<PAGE> 1
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON NOVEMBER 12, 1999
REGISTRATION NO. 333-90235
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
AMENDMENT NO. 1
TO
FORM S-4
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
-------------------------
NUEVO ENERGY COMPANY
(Exact name of registrant as specified in its charter)
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DELAWARE 1311 76-0304436
(State or other jurisdiction of incorporation (Primary Standard Industrial (I.R.S. Employer
or organization) Classification Code Number) Identification Number)
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1021 MAIN, SUITE 2100, HOUSTON, TEXAS 77002
(713) 652-0706
(Address, including zip code, and telephone number,
including area code, of registrant's principal executive offices)
ROBERT M. KING
1021 MAIN, SUITE 2100, HOUSTON, TEXAS 77002
(713) 652-0706
(Name, address, including zip code, and telephone number, including
area code, of agent for service)
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Copies to:
GEORGE G. YOUNG III
HAYNES AND BOONE, L.L.P.
1000 LOUISIANA ST., SUITE 4300
HOUSTON, TEXAS 77002
TELEPHONE: (713) 547-2081
TELECOPY: (713) 547-2600
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APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE OF THE SECURITIES TO
THE PUBLIC: As soon as practicable after the Registration Statement becomes
effective
If the securities being registered on this Form are being offered in
connection with the formation of a holding company and there is compliance with
General Instruction G, check the following box: [ ]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act registration statement number of the earlier effective
registration statement number of the earlier effective registration statement
for the same offering.
---------------
If this Form is a post-effective amendment filed pursuant to Rule
462(d) under the Securities Act, check the following box and list the Securities
Act registration statement number of the earlier effective registration
statement for the same offering. [ ]
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CALCULATION OF REGISTRATION FEE
========================================================================================================================
TITLE OF EACH CLASS OF AMOUNT TO BE PROPOSED PROPOSED MAXIMUM AMOUNT OF
SECURITIES TO BE REGISTERED MAXIMUM OFFERING AGGREGATE OFFERING REGISTRATION FEE
REGISTERED PRICE PER UNIT PRICE
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9 1/2% Senior Subordinated
Notes due 2008................ $257,310,000 100% $257,310,000 $71,533 (1)
========================================================================================================================
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(1) Calculated in accordance with Rule 457(f)(2), fee previously paid.
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE
OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT
SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933, AS AMENDED, OR UNTIL THE REGISTRATION STATEMENT
SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID
SECTION 8(a), MAY DETERMINE.
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[LOGO] NUEVO ENERGY COMPANY
OFFER TO EXCHANGE
9 1/2% SENIOR SUBORDINATED NOTES DUE 2008, SERIES B
THAT HAVE BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933
FOR
ANY AND ALL OUTSTANDING
9 1/2% SENIOR SUBORDINATED NOTES DUE 2008, SERIES A
($257,310,000 IN PRINCIPAL AMOUNT OUTSTANDING)
THE EXCHANGE OFFER
o The exchange offer expires at 5:00 p.m., New York City time, on
December 15, 1999, unless extended.
o The exchange offer is not conditioned upon a minimum aggregate
principal amount of existing notes being tendered.
o All existing notes tendered according to the procedures in this
prospectus and not withdrawn will be exchanged for an equal principal
amount of exchange notes.
o The exchange offer is not subject to any condition other than that it
not violate applicable laws or any applicable interpretation of the
staff of the Securities and Exchange Commission.
THE EXCHANGE NOTES
o The terms of the exchange notes to be issued in the exchange offer are
substantially identical to the existing notes, except that we have
registered the exchange notes with the Securities and Exchange
Commission. In addition, the exchange notes will not be subject to the
transfer restrictions the existing notes are subject to, and
provisions relating to an increase in the stated interest rate on the
existing notes will be eliminated.
o The exchange notes will be senior subordinated obligations of Nuevo
Energy Company. They are subordinate to our senior debt. As of June
30, 1999, we had senior debt outstanding of approximately $120.0
million.
o Interest on the exchange notes will accrue from August 20, 1999 or, if
later, from the most recent date of payment of interest on the existing
notes, at the rate of 9 1/2% per year, payable semi-annually in arrears
on each June 1 and December 1.
------------------
YOU SHOULD CAREFULLY CONSIDER THE RISK FACTORS BEGINNING ON PAGE 15 OF
THIS PROSPECTUS BEFORE PARTICIPATING IN THE EXCHANGE OFFER.
------------------
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE
SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR
DETERMINED IF THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO
THE CONTRARY IS A CRIMINAL OFFENSE.
------------------
THE DATE OF THIS PROSPECTUS IS NOVEMBER 11, 1999.
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TABLE OF CONTENTS
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Page
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Where You Can Find More Information...............................................................................1
Forward-Looking Statements........................................................................................2
Summary...........................................................................................................3
Risk Factors.....................................................................................................15
Use of Proceeds..................................................................................................22
Capitalization...................................................................................................23
Selected Consolidated Financial Data.............................................................................24
Management's Discussion and Analysis of Financial Condition
and Results of Operations.......................................................................................27
Business and Properties..........................................................................................39
Beneficial Ownership of Our Common Stock.........................................................................53
Management.......................................................................................................55
Executive Compensation...........................................................................................59
The Exchange Offer...............................................................................................63
Description of the Exchange Notes................................................................................72
Registration Rights.............................................................................................112
Plan of Distribution............................................................................................113
Legal Matters...................................................................................................113
Experts.........................................................................................................113
Glossary of Oil and Gas Terms...................................................................................114
Index to Financial Statements....................................................................................F1
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WHERE YOU CAN FIND MORE INFORMATION
We file annual, quarterly and special reports, proxy statements and
other information with the SEC. Our SEC filings are available to the public
over the Internet at the SEC's web site at http://www.sec.gov. You may also
read and copy any document we file at the SEC's public reference room at 450
Fifth Street, N.W., Washington, D.C. 20549, and at the regional offices of the
SEC located at 7 World Trade Center, Suite 1300, New York, New York 10048 and
at 500 West Madison Street, Suite 1400, Chicago, Illinois 60661. You may obtain
information on the operation of the SEC's public reference room in Washington,
D.C. by calling the SEC at 1-800-SEC-0330. We also file information with the
New York Stock Exchange. Such reports, proxy statements and other information
may be read and copied at 30 Broad Street, New York, New York 10005.
This prospectus incorporates important business and financial
information about us that is not included in or delivered with this document.
You may request a copy of this information at no cost, by writing or telephoning
us at the following address:
Nuevo Energy Company
1021 Main, Suite 2100
Houston, Texas 77002
Attn: Corporate Secretary
Phone: (800) 364-0206
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THE EXCHANGE OFFER IS EXPECTED TO EXPIRE ON DECEMBER 15, 1999 AND YOU MUST
MAKE YOUR EXCHANGE DECISIONS BY THIS EXPIRATION DATE. TO OBTAIN TIMELY DELIVERY
OF THE REQUESTED INFORMATION, YOU MUST REQUEST THIS INFORMATION BY
DECEMBER 8, 1999, OR THE DATE THAT IS NO LATER THAN FIVE BUSINESS DAYS BEFORE
THE EXPIRATION DATE.
You should rely only on the information provided or incorporated by
reference in this prospectus or any supplement. We have not authorized anyone
else to provide you with different information. We are not making an offer of
these securities in any state where the offer is not permitted. You should not
assume that the information included or incorporated by reference in this
prospectus or any documents incorporated by reference herein is accurate as of
any date other than the date on the front of such documents.
