment default, cross acceleration
provisions, the bankruptcy provisions with respect to Significant Subsidiaries
and the judgment default provision described under "Events of Default" above and
the limitations contained in clause (3) under "Certain Covenants -- Merger and
Consolidation" above ("covenant defeasance").
The Company may exercise its legal defeasance option notwithstanding its
prior exercise of its covenant defeasance option. If the Company exercises its
legal defeasance option, payment of the notes may not be accelerated because of
an Event of Default with respect thereto. If the Company exercises its covenant
defeasance option, payment of the notes may not be accelerated because of an
Event of Default specified in clause (4), (5), (6), (7) (with respect only to
Significant Subsidiaries) or (8) under "Events of Default" above or because of
the failure of the Company to comply with clause (3) under "Certain
Covenants -- Merger and Consolidation" above.
In order to exercise either defeasance option, the Company must irrevocably
deposit in trust (the "defeasance trust") with the trustee money or U.S.
Government Obligations for the payment of principal, premium, if any, 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 (subject to customary exceptions and exclusions) to the
effect that holders of the notes 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 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. 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.
NO PERSONAL LIABILITY OF DIRECTORS, OFFICERS, EMPLOYEES AND SHAREHOLDERS
No director, officer, employee, incorporator or shareholder of the Company,
as such, shall have any liability for any obligations of the Company under the
notes or the indenture or for any claim based on, in respect of, or by reason
of, such obligations or their creation. Each Holder by accepting a note waives
and releases all such liability. The waiver and release are part of the
consideration for issuance of the notes. Such waiver may not be effective to
waive liabilities under the federal securities laws and it is the view of the
Securities and Exchange Commission that such a waiver is against public policy.
CONCERNING THE TRUSTEE
The Chase Manhattan Bank is the trustee under the indenture and has been
appointed by the Company as registrar and paying agent with regard to the notes.
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.
CERTAIN DEFINITIONS
"Additional Assets" means:
(1) any property or assets (other than Indebtedness and Capital Stock)
to be used by the Company or a Restricted Subsidiary in a Related Business;
(2) the Capital Stock of a Person that becomes a Restricted Subsidiary
as a result of the acquisition of such Capital Stock by the Company or a
Restricted Subsidiary of the Company; or
(3) Capital Stock constituting a minority interest in any Person that
at such time is a Restricted Subsidiary of the Company;
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provided, however, that, in the case of clauses (2) and (3), such Restricted
Subsidiary is primarily engaged in a Related Business.
"Adjusted Consolidated Net Tangible Assets" means (without duplication), as
of the date of determination, the remainder of:
(a) the sum of:
(i) discounted future net revenues from proved oil and gas reserves
of the Company and its Restricted Subsidiaries calculated in accordance
with Securities and Exchange Commission guidelines before any
provincial, territorial, state, Federal or foreign income taxes, as
estimated by the Company in a reserve report prepared as of the end of
the Company's most recently completed fiscal year for which audited
financial statements are available, including the Company's interest in
oil and gas reserves of Triton International Oil Corporation, for so
long and the Company owns Voting Stock of Triton International Oil
Corporation, and any other vehicle permitted pursuant to the definition
of Permitted Business Investments by which the Company maintains an
interest in oil and gas reserves (notwithstanding that neither Triton
International Oil Corporation nor such other vehicle is, or may be, a
Restricted Subsidiary of the Company), as increased by, as of the date
of determination, the estimated discounted future net revenues from
(A) estimated proved oil and gas reserves of the Company and its
Restricted Subsidiaries acquired since such year end, which reserves
were not reflected in such year end reserve report, and
(B) estimated oil and gas reserves of the Company and its
Restricted Subsidiaries attributable to extensions, discoveries and
other additions and upward revisions of estimates of proved oil and
gas reserves since such year end due to exploration, development,
exploitation or production activities, in each case calculated in
accordance with Securities and Exchange Commission guidelines
(utilizing the prices utilized in such year end reserve report), and
decreased by, as of the date of determination, the estimated
discounted future net revenues from
(C) estimated proved oil and gas reserves of the Company and its
Restricted Subsidiaries produced or disposed of since such year end,
and
(D) estimated oil and gas reserves attributable to downward
revisions of estimates of proved oil and gas reserves since such year
end due to changes in geological conditions or other factors which
would, in accordance with standard industry practice, cause such
revisions, in each case calculated on a pre-tax basis and
substantially in accordance with Securities and Exchange Commission
guidelines (utilizing the prices utilized in such year end reserve
report), in each case as estimated by the Company's petroleum
engineers or any independent petroleum engineers engaged by the
Company for that purpose;
(ii) the capitalized costs that are attributable to oil and gas
properties of the Company and its Restricted Subsidiaries to which no
proved oil and gas reserves are attributable, based on the Company's
books and records as of a date no earlier than the date of the Company's
latest available annual or quarterly financial statements;
(iii) the Net Working Capital on a date no earlier than the date of
the Company's latest annual or quarterly financial statements; and
(iv) the greater of
(A) the net book value of other tangible assets of the Company
and its Restricted Subsidiaries, as of a date no earlier than the
date of the Company's latest annual or quarterly financial statement,
and
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(B) the appraised value, as estimated by independent appraisers,
of other tangible assets of the Company and its Restricted
Subsidiaries, as of a date no earlier than the date of the Company's
latest audited financial statements; minus
(b) the sum of:
(i) Minority Interests;
(ii) to the extent included in (a)(i) above, any net gas balancing
liabilities of the Company and its Restricted Subsidiaries reflected in
the Company's latest audited financial statements;
(iii) to the extent included in (a)(i) above, the discounted future
net revenues, calculated in accordance with Securities and Exchange
Commission guidelines (utilizing the prices utilized in the Company's
year end reserve report), attributable to reserves which are required to
be delivered to third parties to fully satisfy the obligations of the
Company and its Restricted Subsidiaries with respect to Volumetric
Production Payments (determined, if applicable, using the schedules
specified with respect thereto); and
(iv) the discounted future net revenues, calculated in accordance
with Securities and Exchange Commission guidelines, attributable to
reserves subject to Dollar-Denominated Production Payments which, based
on the estimates of production and price assumptions included in
determining the discounted future net revenues specified (a)(i) above,
would be necessary to fully satisfy the payment obligations of the
Company and its Subsidiaries with respect to Dollar-Denominated
Production Payments (determined, if applicable, using 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. 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 foregoing;
provided that beneficial ownership of 10% or more of the Voting Stock of a
Person shall be deemed to be control. The initial purchasers of the old notes
and each of their respective Affiliates shall not be deemed Affiliates of the
Company by reason of their direct or indirect investments in any fund managed by
Hicks Muse or any Person in which any such fund is invested or the Senior Credit
Agreement, as applicable.
"Asset Disposition" means any direct or indirect sale (other than in a
Sale/Leaseback Transaction), lease (other than an operating lease entered into
in the ordinary course of business), transfer, issuance or other disposition for
value, or a series of related sales, leases, transfers, issuances or
dispositions that are part of a common plan, of shares of Capital Stock of a
Subsidiary (other than directors' qualifying shares or an immaterial number of
shares required by applicable law to be held by a Person other than the Company
or a Restricted Subsidiary), property or other assets (each referred to for the
purposes of this definition as a "disposition") by the Company or any of its
Restricted Subsidiaries, including any disposition by means of a merger,
consolidation or similar transaction.
Notwithstanding the preceding, the following items shall not be deemed to
be Asset Dispositions:
(1) a disposition by a Restricted Subsidiary to the Company or by the
Company or a Restricted Subsidiary to a Restricted Subsidiary;
(2) the sale of Cash Equivalents in the ordinary course of business;
(3) a disposition of inventory in the ordinary course of business;
(4) a disposition of obsolete or worn out equipment or equipment that
is no longer useful in the conduct of the business of the Company and its
Restricted Subsidiaries and that is disposed of in each case in the
ordinary course of business;
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(5) transactions permitted under "Certain Covenants -- Merger and
Consolidation";
(6) an issuance of Capital Stock by a Restricted Subsidiary of the
Company to the Company or to a Restricted Subsidiary;
(7) for purposes of "Certain Covenants -- Limitation on Sales of
Assets and Subsidiary Stock" only, the making of a Permitted Investment or
a disposition subject to "Certain Covenants -- Limitation on Restricted
Payments";
(8) dispositions of assets with a fair market value of less than $5.0
million;
(9) dispositions in connection with Permitted Liens;
(10) the licensing or sublicensing of intellectual property or other
general intangibles and licenses, leases or subleases of other property in
the ordinary course of business and which do not materially interfere with
the business of the Company and its Restricted Subsidiaries;
(11) foreclosure on assets;
(12) sale or transfer (whether or not in the ordinary course of
business) of crude oil and natural gas properties or direct or indirect
interests in real property; provided that at the time of such sale or
transfer such properties do not have associated with them any proved
reserves;
(13) the abandonment, farm-out, lease or sublease of developed or
undeveloped crude oil and natural gas properties in the ordinary course of
business;
(14) the trade or exchange by the Company or any Restricted Subsidiary
of any crude oil and natural gas Property owned or held by the Company or
such Restricted Subsidiary for crude oil and natural gas Property owned or
held by another Person, including any cash or Cash Equivalents necessary in
order to achieve an exchange of equivalent value; provided that any such
cash or Cash Equivalents received by the Company or such Restricted
Subsidiary will be subject to the provisions described in "-- Limitation on
Sales of Assets and Subsidiary Stock," which the Board or Directors of the
Company determines in good faith by resolution to be of approximately
equivalent value;
(15) the sale or transfer of mineral products or surplus or obsolete
equipment, in each case in the ordinary course of business;
(16) any transaction that constitutes a Change of Control following
which the Company makes a Change of Control Offer to repurchase the notes;
or
(17) concessions or similar transactions pursuant to agreements
existing on the Issue Date or that may subsequently be entered into in the
ordinary course of business.
"Attributable Indebtedness" in respect of a Sale/Leaseback Transaction
means, as at the time of determination, the present value (discounted at the
interest rate borne by the notes, compounded semi-annually) of the total
obligations of the lessee for rental payments during the remaining term of the
lease included in such Sale/Leaseback Transaction (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 (1) the sum
of the products of the 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 (2) the sum of all such payments.
"Bank Indebtedness" means any and all amounts, whether outstanding on the
Issue Date or thereafter Incurred, payable by the Company under or in respect of
the Senior Credit Agreement and any related notes, collateral documents, letters
of credit and guarantees and any Interest Rate Agreement entered into in
connection with the Senior Credit Agreement, including principal, premium, if
any, interest (including interest accruing on or after the filing of any
petition in bankruptcy or for reorganization relating to the
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Company at the rate specified therein whether or not a claim for post filing
interest is allowed in such proceedings), fees, charges, expenses, reimbursement
obligations, guarantees and all other amounts payable thereunder or in respect
thereof.
"Board of Directors" means, as to any Person, the board of directors of
such Person or any duly authorized committee thereof.
"Business Day" means any day other than a Saturday, a Sunday or a day on
which federal offices or banking institutions in the City of New York, in the
city of the Corporate Trust Office of the trustee, or at a place of payment are
authorized by law, regulation or executive order to remain closed.
"Capital Stock" of any Person means any and all shares, interests, rights
to purchase, warrants, options, participation 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.
"Capitalized Lease Obligations" means an obligation that is required to be
classified and accounted for as a capitalized lease for financial reporting
purposes in accordance with GAAP, and the amount of Indebtedness represented by
such obligation will be the capitalized amount of such obligation at the time
any determination thereof is to be made as determined in accordance with GAAP,
and the Stated Maturity thereof will be the date of the last payment of rent or
any other amount due under such lease prior to the first date such lease may be
terminated without penalty.
"Cash Equivalents" means:
(1) securities issued or directly and fully guaranteed or insured by
the United States government or any agency or instrumentality thereof,
having maturities of not more than one year from the date of acquisition;
(2) marketable general obligations issued by any state of the United
States of America or any political subdivision of any such state or any
public instrumentality thereof maturing within one year from the date of
acquisition thereof (provided that the full faith and credit of the United
States is pledged in support thereof) and, at the time of acquisition
thereof, having one of the two highest credit ratings from either Standard
& Poor's Ratings Services or Moody's Investors Service, Inc.;
(3) certificates of deposit, time deposits, eurodollar time deposits,
overnight bank deposits or bankers' acceptances having maturities of not
more than one year from the date of acquisition thereof issued by any
commercial bank the long-term debt of which is rated at the time of
acquisition thereof at least "A" or the equivalent thereof by Standard &
Poor's Ratings Services, or "A" or the equivalent thereof by Moody's
Investors Service, Inc., and having combined capital and surplus in excess
of $200 million;
(4) repurchase obligations with a term of not more than seven days for
underlying securities of the types described in clauses (1), (2) and (3)
entered into with any bank meeting the qualifications specified in clause
(3) above;
(5) commercial paper rated at the time of acquisition thereof at least
"A-2" or the equivalent thereof by Standard & Poor's Ratings Services or
"P-2" or the equivalent thereof by Moody's Investors Service, Inc., or
carrying an equivalent rating by a nationally recognized rating agency, if
both of the two named rating agencies cease publishing ratings of
investments, and in either case maturing within one year after the date of
acquisition thereof; and
(6) interests in any investment company or money market fund
substantially all of whose assets comprise securities of the type specified
in clauses (1) through (5) above.
"Change of Control" means:
(1) any "person" or "group" of related persons (as such terms are used
in Sections 13(d) and 14(d) of the Exchange Act), except for HM4 Triton,
L.P. or any of its Affiliates (the "HM Group"), is or becomes the
beneficial owner (as defined in Rules 13d-3 and 13d-5 under the
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Exchange Act, except that such person or group shall be deemed to have
"beneficial ownership" of all shares that any such person or group has the
right to acquire, whether such right is exercisable immediately or only
after the passage of time), directly or indirectly, of more than 50% of the
total voting power of the Voting Stock of the Company (or its successor by
merger, consolidation or purchase of all or substantially all of its
assets) (for the purposes of this clause, such person or group shall be
deemed to beneficially own any Voting Stock of the Company held by an
entity, if such person or group "beneficially owns" (as defined above),
directly or indirectly, more than 50% of the voting power of the Voting
Stock of such entity); provided, however, that no such merger,
consolidation or purchase shall constitute a "Change of Control" if, as a
result of such transaction, the shareholders of the Company immediately
prior to such transaction control, directly or indirectly, 50% or more of
the total voting power of the Voting Stock of the Company or the successor
thereto in such transaction;
(2) the first day on which a majority of the members of the Board of
Directors of the Company are not Continuing Directors; or
(3) the sale, lease, transfer, conveyance or other disposition (other
than by way of merger or consolidation), in one or a series of related
transactions, of all or substantially all of the assets of the Company and
its Restricted Subsidiaries taken as a whole to any "person" (as such term
is used in Sections 13(d) and 14(d) of the Exchange Act), other than to a
member of the HM Group.
"Code" means the Internal Revenue Code of 1986, as amended.
"Commodity Agreements" means, in respect of any Person, any forward
contract, commodity swap agreement, commodity option agreement or other similar
agreement or arrangement designed to protect such Person against fluctuation in
commodity prices.
"Consolidated Coverage Ratio" means as of any date of determination, with
respect to any Person, the ratio of (x) the aggregate amount of Consolidated
EBITDA of such Person for the period of the most recent four consecutive fiscal
quarters ending prior to the date of such determination for which financial
statements are in existence to (y) Consolidated Interest Expense for such four
fiscal quarters, provided, however, that:
(1) if the Company or any Restricted Subsidiary:
(a) has Incurred any Indebtedness since the beginning of such
period that remains outstanding on such date of determination or if the
transaction giving rise to the need to calculate the Consolidated
Coverage Ratio is an Incurrence of Indebtedness, or both, Consolidated
EBITDA and Consolidated Interest Expense for such period will 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 (except that in making such computation, the amount of
Indebtedness under any revolving credit facility outstanding on the date
of such calculation will be computed based on (i) the average daily
balance of such Indebtedness during such four fiscal quarters or such
shorter period for which such facility was outstanding or (ii) if such
facility was created after the end of such four fiscal quarters, the
average daily balance of such Indebtedness during the period from the
date of creation of such facility to the date of such calculation) 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; or
(b) has repaid, repurchased, defeased or otherwise discharged any
Indebtedness since the beginning of the period that is no longer
outstanding on such date of determination or if the transaction giving
rise to the need to calculate the Consolidated Coverage Ratio involves a
discharge of Indebtedness (in each case other than Indebtedness incurred
under any revolving credit facility unless such Indebtedness has been
permanently repaid and the related commitment terminated), Consolidated
EBITDA and Consolidated Interest Expense for such period will be
calculated after giving effect on a pro forma basis to such discharge of
such Indebtedness,
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including with the proceeds of such new Indebtedness, as if such
discharge had occurred on the first day of such period;
(2) if since the beginning of such period the Company or any
Restricted Subsidiary will have made any Asset Disposition or if the
transaction giving rise to the need to calculate the Consolidated Coverage
Ratio is an Asset Disposition:
(a) the Consolidated EBITDA for such period will be reduced by an
amount equal to the Consolidated EBITDA (if positive) directly
attributable to the assets which are the subject of such Asset
Disposition for such period or increased by an amount equal to the
Consolidated EBITDA (if negative) directly attributable thereto for such
period; and
(b) Consolidated Interest Expense for such period will be reduced
by an amount equal to the Consolidated Interest Expense directly
attributable to any Indebtedness of the Company or any Restricted
Subsidiary repaid, repurchased, defeased or otherwise discharged with
respect to the Company and its 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 the Company and
its continuing Restricted Subsidiaries are no longer liable for such
Indebtedness after such sale);
(3) if since the beginning of such period the Company or any
Restricted Subsidiary (by merger or otherwise) will have made an Investment
in any Restricted Subsidiary (or any Person which becomes a Restricted
Subsidiary or is merged with or into the Company) or an acquisition of
assets, including any acquisition of assets occurring in connection with a
transaction causing a calculation to be made hereunder, which constitutes
all or substantially all of an operating unit, division or line of
business, Consolidated EBITDA and Consolidated Interest Expense for such
period will be calculated after giving pro forma effect thereto (including
the Incurrence of any Indebtedness) as if such Investment or acquisition
occurred on the first day of such period; and
(4) if since the beginning of such period any Person (that
subsequently became a Restricted Subsidiary or was merged with or into the
Company or any Restricted Subsidiary since the beginning of such period)
will have made any Asset Disposition or any Investment or acquisition of
assets that would have required an adjustment pursuant to clause (2) or (3)
above if made by the Company or a Restricted Subsidiary during such period,
Consolidated EBITDA and Consolidated Interest Expense for such period will
be calculated after giving pro forma effect thereto as if such Asset
Disposition or Investment or acquisition of assets occurred on the first
day of such period.
For purposes of this definition, whenever pro forma effect is to be given to any
calculation under this definition, the pro forma calculations will be determined
in good faith by a responsible financial or accounting officer of the Company
(including pro forma expense and cost savings following an acquisition resulting
from employee termination, facilities consolidations and closings,
standardization of employee benefits and compensation practices, consolidation
of property, casualty and other insurance coverage and policies, standardization
of sales representation commissions and other contract rates, and reductions in
taxes other than income taxes (collectively, "Cost Savings Measures"), which
cost savings the Company reasonably believes in good faith could have been
achieved during such four quarter period as a result of any such acquisition
(regardless of whether such cost savings could then be reflected in pro forma
financial statements under GAAP, Regulation S-X promulgated by the Securities
and Exchange Commission or any other regulation or policy of the Securities and
Exchange Commission), less the amount of any additional expenses that the
Company reasonably estimates would result from anticipated replacement of any
items constituting Cost Savings Measures in connection with such acquisitions;
provided, however, that both (A) such cost savings and Cost Savings Measures
were identified and such cost savings were quantified in an Officer's
Certificate delivered to the Trustee at the time of the consummation of such
acquisition and (B) with respect to each such acquisition completed prior to the
90th day preceding such date of determination, actions were commenced or
initiated by the Company within 90 days of such acquisition to
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effect the Cost Savings Measures identified in such Officer's Certificate
(regardless, however, of whether the corresponding cost savings have been
achieved). If any Indebtedness bears a floating rate of interest and is being
given pro forma effect, the interest expense on such Indebtedness will 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 EBITDA" for any period means, without duplication, the
Consolidated Net Income for such period, plus the following to the extent
deducted in calculating such Consolidated Net Income:
(1) Consolidated Interest Expense;
(2) Consolidated Income Taxes;
(3) consolidated depreciation expense;
(4) consolidated amortization of intangibles;
(5) exploration and abandonment expense (if applicable); and
(6) other non-cash charges reducing Consolidated Net Income (excluding
any such non-cash charge to the extent 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 not included in the
calculation)
and less, to the extent included in 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 and interest pursuant to
Dollar-Denominated Production Payments. Notwithstanding the preceding sentence,
clauses (2) through (6) relating to amounts of a Restricted Subsidiary of a
Person will be added to Consolidated Net Income to compute Consolidated EBITDA
of such Person only to the extent (and in the same proportion) that the net
income (loss) of such Restricted Subsidiary was included in calculating the
Consolidated Net Income of such Person and only if a corresponding amount would
be permitted at the date of determination to be paid as a dividend (directly or
indirectly through other Restricted Subsidiaries) to the Company by such
Restricted 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
Restricted Subsidiary or its stockholders.
"Consolidated Income Taxes" means, with respect to any Person for any
period, taxes imposed upon such Person or other payments required to be made by
such Person by any governmental authority (including any provision for deferred
taxes) which taxes or other payments are calculated by reference to the income
or profits of such Person or such Person and its Restricted Subsidiaries (to the
extent such income or profits were included in computing Consolidated Net Income
for such period), regardless of whether such taxes or payments are required to
be remitted to any governmental authority.
"Consolidated Interest Expense" means, for any period, the total interest
expense of the Company and its consolidated Restricted Subsidiaries, whether
paid or accrued, plus, to the extent not included in such interest expense:
(1) interest expense attributable to Capitalized Lease Obligations and
the interest portion of rent expense associated with Attributable
Indebtedness in respect of the relevant lease giving rise thereto,
determined as if such lease were a capitalized lease in accordance with
GAAP and the interest component of any deferred payment obligations;
(2) amortization of debt discount and debt issuance cost;
(3) non-cash interest expense;
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(4) commissions, discounts and other fees and charges owed with
respect to letters of credit and bankers' acceptance financing;
(5) the interest expense actually paid by the Company or its
Restricted Subsidiaries on Indebtedness of another Person that is
Guaranteed by such Person or one of its Restricted Subsidiaries or secured
by a Lien on assets of such Person or one of its Restricted Subsidiaries;
(6) net costs associated with Interest Rate Agreements (including
amortization of fees);
(7) the consolidated interest expense of such Person and its
Restricted Subsidiaries that was capitalized during such period;
(8) the product of (a) all dividends paid or payable in cash, Cash
Equivalents or Indebtedness or accrued during such period on any series of
Disqualified Stock of such Person or on Preferred Stock of its Restricted
Subsidiaries payable to a party other than the Company or a Wholly-Owned
Subsidiary, times (b) a fraction, the numerator of which is one and the
denominator of which is one minus the then current combined federal, state,
provincial and local statutory tax rate of such Person, expressed as a
decimal, in each case, on a consolidated basis and in accordance with GAAP;
and
(9) the cash contributions to any employee stock ownership plan or
similar trust to the extent such contributions are used by such plan or
trust to pay interest or fees to any Person (other than the Company) in
connection with Indebtedness Incurred by such plan or trust; provided,
however, that there will be excluded therefrom any such interest expense of
any Unrestricted Subsidiary to the extent the related Indebtedness is not
Guaranteed or paid by the Company or any Restricted Subsidiary.
For purposes of the foregoing, total interest expense will be determined
after giving effect to any net payments made or received by the Company and its
Subsidiaries with respect to Interest Rate Agreements, provided, however,
"Consolidated Interest Expense" shall not include (a) any Consolidated Interest
Expense with respect to any Production Payments and Reserve Sales, (b) to the
extent included in total interest expense, amortization or write-off of deferred
financing costs of such Person or (c) accretion of interest charges on future
plugging and abandonment obligations, future retirement benefits and other
obligations that do not constitute Indebtedness.
"Consolidated Net Income" means, for any period, the net income (loss) of
the Company and its consolidated Restricted Subsidiaries determined in
accordance with GAAP; provided, however, that there will not be included in such
Consolidated Net Income:
(1) any net income (loss) of any Person if such Person is not a
Restricted Subsidiary, except that:
(a) subject to the limitations contained in clauses (4), (5) and
(6) below, the Company's equity in the net income of any such Person for
such period will be included in such Consolidated Net Income up to the
aggregate amount of cash actually distributed by such Person during such
period to the Company or a Restricted Subsidiary as a dividend or other
distribution (subject, in the case of a dividend or other distribution
to a Restricted Subsidiary, to the limitations contained in clause (3)
below); and
(b) the Company's equity in a net loss of any such Person (other
than an Unrestricted Subsidiary) for such period will be included in
determining such Consolidated Net Income to the extent such loss has
been funded with cash from the Company or a Restricted Subsidiary;
(2) any net income (loss) of any Person acquired by the Company or a
Subsidiary in a pooling of interests transaction for any period prior to
the date of such acquisition;
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(3) any net income (but not loss) of any Restricted Subsidiary if such
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 the Company, except that:
(a) subject to the limitations contained in clauses (4), (5) and
(6) below, the Company's equity in the net income of any such Restricted
Subsidiary for such period will be included in such Consolidated Net
Income up to the aggregate amount of cash that could have been
distributed by such Restricted Subsidiary during such period to the
Company or another Restricted Subsidiary as a dividend (subject, in the
case of a dividend to another Restricted Subsidiary, to the limitation
contained in this clause); and
(b) the Company's equity in a net loss of any such Restricted
Subsidiary for such period will be included in determining such
Consolidated Net Income;
(4) any net after-tax gain (loss), less all fees and expenses related
thereto, realized upon the sale or other disposition of any property, plant
or equipment of the Company or its consolidated Restricted Subsidiaries
(including pursuant to any Sale/Leaseback Transaction) which is not sold or
otherwise disposed of in the ordinary course of business and any net
after-tax gain (loss) realized upon the sale or other disposition of any
Capital Stock of any Person;
(5) any extraordinary gain or loss and the related tax effects
according to GAAP;
(6) the cumulative effect of a change in accounting principles;
(7) any write-downs of assets; and
(8) any non-cash compensation expense in connection with the issuance
of employee or independent contractor stock options.
"Continuing Directors" means, as of any date of determination, any member
of the Board of Directors of the Company who:
(1) was a member of such Board of Directors on the date of the
Indenture; or
(2) was nominated for election or elected to such Board of Directors
with the approval of a majority of the Continuing Directors who were
members of such Board at the time of such nomination or election.
"Consolidated Net Worth" of any Person means the stockholders' equity of
such Person and its Subsidiaries, as determined on a consolidated basis in
accordance with GAAP, less (to the extent included in stockholders' equity)
amounts attributable to Redeemable Stock of such Person or its Subsidiaries.
"Currency Agreement" means in respect of a Person any foreign exchange
contract, currency swap agreement or other similar agreement designed to protect
such Person against fluctuations in currency exchange rates as to which such
Person is a party or a beneficiary.
"Default" means any event which 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
of such Person which 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:
(1) matures or is mandatorily redeemable pursuant to a sinking fund
obligation or otherwise;
(2) is convertible or exchangeable for Indebtedness or Disqualified
Stock (excluding Capital Stock which is convertible or exchangeable solely
at the option of the Company or a Restricted Subsidiary); or
(3) is redeemable at the option of the holder thereof, in whole or in
part,
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in each case on or prior to the date that is 91 days after the date (a) on which
the notes mature or (b) on which there are no notes outstanding, provided that
only the portion of Capital Stock which so matures or is mandatorily redeemable,
is so convertible or exchangeable or is so redeemable at the option of the
holder thereof prior to such date will be deemed to be Disqualified Stock;
provided, further that any Capital Stock that would constitute Disqualified
Stock solely because the holders thereof have the right to require the Company
to repurchase such Capital Stock upon the occurrence of a change of control or
asset sale (each defined in a similar manner to the corresponding definitions in
the Indenture) shall not constitute Disqualified Stock if the terms of such
Capital Stock (and all such securities into which it is convertible or for which
it is ratable or exchangeable) provide that the Company may not repurchase or
redeem any such Capital Stock (and all such securities into which it is
convertible or for which it is ratable or exchangeable) pursuant to such
provision prior to compliance by the Company with the provisions of the
Indenture described under the captions "Change of Control" and "Limitation on
Sales of Assets and Subsidiary Stock" and such repurchase or redemption complies
with "Certain Covenants -- Restricted Payments."
"Dollar-Denominated Production Payments" means production payment
obligations recorded as liabilities in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"Equity Offering" means an offering for cash by the Company of its common
stock or options, warrants or rights with respect to its common stock whether
through a public offering pursuant to a registration statement that has been
declared effective by the Securities and Exchange Commission (other than on Form
S-4 or S-8) or through an offering not required to be registered with the
Securities and Exchange Commission.
"GAAP" means generally accepted accounting principles in the United States
of America as in effect as of the date of the indenture, including those set
forth in the opinions and pronouncements of the Accounting Principles Board of
the American Institute of Certified Public Accountants and statements and
pronouncements of the Financial Accounting Standards Board or in such other
statements by such other entity as approved by a significant segment of the
accounting profession. All ratios and computations based on GAAP contained in
the indenture will be computed in conformity with GAAP.
"Government Contract Lien" means any Lien required by any contract,
statute, regulation or order in order to permit the Company or any of its
Subsidiaries to perform any contract or subcontract made by it with or at the
request of the United States or any State thereof or any department, agency or
instrumentality of either or to secure partial, progress, advance or other
payments by the Company or any of its Subsidiaries to the United States or any
State thereof or any department, agency or instrumentality of either pursuant to
the provisions of any contract, statute, regulation or order.
"Guarantee" means any obligation, contingent or otherwise, of any Person
directly or indirectly guaranteeing any Indebtedness of any other Person and any
obligation, direct or indirect, contingent or otherwise, of such Person:
(1) to purchase or pay (or advance or supply funds for the purchase or
payment of) such Indebtedness of such other Person (whether arising by
virtue of partnership arrangements, or by agreement to keep-well, to
purchase assets, goods, securities or services, to take-or-pay, or to
maintain financial statement conditions or otherwise); or
(2) entered into for purposes of assuring in any other manner the
obligee of such Indebtedness of the payment thereof or to protect such
obligee against loss in respect thereof (in whole or in part);
provided, however, that the term "Guarantee" will not include endorsements for
collection or deposit in the ordinary course of business. The term "Guarantee"
used as a verb has a corresponding meaning.
"Hedging Obligations" of any Person means the obligations of such Person
pursuant to any Interest Rate Agreement, Commodity Agreement or Currency
Agreement.
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"Holding Company" means any company as to which the Company is, directly or
indirectly, a Subsidiary.
"Incur" means issue, create, assume, Guarantee, incur or otherwise become
liable for; provided, however, that any Indebtedness or Capital Stock of a
Person existing at the time such Person becomes a Restricted Subsidiary (whether
by merger, consolidation, acquisition or otherwise) will be deemed to be
incurred by such Restricted Subsidiary at the time it becomes a Restricted
Subsidiary; and the terms "Incurred" and "Incurrence" have meanings correlative
to the foregoing.
"Indebtedness" means, with respect to any Person on any date of
determination (without duplication):
(1) the principal of and premium (if any) in respect of indebtedness
of such Person for borrowed money;
(2) the principal of and premium (if any) in respect of obligations of
such Person evidenced by bonds, debentures, notes or other similar
instruments;
(3) the principal component of all obligations of such Person in
respect of letters of credit, bankers' acceptances or other similar
instruments (including reimbursement obligations with respect thereto
except to the extent such reimbursement obligation relates to a trade
payable and such obligation is satisfied within 30 days of Incurrence);
(4) the principal component of all obligations of such Person to pay
the deferred and unpaid purchase price of property (except trade payables
and other accrued current liabilities in the ordinary course of business),
which purchase price is due more than six months after the date of placing
such property in service or taking delivery and title thereto;
(5) Capitalized Lease Obligations and all Attributable Indebtedness of
such Person;
(6) the principal component or liquidation preference 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, any Preferred Stock (but excluding, in each case, any accrued
dividends and further excluding any Preferred Stock owned by the Company or
any of its Restricted Subsidiaries);
(7) the principal component of all Indebtedness of other Persons
secured by a Lien on any asset of such Person, whether or not such
Indebtedness is assumed by such Person; provided, however, that the amount
of such Indebtedness will be the lesser of (a) the fair market value of
such asset securing the Lien at such date of determination and (b) the
amount of such Indebtedness of such other Persons;
(8) the principal component of Indebtedness of other Persons to the
extent Guaranteed by such Person; and
(9) to the extent not otherwise included in this definition, net
obligations of such Person under Currency Agreements and Interest Rate
Agreements (the amount of any such obligations to be equal at any time to
the termination value of such agreement or arrangement giving rise to such
obligation that would be payable by such Person at such time).
In addition, "Indebtedness" of any Person shall include Indebtedness
described in the preceding paragraph that would not appear as a liability on the
balance sheet of such Person if:
(1) such Indebtedness is the obligation of a partnership or joint
venture that is not a Restricted Subsidiary (a "Joint Venture");
(2) such Person or a Restricted Subsidiary of such Person is a general
partner of the Joint Venture (a "General Partner"); and
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(3) there is recourse, by contract or operation of law, with respect
to the payment of such Indebtedness to property or assets of such Person or
a Restricted Subsidiary of such Person; and then such Indebtedness shall be
included in an amount not to exceed:
(a) the lesser of (i) the net assets of the General Partner and
(ii) the amount of such obligations to the extent that there is
recourse, by contract or operation of law, to the property or assets of
such Person or a Restricted Subsidiary of such Person; or
(b) if less than the amount determined pursuant to clause (a)
immediately above, the actual amount of such Indebtedness that is
recourse to such Person or a Restricted Subsidiary of such Person, if
the Indebtedness is evidenced by a writing and is for a determinable
amount and the related interest expense shall be included in
Consolidated Interest Expense to the extent actually paid by the Company
or its Restricted Subsidiaries.
Notwithstanding the preceding, Indebtedness shall not include (a) accounts
payable arising in the ordinary course of business, (b) any obligations in
respect of prepayments for gas or oil production or gas or oil imbalances, (c)
Production Payments and Reserve Sales and (d) any operating lease existing on
the Issue Date that may be recharacterized as a Capitalized Lease Obligation
after the Issue Date.
"Interest Rate Agreement" means with respect to any Person any interest
rate protection agreement, interest rate future agreement, interest rate option
agreement, interest rate swap agreement, interest rate cap agreement, interest
rate collar agreement, interest rate hedge agreement or other similar agreement
or arrangement designed to protect such Person against fluctuations in interest
rates as to which such Person is party or a beneficiary.
"Investment" means, with respect to any Person, all investments by such
Person in other Persons (including Affiliates) in the form of any direct or
indirect advance, loan (other than advances to customers and independent
contractors in the ordinary course of business) or other extension of credit
(including by way of Guarantee or similar arrangement, but excluding any debt or
extension of credit represented by a bank deposit other than a time deposit) 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 or acquisition of Capital Stock, Indebtedness or other
similar instruments issued by, such Person and all other items that are or would
be classified as investments on a balance sheet prepared in accordance with
GAAP; provided that:
(1) Hedging Obligations entered into in the ordinary course of
business and in compliance with the Indenture;
(2) endorsements of negotiable instruments and documents in the
ordinary course of business; and
(3) an acquisition of assets, Capital Stock or other securities by the
Company or a Restricted Subsidiary for consideration consisting exclusively
of common equity securities of the Company, shall in each case not be
deemed to be an Investment.
For purposes of "Certain Covenants -- Limitation on Restricted Payments,"
(1) "Investment" will include the portion (proportionate to the
Company's equity interest in a Restricted Subsidiary to be designated as an
Unrestricted Subsidiary) of the fair market value of the net assets of such
Restricted Subsidiary of the Company at the time that such Restricted
Subsidiary is designated an Unrestricted Subsidiary; provided, however,
that upon a redesignation of such Subsidiary as a Restricted Subsidiary,
the Company will be deemed to continue to have a permanent "Investment" in
an Unrestricted Subsidiary in an amount (if positive) equal to (a) the
Company's "Investment" in such Subsidiary at the time of such redesignation
less (b) the portion (proportionate to the Company's equity interest in
such Subsidiary) of the fair market value of the net assets (as
conclusively determined by the Board of Directors of the Company in good
faith) of such Subsidiary at the time that such Subsidiary is so
re-designated a Restricted Subsidiary; and
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(2) any property transferred to or from an Unrestricted Subsidiary
will 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 the
Company. If the Company or any Restricted Subsidiary of the Company sells
or otherwise disposes of any Voting Stock of any Restricted Subsidiary of
the Company such that, after giving effect to any such sale or disposition,
such entity is no longer a Subsidiary of the Company, the Company shall be
deemed to have made an Investment on the date of any such sale or
disposition equal to the fair market value (as conclusively determined by
the Board of Directors of the Company in good faith) of the Capital Stock
of such Subsidiary not sold or disposed of.
"Investment Grade Rating" means a rating equal to or higher than Baa3 (or
the equivalent) by Moody's Investors Service, Inc. or BBB- (or the equivalent)
by Standard & Poor's Ratings Group.
"Issue Date" means the date on which the old notes were originally issued.
"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).
"Minority Interest" means the percentage interest represented by any shares
of stock of any class of a Restricted Subsidiary of the Company that are not
owned by the Company or a Restricted Subsidiary of the Company.
"Net Available Cash" from an Asset Disposition means cash payments received
(including any cash payments received by way of deferred payment of principal
pursuant to a note or installment receivable or otherwise, but only as and when
received, but excluding any other consideration received in the form of
assumption by the acquiring person of Indebtedness or other obligations relating
to the properties or assets that are the subject of such Asset Disposition or
received in any other noncash form) therefrom, in each case net of:
(1) all legal, accounting, investment banking, title and recording tax
expenses, commissions and other fees and expenses incurred, and all
Federal, state, provincial, foreign and local taxes required to be paid or
accrued as a liability under GAAP (after taking into account any available
tax credits or deductions and any tax sharing agreements), as a consequence
of such Asset Disposition;
(2) all payments made on any Indebtedness which is secured by any
assets subject to such Asset Disposition, in accordance with the terms of
any Lien upon 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; provided,
however, that if the instrument or agreement governing such Asset
Disposition requires the transferor to maintain a portion of the purchase
price in escrow (whether as a reserve for adjustment of the purchase price
or otherwise) or to indemnify the transferee for specified liabilities in a
maximum specified amount, the portion of the cash or Cash Equivalents that
is actually placed in escrow or segregated and set aside by the transferor
for such indemnification obligation shall not be deemed to be Net Available
Cash until the escrow terminates or the transferor ceases to segregate and
set aside such funds, in whole or in part, and then only to the extent of
the proceeds released from escrow to the transferor or that are not longer
segregated and set aside by the transferor;
(3) 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
(4) the deduction of appropriate amounts to be provided by the seller
as a reserve, in accordance with GAAP, against any liabilities associated
with the assets disposed of in such Asset Disposition and retained by the
Company or any Restricted Subsidiary after such Asset Disposition.
"Net Cash Proceeds," with respect to any issuance or sale of Capital Stock,
means the cash proceeds of such issuance or sale net of attorneys' fees,
accountants' fees, underwriters' or placement agents' fees, listing fees,
discounts or commissions and brokerage, consultant and other fees and charges
actually incurred in connection with such issuance or sale and net of taxes paid
or payable as a result of such
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issuance or sale (after taking into account any available tax credit or
deductions and any tax sharing arrangements).
"Net Working Capital" means (a) all current assets of the Company and its
Restricted Subsidiaries, less (b) all current liabilities of the Company and its
Restricted Subsidiaries, except current liabilities included in Indebtedness, in
each case as set forth in the consolidated financial statements of the Company
prepared in accordance with GAAP.
"Non-Recourse Debt" means Indebtedness:
(1) as to which neither the Company nor any Restricted Subsidiary (a)
provides any Guarantee or credit support of any kind (including any
undertaking, guarantee, indemnity, agreement or instrument that would
constitute Indebtedness) or (b) is directly or indirectly liable (as a
guarantor or otherwise);
(2) no default with respect to which (including any rights that the
holders thereof may have to take enforcement action against an Unrestricted
Subsidiary) would permit (upon notice, lapse of time or both) any holder of
any other Indebtedness of the Company or any Restricted Subsidiary to
declare a default under such other Indebtedness or cause the payment
thereof to be accelerated or payable prior to its stated maturity; and
(3) the explicit terms of which provide there is no recourse against
any of the assets of the Company or its Restricted Subsidiaries.
"Officer" means the Chairman of the Board, the Chief Executive Officer, the
President, any Vice President, the Treasurer or the Secretary of the Company.
"Officers' Certificate" means a certificate signed by two Officers or by an
Officer and either an Assistant Treasurer or an Assistant Secretary of the
Company.
"Opinion of Counsel" means a written opinion from legal counsel who is
acceptable to the trustee. The counsel may be an employee of or counsel to the
Company or the trustee.
"Permitted Business Investment" means any investment made in the ordinary
course of, and of a nature that is or shall have become customary in, the
Related Business including investments or expenditures for 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 the Related Business jointly with
third parties, including (i) ownership interests in oil and gas properties,
processing facilities, gathering systems, pipelines 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
(including for limited liability companies) with third parties, excluding,
however, Investments in corporations other than Restricted Subsidiaries, other
than Investments consistent with the purposes of ownership interests and
investments in the nature of (i) and (ii) above (including, without limitation
and by way of example, the Company's and its Restricted Subsidiaries'
investments in Triton International Oil Corporation and OCENSA).
"Permitted Investment" means an Investment by the Company or any Restricted
Subsidiary in:
(1) the Company, a Restricted Subsidiary or a Person which will, upon
the making of such Investment, become a Restricted Subsidiary; provided,
however, that the primary business of such Restricted Subsidiary is a
Related Business;
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(2) 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, the Company or a Restricted Subsidiary;
provided, however, that such Person's primary business is a Related
Business;
(3) cash and Cash Equivalents;
(4) receivables owing to the Company or any Restricted Subsidiary
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 the
Company or any such Restricted Subsidiary deems reasonable under the
circumstances;
(5) payroll, travel and similar advances to cover matters that are
expected at the time of such advances ultimately to be treated as expenses
for accounting purposes and that are made in the ordinary course of
business;
(6) loans or advances to employees or independent contractors made in
the ordinary course of business consistent with past practices of the
Company or such Restricted Subsidiary;
(7) stock, obligations or securities received in settlement of debts
created in the ordinary course of business and owing to the Company or any
Restricted Subsidiary or in satisfaction of judgments or pursuant to any
plan of reorganization or similar arrangement upon the bankruptcy or
insolvency of a debtor;
(8) Investments made as a result of the receipt of non-cash
consideration from an Asset Sale that was made pursuant to and in
compliance with "Certain Covenants -- Limitation on Sales of Assets and
Subsidiary Stock";
(9) Investments in existence on the Issue Date;
(10) Currency Agreements, Commodity Agreements, Interest Rate
Agreements and related Hedging Obligations, which transactions or
obligations are Incurred in compliance with "Certain
Covenants -- Limitation on Indebtedness";
(11) Investments by the Company or any of its Restricted Subsidiaries,
together with all other Investments pursuant to this clause (11), in an
aggregate amount at the time of such Investment not to exceed $50 million
outstanding at any one time;
(12) Guarantees issued in accordance with "Certain
Covenants -- Limitations on Indebtedness";
(13) Permitted Business Investments;
(14) Investments in connection with pledges, deposits, payments or
performance bonds made or given in the ordinary course of business in
connection with or to secure statutory, regulatory or similar obligations,
including obligations under health, safety or environmental obligation; and
(15) Investments the payment for which consists of Capital Stock of
the Company (other than Disqualified Stock), but excluding any debt
security that is convertible into, or exchangeable for, Capital Stock of
the Company;
"Permitted Liens" means, with respect to any Person:
(1) pledges or deposits by such Person under worker's 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 or statutory obligations of such Person or
deposits of cash or United States government bonds to secure performance,
surety or appeal bonds to which such Person is a party or which are
otherwise required of such Person, or deposits as security for contested
taxes or import duties or for the payment of rent or other obligations of
like nature, in each case incurred in the ordinary course of business;
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(2) Liens imposed by law, such as carriers', warehousemen's,
laborers', materialmen's, landlords', vendors', workmen's, operators',
producers' (including those arising pursuant to Article 9.319 of the Texas
Uniform Commercial Code or other similar statutory provisions of other
states with respect to production purchased from others) and mechanics'
Liens, in each case for sums not yet due or being contested in good faith
by appropriate proceedings;
(3) Liens for property taxes, assessments and other governmental
charges or levies not yet delinquent or subject to penalties for nonpayment
or which are being contested in good faith by appropriate proceedings;
(4) minor survey exceptions, minor encumbrances, easements or
reservations of or with respect to, or rights of others for or with respect
to, licenses, rights-of-way, sewers, electric and other utility lines and
usages, telegraph and telephone lines, pipelines, surface use, operation of
equipment, permits, servitudes and other similar matters 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 adversely affect the value of such
properties or materially impair their use in the operation of the business
of such Person;
(5) Liens on property or assets of, or any shares of stock of or
secured debt of, any Person at the time the Company or any of its
Subsidiaries acquired the property or the Person owning such property,
including any acquisition by means of a merger or consolidation with or
into the Company or any of its Subsidiaries;
(6) Liens securing a Hedging Obligation so long as such Hedging
Obligation is of the type customarily entered into in connection with, and
is entered into for the purpose of, limiting risk;
(7) Liens upon specific properties of the Company or any of its
Subsidiaries securing Indebtedness incurred in the ordinary course of
business to provide all or part of the funds for the exploration, drilling
or development of those properties;
(8) Purchase Money Liens and Liens securing Non-Recourse Debt;
provided, however, that the related purchase money Indebtedness and
Non-Recourse Debt, as applicable, shall not be secured by any Property or
assets of the Company or any Restricted Subsidiary other than the Property
acquired by the Company with the proceeds of such purchase money
Indebtedness or Non-Recourse Debt, as applicable;
(9) Liens securing only Indebtedness of a Restricted Subsidiary of the
Company to the Company or to one or more Restricted Subsidiaries of the
Company;
(10) Liens on any property to secure bonds for the construction,
installation or financing of pollution control or abatement facilities or
other forms of industrial revenue bond financing or Indebtedness issued or
guaranteed by the United States, any state or any department, agency or
instrumentality thereof;
(11) Government Contract Liens;
(12) Liens in respect of Production Payments and Reserve Sales;
(13) Liens resulting from the deposit of funds or evidences of
Indebtedness in trust for the purpose of defeasing Indebtedness of the
Company or any of its Subsidiaries;
(14) legal or equitable encumbrances deemed to exist by reason of
negative pledges or the existence of any litigation or other legal
proceeding and any related lis pendens filing (excluding any attachment
prior to judgment, judgment lien or attachment lien in aid of execution on
a judgment);
(15) rights of a common owner of any interest in property held by such
Person;
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(16) farmout, carried working interest, joint operating, unitization,
royalty, overriding royalty, sales and similar agreements relating to the
exploration or development of, or production from, oil and gas properties
entered into in the ordinary course of business;
(17) any defects, irregularities or deficiencies in title to
easements, rights-of-way or other properties that do not in the aggregate
materially adversely affect the value of such properties or materially
impair their use in the operation of the business of such Person;
(18) Liens to secure any refinancing, refunding, extension, renewal or
replacement (or successive refinancings, refundings, extensions, renewals
or replacements), as a whole or in part, of any Indebtedness secured by any
Lien referred to in the foregoing clauses (5) through (12); provided,
however, that (i) such new Lien shall be limited to all or part of the same
property that secured the original Lien, plus improvements on such
property, and (ii) the Indebtedness secured by such Lien at such time is
not increased to any amount greater than the sum of (A) the outstanding
principal amount or, if greater, committed amount of the Indebtedness
described under clauses (5) through (12) at the time the original Lien
became a Permitted Lien and (B) an amount necessary to pay any fees and
expenses, including premiums, related to such refinancing, refunding,
extension, renewal or replacement;
(19) Liens arising solely by virtue of any statutory or common law
provisions relating to banker's Liens, rights of set-off or similar rights
and remedies as to deposit accounts or other funds maintained with a
depositary institution; provided that:
(a) such deposit account is not a dedicated cash collateral account
and is not subject to restrictions against access by the Company in
excess of those set forth by regulations promulgated by the Federal
Reserve Board; and
(b) such deposit account is not intended by the Company or any
Restricted Subsidiary to provide collateral to the depository
institution; and
(20) Liens existing on the Issue Date.
"Person" means any individual, corporation, partnership, joint venture,
association, joint-stock company, trust, unincorporated organization, limited
liability company, government or any agency or political subdivision hereof or
any other entity.
"Preferred Stock," as applied to the Capital Stock of any corporation,
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
corporation, over shares of Capital Stock of any other class of such
corporation.
"Principal Property" means any property owned or leased by the Company or
any Subsidiary of the Company, the gross book value of which exceeds one percent
of Consolidated Net Worth.
"Production Payments and Reserve Sales" means the grant or transfer by the
Company or a Restricted Subsidiary of the Company to any Person of a royalty,
overriding royalty, net profits interest, production payment (whether Volumetric
Production Payments or Dollar Denominated Production Payments), partnership or
other interest in oil and gas properties, reserves or the right to receive all
or a portion of the production or the proceeds from the sale of production
attributable to such properties, including any such grants or transfers pursuant
to incentive compensation programs on terms that are reasonably customary in the
oil and gas business for geologists, geophysicists and other providers of
technical services to the Company or a Restricted Subsidiary of the Company.