FORWARD-LOOKING STATEMENTS
In this prospectus, we make forward-looking statements. We cannot
assure you that the plans, intentions or expectations upon which our
forward-looking statements are based will occur. Our forward-looking statements
are subject to risks, uncertainties and assumptions, including those discussed
elsewhere in this prospectus and the documents that are incorporated by
reference into this prospectus. Some of the risks which could affect our future
results and could cause results to differ materially from those expressed in
our forward-looking statements include:
o the volatility of oil and natural gas prices;
o the uncertainty of estimates of oil and natural gas reserves;
o the impact of competition;
o difficulties encountered during the exploration for and
production of oil and natural gas;
o the difficulties encountered in delivering oil and natural
gas to commercial markets;
o changes in customer demand;
o the uncertainty of our ability to attract capital;
o changes in the extensive government regulations regarding the
oil and natural gas business; and
o compliance with environmental regulations.
The information contained in this prospectus, including the
information set forth under the heading "Risk Factors," identifies additional
factors that could affect our operating results and performance. We urge you to
carefully consider those factors.
Our forward-looking statements are expressly qualified in their
entirety by this cautionary statement.
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SUMMARY
This summary highlights information from this prospectus, but does not
contain all material features of the exchange offer. For a complete description
of information which may be important to you, you should read this entire
document and the materials we have referred you to and consult with your own
legal and tax advisors. If you are not familiar with the terms used to describe
the quantities, present value and other information about oil and gas reserves,
please see "Glossary of Oil and Gas Terms."
In this prospectus, the words "we," "our," "ours," and "us" refer to
Nuevo Energy Company and, except as otherwise specified in this prospectus, to
our subsidiaries.
THE EXCHANGE OFFER
On August 20, 1999, we issued $257,310,000 of our 9 1/2% Senior
Subordinated Notes due 2008, Series A in exchange for $157,460,000 aggregate
principal amount of our 9 1/2% Senior Subordinated Notes due 2006 and
$99,850,000 aggregate principal amount of our 8 7/8% Senior Subordinated Notes
due 2008. The existing notes were issued to qualified institutional buyers and
institutional accredited investors in reliance upon the exemption from
registration provided by Regulation D under the Securities Act. In connection
with the issuance of the existing notes, we entered into a registration
agreement in which we agreed to deliver to you this prospectus and to use our
best efforts to complete the exchange offer or to file and cause to become
effective a registration statement covering the resale of the existing notes.
If the exchange offer is not completed by February 16, 2000 and if we have not
caused a registration statement covering the resale of the existing notes to
become effective by that date, the interest rate on the notes will be increased
by 0.5% per year for the 90 days subsequent to February 16, 1999. The interest
rate on the notes will be increased by an additional 0.25% per year for each
90-day period during which the exchange offer is not completed and the resale
registration statement is not effective. The maximum amount by which the
interest rate will be increased is 1% in total. After the exchange offer is
complete, you will no longer be entitled to any exchange or registration rights
for your notes. You should read the discussion under the heading "The Exchange
Offer" beginning on page 63 and "Description of the Exchange Notes" beginning
on page 72 for further information about the exchange notes.
The Exchange Offer........................ We are offering to exchange up to
$257,310,000 principal amount of
exchange notes for an identical
principal amount of existing notes.
Existing notes may be exchanged
only in $1,000 increments.
The terms of the exchange notes are
identical in all material respects
to the existing notes except that
the exchange notes have been
registered under the Securities
Act. Because we have registered the
exchange notes, the exchange notes
will not be subject to transfer
restrictions and holders of
exchange notes will have no
registration rights. Also, the
exchange notes will not contain
provisions for an increase in their
stated interest rate.
Resale ................................. We believe the notes issued in the
exchange offer may be offered for
resale, resold and otherwise
transferred by you without
compliance with the registration
and prospectus delivery provisions
of the Securities Act provided
that:
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o the exchange notes
received in the exchange
offer are acquired in
the ordinary course of
your business;
o you are not
participating and have
no understanding with
any person to
participate in the
distribution of the
exchange notes issued to
you in the exchange
offer; and
o you are not an affiliate
of ours.
Each broker-dealer issued exchange
notes in the exchange offer for its
own account in exchange for
existing notes acquired by the
broker-dealer as a result of
market-making or other trading
activities must acknowledge that it
will deliver a prospectus meeting
the requirements of the Securities
Act in connection with any resale
of the exchange notes issued in the
exchange offer. A broker-dealer may
use this prospectus for an offer to
resell, resale or other retransfer
of the exchange notes issued to it
in the exchange offer.
Expiration Date........................... 5:00 p.m., New York City time, on
December 15, 1999, unless we
extend the exchange offer. It is
possible that we will extend the
exchange offer until all existing
notes are tendered. You may
withdraw existing notes you
tendered at any time before 5:00
p.m., New York City time, on the
expiration date. See "The Exchange
Offer--Expiration Date; Extensions;
Amendments."
Accrued Interest on the
Exchange Notes and the
Existing Notes....................... The exchange notes will bear
interest from August 20, 1999 or, if
later, from the most recent date of
payment of interest on the existing
notes, at a rate of 9 1/2% per year,
payable semi-annually on June 1 and
December 1. May 15 and November 15
are the record dates for determining
holders entitled to interest
payments.
Conditions to the Exchange
Offer................................ The exchange offer is subject only
to the following conditions:
o the compliance of the
exchange offer with
securities laws;
o the proper tender of the
existing notes;
o the representation by
the holders of the
existing notes that they
are not our affiliate,
that the exchange notes
they will receive are
being acquired by them
in the ordinary course
of their business and
that at the time the
exchange offer is
completed the holder had
no plan to participate
in the distribution of
the exchange notes; and
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o no judicial or
administrative
proceeding shall have
been threatened that
would limit us from
proceeding with the
exchange offer.
Procedures for Tendering Existing
Notes Held in the Form of
Book-Entry Interests................. The existing notes were issued as
global securities and were
deposited with State Street Bank
and Trust Company when they were
issued. State Street Bank and Trust
Company issued a certificateless
depositary interest in each note,
which represents a 100% interest in
the note, to The Depository Trust
Company. Beneficial interests in
the notes held by participants in
DTC, which we will refer to as
notes held in book-entry form, are
shown on, and transfers of the
notes can be made only through,
records maintained in book-entry
form by DTC and its participants.
If you are a holder of an existing
note held in the form of a
book-entry interest and you wish to
tender your book-entry interest for
exchange in the exchange offer, you
must transmit to State Street Bank
and Trust Company, as exchange
agent, at the address on the cover
page of the letter of transmittal,
before the expiration date of the
exchange offer, the following:
EITHER
o a properly completed and
executed letter of
transmittal, which
accompanies this
prospectus, or a
facsimile of the letter
of transmittal,
including all other
documents required by
the letter of
transmittal; or
o a computer-generated
message transmitted by
means of DTC's Automated
Tender Offer Program
(ATOP) system that, when
received by the exchange
agent will form a part
of a confirmation of
book-entry transfer in
which you acknowledge
and agree to be bound by
the terms of the letter
of transmittal;
AND, EITHER
o a timely confirmation of
book-entry transfer of
your existing notes into
the exchange agent's
account at DTC,
according to the
procedure for book-entry
transfers described in
this prospectus under
the heading "The
Exchange
Offer--Procedures for
Tendering--Existing
Notes Held in Book-Entry
Form", must be received
by the exchange agent on
or prior to the
expiration date; or
o the documents necessary
for compliance with the
guaranteed delivery
procedures described
below.
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Procedures for Tendering
Existing Notes Held in
Certificated Form.................... If you hold your existing notes in
certificated form and wish to
accept the exchange offer, sign and
date the letter of transmittal, and
deliver the letter of transmittal,
along with certificates for the
existing notes and any other
required documentation, to the
exchange agent on or before the
expiration date.
Representations and
Warranties........................... By executing the letter of
transmittal or by being deemed to
have executed the letter of
transmittal by tendering through
ATOP, you represent to us that,
among other things:
o the exchange notes you
receive will be acquired
in the ordinary course
of your business;
o you have no arrangement
with any person to
participate in the
distribution of the
exchange notes; and
o you are not an affiliate
of ours or, if you are
an affiliate, you will
comply with the
registration and
prospectus delivery
requirements of the
Securities Act to the
extent applicable.
Special Procedures for
Beneficial Owners.................... If you are a beneficial owner whose
existing notes are registered in
the name of a broker, dealer,
commercial bank, trust company or
other nominee and wish to tender
those existing notes in the
exchange offer, please contact the
registered holder as soon as
possible and instruct them to
tender on your behalf and comply
with the instructions in this
prospectus.
Guaranteed Delivery
Procedures........................... If you are unable to deliver the
existing notes, the letter of
transmittal or any other required
documents to the exchange agent
prior to the expiration date, you
may tender your existing notes
according to the guaranteed
delivery procedures described in
this prospectus under the heading
"The Exchange Offer--Guaranteed
Delivery Procedures."
Withdrawal Rights......................... You may withdraw existing notes you
tendered by furnishing a notice of
withdrawal to the exchange agent or
by complying with applicable ATOP
procedures at any time before 5:00
p.m. New York City time on the
expiration date. See "The Exchange
Offer--Withdrawal of Tenders."
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Acceptance of Existing
Notes and Delivery
of Exchange Notes.................... If the conditions described under
"The Exchange Offer--Conditions"
are satisfied, we will accept for
exchange any and all existing notes
that are properly tendered before
the expiration date. See "The
Exchange Offer--Procedures for
Tendering." If we close the
exchange offer, the exchange notes
will be delivered promptly
following the expiration date.
Otherwise, we will promptly return
any existing notes tendered.
Exchange Agent............................ State Street Bank and Trust Company
is serving as exchange agent for
the exchange offer. The address for
the exchange agent is listed under
"The Exchange Offer--Exchange
Agent." If you would like more
information about the exchange
offer, you should call the exchange
agent at (617) 662-1525. The
facsimile number for the exchange
agent is (617) 662-1452.
See "The Exchange Offer" for more detailed information concerning the terms of
the exchange offer.
TERMS OF THE EXCHANGE NOTES
The form and terms of the exchange notes to be issued in the exchange
offer are the same as the form and terms of the existing notes except that the
exchange notes will be registered under the Securities Act and, accordingly,
will not bear legends restricting their transfer. The notes issued in the
exchange offer will evidence the same debt as the existing notes, and both the
existing notes and the exchange notes are governed by the same indenture.
Title..................................... 9 1/2% Senior Subordinated Notes
due 2008, Series B.
Maturity Date............................. June 1, 2008.
Interest Payment Dates.................... June 1 and December 1 of each year,
commencing on December 1, 1999.
Optional Redemption....................... We may redeem up to one-third of
the exchange notes prior to June 1,
2001 from the proceeds of one or
more bona fide underwritten sales
to the public of our common stock
at a redemption price of 109.5% of
the principal amount. Otherwise, we
will not have the right to redeem
the exchange notes until June 1,
2003, after which we may redeem the
exchange notes if we pay the
redemption premium described under
"Description of the Exchange
Notes--Redemption at the Option of
Nuevo."
Subordination............................. The exchange notes will be
unsecured senior subordinated
obligations of ours. The payment of
the principal of, and premium and
interest on, the exchange notes
will be subordinated in right of
payment to the payment of all of
our current and future senior
indebtedness to the same extent as
the existing notes are subordinated
to senior indebtedness. In
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addition, the exchange notes will
be structurally subordinated to the
liabilities of our subsidiaries.
For a description of the terms and
possible effects of subordination,
see "Risk Factors" and "Description
of the Exchange
Notes--Subordination." At June 30,
1999, we had $120.0 million of
outstanding senior indebtedness and
our subsidiaries had liabilities on
their balance sheets of $106.6
million. The exchange notes will
rank equally with:
o any of the existing
notes not acquired by us
in the exchange offer;
o our 9 1/2% Senior
Subordinated Notes due
2006; and
o our 8 7/8% Senior
Subordinated Notes due
2008.
As of September 1, 1999, there was
outstanding $2,540,000 and $150,000
principal amount of our 9 1/2%
notes due 2006 and our 8 7/8% notes
due 2008, respectively. The
indenture for the exchange notes
will permit us to incur additional
indebtedness, including
indebtedness that ranks senior in
right of payment to the exchange
notes.
Change of Control......................... If a change of control occurs, we
will be required to offer to
repurchase the exchange notes for
cash in the amount of 101% of the
principal amount of the exchange
notes plus accrued and unpaid
interest. For a description of a
change of control, see "Description
of the Exchange Notes--Repurchase
at the Option of the
Holders--Change of Control." Our
bank credit facility currently
prohibits us from purchasing any of
the exchange notes, which would
include any purchase we may be
required to make pursuant to a
change of control offer. We cannot
assure you that we will be able to
amend the bank credit facility to
permit the purchase of exchange
notes or refinance the bank credit
facility with lendors who will
allow us to make the required
purchases. Also, if a change of
control were to occur, there can be
no assurance that we will have
sufficient funds to purchase any of
the exchange notes or be permitted
under the terms of other agreements
to purchase the exchange notes. See
"Risk Factors" for a description of
the possible effects if we are
unable to purchase the exchange
notes upon a change of control.
Exchange Notes Covenants.................. The indenture governing the
exchange notes contains covenants
that limit our ability to, among
other things:
o incur additional
indebtedness;
o pay dividends and
repurchase our capital
stock;
o enter into transactions
with our affiliates;
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<PAGE> 11
o dispose of assets; and
o engage in mergers and
consolidations.
These covenants are subject to
important exceptions and
qualifications which are described
under "Description of the Exchange
Notes--Material Covenants."
Risk Factors.............................. See "Risk Factors" for a discussion
of factors you should carefully
consider before deciding to invest
in the exchange notes.
ABOUT NUEVO
We are an independent oil and gas company. Our properties are
concentrated in California, where we are the largest independent producer, with
properties located both onshore and offshore. Our onshore California properties
are located primarily in the San Joaquin, Los Angeles and Ventura Basins. Our
offshore California properties are located in the Santa Barbara Channel and
offshore Long Beach. We also own properties in the onshore Gulf Coast region
and internationally offshore the Republics of Congo and Ghana in West Africa
and onshore in Tunisia. Since our inception in 1990, we have expanded our
operations through a series of disciplined, low-cost acquisitions of oil and
gas properties and the subsequent exploitation and development of these
properties. We have complemented these efforts with strategic divestitures and
an opportunistic exploration program which provides exposure to prospects with
the potential to add substantially to our growth.
At June 30, 1999, our estimated net proved reserves were 297.4 MMBOE,
of which 75% were proved developed. On a pro forma basis, assuming we had closed
the Star acquisition described below on January 1, 1999, average daily net
production would have been approximately 61.0 MBOE per day during the first half
of 1999. Approximately 85% of this pro forma production on a BOE basis was
attributable to our California properties, while our Gulf Coast area properties
and West Africa properties represented approximately 6% and 9%, respectively, of
this pro forma production. Additionally, our production during the first half of
1999 was 38% light and medium grades of oil and refined products, 48% heavy oil
and 14% natural gas. As of June 30, 1999, we operated properties representing
approximately 85% of our estimated net proved reserves on a BOE basis.
BUSINESS STRATEGY
Our business strategy consists of the following:
o dedication to a management philosophy that frames important
decisions in terms of anticipated impact on per share, rather
than absolute, growth in reserves, production, cash flows and
net asset value;
o maintenance of a sound capital structure that allows us to
implement a contrarian investment orientation;
o the outsourcing of non-strategic functions;
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<PAGE> 12
o the alignment of employee compensation with shareholder
objectives; and
o a commitment to an exemplary corporate governance structure
which reinforces the view of Nuevo as a conduit for
stockholders to achieve superior long term capital gains.