"Property" means, with respect to any Person, any interest of such Person
in any kind of property or asset, whether real, personal or mixed, or tangible
or intangible, including Capital Stock and other securities issued by any other
Person (but excluding Capital Stock or other securities issued by such first
mentioned Person).
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"Purchase Money Lien" means a Lien on property securing Indebtedness
incurred by the Company or any of its Subsidiaries to provide funds for all or
any portion of the cost of (i) acquiring such property incurred before, at the
time of, or within six months after the acquisition of such property or (ii)
constructing, developing, altering, expanding, improving or repairing such
property or assets used in connection with such property.
"Rating Agency" means Standard & Poor's Ratings Group, Inc. and Moody's
Investors Service, Inc. or if Standard & Poor's Ratings Group, Inc. or Moody's
Investors Service, Inc. or both shall not make a rating on the Notes publicly
available, a nationally recognized statistical rating agency or agencies, as the
case may be, selected by the Company (as certified by a resolution of the Board
of Directors) which shall be substituted for Standard & Poor's Ratings Group,
Inc. or Moody's Investors Service, Inc. or both, as the case may be.
"Redeemable Stock" of any Person means any equity security of such Person
that by its terms (or by the terms of any security into which it is convertible
or for which it is exchangeable), or otherwise (including on the happening of an
event), is or could become required to be redeemed for cash or other property or
is or could become redeemable for cash or other property at the option of the
holder thereof, in whole or in part, on or prior to the first anniversary of the
stated maturity of the Notes; or is or could become exchangeable at the option
of the holder thereof for Indebtedness at any time in whole or in part, on or
prior to the first anniversary of the stated maturity of the Notes; provided,
however, that Redeemable Stock shall not include any security that may be
exchanged or converted at the option of the holder for Capital Stock of the
Company having no preference as to dividends or liquidation over any other
Capital Stock of the Company.
"Refinancing Indebtedness" means Indebtedness that is Incurred to refund,
refinance, replace, renew, repay, prepay or extend (including pursuant to any
defeasance or discharge mechanism) (collectively, "refinance," "refinances," and
"refinanced" shall have a correlative meaning) any Indebtedness existing on the
date of the Indenture or Incurred in compliance with the Indenture (including
Indebtedness of the Company that refinances Indebtedness of any Restricted
Subsidiary and Indebtedness of any Restricted Subsidiary that refinances
Indebtedness of another Restricted Subsidiary) including Indebtedness that
refinances Refinancing Indebtedness, provided, however, that:
(1) (a) if the Stated Maturity of the Indebtedness being refinanced is
earlier than the Stated Maturity of the Notes, the Refinancing Indebtedness
has a Stated Maturity no earlier than the Stated Maturity of the
Indebtedness being refinanced or (b) if the Stated Maturity of the
Indebtedness being refinanced is later than the Stated Maturity of the
Notes, the Refinancing Indebtedness has a Stated Maturity at least 91 days
later than the Stated Maturity of the Notes;
(2) the 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
(3) such Refinancing Indebtedness is Incurred in an aggregate
principal amount (or if issued with original issue discount, an aggregate
issue price) that is equal to or less than the sum of the aggregate
principal amount (or if issued with original issue discount, the aggregate
accreted value) then outstanding (plus, without duplication, accrued
interest, fees and expenses, including any premium and defeasance costs) of
the Indebtedness being refinanced.
"Related Business" means (a) the acquisition, exploration, exploitation,
development, production, operation and disposition of interests in oil, gas and
other hydrocarbon properties, (b) the gathering, marketing, treating,
processing, storage, refining, selling and transporting of any production from
such interests or properties and products produced in association therewith and
(c) any power generation and electrical transmission business and (d) any
business or activity relating to, arising from, or necessary, appropriate or
incidental to the activities described in the foregoing clauses (a) through (c)
of this definition.
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"Representative" means any trustee, agent or representative (if any) of an
issue of Senior Indebtedness.
"Restricted Investment" means any Investment other than a Permitted
Investment.
"Restricted Subsidiary" means any Subsidiary of the Company other than an
Unrestricted Subsidiary.
"Sale/Leaseback Transaction" means an arrangement relating to property now
owned or hereafter acquired whereby the Company or a Restricted Subsidiary
transfers such property to a Person and the Company or a Restricted Subsidiary
leases it from such Person other than (i) temporary leases for a term, including
renewals at the option of the lessee, of not more than five years, (ii) leases
between the Company and a Subsidiary of the Company or between Subsidiaries of
the Company, (iii) leases of Principal Property executed by the time of, or
within 12 months after the latest of, the acquisition, the completion of
construction or improvement, or the commencement of commercial operation of the
Principal Property, and (iv) arrangements pursuant to any provision of law with
an effect similar to the former Section 168(f)(8) of the Internal Revenue Code
of 1954.
"Senior Credit Agreement" means, with respect to the Company, one or more
debt facilities (including, without limitation, the Credit Agreement, dated as
of February 29, 2000, among the Company, The Chase Manhattan Bank, as
Administrative Agent, Chase Securities Inc., as Arranger, and the lenders
parties thereto from time to time) or commercial paper facilities with banks or
other institutional lenders providing for revolving credit loans, term loans,
receivables financing (including through the sale of receivables to such lenders
or to special purpose entities formed to borrow from such lenders against such
receivables) or letters of credit, in each case, as amended, restated, modified,
renewed, refunded, replaced or refinanced in whole or in part from time to time
(and whether or not with the original administrative agent and lenders or
another administrative agent or agents or other lenders and whether provided
under the original Credit Agreement or any other credit or other agreement or
indenture).
"Senior Debt Agreements" means, collectively:
(1) the Senior Credit Agreement; and
(2) the Senior Notes, as amended, restated, modified, renewed,
refunded, or refinanced in whole or in part from time to time.
"Senior Indebtedness" means, whether outstanding on the Issue Date or
thereafter issued, created, Incurred or assumed, the notes, the Bank
Indebtedness and all other Indebtedness of the Company, including accrued and
unpaid interest (including interest accruing on or after the filing of any
petition in bankruptcy or for reorganization relating to the Company at the rate
specified in the documentation with respect thereto whether or not a claim for
post filing interest is allowed in such proceeding) and fees relating thereto;
provided, however, that Senior Indebtedness will not include:
(1) any Indebtedness which, in the instrument creating or evidencing
the same or pursuant to which the same is outstanding, it is provided that
the obligations in respect of such Indebtedness are subordinate to payment
of the notes;
(2) any obligation of the Company to any Restricted Subsidiary;
(3) any liability for Federal, state, foreign, local or other taxes
owed or owing by the Company;
(4) any accounts payable or other liability to trade creditors arising
in the ordinary course of business (including Guarantees thereof or
instruments evidencing such liabilities);
(5) any Indebtedness, Guarantee or obligation of the Company (and any
accrued and unpaid interest in respect thereof) that is expressly
subordinate or junior in right of payment to any other Indebtedness,
Guarantee or obligation of the Company, including, without limitation, any
Subordinated Obligations; or
(6) any Capital Stock.
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"Significant Subsidiary" means any Restricted Subsidiary that would be a
"Significant Subsidiary" of the Company within the meaning of Rule 1-02 under
Regulation S-X promulgated by the Securities and Exchange Commission.
"Stated Maturity" means, with respect to any security, the date specified
in such security as the fixed date on which the payment of principal of such
security is due and payable, including pursuant to any mandatory redemption
provision, but shall not include any contingent obligations to repay, redeem or
repurchase any such principal prior to the date originally scheduled for the
payment thereof.
"Subordinated Obligation" means any Indebtedness of the Company (whether
outstanding on the Issue Date or thereafter Incurred) which is subordinate or
junior in right of payment to the Notes pursuant to a written agreement.
"Subsidiary" of any Person means (i) any corporation, association, joint
venture, limited liability company or other business entity of which more than
50% of the Voting Stock or other interests (including joint venture interests)
is at the time owned or controlled, directly or indirectly, by (a) such Person,
(b) such Person and one or more Subsidiaries of such Person or (c) one or more
Subsidiaries of such Person; and (ii) any partnership (a) the sole general
partner or the managing general partner of which is such Person or a Subsidiary
of such Person or (b) the only general partners of which are such Person or one
or more Subsidiaries of such Person (or any combination thereof). Unless
otherwise specified herein, each reference to a Subsidiary will refer to a
Subsidiary of the Company.
"Unrestricted Subsidiary" means:
(1) any Subsidiary of the Company that at the time of determination
shall be designated an Unrestricted Subsidiary by the Board of Directors of
the Company in the manner provided below; and
(2) any Subsidiary of an Unrestricted Subsidiary.
The Board of Directors of the Company may designate any Subsidiary of the
Company (including any newly acquired or newly formed Subsidiary or a Person
becoming a Subsidiary through merger or consolidation or Investment therein) to
be an Unrestricted Subsidiary only if:
(1) such Subsidiary or any of its Subsidiaries does not own any
Capital Stock or Indebtedness of or have any Investment in, or own or hold
any Lien on any property of, any other Subsidiary of the Company which is
not a Subsidiary of the Subsidiary to be so designated or otherwise an
Unrestricted Subsidiary;
(2) all the Indebtedness of such Subsidiary and its Subsidiaries
shall, at the date of designation, and will at all times thereafter,
consist of Non-Recourse Debt;
(3) such designation and the Investment of the Company in such
Subsidiary complies with "Certain Covenants -- Limitation on Restricted
Payments";
(4) such Subsidiary, either alone or in the aggregate with all other
Unrestricted Subsidiaries, does not operate, directly or indirectly, all or
substantially all of the business of the Company and its Subsidiaries; and
(5) such Subsidiary is a Person with respect to which neither the
Company nor any of its Restricted Subsidiaries has any direct or indirect
obligation:
(a) to subscribe for additional Capital Stock of such Person; or
(b) to maintain or preserve such Person's financial condition or to
cause such Person to achieve any specified levels of operating results.
Any such designation by the Board of Directors of the Company shall be
evidenced to the trustee by filing with the trustee a resolution of the Board of
Directors of the Company giving effect to such designation and an Officers'
Certificate certifying that such designation complies with the foregoing
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conditions. If, at any time, any Unrestricted Subsidiary would fail to meet the
foregoing requirements as an Unrestricted Subsidiary, it shall thereafter cease
to be an Unrestricted Subsidiary for purposes of the Indenture and any
Indebtedness of such Subsidiary shall be deemed to be Incurred as of such date.
The Board of Directors of the Company may designate any Unrestricted
Subsidiary to be a Restricted Subsidiary; provided that immediately after giving
effect to such designation, no Default or Event of Default shall have occurred
and be continuing or would occur as a consequence thereof and the Company could
incur at least $1.00 of additional Indebtedness under the first paragraph of the
"Limitation on Indebtedness" covenant on a pro forma basis taking into account
such designation.
"Volumetric Production Payments" means production payment obligations
recorded as defined revenue in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"Voting Stock" of a corporation means all classes of Capital Stock of such
corporation then outstanding and normally entitled (without regard to the
occurrence of any contingency) to vote in the election of directors.
"Wholly-Owned Subsidiary" means a Restricted Subsidiary, all of the Capital
Stock of which (other than directors' qualifying shares or an immaterial number
of shares required by applicable law to be held by a Person other than the
Company or a Restricted Subsidiary) is owned by the Company or one or more
Wholly-Owned Subsidiaries.
TAX CONSIDERATIONS
CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
The following discussion is a summary of certain federal income tax
considerations relevant to the exchange of old notes for new notes, but does not
purport to be a complete analysis of all potential tax effects. The discussion
is based upon the Internal Revenue Code of 1986, as amended, Treasury
Regulations, Internal Revenue Service rulings and pronouncements and judicial
decisions now in effect, all of which may be subject to change at any time by
legislative, judicial or administrative action. These changes may be applied
retroactively in a manner that could adversely affect a holder of new notes. The
description does not consider the effect of any applicable foreign, state, local
or other tax laws or estate or gift tax considerations.
The exchange of old notes for new notes should not be an exchange or
otherwise a taxable event to a holder for United States federal income tax
purposes. Accordingly, a holder should have the same adjusted issue price,
adjusted basis and holding period in the new notes as it had in the old notes
immediately before the exchange.
CERTAIN CAYMAN ISLANDS TAX CONSEQUENCES
According to our Cayman Islands counsel, Walkers, at the present time,
there is no Cayman Islands income or profits tax, withholding tax, capital gains
tax, capital transfer tax, estate duty or inheritance tax payable by a holder in
respect of any income, gain or loss derived from holding the old notes or
exchanging the old notes for new notes.
EACH HOLDER OF OLD NOTES SHOULD CONSULT HIS OR HER OWN TAX ADVISOR AS TO
THE PARTICULAR TAX CONSEQUENCES TO IT OF EXCHANGING OLD NOTES FOR NEW NOTES,
INCLUDING THE APPLICABILITY AND EFFECT OF ANY STATE, LOCAL OR FOREIGN TAX LAWS.
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BOOK-ENTRY; DELIVERY AND FORM
Except as described in the next paragraph, the new notes will be
represented by a single permanent global certificate in definitive, fully
registered form (the "global certificate"). The global certificate will be
deposited with, or on behalf of, DTC, and registered in the name of a nominee of
DTC. If any holder of old notes whose interest in such old notes is represented
by the global certificate representing the old notes fails to tender in the
exchange offer, we may issue and deliver to such holder a separate certificate
representing such holder's old notes in registered form without interest
coupons.
New notes exchanged for old notes originally purchased by or transferred to
- "foreign purchasers" or institutional "accredited investors" (as defined
in Rule 501(a)(1), (2), (3) or (7) under the Securities Act of 1933) who
are not "qualified institutional buyers" (as defined in Rule 144A under
the Securities Act of 1933) ("QIBs"); or
- QIBs who elect to take physical delivery of their certificates instead of
holding their interest through the global certificate (and which are thus
ineligible to trade through DTC) (collectively referred to herein as the
"non-global purchasers")
will be issued in registered form (a "certificated security").
Upon the transfer to a QIB of any certificated security initially issued to
a non-global purchaser, such certificated security will, unless the transferee
requests otherwise or the global certificate has previously been exchanged in
whole for certificated securities, be exchanged for an interest in the global
certificate.
THE GLOBAL CERTIFICATE
Pursuant to procedures established by DTC,
- upon the issuance of the global certificate, DTC or its custodian will
credit, on its internal system, the number of new notes of the individual
beneficial interests represented by such global securities to the
respective accounts of persons who have accounts with such depositary;
and
- ownership of beneficial interests in the global certificate will be shown
on, and the transfer of such ownership will be effected only through,
records maintained by DTC or its nominee (with respect to interests of
participants) and the records of participants (as defined) (with respect
to interests of persons other than participants).
Ownership of beneficial interests in the global certificate are limited to
persons who have accounts with DTC ("participants") or persons who hold
interests through participants. QIBs may hold their interests in the global
certificate directly through DTC if they are participants in such system, or
indirectly through organizations which are participants in such system.
So long as DTC, or its nominee, is the registered owner or holder of the
new notes, DTC or such nominee, as the case may be, will be considered the sole
owner or holder of the new notes represented by such global certificate for all
purposes. No beneficial owner of an interest in the global certificate will be
able to transfer that interest except in accordance with DTC's procedures.
Payments of principal of, premium, if any, and interest, if any, on the
global certificate will be made to DTC or its nominee, as the case may be, as
the registered owner thereof. Neither we nor the 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
certificate or for maintaining, supervising or reviewing any records relating to
such beneficial ownership interest.
We expect that DTC or its nominee, upon receipt of any payment of principal
of, premium, if any, and interest, if any, in respect of the global certificate,
will credit participants' accounts with payments in amounts proportionate to
their respective beneficial interests in the principal amount of the global
certificate as shown on the records of DTC or its nominee. We also expect that
payments by participants
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to owners of beneficial interests in the global certificate held through such
participants will be governed by standing instructions and customary practice,
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 be settled in clearinghouse funds. If a
holder requires physical delivery of a certificated security for any reason,
including to sell new notes to persons in states which require physical delivery
of the certificate evidencing the new notes, or to pledge such securities, such
holder must transfer its interest in the global certificate, in accordance with
the normal procedures of DTC and with the procedures set forth in the indenture
governing the new notes.
DTC has advised us that it will take any action permitted to be taken by a
holder of new notes (including the presentation of new notes for exchange as
described below) only at the direction of one or more participants to whose
account the DTC interests in the global certificate are credited and only in
respect of such new notes as to which such participant or participants has or
have given such direction.
DTC has advised us as that it is:
- a limited purpose trust company organized under the laws of the State of
New York;
- 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. Participants include
securities brokers and dealers, banks, trust companies and clearing corporations
and dealers and trust companies that clear through or maintain a custodial
relationship with a participant, either directly or indirectly.
Although DTC has agreed to the foregoing procedures in order to facilitate
transfers of interests in the global certificate among participants of DTC, it
is under no obligation to perform such procedures, and such procedures may be
discontinued at any time. We will not 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 SECURITIES
If DTC is at any time unwilling or unable to continue as a depositary for
the global certificate and a successor depositary is not appointed by us within
90 days, certificated securities will be issued in exchange for the global
certificate.
PLAN OF DISTRIBUTION
Based on interpretations by the staff of the Securities and Exchange
Commission in no action letters issued to third parties, we believe that you may
transfer new notes issued under the exchange offer in exchange for the old notes
if:
- you acquire the new notes in the ordinary course of your business; and
- you are not engaged in, and do not intend to engage in, and have no
arrangement or understanding with any person to participate in, a
distribution of such new notes.
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You may not participate in the exchange offer if you are:
- our "affiliate" within the meaning of Rule 405 under the Securities Act
of 1933; or
- a broker-dealer that acquired old notes directly from us.
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. To date, the staff of the
Securities and Exchange Commission has taken the position that broker-dealers
may fulfill their prospectus delivery requirements with respect to transactions
involving an exchange of securities such as this exchange offer, other than a
resale of an unsold allotment from the original sale of the old notes, with the
prospectus contained in the exchange offer registration statement. 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 that, for a period of up
to 90 days after the consummation of the exchange offer, we will make this
prospectus, as amended or supplemented, available to any broker-dealer for use
in connection with any such resale. In addition, until such date, all dealers
effecting transactions in new notes may be required to deliver a prospectus.
If you wish to exchange new notes for your old notes in the exchange offer,
you will be required to make representations to us as described in "Exchange
Offer -- Purpose and Effect of the Exchange Offer" and "-- Procedures for
Tendering -- Your Representations to Us" in this prospectus and in the letter of
transmittal. In addition, if you are a broker-dealer who receives new notes for
your own account in exchange for old notes that were acquired by you as a result
of market-making activities or other trading activities, you will be required to
acknowledge that you will deliver a prospectus in connection with any resale by
you of such new notes.
We will not receive any proceeds from any sale 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; and
- at prices related to such prevailing market prices or negotiated prices.
Any such resale may be made directly to purchasers or to or through brokers or
dealers who may receive compensation in the form of commissions or 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 or dealer that
participates in a distribution of such new notes may be deemed to be an
"underwriter" within the meaning of the Securities Act of 1933. 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 of 1933.
For a period of 90 days after the date the exchange offer is consummated,
we will promptly send additional copies of this prospectus and any amendment or
supplement to this prospectus to any broker-dealer that requests such documents
in the letter of transmittal. We have agreed to pay all expenses incident to the
exchange offer (including the expenses of one counsel for the holders of the old
notes) other than commissions or concessions of any broker-dealers and will
indemnify the holders of the old notes (including any broker-dealers) against
certain liabilities, including liabilities under the Securities Act of 1933.
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LEGAL MATTERS
The validity of the new notes offered in this exchange offer will be passed
upon for us by Vinson & Elkins L.L.P., Dallas, Texas and Walkers, Grand Cayman,
Cayman Islands.
EXPERTS
The financial statements as of December 31, 1999 and 1998 and for each of
the three years in the period ended December 31, 1999 included in this
prospectus have been so included in reliance on the report of
PricewaterhouseCoopers LLP, independent accountants, given on the authority of
said firm as experts on auditing and accounting.
Certain information with respect to our gas and oil reserves and that of
our subsidiaries derived from the report of DeGolyer and MacNaughton,
independent petroleum engineers, has been included in this prospectus in
reliance upon such firm as experts with respect to the matters contained
therein.
Certain information with respect to our gas and oil reserves and that of
our subsidiaries derived from the report of Netherland, Sewell & Associates,
Inc., independent petroleum engineers, has been included in this prospectus in
reliance upon such firm as experts with respect to the matters contained
therein.
ENFORCEABILITY OF CIVIL LIABILITIES AGAINST FOREIGN PERSONS
We are a Cayman Islands company, certain of our officers and directors may
be residents of various jurisdictions outside the United States and our Cayman
Islands counsel, Walkers, are residents of the Cayman Islands. All or a
substantial portion of our assets and of such persons may be located outside the
United States. As a result, it may be difficult for investors to effect service
of process within the United States upon such persons or to enforce in United
States courts judgments obtained against such persons in United States courts
and predicated upon the civil liability provisions of the Securities Act.
Notwithstanding the foregoing, we have irrevocably agreed that we may be served
with process with respect to actions based on offers and sales of securities
made hereby in the United States by serving the following person, who is our
United States agent appointed for that purpose:
James C. Musselman
c/o Triton Energy Corporation
6888 North Central Expressway
Suite 1400
Dallas, Texas 75206-9926
We have been advised by our Cayman Islands counsel, Walkers, that there is
doubt as to whether Cayman Islands courts would enforce (a) judgments of United
States courts obtained in actions against such persons or us that are predicated
upon the civil liability provisions of the Securities Act or (b) in original
actions brought against us or such person predicated upon the Securities Act.
There is no treaty in effect between the United States and the Cayman Islands
providing for such enforcement, and there are grounds upon which Cayman Islands
courts may not enforce judgments of United States courts. Certain remedies
available under the United States federal securities laws would not be allowed
in Cayman Islands courts as contrary to that nation's policy.
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WHERE YOU CAN FIND MORE INFORMATION
The Securities and Exchange Commission allows us to incorporate by
reference the information we file with them, which means that we can disclose
important information to you by referring you to those documents, without
including that information or delivering it with this prospectus. We provide a
list of all documents we incorporate by reference in this prospectus under
"Incorporation by Reference."
You may read and copy the information that we incorporate in this
prospectus by reference as well as other reports, proxy statements and other
information that we file with the Securities and Exchange Commission at the
public reference facilities maintained by the Securities and Exchange Commission
at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549 and at the
Securities and Exchange Commission's regional offices located at 7 World Trade
Center, 13th floor, New York, New York 10048 and 500 West Madison Street, Suite
1400, Chicago, Illinois 60661. You may also obtain copies of those materials at
prescribed rates from the public reference section of the Securities and
Exchange Commission at 450 Fifth Street, Washington, D.C. 20549. You may obtain
copies from the public reference room by calling the Securities and Exchange
Commission at (800) SEC-0330. In addition, we are required to file electronic
versions of those materials with the Securities and Exchange Commission through
the Securities and Exchange Commission's EDGAR system. The Securities and
Exchange Commission maintains a web site at http://www.sec.gov that contains
reports, proxy and information statements and other information regarding
registrants that file electronically with the Securities and Exchange
Commission.
You may also request a copy of those materials, free of cost, by writing or
telephoning us at the following address:
Crystal C. Bell
Triton Energy Corporation
6688 North Central Expressway, Suite 1400
Dallas, Texas 75206
(214) 691-5200
This prospectus constitutes part of a registration statement on Form S-4 we
filed with the Securities and Exchange Commission under the Securities Act of
1933. This prospectus omits some of the information contained in the
registration statement, as permitted under the rules and regulations of the
Securities and Exchange Commission. Copies of the registration statement and the
exhibits thereto are on file at the offices of the Securities and Exchange
Commission and may be obtained from the Securities and Exchange Commission for a
prescribed fee or examined at its offices or on its Internet site, as described
above.
INCORPORATION BY REFERENCE
We incorporate by reference into this prospectus the documents listed below
and any future filings we make with the Securities and Exchange Commission under
Sections 13(a), 14 or 15(d) of the Securities Exchange Act of 1934:
- Our annual report on Form 10-K for the fiscal year ended December 31,
1999 (filed on March 10, 2000), as amended by Form 10-K/A (filed on March
15, 2000), as amended by Form 10-K/A (filed on March 16, 2000), and as
further amended by Form 10-K/A (filed on August 1, 2000);
- Our quarterly reports on Form 10-Q for the quarters ended March 31, 2000
(filed on May 12, 2000), as amended by Form 10-Q/A (filed on August 2,
2000), and ended June 30, 2000 (filed on August 10, 2000);
- Our current reports on Form 8-K filed on May 3, 2000; June 14, 2000;
August 28, 2000; September 25, 2000; September 28, 2000, as amended by
Form 8-K/A, filed on September 28, 2000; and October 6, 2000;
- Our definitive proxy statement (filed on March 31, 2000); and
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- All documents we filed with the Securities and Exchange Commission
pursuant to Sections 13(a), 14 or 15(d) of the Securities Exchange Act of
1934 after the date of this prospectus and prior to the termination of
the exchange offer.