BUSINESS STRENGTHS
We believe that the following strengths provide us with significant
competitive advantages.
Timely Acquisitions and Divestitures of Properties. We have
demonstrated an ability to make acquisitions of producing properties with
significant exploitation or exploration opportunities at favorable prices and
have shown discipline in avoiding acquisitions in high-priced markets. We also
seek to divest properties in order to take advantage of strong markets and to
redeploy capital into higher return alternatives. For example, in the first six
months of 1999, we sold our East Texas properties described under "--Recent
Developments" and redeployed a portion of the proceeds in the Star acquisition.
Record of Reserve Growth at Low Finding Costs. Between December 31,
1996 and June 30, 1999, our estimated net proved reserves increased 18% on both
an aggregate and a per share basis, from 251.8 MMBOE to 297.4 MMBOE, at an
average finding cost of $2.83 per BOE. Over this period, our finding costs from
exploration and exploitation per BOE have averaged $2.87 domestically and $9.93
internationally, while our average finding costs from acquisitions were $1.84
per BOE.
Exploitation Projects. We have an inventory of over five years of low
risk exploitation projects which have the potential to significantly increase
reserves. Despite a significantly reduced capital budget in response to low oil
prices, between January 1, 1998 and June 30, 1999, we replaced 282% of our
production through exploitation and exploration.
Long-Lived Production Profile. Our properties are long-lived with a
reserve life index of 14.6 years as of June 30, 1999. This reduces
re-investment risk and adds stability to long term cash flows.
Low Cost Structure. We believe that we have the ability to
significantly reduce operating costs on acquired properties from levels
experienced by prior operators. For example, the lease operating expense per
BOE for the properties acquired in April 1996 from Union Oil Company of
California was reduced from $6.40 in the first quarter of 1996 to $5.94 for the
year ended December 31, 1998 despite an increase in prices for natural gas used
as an energy source in our thermal oil operations and other service costs
during this period. Additionally, we aggressively outsource many day to day
functions to third party service providers, allowing us to maintain a low cost
structure and permitting our executive management team to focus on strategic
decisions.
Preservation of a Sound Capital Structure. We believe that our
contrarian acquisition strategy requires that we maintain a strong capital
structure. Accordingly, as of June 30, 1999 our long term debt was $1.28 per
BOE, which is among the lowest in the industry. During the recent period of
depressed oil prices, our strong capital structure allowed us to maintain
significant liquidity in the form of unused commitments under our bank credit
facility.
Reduction of Commodity Price Risk Exposure. We have implemented a
hedging policy designed to reduce our near term exposure to fluctuating oil
prices. This hedging policy is designed to enhance the stability of our cash
flows, assure us of internal funding for capital projects, improve our debt
capacity and reduce the volatility of our interest coverage ratios. We have
entered into oil
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<PAGE> 13
hedges equal to 67% of our forecasted production in the second half of 1999,
and 60% of our forecasted oil production in 2000.
RECENT DEVELOPMENTS
East Texas Sale. In January 1999, we sold properties in East Texas for
$192.0 million. Reserves attributable to the East Texas properties were
primarily natural gas. The estimated net proved reserves of these properties
were 329 Bcfe on December 31, 1998. We placed $100.0 million of the proceeds of
this sale in an escrow account to facilitate like-kind exchange tax treatment
for any properties we acquired in the first six months of 1999. Of these
escrowed proceeds, $61.4 million were used to fund the Star acquisition. We
used the remaining net proceeds from this sale plus amounts remaining in escrow
after the Star acquisition to reduce amounts outstanding under our bank credit
facility.
Star Acquisition. In June 1999, we acquired oil properties located
onshore and offshore California for $61.4 million from Texaco, Inc. The
acquired properties had estimated net proved reserves at June 30, 1999 of 33.7
MMBOE and will increase our production from California by approximately 5.0
MBOE per day. All of these properties are additional interests in our existing
properties or are located near our existing properties. The acquisition
includes interests in the Cymric, the East Coalinga, the Dos Cuadras and other
fields we operate.
Recovery of Oil Prices. The price for crude oil on the New York
Mercantile Exchange for near month contracts increased from $12.09 per Bbl at
December 31, 1998 to $19.29 per Bbl at June 30, 1999. Our estimated net proved
reserves would have increased 61.8 MMBOE during the first six months of 1999,
without including the effect of acquisitions and divestitures.
PRINCIPAL OFFICE
Our principal executive offices are located at 1021 Main, Suite 2100,
Houston, Texas 77002 and our telephone number is (713) 652-0706.
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<PAGE> 14
SUMMARY CONSOLIDATED FINANCIAL DATA
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
--------------------------------------------------- -----------------------
ACTUAL PRO FORMA ACTUAL
------------------------------------- --------- -----------------------
1996(1) 1997(1) 1998 1998(2) 1998 1999
--------- --------- --------- --------- --------- ---------
(UNAUDITED) (UNAUDITED)
(IN THOUSANDS, EXCEPT RATIOS)
<S> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas revenues ......................... $ 279,859 $ 331,973 $ 240,010 $ 214,195 $ 123,045 $ 95,052
Gain on sale of assets, net .................. 6,008 1,372 5,768 5,768 1,677 80,312
Other ........................................ 43,190 23,933 6,925 6,925 4,451 4,139
--------- --------- --------- --------- --------- ---------
Total revenues ................................. 329,057 357,278 252,703 226,888 129,173 179,503
--------- --------- --------- --------- --------- ---------
Costs and expenses:
Operating expenses ........................... 128,478 138,641 139,934 132,650 69,039 60,355
Provision for impairment of oil and
gas properties(3) ......................... -- 30,000 68,904 68,904 -- --
Provision for (revision of) impairment
of assets held for sale(4) ................ -- 23,942 (3,740) (3,740) -- --
Exploration costs ............................ 4,571 11,082 16,562 16,562 2,331 9,999
Depreciation, depletion and
amortization .............................. 75,664 102,158 85,036 81,695 46,556 46,257
General and administrative expenses .......... 14,880 19,822 18,633 18,633 8,526 7,199
Outsourcing fees ............................. 10,249 11,984 9,461 8,157 7,199 6,846
Interest expense ............................. 36,009 27,357 32,471 25,350 14,444 16,400
Dividends on TECONS(5) ....................... 165 6,613 6,613 6,613 3,306 3,306
Other expense ................................ 1,069 3,019 5,726 5,726 1,846 2,836
--------- --------- --------- --------- --------- ---------
Income (loss) before income taxes, minority
interest and extraordinary item .............. 57,972 (17,340) (126,897) (133,662) (24,074) 26,305
Net income (loss)(6) ........................... 34,278 (13,700) (94,272) (99,303) (14,204) 15,784
STATEMENT OF CASH FLOWS DATA:
Net cash flows provided by (used in)
operating activities ......................... $ 126,921 $ 165,462 $ 35,833 N/A $ 21,917 $ (13,156)
Net cash flows (used in) provided by
investing activities ......................... (546,002) (169,478) (148,335) N/A (94,603) 99,642
Net cash flows provided by (used in)
financing activities ......................... 426,952 (412) 110,697 N/A 69,842 (40,250)
OTHER FINANCIAL DATA:
Capital expenditures:
Acquisitions ................................. $ 492,603 $ 10,206 $ 10,733 $ 10,733 $ 7,810 $ 61,416
Other ........................................ 89,743 185,689 152,541 135,508 94,285 36,695
--------- --------- --------- --------- --------- ---------
Total ........................................ $ 582,346 $ 195,895 $ 163,274 $ 146,241 $ 102,095 $ 98,111
========= ========= ========= ========= ========= =========
EBITDAX(7) ..................................... $ 168,373 $ 182,440 $ 73,181 $ 55,954 $ 40,886 $ 21,955
Ratio of earnings to fixed charges (8) ......... 2.6x -- -- -- -- 2.3x
Ratio of EBITDAX to interest expense(9) ....... 4.7x 6.7x 2.3x 2.2x 2.8x 1.3x
Ratio of EBITDAX to interest expense
and TECON dividends .......................... 4.7x 5.4x 1.9x 1.8x 2.3x 1.1x
Ratio of total debt to EBITDAX(10) ............. 1.7x 1.7x 5.8x 5.9x N/A N/A
</TABLE>
<TABLE>
<CAPTION>
AS OF
JUNE 30, 1999
-------------
<S> <C>
BALANCE SHEET DATA:
Working capital............................................................................. $ 55,917
Total assets................................................................................ 790,274
Total debt.................................................................................. 382,051
Stockholders' equity........................................................................ 247,782
</TABLE>
(See footnotes on the following page)
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<PAGE> 15
- ------------------
(1) Effective January 1, 1998, we changed our method of accounting for our
investments in oil and gas properties from the full cost method to the
successful efforts method. All prior years' financial statements
presented in this memorandum have been restated to reflect this
change. A more detailed explanation of the successful efforts method
of accounting and the effect of the change on our financial statements
is set forth under "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and note 2 to the consolidated
financial statements for the year ended December 31, 1998 included in
our Form 10-K for the year ended December 31, 1998. See "Where You Can
Find More Information."
(2) In January 1999, we sold properties in East Texas. Pro forma
information gives effect to the sale as if it occurred January 1,
1998. Pro forma information is not necessarily indicative of future
results.
(3) We incurred an impairment of $68.9 million at December 31, 1998 and
$30.0 million at December 31, 1997 on our oil and gas properties due
to decreased crude oil prices. For more information with respect to
impairment expense, see note 2 to the consolidated financial
statements for the year ended December 31, 1998, included in our Form
10-K.
(4) The provision for impairment of assets held for sale reflects a charge
we took to write down our midstream assets to their fair value in
1997. These assets are primarily gas pipelines and processing plants.
The impairment represents our estimate of the difference between the
book value of these assets and the amount we expect to receive when we
sell the assets.
(5) TECONS are the Company Obligated Mandatorily Redeemable Convertible
Preferred Securities of our financing subsidiary, Nuevo Financing I.
The principal assets of Nuevo Financing I are $115.0 million of our
5 3/4% convertible subordinated debentures due December 15, 2026.
Interest we pay on the 5 3/4% debentures to Nuevo Financing I are paid
by Nuevo Financing I as dividends on the TECONS.
(6) During 1997, we redeemed our 12 1/2% senior subordinated notes prior
to maturity and recorded $3.0 million as our extraordinarily loss on
early extinguishment of debt, net of income tax benefit.
(7) The term "EBITDAX" means earnings before interest, dividends on
TECONS, taxes, depreciation, depletion and amortization, property
impairment, gain/loss on sale and exploration costs. EBITDAX is
included because it is commonly used as a measure of a company's
ability to incur indebtedness. EBITDAX should not be used as a
substitute for cash flow from operating activities or other income or
cash flow information prepared in accordance with generally accepted
accounting principles as an indication of profitability or liquidity.
EBITDAX may not be comparable to similarly titled items of other
companies.
(8) When we calculate our ratio of earnings to fixed charges, earnings
means income or loss before income taxes and fixed charges. Fixed
charges means the sum of the following:
o interest expense;
o dividends on the TECONS;
o amortization of debt issuance costs; and
o the portion of operating leases deemed to be representative
of interest.
Earnings were not sufficient to cover fixed charges for 1997 and 1998
by $19.5 million and $127.5 million, respectively, and for the six
months ended June 30, 1998 by $24.6 million.
(9) For purposes of this calculation, interest expense does not include
dividends on the TECONS.
(10) Total debt does not include the TECONS.
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<PAGE> 16
SUMMARY OPERATING AND RESERVE DATA
<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
----------------------------------------
1996 1997 1998 1999
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Estimated Net Proved Reserves:
Oil (MBbls) .......................................... 186,053 227,264 190,141 272,266
Gas (MMcf) ........................................... 394,630 390,691 403,256 150,713
Oil equivalent (MBOE) ................................ 251,825 292,379 257,350 297,385
Pretax discounted present value (in thousands) ....... $1,358,581 $ 901,107 $ 299,933 $ 836,002
Percent of proved developed reserves ................. 71% 68% 72% 75%
Reserve life index (in years) ........................ 13.2 12.5 10.6 14.6
Reserve Replacement Data:
Three year average finding costs per BOE(1)
Domestic ........................................... $ 3.03 $ 2.83 $ 3.54 $ 2.58
International ...................................... $ 1.16 $ 1.42 $ 6.80 $ 7.15
Total .............................................. $ 2.85 $ 2.70 $ 3.66 $ 2.83
Three year average production replacement ratio(1) ... 735% 584% 380% 279%
</TABLE>
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
--------------------------------------------- ---------------------
PRO
ACTUAL FORMA(2) ACTUAL
--------------------------------------------- ---------------------
1996 1997 1998 1998 1998 1999
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Production Data:
Oil (MBbls)(3) ............................... 13,344 17,409 18,806 18,718 9,364 8,757
Gas (MMcf) ................................... 34,775 35,625 32,521 19,471 16,736 8,227
Oil equivalent (MBOE) ........................ 19,140 23,347 24,226 21,963 12,154 10,128
Average Sales Price Per Unit(4):
Oil (per Bbl) ................................ $ 15.84 $ 14.86 $ 9.25 $ 9.23 $ 9.48 $ 9.07
Gas (per Mcf) ................................ $ 2.08 $ 2.06 $ 2.00 $ 2.10 $ 2.01 $ 1.87
Oil and Gas Operating Income per BOE:
Revenues ..................................... $ 14.62 $ 14.22 $ 9.91 $ 9.75 $ 10.12 $ 9.39
Operating expenses (including severance
taxes) ..................................... 4.86 5.14 5.56 5.80 5.41 5.71
Exploration costs ............................ 0.24 0.47 0.68 0.75 0.19 0.99
General and administrative expenses (5) ..... 1.31 1.36 1.16 1.22 1.29 1.39
Depreciation, depletion and amortization ..... 3.72 4.23 3.45 3.65 3.77 4.49
-------- -------- -------- -------- -------- --------
Operating income (loss) ...................... $ 4.49 $ 3.02 $ (0.94) $ (1.67) $ (0.54) $ (3.19)
======== ======== ======== ======== ======== ========
</TABLE>
- ------------------
(1) The reserve replacement data and production replacement ratio for June
30, 1999 represent averages over the two years and six months ended
June 30, 1999.
(2) We sold properties in East Texas in January 1999 as described under
"--Recent Developments," above. These properties had estimated net
proved reserves at December 31, 1998 of 329 Bcfe. Pro forma
information gives effect to this sale as if it occurred January 1,
1998.
(3) Includes natural gas liquids.
(4) Average sale prices include the effects of hedging.
(5) Our general and administrative expenses per BOE include outsourcing
fees.
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<PAGE> 17
RISK FACTORS
You should carefully consider all of the information we have included
in this prospectus and the documents we have incorporated by reference before
tendering your existing notes.
OUR SIGNIFICANT DEBT LEVELS AND OUR DEBT COVENANTS MAY LIMIT OUR FUTURE
FLEXIBILITY IN OBTAINING ADDITIONAL FINANCING AND IN PURSUING BUSINESS
OPPORTUNITIES.