At your request, we will provide you with a free copy of any of these
filings (except for exhibits, unless the exhibits are specifically incorporated
by reference into the filing). You may request copies by writing or telephoning
us at the address or telephone number provided in "Where You Can Find More
Information."
Information that we file later with the Securities and Exchange Commission
and that is incorporated by reference in this prospectus will automatically
update and supersede information contained in this prospectus. You will be
deemed to have notice of all information incorporated by reference in this
prospectus as if that information was included in this prospectus.
CERTAIN DEFINITIONS
As used in this prospectus:
- "bbl" means barrel;
- "Bcf" means billion cubic feet;
- "BOPD" means barrels of crude oil per day;
- "boe" means barrels of oil equivalent;
- "CST" is an abbreviation for centistokes, which is a measurement of
viscosity;
- "FPSO vessel" means a floating production storage and off loading vessel;
- "Mcf" means thousand cubic feet;
- "MMcf means million cubic feet;
- "mbbls" means thousand barrels;
- "MMbbls" means million barrels;
- "MMboe" means million barrels of oil equivalent;
- "mmbtu" means thousand British thermal unit; and
- "Tcf" means trillion cubic feet; and
- "WTI" means the West Texas Intermediate price index.
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TRITON ENERGY LIMITED AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
PAGE
----
TRITON ENERGY LIMITED AND SUBSIDIARIES:
Report of Independent Accountants......................... F-2
Consolidated Statements of Operations -- Six months ended
June 30, 2000 (unaudited) and 1999 (unaudited) and
years ended December 31, 1999, 1998 and 1997........... F-3
Consolidated Balance Sheets -- June 30, 2000 (unaudited)
and December 31, 1999 and 1998......................... F-4
Consolidated Statements of Cash Flows -- Six months ended
June 30, 2000 (unaudited) and 1999 (unaudited) and
years ended December 31, 1999, 1998 and 1997........... F-5
Consolidated Statements of Shareholders' Equity -- Six
months ended June 30, 2000 (unaudited) and years ended
December 31, 1999, 1998 and 1997....................... F-6
Notes to Consolidated Financial Statements................ F-7
Schedule II -- Valuation and Qualifying Accounts -- Years
ended December 31, 1999, 1998 and 1997................. F-46
F-1
120
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
Triton Energy Limited
In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of Triton Energy Limited and its subsidiaries at December 31, 1999 and
1998, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 1999, in conformity with accounting
principles generally accepted in the United States. In addition, in our opinion,
the financial statement schedule listed in the accompanying index presents
fairly, in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. These financial
statements and financial schedule are the responsibility of the Company's
management; our responsibility is to express an opinion on these financial
statements and financial schedule based on our audits. We conducted our audits
of these statements in accordance with auditing standards generally accepted in
the United States which 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, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
/s/ PRICEWATERHOUSECOOPERS LLP
Dallas, Texas
February 23, 2000
F-2
121
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
SIX MONTHS ENDED
JUNE 30, YEAR ENDED DECEMBER 31,
------------------- -------------------------------
2000 1999 1999 1998 1997
-------- -------- -------- --------- --------
(UNAUDITED)
SALES AND OTHER OPERATING REVENUES:
Oil and gas sales.................................. $154,001 $108,792 $247,878 $ 160,881 $145,419
Gain on sale of oil and gas assets................. -- -- -- 67,737 4,077
-------- -------- -------- --------- --------
154,001 108,792 247,878 228,618 149,496
-------- -------- -------- --------- --------
COSTS AND EXPENSES:
Operating.......................................... 31,296 38,162 68,130 73,546 51,357
General and administrative......................... 10,349 9,778 23,636 26,653 28,607
Depreciation, depletion and amortization........... 27,406 30,656 61,343 58,811 36,828
Writedown of assets................................ -- -- -- 328,630 --
Special charges.................................... -- 1,220 2,909 18,324 --
-------- -------- -------- --------- --------
69,051 79,816 156,018 505,964 116,792
-------- -------- -------- --------- --------
OPERATING INCOME (LOSS).................... 84,950 28,976 91,860 (277,346) 32,704
Gain on sale of Triton Pipeline Colombia............. -- -- -- 50,227 --
Interest income...................................... 4,791 5,238 10,579 3,258 5,178
Interest expense, net................................ (8,837) (11,937) (22,648) (23,228) (23,858)
Other income (expense), net.......................... (520) 207 (3,614) 8,480 2,872
-------- -------- -------- --------- --------
(4,566) (6,492) (15,683) 38,737 (15,808)
-------- -------- -------- --------- --------
EARNINGS (LOSS) BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM....................... 80,384 22,484 76,177 (238,609) 16,896
Income tax expense (benefit)......................... 25,067 9,714 28,620 (51,105) 11,301
-------- -------- -------- --------- --------
EARNINGS (LOSS) BEFORE EXTRAORDINARY
ITEM..................................... 55,317 12,770 47,557 (187,504) 5,595
Extraordinary item -- extinguishment of debt......... -- -- -- -- (14,491)
-------- -------- -------- --------- --------
NET EARNINGS (LOSS)........................ 55,317 12,770 47,557 (187,504) (8,896)
ACCUMULATED DIVIDENDS ON PREFERENCE SHARES........... 14,680 13,945 28,671 3,061 400
-------- -------- -------- --------- --------
EARNINGS (LOSS) APPLICABLE TO ORDINARY
SHARES................................... $ 40,637 $ (1,175) $ 18,886 $(190,565) $ (9,296)
======== ======== ======== ========= ========
Average ordinary shares outstanding.................. 36,060 36,505 36,135 36,609 36,471
======== ======== ======== ========= ========
BASIC EARNINGS (LOSS) PER ORDINARY SHARE:
Earnings (loss) before extraordinary item.......... $ 1.13 $ (0.03) $ 0.52 $ (5.21) $ 0.14
Extraordinary item -- extinguishment of debt....... -- -- -- -- (0.40)
-------- -------- -------- --------- --------
BASIC EARNINGS (LOSS)...................... $ 1.13 $ (0.03) $ 0.52 $ (5.21) $ (0.26)
======== ======== ======== ========= ========
DILUTED EARNINGS (LOSS) PER ORDINARY SHARE:
Earnings (loss) before extraordinary item.......... $ 0.94 $ (0.03) $ 0.52 $ (5.21) $ 0.14
Extraordinary item -- extinguishment of debt....... -- -- -- -- (0.39)
-------- -------- -------- --------- --------
DILUTED EARNINGS (LOSS).................... $ 0.94 $ (0.03) $ 0.52 $ (5.21) $ (0.25)
======== ======== ======== ========= ========
See accompanying Notes to Consolidated Financial Statements.
F-3
122
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
AS OF AS OF DECEMBER 31,
JUNE 30, ---------------------
2000 1999 1998
----------- --------- ---------
(UNAUDITED)
ASSETS
CURRENT ASSETS:
Cash and equivalents..................................... $ 79,251 $ 186,323 $ 18,757
Trade receivables, net................................... 3,397 17,246 9,514
Other receivables........................................ 29,632 23,814 47,756
Deferred income taxes.................................... 9,178 20,090 --
Inventories, prepaid expenses and other.................. 21,941 7,806 1,639
---------- --------- ---------
TOTAL CURRENT ASSETS............................. 143,399 255,279 77,666
Property and equipment, at cost, net....................... 582,904 524,152 470,907
Investment in affiliates................................... 186,574 93,188 84,735
Deferred income taxes...................................... 88,789 88,228 100,916
Other assets............................................... 13,984 13,628 20,056
---------- --------- ---------
$1,015,650 $ 974,475 $ 754,280
========== ========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt..................... $ 9,144 $ 9,027 $ 14,027
Short-term borrowings.................................... -- -- 5,000
Accounts payable and accrued liabilities................. 71,137 62,576 44,973
Deferred income and other................................ 4,841 22,347 35,254
---------- --------- ---------
TOTAL CURRENT LIABILITIES........................ 85,122 93,950 99,254
Long-term debt, excluding current maturities............... 400,062 404,460 413,465
Deferred income taxes...................................... 9,215 6,677 3,235
Other liabilities.......................................... 6,629 6,336 14,519
SHAREHOLDERS' EQUITY:
5% preference shares, par value $.01; authorized 420,000
shares; issued 185,276 shares at June 30, 2000
(unaudited), and 209,639 shares at December 31, 1999
and 1998; stated value $34.41......................... 6,375 7,214 7,214
8% preference shares, par value $.01; authorized
11,000,000 shares; issued 5,184,909 shares at June 30,
2000 (unaudited), and 5,193,643 and 1,822,500 shares
at December 31, 1999 and 1998, respectively; stated
value $70............................................. 362,944 363,555 127,575
Ordinary shares, par value $.01; authorized 200,000,000
shares; issued 36,431,686 shares at June 30, 2000
(unaudited), and 35,763,728 and 36,643,478 shares at
December 31, 1999 and 1998, respectively.............. 364 358 366
Additional paid-in capital............................... 529,601 531,904 575,863
Accumulated deficit...................................... (382,211) (437,528) (485,085)
Accumulated other non-owner changes in shareholders'
equity................................................ (2,451) (2,451) (2,126)
---------- --------- ---------
TOTAL SHAREHOLDERS' EQUITY....................... 514,622 463,052 223,807
Commitments and contingencies (note 20).................... -- -- --
---------- --------- ---------
$1,015,650 $ 974,475 $ 754,280
========== ========= =========
The Company uses the full cost method to account for its oil- and gas-producing
activities.
See accompanying Notes to Consolidated Financial Statements.
F-4
123
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
SIX MONTHS ENDED
JUNE 30, YEAR ENDED DECEMBER 31,
-------------------- ---------------------------------
2000 1999 1999 1998 1997
--------- -------- --------- --------- ---------
(UNAUDITED)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss)....................................... $ 55,317 $ 12,770 $ 47,557 $(187,504) $ (8,896)
Adjustments to reconcile net earnings to net cash provided
by operating activities:
Depreciation, depletion and amortization................ 27,406 30,656 61,343 58,811 36,828
Proceeds from forward oil sale.......................... -- 30,000 31,932 1,770 830
Amortization of deferred income......................... (8,814) (17,627) (35,254) (35,254) (28,467)
Gain on sale of oil and gas assets...................... -- -- -- (67,737) (4,077)
Gain on sale of Triton Pipeline Colombia................ -- -- -- (50,227) --
Writedown of assets..................................... -- -- -- 328,630 --
Payment of accreted interest on extinguishment of
debt................................................. -- -- -- -- (124,794)
Extraordinary loss on extinguishment of debt, net of
tax.................................................. -- -- -- -- 14,491
Amortization of debt discount........................... -- -- -- -- 7,949
Deferred income taxes................................... 5,089 7,158 7,827 (55,592) 8,078
(Gain) loss on sale of other assets..................... 83 (362) (677) (7,590) (1,409)
Other, net.............................................. 2,384 971 8,921 3,962 6,100
Changes in working capital:
Trade and other receivables.......................... 10,439 (10,615) (16,131) 6,300 (3,238)
Inventories, prepaid expenses and other.............. (17,119) (735) (3,577) 918 1,794
Accounts payable and accrued liabilities............. (8,596) (2,387) 14,581 4,979 (2,605)
--------- -------- --------- --------- ---------
Net cash provided (used) by operating activities... 66,189 49,829 116,522 1,466 (97,416)
--------- -------- --------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures and investments...................... (74,398) (49,959) (121,483) (180,215) (219,216)
Purchase of affiliate..................................... (88,800) -- -- -- --
Proceeds from sale of oil and gas assets.................. -- -- -- 147,027 4,077
Proceeds from sale of Triton Pipeline Colombia............ -- -- -- 97,656 --
Proceeds from sales of other assets....................... -- 1,465 2,353 22,353 1,822
Other..................................................... 128 2,026 600 (2,630) 617
--------- -------- --------- --------- ---------
Net cash provided (used) by investing activities... (163,070) (46,468) (118,530) 84,191 (212,700)
--------- -------- --------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving lines of credit and long-term
debt.................................................... -- -- -- 162,530 620,413
Payments on revolving lines of credit and long-term
debt.................................................... (4,529) (14,514) (19,028) (350,511) (321,515)
Short-term notes payable, net............................. -- -- -- (9,600) 9,600
Issuance of 8% preference shares, net..................... -- 217,805 217,805 115,329 --
Issuances of ordinary shares.............................. 10,935 100 419 2,544 5,260
Repurchase of ordinary shares............................. -- (9,685) (11,285) -- --
Dividends paid on preference shares....................... (14,682) (2,875) (17,617) (368) (400)
Other..................................................... (1,735) (3) (151) 5 10
--------- -------- --------- --------- ---------
Net cash provided (used) by financing activities... (10,011) 190,828 170,143 (80,071) 313,368
--------- -------- --------- --------- ---------
Effect of exchange rate changes on cash and equivalents..... (180) (139) (569) (280) (849)
--------- -------- --------- --------- ---------
Net increase in cash and equivalents........................ (107,072) 194,050 167,566 5,306 2,403
CASH AND EQUIVALENTS AT BEGINNING OF PERIOD................. 186,323 18,757 18,757 13,451 11,048
--------- -------- --------- --------- ---------
CASH AND EQUIVALENTS AT END OF PERIOD....................... $ 79,251 $212,807 $ 186,323 $ 18,757 $ 13,451
========= ======== ========= ========= =========
See accompanying Notes to Consolidated Financial Statements.
F-5
124
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
SIX MONTHS ENDED -----------------------------------------------------------------
JUNE 30, 2000 1999 1998 1997
-------------------- ------------------- --------------------- -------------------
(UNAUDITED)
OWNER SOURCES OF SHAREHOLDERS' EQUITY:
5% PREFERENCE SHARES:
Balance at beginning of period..... $ 7,214 $ 7,214 $ 7,511 $ 8,515
Conversion of 5% preference
shares........................... (839) -- (297) (1,004)
--------- --------- --------- ---------
Balance at end of period........... 6,375 7,214 7,214 7,511
--------- --------- --------- ---------
8% PREFERENCE SHARES:
Balance at beginning of period..... 363,555 127,575 -- --
Issuances of 8% preference
shares........................... -- 222,425 127,575 --
Conversion of 8% preference
shares........................... (611) (192) -- --
Stock dividends, 8% preference
shares........................... -- 13,747 -- --
--------- --------- --------- ---------
Balance at end of period........... 362,944 363,555 127,575 --
--------- --------- --------- ---------
ORDINARY SHARES:
Balance at beginning of period..... 358 366 365 363
Stock repurchase................... -- (9) -- --
Exercise of employee stock
options.......................... 6 1 1 2
--------- --------- --------- ---------
Balance at end of period........... 364 358 366 365
--------- --------- --------- ---------
ADDITIONAL PAID-IN CAPITAL:
Balance at beginning of period..... 531,904 575,863 588,454 582,581
Dividends, 5% preference shares.... (163) (361) (368) (400)
Dividends, 8% preference shares.... (14,519) (28,310) (2,693) --
Exercise of employee stock
options.......................... 10,929 418 2,548 3,831
Conversion of 5% preference
shares........................... 838 -- 297 1,004
Conversion of 8% preference
shares........................... 612 192 -- --
Transaction costs for issuance of
8% preference shares............. -- (4,620) (12,370) --
Stock repurchase................... -- (11,276) -- --
Other, net......................... -- (2) (5) 1,438
--------- --------- --------- ---------
Balance at end of period........... 529,601 531,904 575,863 588,454
--------- --------- --------- ---------
TREASURY SHARES:
Balance at beginning of period..... -- -- (3) (2)
Retirement and other, net.......... -- -- 3 (1)
--------- --------- --------- ---------
Balance at end of period........... -- -- -- (3)
--------- --------- --------- ---------
TOTAL OWNER SOURCES OF
SHAREHOLDERS' EQUITY......... 899,284 903,031 711,018 596,327
--------- --------- --------- ---------
NON-OWNER SOURCES OF SHAREHOLDERS'
EQUITY:
ACCUMULATED DEFICIT:
Balance at beginning of period..... (437,528) (485,085) (297,581) (288,685)
Net earnings (loss)................ 55,317 $55,317 47,557 $47,557 (187,504) $(187,504) (8,896) $(8,896)
--------- --------- --------- ---------
Balance at end of period........... (382,211) (437,528) (485,085) (297,581)
--------- --------- --------- ---------
ACCUMULATED OTHER NON-OWNER CHANGES
IN
SHAREHOLDERS' EQUITY:
Balance at beginning of period..... (2,451) (2,126) (2,126) (2,128)
Valuation reserve on marketable
securities....................... -- -- -- 2
Adjustment for minimum pension
liability........................ -- (325) -- --
------- ------- --------- -------
Other non-owner changes in
shareholders' equity............. -- -- (325) (325) -- -- 2 2
--------- ------- --------- ------- --------- --------- --------- -------
Non-owner changes in shareholders'
equity........................... $55,317 $47,232 $(187,504) $(8,894)
======= ======= ========= =======
Balance at end of period........... (2,451) (2,451) (2,126) (2,126)
--------- --------- --------- ---------
TOTAL NON-OWNER SOURCES OF
SHAREHOLDERS' EQUITY......... (384,662) (439,979) (487,211) (299,707)
--------- --------- --------- ---------
TOTAL SHAREHOLDERS' EQUITY..... $ 514,622 $ 463,052 $ 223,807 $ 296,620
========= ========= ========= =========
See accompanying Notes to Consolidated Financial Statements.
F-6
125
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS IN TABLES IN THOUSANDS, EXCEPT FOR SHARE, PER SHARE AND PER BARREL
DATA)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Triton Energy Limited ("Triton") is an international oil and gas
exploration and production company. The term "Company" when used herein means
Triton and its subsidiaries and other affiliates through which the Company
conducts its business. The Company's principal properties, operations, and oil
and gas reserves are located in Colombia, Malaysia-Thailand and Equatorial
Guinea. The Company is exploring for oil and gas in these areas, as well as in
southern Europe, Africa, and the Middle East. All sales are currently derived
from oil and gas production in Colombia.
Triton, a Cayman Islands company, was incorporated in 1995 to become the
parent holding company of Triton Energy Corporation, a Delaware corporation
("TEC"). On March 25, 1996, the stockholders of TEC approved the merger of a
wholly owned subsidiary of Triton with and into TEC (the "Reorganization").
Pursuant to the Reorganization, Triton became the parent holding company of TEC
and each share of common stock, par value $1.00, and 5% preferred stock of TEC
outstanding on March 25, 1996, was converted into one Triton ordinary share, par
value $.01, and one 5% Triton preference share, respectively. The Reorganization
has been accounted for as a combination of entities under common control.
Interim Financial Data
The unaudited consolidated financial statements as of June 30, 2000, and
for the six month periods ended June 30, 2000 and 1999, and all related footnote
information for these periods have been prepared on the same basis as the
audited financial statements and, in the opinion of management, include all
adjustments, consisting of normal recurring adjustments, necessary for a fair
statement of financial positions, results of operations and cash flows in
accordance with accounting principles generally accepted in the United States.
Principles of Consolidation
The consolidated financial statements include the accounts of Triton and
its majority-owned subsidiaries. All intercompany balances and transactions have
been eliminated in consolidation. Investments in 20%-to 50%-owned affiliates
which the Company exercises significant influence over operating and financial
policies are accounted for using the equity method. Investments in less than
20%-owned affiliates are accounted for using the cost method.
Cash Equivalents
Cash equivalents are highly liquid investments purchased with an original
maturity of three months or less.
Inventories
Inventories consist principally of oil produced but not sold, stated at
market value, and materials and supplies, stated at the lower of cost or market.
F-7
126
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Property and Equipment
The Company follows the full cost method of accounting for exploration and
development of oil and gas reserves, whereby all acquisition, exploration and
development costs are capitalized. Individual countries are designated as
separate cost centers. All capitalized costs plus the undiscounted estimated
future development costs of proved reserves are depleted using the
unit-of-production method based on total proved reserves applicable to each
country. A gain or loss is recognized on sales of oil and gas properties only
when the sale involves significant reserves.
Costs related to acquisition, holding and initial exploration of licenses
in countries with no proved reserves are initially capitalized, including
internal costs directly identified with acquisition, exploration and development
activities. Costs related to production, general overhead or similar activities
are expensed. The Company's exploration licenses are periodically assessed for
impairment on a country-by-country basis. If the Company's investment in
exploration licenses within a country where no proved reserves are assigned is
deemed to be impaired, the licenses are written down to estimated recoverable
value. If the Company abandons all exploration efforts in a country where no
proved reserves are assigned, all acquisition and exploration costs associated
with the country are expensed. Due to the unpredictable nature of exploration
drilling activities, the amount and timing of impairment expense are difficult
to predict with any certainty.
The net capitalized costs of oil and gas properties for each cost center,
less related deferred income taxes, cannot exceed the sum of (i) the estimated
future net revenues from the properties, discounted at 10%; (ii) unevaluated
costs not being amortized; and (iii) the lower of cost or estimated fair value
of unproved properties being amortized; less (iv) income tax effects related to
differences between the financial statement basis and tax basis of oil and gas
properties.
The estimated costs, net of salvage value, of dismantling facilities or
projects with limited lives or facilities that are required to be dismantled by
contract, regulation or law, and the estimated costs of restoration and
reclamation associated with oil and gas operations are included in estimated
future development costs as part of the amortizable base.
Support equipment and facilities are depreciated using the
unit-of-production method based on total reserves of the field related to the
support equipment and facilities. Other property and equipment, which includes
furniture and fixtures, vehicles and leasehold improvements, are depreciated
principally on a straight-line basis over estimated useful lives ranging from 3
to 20 years.
Repairs and maintenance are expensed as incurred, and renewals and
improvements are capitalized.
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.
Income Taxes
Deferred tax liabilities or assets are recognized for the anticipated
future tax effects of temporary differences between the financial statement
basis and the tax basis of the Company's assets and liabilities using the
enacted tax rates in effect at year end. A valuation allowance for deferred tax
assets is recorded when it is more likely than not that the benefit from the
deferred tax asset will not be realized.
F-8
127
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Revenue Recognition
Cost reimbursements arising from carried interests granted by the Company
are revenues to the extent the reimbursements are contingent upon and derived
from production. Obligations arising from net profit interest conveyances are
recorded as operating expenses when the obligation is incurred.
Foreign Currency Translation
The U.S. dollar is the designated functional currency for all of the
Company's foreign operations. The cumulative translation adjustment represents
the cumulative effect of translating the balance sheet accounts of Triton
Colombia, Inc. from the functional currency into U.S. dollars during the period
when the Colombian peso was the functional currency.
Risk Management
Oil and natural gas sold by the Company are normally priced with reference
to a defined benchmark, such as light, sweet crude oil traded on the New York
Mercantile Exchange (West Texas Intermediate or "WTI"). Actual prices received
vary from the benchmark depending on quality and location differentials. From
time to time, it is the Company's policy to use financial market transactions,
including swaps, collars and options, with creditworthy counterparties,
primarily to reduce risk associated with the pricing of a portion of the oil and
natural gas that it sells. The Company does not enter into financial market
transactions for trading purposes.
Gains or losses on financial market transactions that qualify for hedge
accounting are recognized in oil and gas sales at the time of settlement of the
underlying hedged transactions. Premiums paid for financial market contracts are
capitalized and amortized as operating expenses over the contract period.
Changes in the fair market value of financial market transactions that do not
qualify for hedge accounting are reflected as noncash adjustments to other
income (expense), net in the period the change occurs. Realized gains or losses
on financial market transactions that do not qualify for hedge accounting are
recorded in oil and gas sales.
Stock-Based Compensation
Statement of Financial Accounting Standards No. 123 ("SFAS 123"),
"Accounting for Stock-Based Compensation," encourages, but does not require, the
adoption of a fair value-based method of accounting for employee stock-based
compensation transactions. The Company has elected to apply the provisions of
Accounting Principles Board Opinion No. 25 ("Opinion 25"), "Accounting for Stock
Issued to Employees," and related interpretations, in accounting for its
stock-based compensation plans. Under Opinion 25, compensation cost is measured
as the excess, if any, of the quoted market price of the Company's stock at the
date of the grant above the amount an employee must pay to acquire the stock.
Earnings per Ordinary Share
Basic earnings (loss) per ordinary share amounts were computed by dividing
net earnings (loss) after deduction of dividends on preference shares by the
weighted average number of ordinary shares outstanding during the period.
Diluted earnings (loss) per ordinary share assumes the conversion of all
securities that are exercisable or convertible into ordinary shares that would
dilute the basic earnings per ordinary share during the period.
Comprehensive Income
Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income," established standards for the reporting and display of
comprehensive income and its components,
F-9
128
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
specifically net income and all other changes in shareholders' equity except
those resulting from investments by and distributions to shareholders. The
Company, which adopted the standard beginning January 1, 1998, has elected to
display comprehensive income (or non-owner changes in shareholders' equity) in
the Consolidated Statement of Shareholders' Equity.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board issued Statement No.