As of June 30, 1999, we had approximately $380.0 million in long-term
debt, excluding current maturities. The level of our indebtedness will have
important effects on our future operations, including:
o A portion of our cash flow will be used to pay interest and
principal on our debt and will not be available for other
purposes.
o Our bank credit facility contains financial tests which we
must satisfy in order to avoid a default under our bank
credit facility.
o Covenants in the new notes, our existing senior subordinated
notes and our bank credit facility require us to meet
financial tests in order to borrow additional money, which
may have the effect of limiting our flexibility in reacting
to changes in our business and our ability to fund future
operations and acquisitions.
o Our ability to obtain additional financing for capital
expenditures and other purposes may be limited.
SINCE THE EXCHANGE NOTES ARE SUBORDINATED TO SENIOR DEBT, THERE MAY NOT BE
SUFFICIENT ASSETS TO PAY AMOUNTS OWED ON THE EXCHANGE NOTES IF A DEFAULT
OCCURS.
The exchange notes will be subordinated to our current and future
senior debt. In addition, the exchange notes will rank equally with our
existing and future senior subordinated indebtedness and will be subordinated
to the obligations of our subsidiaries. Upon a liquidation or in a bankruptcy
or other similar proceeding, the holders of our senior debt will be entitled to
be paid in full before any payment may be made to the holders of the exchange
notes. In addition, creditors of our subsidiaries will be paid prior to any use
of our subsidiaries' assets to make payments on the exchange notes. As a
result, the holders of exchange notes may receive less, proportionately, than
the holders of senior debt. We cannot assure you that we will have sufficient
assets to pay amounts due on the exchange notes. Our indenture for the exchange
notes will permit us to incur additional debt in the future, including the
entire amount that will be available for borrowing under our bank credit
facility.
YOU MAY SUFFER ADVERSE CONSEQUENCES IF YOU DO NOT EXCHANGE EXISTING NOTES.
The existing notes that are not exchanged for exchange notes have not
been registered with the SEC or in any state. Unless the existing notes are
registered, they may only be offered and sold pursuant to an exemptions from,
or in a transaction that is not subject to, the registration requirements of
the Securities Act. Depending upon the percentage of existing notes exchanged
for exchange notes, the liquidity of the existing notes may be adversely
affected.
WE MAY NOT BE ABLE TO REPURCHASE EXCHANGE NOTES UPON A CHANGE OF CONTROL.
If a change of control occurs, each holder of exchange notes will have
the right to require us to repurchase all or any part of that holder's exchange
notes as described under "Description of the Exchange Notes--Repurchase at the
Option of Holders--Change of Control." Our bank credit facility
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<PAGE> 18
prohibits the repurchase of the exchange notes. In order to repurchase the
exchange notes, we would be required to repay our debt under our bank credit
facility or obtain consents from our bank lenders. If we cannot repay the bank
credit facility or obtain the consents, we would not be able to repurchase the
exchange notes. Also, we may not have sufficient funds available or be able to
obtain the financing necessary to repurchase the exchange notes.
If a change of control occurs and we do not offer to repurchase the
exchange notes or if we do not repurchase the exchange notes when we are
required to, an event of default will occur under the indenture governing the
exchange notes, which would also be a default under our bank credit facility.
Each of these defaults could have a material adverse effect on us and the
holders of the exchange notes.
OIL AND GAS PRICES ARE VOLATILE AND WERE DEPRESSED RECENTLY.
Our success is highly dependent on prices for oil and gas, which are
extremely volatile. Beginning in 1997 and continuing through earlier this year,
the prices we received for our production declined, especially for oil. Any
substantial or extended decline in the price of oil would have a material
adverse effect on us. Oil and gas markets are both seasonal and cyclical. The
prices of oil and gas depend on factors we cannot control such as weather,
economic conditions and government actions. Prices of oil and gas will affect
the following aspects of our business:
o our revenues, cash flows and earnings;
o our ability to attract capital to finance our operations and
the cost of the capital;
o the amount we are allowed to borrow under our bank credit
facility;
o the value of our oil and gas properties; and
o the profit or loss we incur in exploring for and developing
our reserves.
OUR CALIFORNIA HEAVY OIL PRODUCTION MAY INCREASE OUR SUSCEPTIBILITY TO OIL
PRICE VOLATILITY.
The price we receive for heavy oil is lower than for lighter oil. In
addition, the difference between the prices we receive for California heavy oil
and our production costs are less than for lighter grades. As a result, the
effect of a decrease in the price of oil will more adversely affect the
profitability of heavy oil compared with lighter oil.
WE MAY BE UNABLE TO REPLACE RESERVES WHICH WE HAVE PRODUCED.
Our future success depends upon our ability to find, develop and
acquire additional oil and gas reserves that are economically recoverable.
Without successful exploration, exploitation or acquisition activities, our
reserves and revenues will decline. We cannot assure you that we will be able
to find and develop or acquire additional reserves at an acceptable cost.
WE MAY NOT BE SUCCESSFUL IN ACQUIRING AND DEVELOPING OIL AND GAS PROPERTIES.
The successful acquisition and development of oil and gas properties
requires an assessment of recoverable reserves, future oil and gas prices and
operating costs, potential environmental and other liabilities and other
factors. Such assessments are necessarily inexact. As a result, we may not
recover the purchase price of a property from the sale of production from the
property, or may not recognize an acceptable return from properties we
acquired. In addition, we cannot assure you that
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<PAGE> 19
our exploitation and development activities will result in any increases in
reserves. Our operations may be curtailed, delayed or canceled as a result of
lack of adequate capital and other factors, such as title problems, weather,
compliance with governmental regulations or price controls, mechanical
difficulties or shortages or delays in the delivery of equipment. In addition,
the costs of exploitation and development may materially exceed initial
estimates.
WE MAY NOT BE ABLE TO MAKE ACQUISITIONS OR GENERATE CASH FLOWS IF WE ARE UNABLE
TO RAISE CAPITAL.
We will be required to make substantial capital expenditures to
develop our existing reserves and to discover new oil and gas reserves.
Historically, we have financed these expenditures primarily with cash from
operations, proceeds from bank borrowings and proceeds from the sale of debt
and equity securities. We cannot assure you that we will be able to raise
capital in the future. We also make offers to acquire oil and gas properties in
the ordinary course of our business. If these offers are accepted, our capital
needs may increase substantially.
INFORMATION IN THIS PROSPECTUS REGARDING OUR FUTURE EXPLOITATION AND
EXPLORATION PROJECTS REFLECTS OUR CURRENT INTENT AND IS SUBJECT TO CHANGE.
We describe our current exploitation and exploration plans in this
prospectus and the materials incorporated by reference in this prospectus.
Whether we ultimately undertake an exploitation or exploration project will
depend on the following factors:
o availability and cost of capital;
o receipt of additional seismic data or the reprocessing of
existing data;
o material changes in oil or gas prices;
o the costs and availability of drilling rigs and other
equipment, supplies and personnel necessary to conduct these
operations;
o success or failure of activities in similar areas;
o changes in the estimates of the costs to complete the
projects;
o our ability to attract other industry partners to acquire a
portion of the working interest to reduce exposure to costs
and risks; and
o decisions of our joint working interest owners.
We will continue to gather data about our projects, and it is possible
that additional information may cause us to alter our schedule or determine
that a project should not be pursued at all. You should understand that our
plans regarding our projects are subject to change.
YOU SHOULD NOT PLACE UNDUE RELIANCE ON RESERVE INFORMATION BECAUSE RESERVE
INFORMATION REPRESENTS ESTIMATES.
Estimating quantities of proved reserves is inherently imprecise and
involves uncertainties and factors beyond our control. The reserve data in this
prospectus represent only estimates. Such estimates are based upon assumptions
about future production levels, future oil and gas prices and future operating
costs. As a result, the quantity of proved reserves may be subject to downward
or
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<PAGE> 20
upward adjustment. In addition, estimates of the economically recoverable oil
and gas reserves, classifications of such reserves, and estimates of future net
cash flows, prepared by different engineers or by the same engineers at
different times, may vary substantially. Information about reserves constitutes
forward-looking information. See "Forward-Looking Statements." Estimates as of
June 30, 1999 included in this prospectus are estimates prepared by our
internal staff of engineers and were not reviewed by our independent reserve
engineers. See "Experts."