133 ("SFAS 133"), "Accounting for Derivative Instruments and Hedging
Activities." This statement, as amended in June 2000 by SFAS 138 "Accounting for
Certain Derivative Instruments and Certain Hedging Activities -- an Amendment of
SFAS 133," establishes accounting and reporting standards for derivative
instruments and for hedging activities. It requires enterprises to recognize all
derivatives as either assets or liabilities in the balance sheet and measure
those instruments at fair value. The requisite accounting for changes in the
fair value of a derivative will depend on the intended use of the derivative and
the resulting designation. The Company must adopt SFAS 133 and 138 effective
January 1, 2001. Based on the Company's outstanding derivatives contracts, the
Company believes that the impact of adopting this standard would not have a
material adverse effect on the Company's operations or consolidated financial
condition. However, no assurances can be given with regard to the level of the
Company's derivatives activities at the time SFAS 133 and 138 are adopted or the
resulting effect on the Company's operations or consolidated financial
condition.
The Use of Estimates in Preparing Financial Statements
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities,
disclosure of contingent assets and liabilities at the date of the financial
statements, and reported amounts of revenues and expenses during the reporting
period. Actual results could differ from these estimates.
Reclassifications
Certain previously reported financial information has been reclassified to
conform to the current period's presentation.
2. ASSET DISPOSITIONS
In December 1998, the Company sold its Bangladesh subsidiary for cash
proceeds of $4.5 million and recognized a gain of $4.5 million in gain on sale
of oil and gas assets.
In July 1998, the Company and Atlantic Richfield Company ("ARCO") signed an
agreement providing financing for the development of the Company's gas reserves
on Block A-18 of the Malaysia-Thailand Joint Development Area. Under terms of
the agreement, consummated in August 1998, the Company sold to a subsidiary of
ARCO for $150 million one-half of the shares of the subsidiary through which the
Company owned its 50% share of Block A-18. The Company received net proceeds of
$142 million and recorded a gain of $63.2 million in gain on the sale of oil and
gas assets. After the sale, which resulted in a 50% ownership in the previously
wholly owned subsidiary, the Company's remaining ownership is accounted for
using the equity method. This investment in Block A-18 is presented in
investment in affiliate at December 31, 1999 and 1998.
The agreements also require ARCO to pay the future exploration and
development costs attributable to the Company's and ARCO's collective interest
in Block A-18, up to $377 million or until first production from a gas field,
after which the Company and ARCO would each pay 50% of such costs.
F-10
129
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
There can be no assurance that the Company's and ARCO's collective share of the
cost of developing the project will not exceed $377 million. Additionally, the
agreements require ARCO to pay the Company an additional $65 million each at
July 1, 2002, and July 1, 2005, if certain specific development objectives are
met by such dates, or $40 million each if the objectives are met within one year
thereafter. There can be no assurance that the Company will receive any
incentive payments. The agreements provide that the Company will recover its
investment in recoverable costs in the project, approximately $100 million, and
that ARCO will recover its investment in recoverable costs, on a first-in,
first-out basis from the cost-recovery portion of future production.
In February 1998, the Company sold Triton Pipeline Colombia, Inc. ("TPC"),
a wholly owned subsidiary that held the Company's 9.6% equity interest in the
Colombian pipeline company, Oleoducto Central S.A. ("OCENSA"), to an unrelated
third party (the "Purchaser") for $100 million. Net proceeds were approximately
$97.7 million. The sale resulted in a gain of $50.2 million.
In conjunction with the sale of TPC, the Company entered into an equity
swap with a creditworthy financial institution (the "Counterparty"). The equity
swap has a notional amount of $97 million and requires the Company to make
quarterly floating LIBOR-based payments on the notional amount to the
Counterparty. In exchange, the Counterparty is required to make payments to the
Company equivalent to 97% of the dividends TPC receives in respect of its equity
interest in OCENSA. The equity swap is carried in the Company's financial
statements at fair value during its term, which, as amended, will expire April
14, 2000 (See note 24 -- Subsequent Events). The value of the equity swap in the
Company's financial statements is equal to 97% of the estimated fair value of
the shares of OCENSA owned by TPC. Because there is no public market for the
shares of OCENSA, the Company estimates their value using a discounted cash flow
model applied to the distributions expected to be paid in respect of the OCENSA
shares. The discount rate applied to the estimated cash flows from the OCENSA
shares is based on a combination of current market rates of interest, a credit
spread for OCENSA's debt, and a spread to reflect the preferred stock nature of
the OCENSA shares. During the years ended December 31, 1999 and 1998, the
Company recorded an expense of $6.9 million and $3.3 million, respectively, in
other income (expense), net, related to the net payments made under the equity
swap and its change in fair value. Net payments made (or received) under the
equity swap, and any fluctuations in the fair value of the equity swap, in
future periods, will affect other income in such periods. There can be no
assurance that changes in interest rates, or in other factors that affect the
value of the OCENSA shares and/or the equity swap, will not have a material
adverse effect on the carrying value of the equity swap.
Upon the expiration of the equity swap in April 2000, the Company expects
that the Purchaser will sell the TPC shares. Under the terms of the equity swap
with the Counterparty, upon any sale by the Purchaser of the TPC shares, the
Company will receive from the Counterparty, or pay to the Counterparty, an
amount equal to the excess or deficiency, as applicable, of the difference
between 97% of the net proceeds from the Purchaser's sale of the TPC shares and
the notional amount of $97 million. For example, if the Purchaser sold the TPC
shares for an amount equal to the value the Company has estimated for purposes
of preparing its balance sheet as of December 31, 1999, the Company would have
to make a payment to the Counterparty under the equity swap of approximately
$8.4 million. There can be no assurance that the value the Purchaser may realize
in any sale of the TPC shares will equal the value of the shares estimated by
the Company for purposes of valuing the equity swap. The Company has no right or
obligation to repurchase the TPC shares at any time, but the Company is not
prohibited from offering to purchase the shares if the Purchaser offers to sell
them. (See note 24 -- Subsequent Events.)
In June 1997, the Company sold its Argentine subsidiary for cash proceeds
of $4.1 million and recognized a gain of $4.1 million in gain on sale of oil and
gas assets.
F-11
130
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
3. WRITEDOWN OF ASSETS
Writedown of assets in 1998 is summarized as follows:
YEAR ENDED
DECEMBER 31,
1998
------------
Evaluated oil and gas properties (SEC ceiling test)..... $241,005
Unevaluated oil and gas properties...................... 73,890
Other assets............................................ 13,735
--------
$328,630
========
In June and December 1998, the carrying amount of the Company's evaluated
oil and gas properties in Colombia was written down by $105.4 million ($68.5
million, net of tax) and $135.6 million ($115.9 million, net of tax),
respectively, through application of the full cost ceiling limitation as
prescribed by the Securities and Exchange Commission ("SEC"), principally as a
result of a decline in oil prices. No adjustments were made to the Company's
reserves in Colombia as a result of the decline in prices. The SEC ceiling test
was calculated using the June 30, and December 31, 1998, WTI oil prices of
$14.18 per barrel and $12.05 per barrel, respectively, that, after a
differential for Cusiana crude delivered at the port of Covenas in Colombia,
resulted in a net price of approximately $13 per barrel and $11 per barrel,
respectively.
In conjunction with the plan to restructure operations and scale back
exploration-related expenditures, the Company assessed its investments in
exploration licenses and determined that certain investments were impaired. As a
result, unevaluated oil and gas properties and other assets totaling $77.3
million ($72.6 million, net of tax) were expensed in June 1998. The writedown
included $27.2 million and $22.5 million related to exploration activity in
Guatemala and China, respectively. The remaining writedowns related to the
Company's exploration projects in certain other areas of the world.
During 1998, the Company evaluated the recoverability of its approximate
6.6% investment in a Colombian pipeline company, Oleoducto de Colombia S.A.
("ODC"), which is accounted for under the cost method. Based on an analysis of
the future cash flows expected to be received from ODC, the Company expensed the
carrying value of its investment totaling $10.3 million.
4. SPECIAL CHARGES
In September 1999, the Company recognized special charges totaling $2.4
million related to the transfer of its working interest in Ecuador to a third
party.
In July 1998, the Company commenced a plan to restructure the Company's
operations, reduce overhead costs and substantially scale back
exploration-related expenditures. The plan contemplated the closing of foreign
offices in four countries, the elimination of approximately 105 positions, or
41% of the worldwide workforce, and the relinquishment or other disposal of
several exploration licenses. As a result of the restructuring, the Company
recognized special charges of $15 million during the third quarter of 1998 and
$3.3 million during the fourth quarter of 1998 for a total of $18.3 million. Of
the $18.3 million in special charges, $14.5 million related to the reduction in
workforce, and represented the estimated costs for severance, benefit
continuation and outplacement costs, which will be paid over a period of up to
two years according to the severance formula. Since July 1998, the Company has
paid $13.1 million in severance, benefit continuation and outplacement costs. A
total of $2.1 million of special charges related to the closing of foreign
offices, and represented the estimated costs of terminating office leases and
the write-off of related assets. The remaining special charges of $1.7 million
primarily related to the write-off of other surplus fixed assets resulting from
the reduction in workforce. At December 31, 1999, all of the
F-12
131
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
positions had been eliminated, all designated foreign offices had closed and all
licenses had been relinquished, sold or their commitments renegotiated. During
the fourth quarter of 1999, the Company reversed $.7 million of the accrual
associated with the completion of restructuring activities. The remaining
liability related to the restructuring activities undertaken in 1998 was $1
million at December 31, 1999.
In March 1999, the Company accrued special charges of $1.2 million related
to an additional 15% reduction in the number of employees resulting from the
Company's continuing efforts to reduce costs. The special charges consisted of
$1 million for severance, benefit continuation and outplacement costs and $.2
million related to the write-off of surplus fixed assets. Since March 1999, the
Company has paid $.9 million in severance, benefit continuation and outplacement
costs. At December 31, 1999, the remaining liability related to the
restructuring activities undertaken in 1999 was $.1 million.
5. OTHER RECEIVABLES
Other receivables consisted of the following:
DECEMBER 31,
------------------
1999 1998
------- -------
Receivables from and advances to partners and others........ $10,684 $ 2,007
Receivable from financial market transactions............... 4,861 180
Receivable from insurance................................... 2,300 7,800
Receivable from the forward oil sale........................ 1,081 31,932
Other....................................................... 4,888 5,837
------- -------
$23,814 $47,756
======= =======
6. PROPERTY AND EQUIPMENT
Property and equipment, at cost, are summarized as follows:
DECEMBER 31,
--------------------
1999 1998
-------- --------
Oil and gas properties, full cost method:
Evaluated................................................. $560,240 $543,514
Unevaluated............................................... 78,527 70,836
Support equipment and facilities.......................... 303,953 289,659
Other....................................................... 17,535 18,790
-------- --------
960,255 922,799
Less accumulated depreciation and depletion................. 436,103 451,892
-------- --------
$524,152 $470,907
======== ========
The Company capitalized general and administrative expenses related to
exploration and development activities of $6.9 million, $20.6 million and $32.4
million in the years ended December 31, 1999, 1998 and 1997, respectively.
F-13
132
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
7. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
Accounts payable and accrued liabilities are summarized as follows:
DECEMBER 31,
------------------
1999 1998
------- -------
Colombian income taxes...................................... $14,471 $ --
Accrued exploration and development......................... 9,762 3,774
Equity swap................................................. 8,435 --
Accrued interest payable.................................... 7,864 8,160
Taxes other than income..................................... 7,713 2,970
Litigation and environmental matters........................ 3,872 2,064
Accrued special charges..................................... 1,246 7,869
Accounts payable, principally trade......................... 1,242 9,136
Dividends payable........................................... -- 2,693
Other....................................................... 7,971 8,307
------- -------
$62,576 $44,973
======= =======
8. DEFERRED INCOME AND OTHER
In May 1995, the Company sold 10.4 million barrels of oil from the Cusiana
and Cupiagua fields in Colombia in a forward oil sale. Under the terms of the
sale, the Company received approximately $87 million of the approximately $124
million net proceeds. In 1999, the Company received substantially all of the
remaining proceeds totaling approximately $31.9 million. The Company has
recorded the net proceeds as deferred income and recognizes such revenue when
the barrels of oil are delivered during the five-year period that began in June
1995. Under the terms of the agreement, the Company must deliver to the buyer
58,425 barrels per month through March 1997 and 254,136 barrels per month from
April 1997 to March 2000. At December 31, 1999 and 1998, $8.8 million and $35.3
million, respectively, were recorded as deferred income and included in current
liabilities.
During 1999, the Company acquired the Colombian entity of its former
partner in the El Pinal field. In addition to the working interest in the El
Pinal field, the acquired entity has tax basis and net operating loss
carryforwards ("NOLs") totaling approximately $40 million, which the Company
expects to utilize in 2000. At December 31, 1999, the tax affected amount of the
tax basis and NOLs ($14.2 million) was included in current assets as a deferred
tax asset. In addition, the Company recorded deferred income of $10.6 million,
representing the difference between the value of the deferred tax asset and the
purchase price. During 2000, the deferred tax asset and the deferred income will
be reduced as the tax basis and NOLs are utilized.
F-14
133
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. DEBT
A summary of long-term debt follows:
DECEMBER 31,
-------------------
1999 1998
-------- --------
Senior Notes due 2005....................................... $200,000 $200,000
Senior Notes due 2002....................................... 199,947 199,924
Term credit facility maturing 2001.......................... 13,540 22,568
Revolving credit facility maturing 1999..................... -- 5,000
-------- --------
413,487 427,492
Less current maturities..................................... 9,027 14,027
-------- --------
$404,460 $413,465
======== ========
In April 1997, the Company issued $400 million aggregate face value of
senior indebtedness to refinance other indebtedness. The senior indebtedness
consisted of $200 million face amount of 8 3/4% Senior Notes due April 15, 2002
(the "2002 Notes"), at 99.942% of the principal amount (resulting in $199.9
million aggregate net proceeds) and $200 million face amount of 9 1/4% Senior
Notes due April 15, 2005 (the "2005 Notes" and, together with the 2002 Notes,
the "Senior Notes"), at 100% of the principal amount, for total aggregate net
proceeds of $399.9 million before deducting transaction costs of approximately
$1 million.
Interest on the Senior Notes is payable semi-annually on April 15 and
October 15. The Senior Notes are redeemable at any time at the option of the
Company, in whole or in part, and contain certain covenants limiting the
incurrence of certain liens, sale/leaseback transactions, and mergers and
consolidations.
In November 1995, a subsidiary signed an unsecured term credit facility
with a bank supported by a guarantee issued by the Export-Import Bank of the
United States ("EXIM") for $45 million, which matures in January 2001. Principal
and interest payments are due semi-annually on January 15 and July 15 and
borrowings bear interest at LIBOR plus .25%, adjusted on a semi-annual basis. At
December 31, 1999, the Company had outstanding borrowings of $13.5 million under
the facility.
In February 2000, the Company entered into an unsecured two-year revolving
credit facility with a group of banks, which matures in February 2002. The
credit facility gives the Company the right to borrow from time to time up to
the amount of the borrowing base determined by the banks, not to exceed $150
million. As of February 2000, the borrowing base was $150 million. The credit
facility contains various restrictive covenants, including covenants that
require the Company to maintain a ratio of earnings before interest,
depreciation, depletion, amortization and income taxes to net interest expense
of at least 2.5 to 1, and that prohibit the Company from permitting net debt to
exceed the product of 3.75 times the Company's earnings before interest,
depreciation, depletion, amortization and income taxes, in each case, on a
trailing four quarters basis.
The Company capitalizes interest on qualifying assets, principally
unevaluated oil and gas properties, major development projects in progress and
investments accounted for by the equity method while the investee has activities
in progress necessary to commence its principle operations. Capitalized interest
amounted to $14.5 million, $23.2 million and $25.8 million in the years ended
December 31, 1999, 1998 and 1997, respectively.
The Company amortizes debt issue costs over the life of the borrowing using
the interest method. Amortization related to the Company's debt issue costs was
$.5 million, $2.9 million and $2 million in the years ended December 31, 1999,
1998 and 1997, respectively. The aggregate maturities of long-term debt
F-15
134
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
for the five years during the period ending December 31, 2004, are as follows:
2000 -- $9 million; 2001 -- $4.5 million; 2002 -- $199.9 million; 2003 -- nil;
and 2004 -- nil.
10. INCOME TAXES
The components of earnings (loss) from continuing operations before income
taxes and extraordinary item were as follows:
YEAR ENDED DECEMBER 31,
-------------------------------
1999 1998 1997
-------- --------- --------
Cayman Islands...................................... $(35,907) $ 82,995 $(12,969)
United States....................................... (7,810) (24,003) (31,694)
Foreign -- other.................................... 119,894 (297,601) 61,559
-------- --------- --------
$ 76,177 $(238,609) $ 16,896
======== ========= ========
Pursuant to the Reorganization in March 1996, Triton, a Cayman Islands
company, became the parent holding company of TEC, a Delaware corporation. As a
result, the Company's corporate domicile became the Cayman Islands.
The components of the provision for income taxes on continuing operations
were as follows:
YEAR ENDED DECEMBER 31,
----------------------------
1999 1998 1997
------- -------- -------
Current:
Cayman Islands....................................... $ -- $ -- $ --
United States........................................ -- -- (7)
Foreign -- other..................................... 20,793 4,487 3,230
------- -------- -------
Total current................................ 20,793 4,487 3,223
------- -------- -------
Deferred:
Cayman Islands....................................... -- -- --
United States........................................ (1,410) 1,457 (7,929)
Foreign -- other..................................... 9,237 (57,049) 16,007
------- -------- -------
Total deferred............................... 7,827 (55,592) 8,078
------- -------- -------
Total........................................ $28,620 $(51,105) $11,301
======= ======== =======
F-16
135
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A reconciliation of the differences between the Company's applicable
statutory tax rate and the Company's effective income tax rate follows:
YEAR ENDED DECEMBER 31,
------------------------
1999 1998 1997
----- ----- ------
Tax provision at statutory tax rate........................ 0.0% 0.0% 0.0%
Increase (decrease) resulting from:
Net change in valuation allowance........................ (15.7) 3.9 263.0
Foreign items without tax benefit........................ 18.9 (34.9) 77.8
Income subject to tax in excess of statutory rate........ 36.6 32.6 36.9
Current year change in NOL/credit carryforwards.......... (7.6) (4.8) (356.7)
Temporary differences:
Oil and gas basis adjustments......................... 3.3 25.7 32.5
Reimbursement of pre-commerciality costs.............. 2.3 (1.1) 13.2
Other.................................................... (0.2) -- 0.2
----- ----- ------
37.6% 21.4% 66.9%
===== ===== ======
The components of the net deferred tax asset and liability were as follows:
DECEMBER 31, 1999 DECEMBER 31, 1998
------------------------------ ------------------------------
OTHER OTHER
U.S. COLOMBIA FOREIGN U.S. COLOMBIA FOREIGN
-------- -------- -------- -------- -------- --------
Deferred tax asset:
Net operating loss
carryforwards....................... $157,558 $20,090 $ 9,832 $145,475 $ 7,992 $ 7,219
Depreciable/depletable property....... 1,748 8,778 -- 1,252 27,730 --
Credit carryforwards.................. 2,048 -- -- 1,731 6,813 --
Reserves.............................. 819 -- -- 2,502 -- --
Other................................. 176 -- -- 1,505 -- --
-------- ------- -------- -------- -------- --------
Gross deferred tax asset................ 162,349 28,868 9,832 152,465 42,535 7,219
Valuation allowances.................... (72,908) (8,778) -- (65,881) (27,730) --
-------- ------- -------- -------- -------- --------
Net deferred tax asset.................. 89,441 20,090 9,832 86,584 14,805 7,219
-------- ------- -------- -------- -------- --------
Deferred tax liability:
Depreciable/depletable property....... -- -- (16,509) -- -- (10,454)
Other................................. (1,213) -- -- (473) -- --
-------- ------- -------- -------- -------- --------
Net deferred tax asset (liability)...... 88,228 20,090 (6,677) 86,111 14,805 (3,235)
Less current deferred tax asset
(liability)........................... -- 20,090 -- -- -- --
-------- ------- -------- -------- -------- --------
Noncurrent deferred tax asset
(liability)........................... $ 88,228 $ -- $ (6,677) $ 86,111 $ 14,805 $ (3,235)
======== ======= ======== ======== ======== ========
F-17
136
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
At December 31, 1999, the Company had NOLs and depletion carryforwards for
U.S. tax purposes of $450.2 million and $20.3 million, respectively. The U.S.
NOLs expire from 2000 through 2020 as follows:
NOLS
EXPIRING
BY YEAR
--------
May 2000.................................................. $ 19,571
May 2001.................................................. 30,389
May 2002.................................................. 22,702
May 2003.................................................. 20,566
May 2004.................................................. 8,263
May 2005-May 2020......................................... 348,675
--------
$450,166
========
At December 31, 1999, the Company's Colombian operations and other foreign
operations had NOLs and other credit carryforwards totaling $57.4 million and
$40.7 million, respectively. The NOLs expire from 2001 through 2004.
The deferred tax valuation allowance of $81.7 million at December 31, 1999,
is primarily attributable to management's assessment of the utilization of NOLs
in the U.S., the expectation that other tax credits will expire without being
utilized, and certain temporary differences will reverse without a benefit to
the Company. The minimum amount of future taxable income necessary to realize
the deferred tax asset is approximately $252 million and $57 million in the U.S.
and Colombia, respectively. Although there can be no assurance the Company will
achieve such levels of income, management believes the deferred tax asset will
be realized through income from its operations.
If certain changes in the Company's ownership should occur, there would be
an annual limitation on the amount of U.S. NOLs that can be utilized. To the
extent a change in ownership does occur, the limitation is not expected to
materially impact the utilization of such carryforwards.
F-18
137
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
11. EMPLOYEE BENEFITS
Pension Plans
The Company has a defined benefit pension plan covering substantially all
employees in the United States. The benefits are based on years of service and
the employee's final average monthly compensation. Contributions are intended to
provide for benefits attributed to past and future services. The Company also
has a Supplemental Executive Retirement Plan ("SERP") that is unfunded and
provides supplemental pension benefits to a select group of management and key
employees.
The funding status of the plans follows:
DECEMBER 31,
-------------------------------------
1999 1998
----------------- -----------------
DEFINED DEFINED
BENEFIT SERP BENEFIT SERP
PLAN PLAN PLAN PLAN
------- ------- ------- -------
Change in benefit obligation:
Benefit obligation at beginning of year....... $ 6,435 $ 6,579 $6,008 $ 6,621
Service cost.................................. 392 537 560 799
Interest cost................................. 421 435 438 607
Amendments.................................... -- -- -- 434
Actuarial loss/(gain)......................... (750) 1,465 472 913
Benefits paid................................. (531) (1,385) (377) (1,617)
Curtailment gain.............................. -- -- (666) (1,178)
------- ------- ------ -------
Benefit obligation at end of year............. 5,967 7,631 6,435 6,579
------- ------- ------ -------
Change in plan assets:
Fair value of plan assets at beginning of
year....................................... 7,068 -- 5,531 --
Actual return on plan assets.................. 1,971 -- 1,446 --
Company contribution.......................... 480 1,385 468 1,617
Benefits paid................................. (531) (1,385) (377) (1,617)
------- ------- ------ -------
Fair value of plan assets at end of year...... 8,988 -- 7,068 --
------- ------- ------ -------
Reconciliation:
Funded status................................. 3,021 (7,631) 633 (6,579)
Unrecognized actuarial (gain)/loss............ (2,999) 1,945 (908) 480
Unrecognized transition (asset)/obligation.... (6) 527 (8) 695
Unrecognized prior service cost............... 317 226 373 253
------- ------- ------ -------
Prepaid/(accrued) pension cost................ 333 (4,933) 90 (5,151)
------- ------- ------ -------
Adjustment for minimum liability.............. -- (1,255) -- --
------- ------- ------ -------
Adjusted prepaid/(accrued) pension cost......... $ 333 $(6,188) $ 90 $(5,151)
======= ======= ====== =======
The adjustment required to recognize the minimum liability for the SERP
plan at December 31, 1999, resulted in the recognition of $.8 million as an
intangible asset and $.5 million ($.3 million net of tax) as a charge to
accumulated other non-owner changes in shareholder's equity.
F-19
138
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A summary of the components of pension expense follows:
YEAR ENDED DECEMBER 31,
------------------------
1999 1998 1997
------ ------ ------
Components of net periodic pension cost:
Service cost............................................. $ 929 $1,359 $ 832
Interest cost............................................ 856 1,045 783
Expected return on plan assets........................... (618) (481) (416)
Recognized net actuarial loss/(gain)..................... (12) -- --
Amortization of transition obligation.................... 166 591 166
Amortization of prior service cost....................... 83 538 67
------ ------ ------
Net periodic pension cost.................................. $1,404 $3,052 $1,432
====== ====== ======
The projected benefit obligations at December 31, 1999 and 1998, assume a
discount rate of 7.75% and 6.75%, respectively, and a rate of increase in
compensation expense of 5%. The expected long-term rate of return on assets is
9% for the defined benefit plan. During 1998, work-force reductions resulted in
the recognition of additional prior service cost of $.2 million each for the
defined benefit plan and the SERP plan and additional transition obligation of
$.4 million for the SERP plan.