WEATHER, UNEXPECTED SURFACE CONDITIONS, AND OTHER UNFORESEEN OPERATING HAZARDS
MAY ADVERSELY IMPACT OUR OIL AND GAS ACTIVITIES.
There are many operating hazards in exploring for and producing oil
and gas, including:
o our drilling operations may encounter unexpected formations
or pressures which could cause damage to equipment or
personal injury;
o we may experience equipment failure which curtails or stops
production; and
o we could experience blowouts or other damages to the
productive formations which may require a well to be
re-drilled or other corrective action to be taken.
In addition, any of the foregoing may result in environmental damages
or personal injury for which we will be liable. Moreover, our offshore
operations are subject to a variety of risks peculiar to the marine environment
such as hurricanes and other adverse weather conditions. Offshore operations
are also subject to more extensive governmental regulations.
We cannot assure you that we will be able to maintain adequate
insurance at rates we consider reasonable to cover our possible losses from
operating hazards. The occurrence of a significant event not fully insured or
indemnified against could materially and adversely affect our financial
condition and results of operations.
THE RECENT DEPRESSED FINANCIAL CONDITIONS IN THE OIL AND GAS INDUSTRY MAY
CHANGE EXPLORATION AND DEVELOPMENT PLANS OR CAUSE DIFFICULTIES IN FINANCING
ACTIVITIES.
The low prices for oil and gas during 1998 and the first half of 1999
have limited the access of many independent oil and gas companies to the
capital necessary to finance activities. As a result, the decision not to drill
or complete a well may be based on a lack of available capital rather than the
quality of the project. Most oil companies have substantially reduced their
capital budgets for 1999 and 2000.
In addition, some of the other working interest owners of our wells
may be unwilling or unable to pay their share of the costs or projects as they
become due. At worst, a working interest owner may declare bankruptcy and
refuse or be unable to pay its share of the cost of a project. In such cases,
we could be required to pay other working interest owners' share of the costs.
TURMOIL IN FOREIGN COUNTRIES MAY AFFECT OUR FOREIGN INVESTMENTS.
Our foreign investments involve risks typically associated with
investments in emerging markets, including:
o we may experience political instability in the countries
where we have foreign investments;
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<PAGE> 21
o we may be forced to renegotiate our contracts with foreign
governments;
o we may experience the nationalization of the oil and gas
industry in the countries where we have foreign investments;
o we may experience foreign government restrictions on their
currency and large fluctuations in the exchange rate; and
o we may have increased taxes or royalties imposed on our
foreign operations by foreign governments.
Political conditions in the geographic area around the Congo have been
unstable in recent years. During 1997, a new government took power in the Congo
following a civil war. Our Congo production is located approximately 30 miles
offshore and has experienced no material interruption as a result of the
political instability. We attempt to conduct our business in such a manner so
that political and economical events of this nature will continue to have
minimal effect on our operations, but we cannot assure you that we will be
successful in protecting against such risks. Previous Congo governments have
requested that we convert our Marine I Exploitation Permit to a production
sharing agreement. We cannot assure you that the new government will not make
such a request or as to the terms of the agreement if such a request is made.
WE HAVE LESS CONTROL OVER OUR FOREIGN THAN OUR DOMESTIC INVESTMENTS.
Foreign governments often retain ownership of the minerals. Our lack
of control over the minerals could result in the following:
o the foreign country may require exploration or development to
progress on a faster of slower pace than we prefer;
o the foreign country may require us to pay large royalties or
taxes to them; and
o the foreign country may require us to spend larger amounts on
exploration and development than we have funds for or than we
deem appropriate, which may mean that we forfeit all or a
portion of acreage subject to this requirement.
All of these events could reduce the value of our foreign investments.
WE COULD INCUR LIABILITY IN CONNECTION WITH OUR PROPERTIES IN THE CONGO.
In connection with our respective acquisitions of two subsidiaries
owning interests in the Yombo field offshore the Republic of Congo, we and a
wholly-owned subsidiary of CMS NOMECO Oil and Gas Co. agreed with the seller of
the subsidiaries not to claim tax losses, called "dual consolidated losses,"
incurred by such subsidiaries prior to the acquisitions. Under the agreement,
we and the CMS subsidiary may be liable to the seller for the recapture of dual
consolidated losses utilized by the seller in years prior to the acquisitions
if triggering events occur. These triggering events include:
o the disposition by us or the CMS subsidiary of a respective
Congo subsidiary;
o either Congo subsidiary's sale of its interest in the Yombo
field;
o the acquisition of us or CMS by another consolidated group;
or
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<PAGE> 22
o the failure of a Congo subsidiary to continue as a member of
its respective consolidated group.
A triggering event will not occur, however, if a subsequent purchase
enters into agreements specified in the U.S. Internal Revenue Service's
consolidated return regulations intended to ensure that such dual consolidated
losses will not be claimed. We have agreed with CMS that the party responsible
for the triggering event shall indemnify the other for any liability to the
seller as a result of such triggering event. Our potential direct liability
could be as much as $50 million, as of December 31, 1998, if a triggering event
with respect to us occurs. We believe that CMS's liability, for which we would
be jointly liable with an indemnification right against CMS, could be as much
as $67 million, as of December 31, 1998. We do not expect a triggering event to
occur with respect to us or CMS and do not believe that the agreement will have
a material adverse effect on us.
WE MAY NOT HAVE PRODUCTION TO OFFSET HEDGES; BY HEDGING, WE MAY NOT BENEFIT
FROM PRICE INCREASES.
Part of our business strategy is to reduce our exposure to the
volatility of oil and gas prices by hedging a portion of our production. In a
typical hedge transaction, we will have the right to receive from the other
parties to the hedge the excess of the fixed price specified in the hedge over
a floating price based on a market index, multiplied by the quantity hedged. If
the floating price exceeds the fixed price, we are required to pay the other
parties this difference multiplied by the quantity hedged. We are required to
pay the difference between the floating price and the fixed priced when the
floating price exceeds the fixed price regardless of whether we have sufficient
production to cover the quantities specified in the hedge. Significant
reductions in production at times when the floating price exceeds the fixed
price could require us to make payments under the hedge agreements even though
such payments are not offset by sales of production. Hedging will also prevent
us from receiving the full advantage of increases in oil or gas prices above
the fixed amount specified in the hedge. The price of California heavy crude
oil may vary widely from the index prices typically used in oil hedges. This
difference increases the risk involved in hedging the California heavy crude
oil.
COMPLIANCE WITH ENVIRONMENTAL AND OTHER GOVERNMENT REGULATIONS COULD BE COSTLY
AND COULD NEGATIVELY IMPACT PRODUCTION.
Our operations are subject to numerous laws and regulations governing
the operation and maintenance of our facilities and the discharge of materials
into the environment or otherwise relating to environmental protection. These
laws and regulations may:
o require that we acquire permits before commencing drilling;
o restrict the substances that can be released into the
environment in connection with drilling and production
activities;
o limit or prohibit drilling activities on protected areas such
as wetlands or wilderness areas; and
o require remedial measure to mitigate pollution from former
operations, such as plugging abandoned wells.
Under these laws and regulations, we could be liable for personal
injury and clean-up costs and other environmental and property damages, as well
as administrative, civil and criminal penalties. We maintain limited insurance
coverage for sudden and accidental environmental
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<PAGE> 23
damages. We do not believe that insurance coverage for environmental damages
that occur over time is available at a reasonable cost. Moreover, we do not
believe that insurance coverage for the full potential liability that could be
caused by sudden and accidental environmental damages is available at a
reasonable cost. Accordingly, we may be subject to liability or we may be
required to cease production from properties in the event of environmental
damages.