Employee Stock Ownership Plan
Effective January 1, 1994, the Company amended and restated the employee
stock ownership plan to form a 401(k) plan (the "Plan"). The Company recognizes
expense based on actual amounts contributed to the Plan. The cost recognized for
the Plan was $.2 million, $.6 million and $.6 million for the years ended
December 31, 1999, 1998 and 1997, respectively.
12. SHAREHOLDERS' EQUITY
5% Convertible Preference Shares
In connection with the acquisition of the minority interest in Triton
Europe in 1994, the Company designated a series of 550,000 preferred shares
(522,460 shares issued) as 5% Preferred Stock, no par value, with a stated value
of $34.41 per share. Pursuant to the Reorganization, Triton converted each share
of 5% Preferred Stock into one 5% Convertible Preference Share, par value $.01.
Each share of the Company's 5% Convertible Preference Shares is convertible into
one Triton ordinary share and bears a cash dividend, which has priority over
dividends on Triton's ordinary shares, equal to 5% per annum on the redemption
price of $34.41 per share, payable semi-annually on March 30 and September 30 of
each year. The 5% Convertible Preference Shares have priority over Triton
ordinary shares upon liquidation, and may be redeemed at Triton's option at any
time on or after March 30, 1998, for cash equal to the redemption price. Any
shares that remain outstanding on March 30, 2004, must be redeemed at the
redemption price, either for cash or, at the Company's option, for Triton
ordinary shares. At December 31, 1999 and 1998, there were 209,639 5%
Convertible Preference Shares outstanding and at December 31, 1997, there were
218,285 shares outstanding. (See note 24 -- Subsequent Events.)
8% Convertible Preference Shares
In August 1998, the Company and HM4 Triton, L.P., an affiliate of Hicks,
Muse, Tate & Furst Incorporated ("Hicks Muse"), entered into a stock purchase
agreement (the "Stock Purchase Agreement") that provided for a $350 million
equity investment in the Company. The investment was effected in two stages. At
the closing of the first stage in September 1998 (the "First Closing"), the
Company issued to HM4 Triton, L.P. 1,822,500 shares of 8% Convertible Preference
Shares for $70 per
F-20
139
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
share (for proceeds of $116.8 million, net of transaction costs). Pursuant to
the Stock Purchase Agreement, the second stage was effected through a rights
offering for 3,177,500 shares of 8% Convertible Preference Shares at $70 per
share, with HM4 Triton, L.P. being obligated to purchase any shares not
subscribed. At the closing of the second stage, which occurred on January 4,
1999 (the "Second Closing"), the Company issued an additional 3,177,500 8%
Convertible Preference Shares for proceeds totaling $217.8 million, net of
closing costs (of which, HM4 Triton, L.P. purchased 3,114,863 shares).
Each 8% Convertible Preference Share is convertible at any time at the
option of the holder into four ordinary shares of the Company (subject to
certain antidilution protections). Holders of 8% Convertible Preference Shares
are entitled to receive, when and if declared by the Board of Directors,
cumulative dividends at a rate per annum equal to 8% of the liquidation
preference of $70 per share, payable for each semi-annual period ending June 30
and December 30 of each year. At the Company's option, dividends may be paid in
cash or by the issuance of additional whole shares of 8% Convertible Preference
Shares. If a dividend is to be paid in additional shares, the number of
additional shares to be issued in payment of the dividend will be determined by
dividing the amount of the dividend by $70, with amounts in respect of any
fractional shares to be paid in cash. The first dividend period was the period
from January 4, 1999, to June 30, 1999. The Company's Board of Directors elected
to pay the dividend for that period in additional shares resulting in the
issuance of 196,388 8% Convertible Preference Shares. The dividend for the
period July 1, 1999 to December 31, 1999 was paid in cash. The declaration of a
dividend in cash or additional shares for any period should not be considered an
indication as to whether the Board will declare dividends in cash or additional
shares in future periods. Holders of 8% Convertible Preference Shares are
entitled to vote with the holders of ordinary shares on all matters submitted to
the shareholders of the Company for a vote, with each 8% Convertible Preference
Share entitling its holder to a number of votes equal to the number of ordinary
shares into which it could be converted at that time. At December 31, 1999 and
1998, 5,193,643 and 1,822,500 8% Convertible Preference Shares were outstanding,
respectively.
Ordinary Shares
Changes in issued ordinary shares were as follows:
YEAR ENDED DECEMBER 31,
------------------------------------
1999 1998 1997
---------- ---------- ----------
Balance at beginning of year..................... 36,643,478 36,541,064 36,342,181
Share repurchase............................... (948,300) -- --
Issuances under stock plans.................... 49,367 46,648 35,961
Conversion of 8% preference shares............. 10,980 -- --
Exercise of employee stock options............. 8,213 47,238 83,736
Conversion of 5% preference shares............. -- 8,646 29,184
Other, net..................................... (10) (118) 50,002
---------- ---------- ----------
Balance at end of year........................... 35,763,728 36,643,478 36,541,064
========== ========== ==========
Changes in ordinary shares held in treasury were as follows:
YEAR ENDED
DECEMBER 31,
-------------
1998 1997
----- -----
Balance at beginning of year................................ 73 40
Purchase of treasury shares............................... 64 33
Retirement of treasury shares............................. (137) --
---- --
Balance at end of year...................................... -- 73
==== ==
F-21
140
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Share Repurchase
In April 1999, the Company's Board of Directors authorized a share
repurchase program enabling the Company to repurchase up to ten percent of the
Company's then outstanding 36.7 million ordinary shares. Purchases of ordinary
shares by the Company began in April and may be made from time to time in the
open market or through privately negotiated transactions at prevailing market
prices depending on market conditions. The Company has no obligation to
repurchase any of its outstanding shares and may discontinue the share
repurchase program at management's discretion. As of December 31, 1999, the
Company had purchased 948,300 ordinary shares for $11.3 million. The Company
canceled and returned the repurchased ordinary shares to the status of
authorized but unissued shares. The Company's revolving credit facility entered
into in February 2000, generally does not permit the Company to repurchase its
ordinary shares without the bank's consent.
Shareholder Rights Plan
The Company has adopted a Shareholder Rights Plan pursuant to which
preference share rights attach to all ordinary shares at the rate of one right
for each ordinary share. Each right entitles the registered holder to purchase
from the Company one one-thousandth of a Series A Junior Participating
Preference Share, par value $.01 per share ("Junior Preference Shares"), of the
Company at a price of $120 per one one-thousandth of a share of such Junior
Preference Shares, subject to adjustment. Generally, the rights only become
distributable 10 days following public announcement that a person has acquired
beneficial ownership of 15% or more of Triton's ordinary shares or 10 business
days following commencement of a tender offer or exchange offer for 15% or more
of the outstanding ordinary shares; provided that, pursuant to the terms of the
plan, any acquisition of Triton shares by HM4 Triton, L.P. or its affiliates,
including Hicks, Muse, Tate & Furst Incorporated, will not result in the
distribution of rights unless and until HM4 Triton, L.P.'s ownership of Triton
shares is reduced below certain levels.
If, among other events, any person becomes the beneficial owner of 15% or
more of Triton's ordinary shares (except as provided with respect to HM4 Triton,
L.P.), each right not owned by such person generally becomes the right to
purchase a number of ordinary shares of the Company equal to the number obtained
by dividing the right's exercise price (currently $120) by 50% of the market
price of the ordinary shares on the date of the first occurrence. In addition,
if the Company is subsequently merged or certain other extraordinary business
transactions are consummated, each right generally becomes a right to purchase a
number of shares of common stock of the acquiring person equal to the number
obtained by dividing the right's exercise price by 50% of the market price of
the common stock on the date of the first occurrence.
Under certain circumstances, the Company's directors may determine that a
tender offer or merger is fair to all shareholders and prevent the rights from
being exercised. At any time after a person or group acquires 15% or more of the
ordinary shares outstanding (other than with respect to HM4 Triton, L.P.) and
prior to the acquisition by such person or group of 50% or more of the
outstanding ordinary shares or the occurrence of an event described in the prior
paragraph, the Board of Directors of the Company may exchange the rights (other
than rights owned by such person or group which will become void), in whole or
in part, at an exchange ratio of one ordinary share, or one one-thousandth of a
Junior Preference Share, per right (subject to adjustment). The Company has the
ability to amend the rights (except the redemption price) in any manner prior to
the public announcement that a 15% position has been acquired or a tender offer
has been commenced. The Company will be entitled to redeem the rights at $0.01 a
right at any time prior to the time that a 15% position has been acquired. The
rights will expire on May 22, 2005, unless earlier redeemed by the Company.
F-22
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
13. STOCK COMPENSATION PLANS
Stock Option Plans
Options to purchase ordinary shares of the Company may be granted to
officers and employees under various stock option plans. The exercise price of
each option is equal to or greater than the market price of the Company's
ordinary shares on the date of grant. Grants generally become exercisable in 25%
or 33% cumulative annual increments beginning one year from the date of issuance
and generally expire during a period from 5 to 10 years after the date of grant,
depending on terms of the grant. In addition, each non-employee director
receives an option to purchase 15,000 shares each year. These grants become
exercisable at the date of the grant and expire at the end of 10 years. At
December 31, 1999 and 1998, shares available for grant were 1,019,021 and
2,521,133, respectively.
A summary of the status of the Company's stock option plans is presented
below:
DECEMBER 31, 1999 DECEMBER 31, 1998 DECEMBER 31, 1997
-------------------- --------------------- --------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
--------- -------- ---------- -------- --------- --------
Outstanding at beginning of year........... 4,057,207 $26.51 4,449,435 $39.05 3,854,046 $38.81
Granted.................................... 2,150,000 14.03 2,894,603 20.56 744,250 39.99
Exercised.................................. (8,213) 10.57 (47,238) 29.30 (83,736) 30.76
Canceled................................... (351,138) 29.24 (3,239,593) 38.39 (65,125) 46.09
--------- ---------- ---------
Outstanding at end of year................. 5,847,856 21.78 4,057,207 26.51 4,449,435 39.05
========= ========== =========
Options exercisable at year-end............ 3,121,601 2,804,584 2,728,254
Weighted average fair value of options:
Granted at market prices................. $ 2.71 $ 6.12 $ 16.37
Granted at greater than market prices.... 4.93 2.84 --
On December 2, 1998, the Compensation Committee approved the grant of new
stock options totaling 440,103 shares with an exercise price of $14.50 to
substantially all of its employees. Each participating employee was granted
options in an amount equal to one-half of any options then held by the employees
with an exercise price greater than $30.00 per share and the options with an
exercise price greater than $30.00 per share expired.
The following table summarizes information about stock options outstanding
at December 31, 1999:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------------- -------------------------
WEIGHTED
RANGE AVERAGE WEIGHTED WEIGHTED
OF NUMBER REMAINING AVERAGE NUMBER AVERAGE
EXERCISE OUTSTANDING AT CONTRACTUAL EXERCISE EXERCISABLE AT EXERCISE
PRICES DEC. 31, 1999 LIFE PRICE DEC. 31, 1999 PRICE
- ------------ -------------- ----------- -------- -------------- --------
$ 6.94-14.50 2,904,852 4.9 years $14.10 657,773 $12.75
16.81-29.50 1,607,932 3.9 years 20.52 1,150,006 21.64
31.75-39.63 667,072 2.4 years 34.10 667,072 34.10
40.25-52.25 668,000 3.6 years 45.86 646,750 46.04
--------- ---------
5,847,856 3,121,601
========= =========
Employee Stock Purchase Plan
The Company has an employee stock purchase plan that provides for the award
of ordinary shares to officers and employees. Under the terms of the plan,
employees can choose each semi-annual period to
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
have up to 15% of their annual gross or base compensation withheld to purchase
the Company's ordinary shares. The purchase price of the stock is 85% of the
lower of its beginning of period or end of period market price. Under the plan,
the Company sold 49,367 shares and 46,648 shares to employees for the years
ended December 31, 1999 and 1998, respectively.
Fair Value of Stock Compensation
The Company applies Opinion 25 in accounting for its plans. Accordingly, no
compensation cost has been recognized for its fixed stock option plans and stock
purchase plan. Had the Company elected to recognize compensation expense
consistent with the fair value-based methodology in SFAS 123, the Company's net
income (loss) and earnings (loss) per share would have been as follows:
YEAR ENDED DECEMBER 31,
------------------------------
1999 1998 1997
------- --------- --------
Net earnings (loss) applicable to ordinary shares:
As reported........................................ $18,886 $(190,565) $ (9,296)
Pro forma.......................................... 12,579 (200,147) (16,802)
Basic earnings (loss) per ordinary share:
As reported........................................ $ 0.52 $ (5.21) $ (0.26)
Pro forma.......................................... 0.35 (5.47) (0.46)
Diluted earnings (loss) per ordinary share:
As reported........................................ $ 0.52 $ (5.21) $ (0.25)
Pro forma.......................................... 0.35 (5.47) (0.46)
The fair value of each option granted was estimated on the date of grant
using the Black-Scholes option-pricing model with the following weighted average
assumptions used for grants in 1999, 1998 and 1997: dividend yield of 0%;
expected volatility of approximately 54%, 40% and 26%, respectively; risk-free
interest rates of approximately 6%, 5% and 6%, respectively; and an expected
life of approximately three to seven years.
Stock Appreciation Rights Plan
The Company had a stock appreciation rights ("SARs") plan which granted
SARs to non-employee directors of the Company. Upon exercise, SARs allow the
holder to receive the difference between the SARs' exercise price and the fair
market value of the ordinary shares covered by SARs on the exercise date and
expire at the earlier of 10 years or a date based on the termination of the
holder's membership on the board of directors. At December 31, 1999, SARs
covering 20,000 ordinary shares, with an exercise price of $8.00 per share, were
outstanding.
14. FAIR VALUE OF FINANCIAL INSTRUMENTS, RISK MANAGEMENT AND CREDIT RISK
CONCENTRATIONS
Fair Value of Financial Instruments
At December 31, 1999 and 1998, the Company's financial instruments included
cash and equivalents, short-term receivables, long-term receivables, short-term
and long-term debt, and financial market transactions. The fair value of cash,
cash equivalents, short-term receivables and short-term debt approximated
carrying values because of the short maturities of these instruments. The fair
values of the Company's long-term receivables and financial market transactions,
based on broker quotes and discounted cash flows, approximated the carrying
values. The estimated fair value of long-term debt, based on quoted market
prices and market data for similar instruments, was $416 million (carrying
value -- $413 million) and $397 million (carrying value -- $428 million) at
December 31, 1999 and 1998, respectively.
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Risk Management
Oil and natural gas sold by the Company are normally priced with reference
to a defined benchmark, such as light, sweet crude oil traded on the New York
Mercantile Exchange (WTI). Actual prices received vary from the benchmark
depending on quality and location differentials. From time to time, it is the
Company's policy to use financial market transactions, including swaps, collars
and options, with creditworthy counterparties primarily to reduce risk
associated with the pricing of a portion of the oil and natural gas that it
sells. The policy is structured to underpin the Company's planned revenues and
results of operations. The Company does not enter into financial market
transactions for trading purposes. There can be no assurance that the use of
financial market transactions will not result in losses.
During the years ended December 31, 1999 and 1997, markets provided the
Company the opportunity to realize WTI benchmark oil prices on average $6.37 per
barrel and $2.35 per barrel, respectively, above the WTI benchmark oil price the
Company set as part of its annual plan for the period. During the year ended
December 31, 1998, the Company did not have any outstanding financial market
transactions to hedge against oil price fluctuations. As a result of financial
and commodity market transactions settled during the years ended December 31,
1999 and 1997, the Company's risk management program resulted in an average net
realization of approximately $1.65 per barrel and $.11 per barrel, respectively,
lower than if the Company had not entered into such transactions.
In anticipation of entering into the forward oil sale, in 1995 the Company
purchased WTI benchmark call options to retain the ability to benefit from WTI
price increases above a weighted average price of $20.42 per barrel. The volumes
and expiration dates on the call options coincide with the volumes and delivery
dates of the forward oil sale which will be completed in March 2000. During the
years ended December 31, 1999, 1998 and 1997, the Company recorded a gain (loss)
of $6.1 million, $.4 million, and ($9.7 million), respectively, in other income
(expense), net, related to the change in the fair market value of the call
options. In November 1999, the Company sold WTI benchmark call options with the
same notional quantities, strike price and contract period as the remaining call
option contracts outstanding for a premium of $4.4 million for the purpose of
realizing the fair value of the purchased call options. As a result, the Company
has eliminated its exposure to future changes in value of the call options
caused by fluctuations in oil prices.
Concentration of Credit Risk
Financial instruments that are potentially subject to concentrations of
credit risk consist of cash equivalents, receivables and financial market
transactions. The Company places its cash equivalents and financial market
transactions with high credit-quality financial institutions. The Company
believes the risk of incurring losses related to credit risk is remote.
The Company sells its crude oil production from the Cusiana and Cupiagua
fields through an agreement with a third party to approximately 10 to 15 buyers
located primarily in the United States. The Company does not believe that the
loss of any single customer or a termination of the agreement with the third
party would have a long-term material, adverse effect on its operations.
F-25
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
15. OTHER INCOME (EXPENSE), NET
Other income (expense), net is summarized as follows:
YEAR ENDED DECEMBER 31,
---------------------------
1999 1998 1997
------- ------- -------
Equity swap............................................. $(6,858) $(3,283) $ --
Change in fair market value of WTI benchmark call
options............................................... 6,150 366 (9,689)
Foreign exchange gain (loss)............................ (2,674) 2,113 9,549
Loss provisions......................................... (2,250) (750) --
Gain on sale of corporate assets........................ 443 7,593 1,414
Other................................................... 1,575 2,441 1,598
------- ------- -------
$(3,614) $ 8,480 $ 2,872
======= ======= =======
In 1999, 1998 and 1997, the Company recognized a net foreign exchange gain
(loss) of ($2.7 million), $2.1 million and $9.5 million, respectively,
consisting primarily of noncash adjustments related to deferred taxes in
Colombia associated with devaluation of the Colombian peso versus the U.S.
dollar.
16. EARNINGS PER ORDINARY SHARE
The following table reconciles the numerators and denominators of the basic
and diluted six months ended June 30, 2000 (unaudited) and for the years ended
December 31, 1999 and 1997.
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ---------
SIX MONTHS ENDED JUNE 30, 2000:
Net earnings........................................... $ 55,317
Less: Accumulated dividends on preference shares....... (14,680)
--------
Earnings available to ordinary shareholders............ 40,637
Basic earnings per ordinary share................... 36,060 $1.13
=====
Effect of dilutive securities:
Stock options....................................... -- 2,075
8% preference shares................................ 14,519 20,753
5% preference shares................................ 161 196
-------- ------
Earnings available to ordinary shareholders and assumed
conversions......................................... $ 55,317
========
Diluted earnings per ordinary share................. 59,084 $0.94
====== =====
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ---------
YEAR ENDED DECEMBER 31, 1999:
Net earnings........................................... $ 47,557
Less: Preference share dividends....................... (28,671)
--------
Earnings available to ordinary shareholders............ 18,886
Basic earnings per ordinary share................... 36,135 $0.52
=====
Effect of dilutive securities
Stock options....................................... -- 62
-------- ------
Earnings available to ordinary shareholders and assumed
conversions......................................... $ 18,886
========
Diluted earnings per ordinary share................. 36,197 $0.52
====== =====
YEAR ENDED DECEMBER 31, 1997:
Earnings before extraordinary item..................... $ 5,595
Less: Preference share dividends....................... (400)
--------
Earnings available to ordinary shareholders............ 5,195
Basic earnings per ordinary share................... 36,471 $0.14
=====
Effect of dilutive securities
Stock options....................................... -- 457
Convertible debentures.............................. -- 80
-------- ------
Earnings available to ordinary shareholders and assumed
conversions......................................... $ 5,195
========
Diluted earnings per ordinary share................. 37,008 $0.14
====== =====
For the six months ended June 30, 1999 (unaudited) and for the year ended
December 31, 1998, the computation of diluted net loss per ordinary share was
antidilutive, and therefore, the amounts reported for basic and diluted net loss
per ordinary share were the same.
At December 31, 1999, 5,193,643 shares of 8% Convertible Preference Shares
and 209,639 shares of 5% Convertible Preference Shares were outstanding. Each 8%
Convertible Preference Share is convertible any time into four ordinary shares,
subject to adjustment in certain events. Each 5% Convertible Preference Share is
convertible any time into one ordinary share, subject to adjustment in certain
events. The 8% Convertible Preference Shares and 5% Convertible Preference
Shares were not included in the computation of diluted earnings per ordinary
share because the effect of assuming conversion was antidilutive.
F-27
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
17. STATEMENTS OF CASH FLOWS
Supplemental disclosures of cash payments and noncash investing and
financing activities follow:
YEAR ENDED DECEMBER 31,
----------------------------
1999 1998 1997
------- ------- --------
Cash paid during the year for:
Interest (net of amount capitalized)................. $22,810 $24,517 $133,265
Income taxes......................................... 5,564 4,339 4,666
Noncash financing activities:
8% Convertible preference shares issued in lieu of
cash dividend..................................... $13,747 $ -- $ --
Conversion of preference shares into ordinary
shares............................................ 192 297 1,004
Cash paid for interest in 1997 included $124.8 million of interest accreted
with respect to the Senior Subordinated Discount Notes due November 1, 1997 and
the 9 3/4% Senior Subordinated Discount Notes due September 15, 2000 through the
dates of retirement.
18. RELATED PARTY TRANSACTIONS
Pursuant to a financial advisory agreement (the "Financial Advisory
Agreement") between Triton and Hicks, Muse & Co. Partners L.P. ("Hicks Muse
Partners"), an affiliate of Hicks Muse, the Company paid Hicks Muse Partners
transaction fees aggregating approximately $9.6 million and $4.4 million for
services as financial advisor to the Company in connection with the First
Closing and Second Closing, respectively, contemplated by the Stock Purchase
Agreement. In accordance with the terms of the Financial Advisory Agreement, the
Company has retained Hicks Muse Partners as its exclusive financial advisor in
connection with any Sale Transaction (defined below) unless Hicks Muse Partners
and the Company agree to retain an additional financial advisor in connection
with any particular Sale Transaction. The Financial Advisory Agreement requires
the Company to pay a fee to Hicks Muse Partners in connection with any Sale
Transaction (unless the Chief Executive Officer of the Company elects not to
retain a financial advisor) in an amount equal to the lesser of (i) the amount
of fees then charged by first-tier investment banking firms for similar advisory
services rendered in similar transactions or (ii) 1.5% of the Transaction Value
(as defined in the Financial Advisory Agreement); provided that such fee will be
divided equally between Hicks Muse Partners and any additional financial advisor
which the Company and Hicks Muse Partners agree will be retained by the Company
with respect to any such transaction. A "Sale Transaction" is defined as any
merger, sale of securities representing a majority of the combined voting power
of the Company, sale of assets of the Company representing more than 50% of the
total market value of the assets of the Company and its subsidiaries or other
similar transaction. The Company is also required to reimburse Hicks Muse
Partners for reasonable disbursements and out-of-pocket expenses of Hicks Muse
Partners incurred in connection with its advisory services.
Pursuant to a monitoring agreement (the "Monitoring Agreement") between
Triton and Hicks Muse Partners, Hicks Muse Partners will provide financial
oversight and monitoring services as requested by the Company and the Company
will pay to Hicks Muse Partners an annual fee of $.5 million. In addition, the
Company will reimburse Hicks Muse Partners for reasonable disbursements and
out-of-pocket expenses incurred by Hicks Muse Partners or its affiliates for the
account of the Company or in connection with the performance of its services.
During the years ended December 31, 1999 and 1998, the Company paid Hicks Muse
Partners $.6 million and $.1 million, respectively, under the terms of the
Monitoring Agreement.
F-28
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Financial Advisory Agreement and the Monitoring Agreement will remain
in effect until the earlier of (i) September 30, 2008, or (ii) the date on which
HM4 Triton, L.P. and its affiliates cease to own beneficially, directly or
indirectly, at least 5% of the Company's outstanding Ordinary Shares (determined
after giving effect to the conversion of all 8% Convertible Preference Shares
held by HM4 Triton, L.P. and its affiliates). The Company has agreed to
indemnify Hicks Muse Partners with respect to liabilities incurred as a result
of Hicks Muse Partners' performance of services for the Company pursuant to the
Financial Advisory Agreement and the Monitoring Agreement.
In 1999, the Company sold its hunting lease and related facilities to HMTF
Operating, L.P., an affiliate of Hicks Muse, for proceeds of $.9 million and
recognized a gain of $.4 million in other income (expense), net.
19. CERTAIN FACTORS THAT COULD AFFECT FUTURE OPERATIONS
Certain information contained in this report, as well as written and oral
statements made or incorporated by reference from time to time by the Company
and its representatives in other reports, filings with the Securities and
Exchange Commission, press releases, conferences, teleconferences, or otherwise,
may be deemed to be "forward-looking statements" within the meaning of Section
21E of the Securities Exchange Act of 1934 and are subject to the "Safe Harbor"
provisions of that section. Forward-looking statements include statements
concerning the Company's and management's plans, objectives, goals, strategies
and future operations and performance and the assumptions underlying such
forward-looking statements. When used in this document, the words "anticipates,"
"estimates," "expects," "believes," "intends," "plans," and similar expressions
are intended to identify such forward-looking statements. These statements
include information regarding:
- drilling schedules;
- expected or planned production capacity;
- future production from the Cusiana and Cupiagua fields in Colombia,
including from the Recetor license;
- the completion of development and commencement of production in
Malaysia-Thailand;
- future production of the Ceiba field in Equatorial Guinea, including
volumes and timing of first production;
- the acceleration of the Company's exploration, appraisal and development
activities in Equatorial Guinea;
- the Company's capital budget and future capital requirements;
- the Company's meeting its future capital needs;
- the Company's utilization of net operating loss carryforwards and
realization of its deferred tax asset;
- the level of future expenditures for environmental costs;
- the outcome of regulatory and litigation matters;
- the estimated fair value of derivative instruments, including the equity
swap; and
- proven oil and gas reserves and discounted future net cash flows
therefrom.
These statements are based on current expectations and involve a number of
risks and uncertainties, including those described in the context of such
forward-looking statements, as well as those presented
F-29
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
below. Actual results and developments could differ materially from those
expressed in or implied by such statements due to these and other factors.
Certain Factors Relating to the Oil and Gas Industry
The markets for oil and natural gas historically have been volatile and are
likely to continue to be volatile in the future. Oil and natural gas prices have
been subject to significant fluctuations during the past several decades in
response to relatively minor changes in the supply of and demand for oil and
natural gas, market uncertainty and a variety of additional factors that are
beyond the control of the Company. These factors include the level of consumer
product demand, weather conditions, domestic and foreign government regulations,
political conditions in the Middle East and other production areas, the foreign
supply of oil and natural gas, the price and availability of alternative fuels,
and overall economic conditions. It is impossible to predict future oil and gas
price movements with any certainty.
The Company follows the full cost method of accounting for exploration and
development of oil and gas reserves, whereby all acquisition, exploration and
development costs are capitalized. Costs related to acquisition, holding and
initial exploration of licenses in countries with no proved reserves are
initially capitalized, including internal costs directly identified with
acquisition, exploration and development activities. The Company's exploration
licenses are periodically assessed for impairment on a country-by-country basis.
If the Company's investment in exploration licenses within a country where no
proved reserves are assigned is deemed to be impaired, the licenses are written
down to estimated recoverable value. If the Company abandons all exploration
efforts in a country where no proved reserves are assigned, all acquisition and
exploration costs associated with the country are expensed. The Company's
assessments of whether its investment within a country is impaired and whether
exploration activities within a country will be abandoned are made from time to
time based on its review and assessment of drilling results, seismic data and
other information it deems relevant. Due to the unpredictable nature of
exploration drilling activities, the amount and timing of impairment expense are
difficult to predict with any certainty. Financial information concerning the
Company's assets at December 31, 1999, including capitalized costs by geographic
area, is set forth in note 21.
The Company's oil and gas business is also subject to all of the operating
risks normally associated with the exploration for and production of oil and
gas, including, without limitation, blowouts, explosion, uncontrollable flows of
oil, gas or well fluids, pollution, earthquakes, formations with abnormal
pressures, labor disruptions and fires, each of which could result in
substantial losses to the Company due to injury or loss of life and damage to or
destruction of oil and gas wells, formations, production facilities or other
properties. In accordance with customary industry practices, the Company
maintains insurance coverage limiting financial loss resulting from certain of
these operating hazards. Losses and liabilities arising from uninsured or
underinsured events would reduce revenues and increase costs to the Company.
There can be no assurance that any insurance will be adequate to cover losses or
liabilities. The Company cannot predict the continued availability of insurance,
or its availability at premium levels that justify its purchase.
The Company's oil and gas business is also subject to laws, rules and
regulations in the countries where it operates, which generally pertain to
production control, taxation, environmental and pricing concerns, and other
matters relating to the petroleum industry. Many jurisdictions have at various
times imposed limitations on the production of natural gas and oil by
restricting the rate of flow for oil and natural gas wells below their actual
capacity. There can be no assurance that present or future regulation will not
adversely affect the operations of the Company.
The Company is subject to extensive environmental laws and regulations.
These laws regulate the discharge of oil, gas or other materials into the
environment and may require the Company to remove or mitigate the environmental
effects of the disposal or release of such materials at various sites. In
addition, the Company could be held liable for environmental damages caused by
previous owners of its properties
F-30
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
or its predecessors. The Company does not believe that its environmental risks
are materially different from those of comparable companies in the oil and gas
industry. Nevertheless, no assurance can be given that environmental laws and
regulations will not, in the future, adversely affect the Company's consolidated
results of operations, cash flows or financial position. Pollution and similar
environmental risks generally are not fully insurable.
Certain Factors Relating to International Operations
The Company derives substantially all of its consolidated revenues from
international operations. Risks inherent in international operations include
risk of expropriation, nationalization, war, revolution, border disputes,
renegotiation or modification of existing contracts, import, export and
transportation regulations and tariffs; taxation policies, including royalty and
tax increases and retroactive tax claims; exchange controls, currency
fluctuations and other uncertainties arising out of foreign government
sovereignty over the Company's international operations; laws and policies of
the United States affecting foreign trade, taxation and investment; and the
possibility of having to be subject to the exclusive jurisdiction of foreign
courts in connection with legal disputes and the possible inability to subject
foreign persons to the jurisdiction of courts in the United States. To date, the
Company's international operations have not been materially affected by these
risks.
Certain Factors Relating to Colombia
The Company is a participant in significant oil and gas discoveries in the
Cusiana and Cupiagua fields, located approximately 160 kilometers (100 miles)
northeast of Bogota, Colombia. Development of reserves in the Cusiana and
Cupiagua fields is ongoing and will require additional drilling. Pipelines
connect the major producing fields in Colombia to export facilities and to
refineries.
From time to time, guerrilla activity in Colombia has disrupted the
operation of oil and gas projects. Such activity increased over the last year
and appears to be increasing as political negotiations among government and
various rebel groups proceed. In one recent case, a bomb planted near the
pipeline caused OCENSA to halt shipments, which in turn caused the operator of
the fields to curtail production for approximately two days. Although the
Colombian government, the Company and its partners have taken steps to maintain
security and favorable relations with the local population, there can be no
assurance that attempts to reduce or prevent guerrilla activity will be
successful or that guerrilla activity will not disrupt operations in the future.
Colombia is among several nations whose progress in stemming the production
and transit of illegal drugs is subject to annual certification by the President
of the United States. Although the President granted Colombia certification in
1999, Colombia was denied certification the last two years and only received a
national interest waiver for one of those years. There can be no assurance that,
in the future, Colombia will receive certification or a national interest
waiver. The consequences of the failure to receive certification or a national
interest waiver generally include the following: all bilateral aid, except anti-
narcotics and humanitarian aid, would be suspended; the Export-Import Bank of
the United States and the Overseas Private Investment Corporation would not
approve financing for new projects in Colombia; U.S. representatives at
multilateral lending institutions would be required to vote against all loan
requests from Colombia, although such votes would not constitute vetoes; and the
President of the United States and Congress would retain the right to apply
future trade sanctions. Each of these consequences could result in adverse
economic consequences in Colombia and could further heighten the political and
economic risks associated with the Company's operations in Colombia. Any changes
in the holders of significant government offices could have adverse consequences
on the Company's relationship with the Colombian national oil company and the
Colombian government's ability to control guerrilla activities and could
exacerbate the factors relating to foreign operations discussed above.
F-31
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Certain Factors Relating to Malaysia-Thailand
The Company is a partner in a significant gas exploration project located
in the Gulf of Thailand approximately 450 kilometers (280 miles) northeast of
Kuala Lumpur and 750 kilometers (470 miles) south of Bangkok as a contractor
under a production-sharing contract covering Block A-18 of the Malaysia-Thailand
Joint Development Area. On October 30, 1999, the Company and the other parties
to the production-sharing contract for Block A-18 executed a gas sales agreement
providing for the sale of the first phase of gas. Under terms of the gas sales
agreement, delivery of gas is scheduled to begin by the end of the second
quarter of 2002, following timely completion and approval of an environmental
impact assessment associated with the buyers' pipeline and processing
facilities. No assurance can be given as to when such approval will be obtained.
A lengthy approval process, or significant opposition to the project, could
delay construction and the commencement of gas sales.
In connection with the sale to ARCO of one-half of the shares through which
the Company owned its interest in Block A-18, ARCO agreed to pay the future
exploration and development costs attributable to the Company's and ARCO's
collective interest in Block A-18, up to $377 million or until first production
from a gas field, after which the Company and ARCO would each pay 50% of such
costs. There can be no assurance that the Company's and ARCO's collective share
of the cost of developing the project will not exceed $377 million. ARCO also
agreed to pay the Company certain incentive payments if certain criteria were
met. The first $65 million in incentive payments is conditioned upon having the
production facilities for the sale of gas from Block A-18 completed by June 30,
2002. If the facilities are completed after June 30, 2002 but before June 30,
2003, the incentive payment would be reduced to $40 million. A lengthy
environmental approval process, or unanticipated delays in construction of the
facilities, could result in the Company's receiving a reduced incentive payment
or possibly the complete loss of the first incentive payment. In addition, the
Company has agreed to share with ARCO some of the risk that the environmental
approval might be delayed by agreeing to pay to ARCO $1.25 million per month for
each month, if applicable, that first gas sales are delayed beyond 30 months
following the commitment to an engineering, procurement and construction
contract for the project. The Company's obligation is capped at 24 months of
these payments.
Influence of Hicks Muse
In connection with the issuance of 8% Convertible Preference Shares to HM4
Triton, L.P., the Company and HM4 Triton, L.P. entered into a shareholders
agreement (the "Shareholders Agreement") pursuant to which, among other things,
the size of the Company's Board of Directors was set at ten, and HM4 Triton,
L.P. exercised its right to designate four out of such ten directors. The
Shareholders Agreement provides that, in general, for so long as the entire
Board of Directors consists of ten members, HM4 Triton, L.P. (and its designated
transferees, collectively) may designate four nominees for election to the Board
of Directors.
The right of HM4 Triton, L.P. (and its designated transferees) to designate
nominees for election to the Board will be reduced if the number of ordinary
shares held by HM4 Triton, L.P. and its affiliates (assuming conversion of 8%
Convertible Preference Shares into ordinary shares) represents less than certain
specified percentages of the number of ordinary shares (assuming conversion of
8% Convertible Preference Shares into ordinary shares) purchased by HM4 Triton,
L.P. pursuant to the Stock Purchase Agreement.
The Shareholders Agreement provides that, for so long as HM4 Triton, L.P.
and its affiliates continue to hold a certain minimum number of ordinary shares
(assuming conversion of 8% Convertible Preference Shares into ordinary shares),
the Company may not take certain actions without the consent of HM4 Triton,
L.P., including (i) amending its Articles of Association or the terms of the 8%
Convertible Preference Shares with respect to the voting powers, rights or
preferences of the holders of 8% Convertible
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Preference Shares, (ii) entering into a merger or similar business combination
transaction, or effecting a reorganization, recapitalization or other
transaction pursuant to which a majority of the outstanding ordinary shares or
any 8% Convertible Preference Shares are exchanged for securities, cash or other
property, (iii) authorizing, creating or modifying the terms of any series of
securities that would rank equal to or senior to the 8% Convertible Preference
Shares, (iv) selling or otherwise disposing of assets comprising in excess of
50% of the market value of the Company, (v) paying dividends on ordinary shares
or other shares ranking junior to the 8% Convertible Preference Shares, other
than regular dividends on the Company's 5% Convertible Preference Shares, (vi)
incurring or guaranteeing indebtedness (other than certain permitted
indebtedness), or issuing preference shares, unless the Company's leverage ratio
at the time, after giving pro forma effect to such incurrence or issuance and to
the use of the proceeds, is less than 2.5 to 1, (vii) issuing additional shares
of 8% Convertible Preference Shares, other than in payment of accumulated
dividends on the outstanding 8% Convertible Preference Shares, (viii) issuing
any shares of a class ranking equal or senior to the 8% Convertible Preference
Shares, (ix) commencing a tender offer or exchange offer for all or any portion
of the ordinary shares or (x) decreasing the number of shares designated as 8%
Convertible Preference Shares.
As a result of HM4 Triton, L.P.'s ownership of 8% Convertible Preference
Shares and ordinary shares and the rights conferred upon HM4 Triton, L.P. and
its designees pursuant to the Shareholder Agreement, HM4 Triton, L.P. has
significant influence over the actions of the Company and will be able to
influence, and in some cases determine, the outcome of matters submitted for
approval of the shareholders. The existence of HM4 Triton, L.P. as a shareholder
of the Company may make it more difficult for a third party to acquire, or
discourage a third party from seeking to acquire, a majority of the outstanding
ordinary shares. A third party would be required to negotiate any such
transaction with HM4 Triton, L.P. and the interests of HM4 Triton, L.P. as a
shareholder may be different from the interests of the other shareholders of the
Company.
Possible Future Acquisitions
The Company's strategy includes the possible acquisition of additional
reserves, including through possible future business combination transactions.
There can be no assurance as to the terms upon which any such acquisitions would
be consummated or as to the affect any such transactions would have on the
Company's financial condition or results of operations. Such acquisitions, if
any, could involve the use of the Company's cash, or the issuance of the
Company's debt or equity securities, which could have a dilutive effect on the
current shareholders.
Competition
The Company encounters strong competition from major oil companies
(including government-owned companies), independent operators and other
companies for favorable oil and gas concessions, licenses, production-sharing
contracts and leases, drilling rights and markets. Additionally, the governments
of certain countries in which the Company operates may, from time to time, give
preferential treatment to their nationals. The oil and gas industry as a whole
also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual consumers. The Company
believes that the principal means of competition in the sale of oil and gas are
product availability, price and quality.
Markets
Crude oil, natural gas, condensate, and other oil and gas products
generally are sold to other oil and gas companies, government agencies and other
industries. The availability of ready markets for oil and gas that might be
discovered by the Company and the prices obtained for such oil and gas depend on
many factors beyond the Company's control, including the extent of local
production and imports of oil and gas,
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the proximity and capacity of pipelines and other transportation facilities,
fluctuating demands for oil and gas, the marketing of competitive fuels, and the
effects of governmental regulation of oil and gas production and sales. Pipeline
facilities do not exist in certain areas of exploration and, therefore, any
actual sales of discovered oil or gas might be delayed for extended periods
until such facilities are constructed.
Litigation
The outcome of litigation and its impact on the Company are difficult to
predict due to many uncertainties, such as jury verdicts, the application of
laws to various factual situations, the actions that may or may not be taken by
other parties and the availability of insurance. In addition, in certain
situations, such as environmental claims, one defendant may be responsible for
the liabilities of other parties. Moreover, circumstances could arise under
which the Company may elect to settle claims at amounts that exceed the
Company's expected liability for such claims in an attempt to avoid costly
litigation. Judgments or settlements could, therefore, exceed any reserves.
20. COMMITMENTS AND CONTINGENCIES
For internal planning purposes, the Company's capital spending program for
the year ending December 31, 2000, is approximately $191 million, excluding
capitalized interest and acquisitions, of which approximately $122 million
relates to exploration and development activities in Equatorial Guinea, $58
million relates to the Cusiana and Cupiagua fields in Colombia and $11 million
relates to the Company's exploration activities in other parts of the world.
(See note 24 -- Subsequent Events.)
During the normal course of business, the Company is subject to the terms
of various operating agreements and capital commitments associated with the
exploration and development of its oil and gas properties. It is management's
belief that such commitments, including the capital requirements in Colombia,
Equatorial Guinea and other parts of the world discussed above, will be met
without any material adverse effect on the Company's operations or consolidated
financial condition.
The Company leases office space, other facilities and equipment under
various operating leases expiring through 2005. Total rental expense was $1.3
million, $2.1 million and $2 million for the years ended December 31, 1999, 1998
and 1997, respectively. At December 31, 1999, the minimum payments required
under terms of the leases are as follows 2000 -- $1.5 million; 2001 -- $1.6
million; 2002 -- $1.6 million; 2003 -- $1.6 million; 2004 -- $1.6 million; and
thereafter $1 million.
Guarantees
At June 30, 2000 and December 31, 1999, the Company had guaranteed the
performance of a total of $11.4 million (unaudited) and $16.4 million in future
exploration expenditures to be incurred through September 2001 in various
countries. A total of approximately $6 million of the exploration expenditures
are included in the 2000 capital spending program related to a commitment for
two onshore exploratory wells in Greece. These commitments are backed primarily
by unsecured letters of credit. The Company also had guaranteed loans of
approximately $1.4 million, which expire September 2000, for a Colombian
pipeline company, ODC, in which the Company has an ownership interest.
Environmental Matters
The Company is subject to extensive environmental laws and regulations.
These laws regulate the discharge of oil, gas or other materials into the
environment and may require the Company to remove or mitigate the environmental
effects of the disposal or release of such materials at various sites. The
Company believes that the level of future expenditures for environmental
matters, including clean-up
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
obligations, is impracticable to determine with a precise and reliable degree of
accuracy. Management believes that such costs, when finally determined, will not
have a material adverse effect on the Company's operations or consolidated
financial condition.
Litigation
In July through October 1998, eight lawsuits were filed against the Company
and Thomas G. Finck and Peter Rugg, in their capacities as Chairman and Chief
Executive Officer and Chief Financial Officer, respectively. The lawsuits were
filed in the United States District Court for the Eastern District of Texas,
Texarkana Division, and have been consolidated and are styled In re: Triton
Energy Limited Securities Litigation. In November 1999, the plaintiffs filed a
consolidated complaint. It alleges violations of Sections 10(b) and 20(a) of the
Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated
thereunder, in connection with disclosures concerning the Company's properties,
operations, and value relating to a prospective sale of the Company or of all or
a part of its assets. The lawsuits seek recovery of an unspecified amount of
compensatory damages, fees and costs. In the consolidated complaint, the
plaintiffs abandoned a claim for negligent misrepresentation and punitive
damages that had previously been asserted in one of the eight individual suits.
In September 1999, the court granted the plaintiffs' motion for appointment
as lead plaintiffs and for approval of selection of lead counsel. In October
1999, the defendants filed a motion to dismiss the claims alleged in the eight
individual suits, and in December 1999, the defendants filed a supplement to
their motion to dismiss to address the plaintiffs' consolidated complaint. The
Company's motion, as supplemented, is currently pending.
The Company believes its disclosures have been accurate and intends to
vigorously defend these actions. There can be no assurance that the litigation
will be resolved in the Company's favor. An adverse result could have a material
adverse effect on the Company's financial position or results of operations.
In November 1999, a lawsuit was filed against the Company, and one of its
subsidiaries and Thomas G. Finck, Peter Rugg and Robert B. Holland, III, in
their capacities as officers of the Company, in the District Court of the State
of Texas for Dallas County. The lawsuit is styled Aaron Sherman, et al. vs.
Triton Energy Corporation et al. and seeks an unspecified amount of compensatory
and punitive damages and interest. The lawsuit alleges as causes of action fraud
and negligent misrepresentation in connection with disclosures concerning the
prospective sale by the Company of all or a substantial part of its assets
announced in March 1998. The Company's date to answer has not yet run. Its
subsidiary has filed various motions to dispose of the lawsuit on the grounds
that the plaintiffs do not have standing. The Court has ordered the plaintiffs
to replead and has stayed discovery pending its further orders. In August 1997,
the Company was sued in the Superior Court of the State of California for the
County of Los Angeles, by David A. Hite, Nordell International Resources Ltd.,
and International Veronex Resources, Ltd. The action has since been removed to
the United States District Court for the Central District of California. The
Company and the plaintiffs were adversaries in a 1990 arbitration proceeding in
which the interest of Nordell International Resources Ltd. in the Enim oil field
in Indonesia was awarded to the Company (subject to a 5% net profits interest
for Nordell) and Nordell was ordered to pay the Company nearly $1 million. The
arbitration award was followed by a series of legal actions by the parties in
which the validity of the award and its enforcement were at issue. As a result
of these proceedings, the award was ultimately upheld and enforced. The current
suit alleges that the plaintiffs were damaged in amounts aggregating $13 million
primarily because of the Company's prosecution of various claims against the
plaintiffs as well as its alleged misrepresentations, infliction of emotional
distress, and improper accounting practices. The suit seeks specific performance
of the arbitration award, damages for alleged fraud and misrepresentation in
accounting for Enim field operating results, an accounting for Nordell's 5% net
profit interest, and damages for emotional distress and various other alleged
torts. The suit seeks
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
interest, punitive damages and attorneys fees in addition to the alleged actual
damages. In August 1998, the district court dismissed all claims asserted by the
plaintiffs other than claims for malicious prosecution and abuse of the legal
process, which the court held could not be subject to a motion to dismiss. The
abuse of process claim was later withdrawn, and the damages sought were reduced
to approximately $700,000 (not including punitive damages). The lawsuit was
tried and the jury found in favor of the plaintiffs and assessed compensatory
damages against the Company in the amount of approximately $700,000 and punitive
damages in the amount of approximately $11 million. The Company believes it has
acted appropriately and intends to appeal the verdict.
The Company is subject to certain other litigation matters, none of which
is expected to have a material, adverse effect on the Company's operations or
consolidated financial condition.
21. GEOGRAPHIC INFORMATION
Triton's operations are primarily related to crude oil and natural gas
exploration and production. The Company's principal properties, operations and
oil and gas reserves are located in Colombia, Malaysia-Thailand and Equatorial
Guinea. The Company is exploring for oil and gas in these areas, as well as in
southern Europe, Africa and the Middle East. All sales are currently derived
from oil and gas production in Colombia. Financial information about the
Company's operations by geographic area is presented below:
CORPORATE
MALAYSIA- EQUATORIAL AND
COLOMBIA THAILAND GUINEA EXPLORATION OTHER TOTAL
--------- --------- ---------- ----------- --------- ----------
YEAR ENDED DECEMBER 31, 1999:
Sales and other operating revenues..... $ 247,878 $ -- $ -- $ -- $ -- $ 247,878
Operating income (loss)................ 115,877 -- (469) (7,214) (16,334) 91,860
Depreciation, depletion and
amortization......................... 59,728 -- 16 144 1,455 61,343
Capital expenditures and investments... 79,889 8,453 19,968 12,419 754 121,483
Assets................................. 476,543 93,188 37,229 85,250 282,265 974,475
YEAR ENDED DECEMBER 31, 1998:
Sales and other operating revenues..... $ 160,881 $ 63,237 $ -- $ 4,500 $ -- $ 228,618
Operating income (loss)................ (220,697) 62,538 (124) (79,703) (39,360) (277,346)
Depreciation, depletion and
amortization......................... 53,641 49 1 175 4,945 58,811
Writedown of assets.................... 251,312 -- -- 76,664 654 328,630
Capital expenditures and investments... 106,624 25,319 5,913 41,603 756 180,215
Assets................................. 468,533 84,735 10,766 78,086 112,160 754,280
YEAR ENDED DECEMBER 31, 1997:
Sales and other operating revenues..... $ 145,419 $ -- $ -- $ 4,077 $ -- $ 149,496
Operating income (loss)................ 59,719 (536) (42) (6,270) (20,167) 32,704
Depreciation, depletion and
amortization......................... 31,186 60 -- 505 5,077 36,828
Capital expenditures and investments... 129,589 37,328 4,471 43,371 4,457 219,216
Assets................................. 712,512 148,780 4,841 105,720 126,186 1,098,039
During 1998, the Company sold one-half of the shares of the subsidiary
through which the Company owned its 50% share of Block A-18 resulting in a gain
of $63.2 million which is included in Malaysia-Thailand sales and other
operating revenues and operating income (loss). See note 2 -- Asset
Dispositions. After the sale, which resulted in a 50% ownership in the
previously wholly owned subsidiary, the Company's remaining ownership is
accounted for using the equity method. This investment in Block A-18 is
presented in Malaysia-Thailand assets at December 31, 1999 and 1998.
Colombia operating income (loss) for the year ended December 31, 1998,
included a SEC full cost ceiling limitation writedown of $241 million.
Additionally, Exploration operating income (loss) included
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
writedowns of oil and gas properties and other assets totaling $76.7 million for
the year ended December 31, 1998.
At December 31, 1999, corporate assets were principally cash and
equivalents and the U.S. deferred tax asset. Exploration assets included $41.6
million, $17.6 million, $16.5 million and $8.4 million in Italy, Greece, Oman
and Madagascar, respectively.
22. QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTER
------------------------------------------
FIRST SECOND THIRD FOURTH
------- --------- -------- ---------
YEAR ENDED DECEMBER 31, 1999:
Sales and other operating revenues.................. $49,170 $ 59,622 $ 67,295 $ 71,791
Gross profit........................................ 14,823 25,151 32,349 46,082
Net earnings........................................ 1,887 10,883 11,762 23,025
Basic earnings (loss) per ordinary share............ (0.14) 0.11 0.12 0.44
Diluted earnings (loss) per ordinary share.......... (0.14) 0.11 0.12 0.40
Investment in affiliate............................. 86,704 88,179 91,008 93,188
YEAR ENDED DECEMBER 31, 1998:
Sales and other operating revenues.................. $36,175 $ 36,378 $105,862 $ 50,203
Gross profit (loss)................................. 8,409 (180,179) 73,751 (134,350)
Net earnings (loss)................................. 42,912 (150,062) 47,208 (127,562)
Basic earnings (loss) per ordinary share............ 1.17 (4.10) 1.29 3.56
Diluted earnings (loss) per ordinary share.......... 1.16 (4.10) 1.28 3.56
Investment in affiliate............................. -- -- 82,511 84,735
Gross profit (loss) is comprised of sales and other operating revenues less
operating expenses, depreciation, depletion and amortization, and writedowns
pertaining to operating assets. Gross profit for the fourth quarter of 1999
included a non-recurring credit issued by OCENSA in February 2000 totaling $4.2
million. The credit to pipeline tariffs resulted from OCENSA's compliance with a
Colombian government decree in December 1999 that reduced its 1999 noncash
expenses.
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
23. OIL AND GAS DATA (UNAUDITED)
The following tables provide additional information about the Company's oil
and gas exploration and production activities. The oil and gas data reflect the
Company's proportionate interest in Block A-18 on an equity investment basis
since the sale of one-half of the subsidiary through which the Company owned its
50% share of Block A-18 in August 1998.
Results of Operations
The results of operations for oil- and gas-producing activities,
considering direct costs only, follow:
COLOMBIA
---------
YEAR ENDED DECEMBER 31, 1999:
Revenues............................... $ 247,878
Costs:
Production costs.................... 68,130
General operating expenses.......... 3,954
Depletion........................... 59,512
Income tax expense.................. 42,083
---------
Results of operations.................. $ 74,199
=========
MALAYSIA- TOTAL
COLOMBIA THAILAND OTHER WORLDWIDE
--------- --------- -------- ---------
YEAR ENDED DECEMBER 31, 1998:
Revenues............................... $ 160,881 $63,237 $ 4,500 $ 228,618
Costs:
Production costs.................... 73,546 -- -- 73,546
General operating expenses.......... 2,460 -- -- 2,460
Depletion........................... 53,304 -- -- 53,304
Writedown of assets................. 251,312 -- 76,664 327,976
Income tax benefit.................. (76,048) -- (22,527) (98,575)
--------- ------- -------- ---------
Results of operations.................. $(143,693) $63,237 $(49,637) $(130,093)
========= ======= ======== =========
TOTAL
COLOMBIA OTHER WORLDWIDE
--------- --------- ---------
YEAR ENDED DECEMBER 31, 1997:
Revenues............................... $ 145,419 $ 4,077 $149,496
Costs:
Production costs.................... 51,357 -- 51,357
General operating expenses.......... 2,886 -- 2,886
Depletion........................... 30,729 -- 30,729
Income tax expense.................. 22,167 1,223 23,390
--------- ------- --------
Results of operations.................. $ 38,280 $ 2,854 $ 41,134
========= ======= ========
Malaysia-Thailand revenues for the year ended December 31, 1998, included a
gain of $63.2 million from the sale of one-half of the shares of the subsidiary
through which the Company owned its 50% share of Block A-18. Other revenues for
the years ended December 31, 1998 and 1997, included gains of $4.5 million, and
$4.1 million from the sale of the Company's Bangladesh subsidiary and Argentine
subsidiary, respectively.
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Depletion includes depreciation on support equipment and facilities
calculated on the unit-of-production method.
Costs Incurred and Capitalized Costs
The costs incurred in oil and gas acquisition, exploration and development
activities and related capitalized costs follow:
EQUATORIAL TOTAL
COLOMBIA GUINEA OTHER WORLDWIDE
-------- ---------- ---------- ---------
DECEMBER 31, 1999:
Costs incurred:
Property acquisition......................... $ 6,400 $ -- $ 20 $ 6,420
Exploration.................................. 155 23,631 13,051 36,837
Development.................................. 80,782 -- -- 80,782
Depletion per equivalent barrel of
production................................... 3.80 -- -- 3.80
Cost of properties at year-end:
Unevaluated.................................. $ -- $ 5,772 $72,755 $ 78,527
======== ======= ======= ========
Evaluated.................................... $530,947 $28,613 $ 680 $560,240
======== ======= ======= ========
Support equipment and facilities............. $303,244 $ 709 $ -- $303,953
======== ======= ======= ========
Accumulated depletion and depreciation at
year-end..................................... $419,651 $ -- $ 680 $420,331
======== ======= ======= ========
MALAYSIA- EQUATORIAL TOTAL
COLOMBIA THAILAND GUINEA OTHER WORLDWIDE
-------- ---------- ---------- --------- ---------
DECEMBER 31, 1998:
Costs incurred:
Property acquisition......................... $ -- $ -- $ -- $ 500 $ 500
Exploration.................................. 2,886 17,739 5,913 43,153 69,691
Development.................................. 83,088 1,026 -- -- 84,114
Depletion per equivalent barrel of
production................................... 4.07 -- -- -- 4.07
Cost of properties at year-end:
Unevaluated.................................. $ -- $ -- $10,754 $60,082 $ 70,836
======== ======= ======= ======= ========
Evaluated.................................... $467,147 $ -- $ -- $76,367 $543,514
======== ======= ======= ======= ========
Support equipment and facilities............. $289,659 $ -- $ -- $ -- $289,659
======== ======= ======= ======= ========
Accumulated depletion and depreciation at
year-end..................................... $360,324 $ -- $ -- $76,367 $436,691
======== ======= ======= ======= ========
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
MALAYSIA- EQUATORIAL TOTAL
COLOMBIA THAILAND GUINEA OTHER WORLDWIDE
-------- --------- ---------- ------- ---------
DECEMBER 31, 1997:
Costs incurred:
Property acquisition................. $ -- $ -- $1,500 $ 1,628 $ 3,128
Exploration.......................... 7,583 36,373 2,971 44,893 91,820
Development.......................... 62,251 187 -- -- 62,438
Depletion per equivalent barrel of
production........................... 3.67 -- -- -- 3.67
Cost of properties at year-end:
Unevaluated.......................... $ 2,172 $ 30,327 $4,841 $93,286 $130,626
======== ======== ====== ======= ========
Evaluated............................ $396,774 $114,243 $ -- $ 7,563 $518,580
======== ======== ====== ======= ========
Support equipment and facilities..... $250,193 $ -- $ -- $ -- $250,193
======== ======== ====== ======= ========
Accumulated depletion and depreciation
at year-end.......................... $ 66,250 $ -- $ -- $ 7,563 $ 73,813
======== ======== ====== ======= ========
A summary of costs excluded from depletion at December 31, 1999, by year
incurred follows:
DECEMBER 31,
--------------------------------------------
TOTAL 1999 1998 1997 1996 AND PRIOR
-------- ------- ------- ------- --------------
Property acquisition..................... $ 2,820 $ 20 $ 500 $ 1,700 $ 600
Exploration.............................. 93,258 29,697 34,394 16,008 13,159
Capitalized interest..................... 11,062 6,587 2,971 1,383 121
-------- ------- ------- ------- -------
Total worldwide................ $107,140 $36,304 $37,865 $19,091 $13,880
======== ======= ======= ======= =======
The Company excludes from its depletion computation property acquisition
and exploration costs of unevaluated properties and major development projects
in progress. The excluded costs include $34.4 million ($28.6 million and $5.8
million classified as evaluated and unevaluated, respectively) which relate
primarily to the Ceiba field in Equatorial Guinea that will become depletable
once production begins, currently estimated for year end 2000. Additionally,
excluded costs include exploration costs of $34.6 million, $16.8 million, $11.8
million and $8.4 million in Italy, Greece, Oman and Madagascar, respectively,
where there are no proved reserves at December 31, 1999. At this time, the
Company is unable to predict either the timing of the inclusion of these costs
and any related oil and gas reserves in its depletion computation or their
potential future impact on depletion rates. Drilling or other exploration
activities are being conducted in each of these cost centers.
The Company's share of costs incurred for Block A-18 were $8.2 million and
$3.2 million for the years ended December 31, 1999 and 1998, respectively. Net
capitalized costs were $90.2 million and $85.2 million at December 31, 1999 and
1998, respectively.
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Oil and Gas Reserve Data (Oil reserves are stated in thousands of barrels and
gas reserves are stated in millions of cubic feet.)
The following tables present the Company's estimates of its proved oil and
gas reserves. The estimates for the proved reserves in the Cusiana and Cupiagua
fields in Colombia and the Ceiba field in Equatorial Guinea were prepared by the
Company's independent petroleum engineers, DeGolyer and MacNaughton and
Netherland, Sewell & Associates, Inc., respectively. The estimates for proved
reserves in Malaysia-Thailand were prepared by the internal petroleum engineers
of the operating company, Carigali-Triton Operating Company (CTOC). The
estimates for the proved reserves in the Liebre field in Colombia were prepared
by the Company's internal petroleum reservoir engineers. The Company emphasizes
that reserve estimates are approximate and are expected to change as additional
information becomes available. Reservoir engineering is a subjective process of
estimating underground accumulations of oil and gas that cannot be measured in
an exact way, and the accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological interpretation and
judgment. Accordingly, there can be no assurance that the reserves set forth
herein will ultimately be produced, and there can be no assurance that the
proved undeveloped reserves will be developed within the periods anticipated. As
of December 31, 1999, gas sales had not yet commenced from the Company's
interest in the Malaysia-Thailand Joint Development Area. In estimating its
reserves attributable to such interest, the Company assumed that production from
the interest would be sold at the base price in the gas sales agreement of
$2.30. The base price is subject to annual adjustments based on various indices.
There can be no assurance as to what the actual price will be when gas sales
commence.
EQUITY
INVESTMENT
EQUATORIAL MALAYSIA-
COLOMBIA GUINEA TOTAL WORLDWIDE THAILAND
---------------- ---------------- ---------------- ----------------
OIL GAS OIL GAS OIL GAS OIL GAS
------- ------ ------ ------- ------- ------ ------ -------
PROVED DEVELOPED AND UNDEVELOPED RESERVES
AS OF DECEMBER 31, 1998.................. 135,327 12,284 -- -- 135,327 12,284 8,017 570,312
Revisions................................ (567) (259) -- -- (567) (259) 5,206 (16,450)
Purchases................................ 3,280 -- -- -- 3,280 -- -- --
Extensions and discoveries............... -- -- 32,033 -- 32,033 -- -- --
Production............................... (12,469) (459) -- -- (12,469) (459) -- --
------- ------ ------ ------- ------- ------ ------ -------
AS OF DECEMBER 31, 1999.................... 125,571 11,566 32,033 -- 157,604 11,566 13,223 553,862
======= ====== ====== ======= ======= ====== ====== =======
PROVED DEVELOPED RESERVES AT DECEMBER 31,
1999..................................... 91,859 11,566 -- -- 91,859 11,566 -- --
======= ====== ====== ======= ======= ====== ====== =======
EQUITY
INVESTMENT
MALAYSIA-
COLOMBIA MALAYSIA-THAILAND TOTAL WORLDWIDE THAILAND
---------------- ------------------- ------------------- ---------------
OIL GAS OIL GAS OIL GAS OIL GAS
------- ------ ------- --------- ------- --------- ----- -------
PROVED DEVELOPED AND UNDEVELOPED
RESERVES AS OF DECEMBER 31, 1997..... 145,999 14,619 29,800 1,223,800 175,799 1,238,419 -- --
Revisions............................ (693) (1,832) (6,583) (41,588) (7,276) (43,420) -- --
Sales................................ -- -- (15,200) (625,400) (15,200) (625,400) -- --
Equity investment.................... -- -- (8,017) (570,312) (8,017) (570,312) 8,017 570,312
Extensions and discoveries........... -- -- -- 13,500 -- 13,500 -- --
Production........................... (9,979) (503) -- -- (9,979) (503) -- --
------- ------ ------- --------- ------- --------- ----- -------
AS OF DECEMBER 31, 1998................ 135,327 12,284 -- -- 135,327 12,284 8,017 570,312
======= ====== ======= ========= ======= ========= ===== =======
PROVED DEVELOPED RESERVES AT DECEMBER
31, 1998............................. 86,039 12,284 -- -- 86,039 12,284 -- --
======= ====== ======= ========= ======= ========= ===== =======
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
COLOMBIA MALAYSIA-THAILAND TOTAL WORLDWIDE
---------------- ------------------- -------------------
OIL GAS OIL GAS OIL GAS
------- ------ ------- --------- ------- ---------
PROVED DEVELOPED AND UNDEVELOPED
RESERVES AS OF DECEMBER 31, 1996.... 135,310 14,651 24,700 871,100 160,010 885,751
Revisions........................... 14,157 770 (2,000) (7,600) 12,157 (6,830)
Extensions and discoveries.......... 2,308 -- 7,100 360,300 9,408 360,300
Production.......................... (5,776) (802) -- -- (5,776) (802)
------- ------ ------- --------- ------- ---------
AS OF DECEMBER 31, 1997............... 145,999 14,619 29,800 1,223,800 175,799 1,238,419
======= ====== ======= ========= ======= =========
PROVED DEVELOPED RESERVES AT DECEMBER
31, 1997............................ 81,931 14,619 -- -- 81,931 14,619
======= ====== ======= ========= ======= =========
Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein
The following table presents for the net quantities of proved oil and gas
reserves a standardized measure of discounted future net cash inflows discounted
at an annual rate of 10%. The future net cash inflows were calculated in
accordance with Securities and Exchange Commission guidelines. Future cash
inflows were computed by applying year-end prices of oil and gas relating to the
Company's proved reserves to the estimated year-end quantities of those
reserves. The future cash inflow estimates for 1999 attributable to oil reserves
were based on the year end WTI crude oil price of $25.60 per barrel for the
Company's reserves in Colombia and Malaysia-Thailand, and the year end Brent
crude oil price of $24.89 per barrel for the Company's reserves in Equatorial
Guinea, in each case before adjustments for oil quality and transportation
costs.
In 1999, the Company and the other parties to the production-sharing
contract for Block A-18 executed a gas sales agreement providing for the sale of
the first phase of gas. In estimating discounted future net cash inflows
attributable to such interest, the Company assumed that production from the
interest would be sold at the base price in the gas sales agreement of $2.30.
The base price is subject to annual adjustments based on various indices. There
can be no assurance as to what the actual price will be when gas sales commence.
Future production and development costs were computed by estimating those
expenditures expected to occur in developing and producing the proved oil and
gas reserves at the end of the year, based on year-end costs. The Company
emphasizes that the future net cash inflows should not be construed as
representative of the fair market value of the Company's proved reserves.
The meaningfulness of the estimates is highly dependent upon the accuracy of the
assumptions upon which they were based. Actual future cash inflows may vary
materially.
In connection with the sale to ARCO of one-half of the shares through which
the Company owned its interest in Block A-18, ARCO agreed to pay the Company an
additional $65 million each at July 1, 2002, and July 1, 2005, if certain
specific development objectives are met by such dates, or $40 million each if
the objectives are met within one year thereafter. For purposes of calculating
future cash inflows for Malaysia-Thailand at December 31, 1999, the Company
assumed that it would receive an incentive payment of $65 million in July 2002.
There can be no assurances that the Company will receive any
F-42
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
incentive payments. See note 19, "Certain Factors that Could Affect Future
Operations -- Certain Factors Related to Malaysia-Thailand."
EQUITY
INVESTMENT
EQUATORIAL TOTAL MALAYSIA-
COLOMBIA GUINEA WORLDWIDE THAILAND
---------- ---------- ---------- ----------
DECEMBER 31, 1999:
Future cash inflows......................... $3,152,352 $765,275 $3,917,627 $1,649,881
Future production and
development costs........................ 817,065 399,365 1,216,430 703,419
---------- -------- ---------- ----------
Future net cash inflows before income
taxes.................................... $2,335,287 $365,910 $2,701,197 $ 946,462
========== ======== ========== ==========
Future net cash inflows before income taxes
discounted at 10% per annum.............. $1,414,433 $263,849 $1,678,282 $ 266,631
Future income taxes discounted at 10% per
annum.................................... 391,796 57,589 449,385 15,845
---------- -------- ---------- ----------
Standardized measure of discounted future
net cash inflows......................... $1,022,637 $206,260 $1,228,897 $ 250,786
========== ======== ========== ==========
EQUITY
INVESTMENT
MALAYSIA-
COLOMBIA THAILAND
---------- ----------
DECEMBER 31, 1998:
Future cash inflows........................ $1,481,065 $1,555,929
Future production and development
costs................................... 734,025 695,575
---------- ----------
Future net cash inflows before income
taxes................................... $ 747,040 $ 860,354
========== ==========
Future net cash inflows before income taxes
discounted at 10% per annum............. $ 415,127 $ 253,535
Future income taxes discounted at 10% per
annum................................... 3,909 8,917
---------- ----------
Standardized measure of discounted future
net cash inflows........................ $ 411,218 $ 244,618
========== ==========
MALAYSIA- TOTAL
COLOMBIA THAILAND WORLDWIDE
---------- ---------- ----------
DECEMBER 31, 1997:
Future cash inflows........................ $2,524,291 $4,078,609 $6,602,900
Future production and
development costs....................... 1,142,382 1,883,881 3,026,263
---------- ---------- ----------
Future net cash inflows before income
taxes................................... $1,381,909 $2,194,728 $3,576,637
========== ========== ==========
Future net cash inflows before income taxes
discounted at 10% per annum............. $ 852,421 $ 427,463 $1,279,884
Future income taxes discounted at 10% per
annum................................... 173,785 36,756 210,541
---------- ---------- ----------
Standardized measure of discounted future
net cash inflows........................ $ 678,636 $ 390,707 $1,069,343
========== ========== ==========
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Changes in the standardized measure of discounted future net cash inflows
follow:
DECEMBER 31,
------------------------------------
1999 1998 1997
---------- ---------- ----------
Total worldwide:
Beginning of year.............................. $ 411,218 $1,069,343 $1,292,195
Sales, net of production costs.............. (179,748) (87,335) (94,062)
Sales of reserves........................... -- (70,543) --
Equity investment........................... -- (244,618) --
Revisions of quantity estimates............. (6,546) (29,321) 75,253
Net change in prices and production costs... 1,105,963 (579,212) (552,863)
Extensions, discoveries and improved
recovery.................................. 206,260 6,516 42,918
Change in future development costs.......... (61,728) (46,633) (5,936)
Purchases of reserves....................... 6,400 -- --
Development and facilities costs incurred... 70,828 105,808 53,199
Accretion of discount....................... 74,704 120,270 160,406
Changes in production rates and other....... (10,567) (30,772) (3,089)
Net change in income taxes.................. (387,887) 197,715 101,322
---------- ---------- ----------
End of year.................................... $1,228,897 $ 411,218 $1,069,343
========== ========== ==========
24. SUBSEQUENT EVENTS (SUBSEQUENT TO THE DATE OF THE AUDITOR'S REPORT AND
UNAUDITED.)
Acquisition of Triton Pipeline Colombia -- Investment in Affiliate
In May 2000, the Company acquired from an unrelated third party, for $88.8
million in cash, 100% of the shares of Triton Pipeline Colombia, Inc. ("TPC"), a
formerly wholly owned subsidiary up to its disposal on February 2, 1998. TPC's
sole asset is its 9.6% equity interest in the Colombian pipeline company OCENSA.
OCENSA owns and operates the pipeline and port facilities, which transport and
handle crude oil from the Cusiana and Cupiagua fields to the Caribbean port of
Covenas. Following the Company's acquisition of shares of TPC in 2000, the
Company elected to cancel the dividend it would receive as an owner of the
OCENSA shares to reduce its tariff. The investment in TPC is accounted for under
the cost method.
Trade Receivables and Inventories, Prepaid Expenses and Other
Trade receivables were $3.4 million and $17.2 million at June 30, 2000 and
December 31, 1999, respectively. June 2000 crude oil liftings occurred early in
the month, resulting in the collection of substantially all of the trade
receivables at June 30, 2000. Crude oil inventory was $13.6 million and $3.7
million at June 30, 2000 and December 31, 1999, respectively.
Revised Capital Spending Program
During 2000, the Company revised its capital spending program for the year
ending December 31, 2000 to approximately $256 million, excluding capitalized
interest and acquisitions. The $256 million comprises approximately $187 million
for exploration and development activities in Equatorial Guinea, $58 million for
the Cusiana and Cupiagua fields in Colombia and $11 million for the Company's
exploration activities in other parts for the world.
F-44
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TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5% Preference Shares
During September 2000, the Company called for redemption of the outstanding
5% preference shares. The redemption date is October 31, 2000, so that any 5%
preference shares outstanding on that date will be redeemed for cash at the
redemption price of $34.56 per share. The redemption price represents the stated
value of $34.41 plus the amount of dividends that would accrue per share from
September 30, 2000, through the redemption date of October 31, 2000.
Each 5% preference share is convertible into one Triton ordinary share. Any
holders of 5% preference shares who wish to convert their shares into Triton
ordinary shares will have until the close of business on October 24, 2000. As of
September 6, 2000, there were 185,276 5% preference shares outstanding.
Writedown
In September 2000, the Company announced it expects to take an approximate
$19 million pre-tax (about $17 million after-tax) noncash writedown related to
its operations in Greece. The Company relinquished its interest in the
Aitoloakarnania license onshore Greece to the government after drilling two dry
holes.
8 7/8% Senior Notes due 2007
In October 2000, the Company issued $300 million face value of 8 7/8%
Senior Notes due October 1, 2007 (the "2007 Notes") for proceeds of $300 million
before deducting transaction costs of approximately $6 million. Interest is
payable semi-annually on April 1 and October 1, commencing April 1, 2001. The
2007 Notes are redeemable, in whole or in part, at any time on or after October
1, 2004 at the option of the Company, or up to $105 million may be redeemed
using proceeds of future equity offerings completed before October 1, 2003. The
2007 Notes contain various restrictive covenants that limit the Company's
ability to borrow money or guarantee other indebtedness, create liens, make
investments, use assets as security in other transactions, pay dividends on
stock, enter into sale and leaseback transactions, sell assets, sell capital
stock of subsidiaries, enter into agreements that restrict dividends from
subsidiaries, merge or consolidate, enter into transactions with affiliates and
enter into different lines of business.
Subject to certain exceptions, the Company may not incur additional
indebtedness unless, at the time of the incurrence, the ratio of earnings before
interest, income taxes, depreciation, depletion, amortization, and writedowns to
the sum of interest expense and capitalized interest is not less than 2.5 to 1.
One of the exceptions would permit the Company to incur additional indebtedness
under certain credit arrangements with financial institutions, so long as the
total amount of indebtedness outstanding under this exception does not exceed
the greater of: (i) $250 million; or (ii) an amount equal to the sum of $100
million plus 20% of the adjusted net tangible assets as defined in the indenture
agreement.
Redemption of 2002 Notes
The Company intends to use approximately $207 million of the net proceeds
from the sale of the 2007 Notes to redeem all of the Company's outstanding 2002
Notes. The remaining net proceeds will be used to fund the Company's future
capital expenditure plans as well as for general corporate purposes.
In October 2000, the Company gave notice of redemption of the 2002 Notes at
a price, including accrued interest, of $1,038.40 for each $1,000 note
outstanding, with a redemption date of November 3, 2000. The Company expects its
results of operations for the quarter ending December 31, 2000, will include an
extraordinary expense of approximately $7 million associated with the
extinguishment of the 2002 Notes.
F-45
164
SCHEDULE II
TRITON ENERGY LIMITED AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(In thousands)
ADDITIONS
-----------------------
BALANCE AT CHARGED TO BALANCE
BEGINNING CHARGED TO OTHER AT CLOSE
CLASSIFICATIONS OF YEAR EARNINGS ACCOUNTS DEDUCTIONS OF YEAR
- --------------- ---------- ---------- ---------- ---------- --------
Year ended Dec. 31, 1997:
Allowance for doubtful receivables..... $ 76 $ -- $-- $ (35) $ 41
========== ======== === ========== =======
Allowance for deferred tax assets...... $ 30,657 $ 44,435 $-- $ -- $75,092
========== ======== === ========== =======
Year ended Dec. 31, 1998:
Allowance for doubtful receivables..... $ 41 $ -- $-- $ (41) $ --
========== ======== === ========== =======
Allowance for deferred tax asset....... $ 75,092 $ 18,519 $-- $ -- $93,611
========== ======== === ========== =======
Year ended Dec. 31, 1999:
Allowance for deferred tax asset....... $ 93,611 $(11,925) $-- $ -- $81,686
========== ======== === ========== =======
F-46
165
[TRITON LOGO]
TRITON ENERGY LIMITED
OFFER TO EXCHANGE UP TO
$300,000,000 8 7/8% SENIOR NOTES DUE 2007
FOR
$300,000,000 8 7/8% SENIOR NOTES DUE 2007
THAT HAVE BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933