FACTORS BEYOND OUR CONTROL AFFECT OUR ABILITY TO MARKET PRODUCTION.
The ability to market oil and gas from our wells depends upon numerous
factors beyond our control. These factors include:
o the extent of domestic production and imports of oil and gas;
o the availability of capacity to refine heavy oil;
o the proximity of the gas production to gas pipelines;
o the availability of pipeline capacity;
o the demand for oil and gas by utilities and other end users;
o the availability of alternative fuel sources;
o the effects of inclement weather;
o state and federal regulation of oil and gas marketing; and
o federal regulation of gas sold or transported in interstate
commerce.
Because of these factors, we may be unable to market all of the oil or
gas we produce. In addition, we may be unable to obtain favorable prices for
the oil and gas we produce.
THERE MAY NOT BE A LIQUID MARKET FOR RESALE OF THE EXCHANGE NOTES.
There is not established trading market for the exchange notes. We do
not intend to apply for listing the exchange notes on any securities exchange
or for quotations through the NASDAQ National Market. We cannot assure you that
a market for the exchange notes will develop, or that the market will have
sufficient liquidity to enable resale of the exchange notes.
WE FACE A THREAT OF BUSINESS DISRUPTION FROM THE YEAR 2000 ISSUE.
The year 2000 issue refers to the inability of computer and other
information technology systems to properly process date and time information,
stemming from the outdated programming practice of using two digits rather than
four to represent the year in a date. The consequence of the year 2000 issue is
that computer and embedded processing systems are at risk of malfunctioning,
particularly during the transition from 1999 to 2000. The effects of the year
2000 issue are exacerbated by the interdependence of the computer and
telecommunications systems throughout the world. This interdependence also
exists among Nuevo and our vendors, customers and business partners, as well as
with regulators in the United States.
-21-
<PAGE> 24
Our operations are highly dependent on automation. The risks to us
associated with the year 2000 issue fall into three general areas:
o failure of our financial and administrative systems which
could result in our receiving incorrect information upon
which we base decisions;
o failure of the embedded systems which control our highly
automated production facilities; and
o failure of our suppliers and purchasers to correct their year
2000 problems.
USE OF PROCEEDS
We will not receive any cash proceeds from the issuance of the exchange
notes. In consideration for issuing the exchange notes as contemplated in this
prospectus, we will receive in exchange existing notes in like principal amount.
The existing notes surrendered in exchange for exchange notes will be retired
and canceled and cannot be reissued. Issuance of the exchange notes will not
result in a change in our amount of outstanding debt.
-22-
<PAGE> 25
CAPITALIZATION
Our consolidated capitalization at June 30, 1999, as adjusted to give
effect to the exchange of the exchange notes for the existing notes, is
described below:
<TABLE>
<CAPTION>
JUNE 30, 1999
-------------------------------------------
PRO PRO FORMA
ACTUAL FORMA(1) AS ADJUSTED(2)
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Cash and cash equivalents ........................................ $ 53,639 $ 46,116 $ 46,016
========== ========== ==========
Long-term debt (excluding current maturities):
Credit Facility ................................................ $ 120,000 $ 120,000 $ 120,000
Exchange notes ................................................. -- -- 257,310
Existing notes ................................................. -- 257,310 --
8 7/8% senior subordinated notes due 2008 ...................... 100,000 150 150
9 1/2% senior subordinated notes due 2006 ...................... 160,000 2,540 2,540
---------- ---------- ----------
Total long-term debt ....................... 380,000 380,000 380,000
Company-obligated Mandatorily Redeemable Convertible Preferred
Securities of Nuevo Financing I ("TECONS") ..................... 115,000 115,000 115,000
Stockholders' equity:
Preferred stock, $1.00 par value, 10,000,000 shares authorized;
none outstanding ............................................. -- -- --
Common stock, $.01 par value, 50,000,000 shares authorized;
20,308,462 issued(3) ......................................... 203 203 203
Treasury stock, 449,255 shares ................................. (19,053) (19,053) (19,053)
Stock held by benefit trust, 71,630 shares ..................... (2,014) (2,014) (2,014)
Additional paid-in capital ..................................... 355,720 355,720 355,720
Accumulated deficit ............................................ (87,074) (88,804) (88,864)(4)
---------- ---------- ----------
Total stockholders' equity ........................ 247,782 246,052 245,992
---------- ---------- ----------
Total capitalization .............................. $ 742,782 $ 741,052 $ 740,992
========== ========== ==========
</TABLE>
- -------------------
(1) Pro forma amounts give effect to the exchange of existing notes for
our 9 1/2% senior subordinated notes due 2006 and our 8 7/8% senior
subordinated notes due 2008.
(2) Assumes that all holders of the existing notes validly tender their
existing notes and that net fees and expenses payable by us associated
with the exchange offer aggregate approximately $100,000.
(3) Does not include 2,745,613 shares of common stock subject to
outstanding options which may be issued under our stock incentive
plans.
(4) Reflects estimated costs and expenses for third-party financial
advisory, legal and accounting services rendered in connection with
the exchange offer. Does not include interest payable to holders of
existing notes in the exchange offer.
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<PAGE> 26
SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth our selected financial data for the
five years ended December 31, 1998 and for the six-month periods ended June 30,
1998 and 1999. The financial data for each of the five years in the period
ended December 31, 1998 has been derived from our audited consolidated
financial statements for these periods which are incorporated by reference into
this prospectus. The financial data for each of the six-month periods ended
June 30, 1999 and 1998 has been derived from our unaudited condensed
consolidated financial statements for these periods which are also incorporated
by reference into this prospectus. Such unaudited financial statements have
been prepared on the same basis as our audited financial statements. We believe
that such unaudited financial statements contain all adjustments necessary for
a fair presentation of the financial information presented (consisting only of
normal recurring adjustments). Interim results are not necessarily indicative
of results for the full year. The selected financial data is not necessarily
indicative of our future results.
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
--------------------------------------------------------- --------------------
1994(1) 1995(1) 1996(1) 1997(1) 1998 1998 1999
-------- -------- -------- -------- --------- -------- --------
(UNAUDITED)
(IN THOUSANDS, EXCEPT RATIOS AND PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas revenues ................. $ 79,968 $102,455 $279,859 $331,973 $ 240,010 $123,045 $ 95,052
Gas plant revenues ................... 28,798 27,183 34,802 14,826 2,665 1,405 1,288
Pipeline and other revenues .......... 10,309 7,222 6,774 5,772 2,700 1,722 4
Gain on sale of assets, net .......... 2,402 -- 6,008 1,372 5,768 1,677 80,312
Interest and other income ............ 245 1,106 1,614 3,335 1,560 1,324 2,847
-------- -------- -------- -------- --------- -------- --------
Total revenues .................... 121,722 137,966 329,057 357,278 252,703 129,173 179,503
-------- -------- -------- -------- --------- -------- --------
Costs and expenses:
Lease operating expenses ............. 15,160 28,873 93,062 120,042 134,704 65,774 57,876
Gas plant operating expenses ......... 25,794 22,667 29,311 13,356 3,202 1,423 2,336
Pipeline and other operating costs ... 6,767 4,726 6,105 5,243 2,028 1,842 143
Provision for impairment of oil and
gas properties(2) ................. -- -- -- 30,000 68,904 -- --
Provision for (revision of)
impairment of assets held for
sale(3) ........................... -- -- -- 23,942 (3,740) -- --
Exploration costs .................... 4,300 2,357 4,571 11,082 16,562 2,331 9,999
Depreciation, depletion and
amortization ...................... 48,144 45,233 75,664 102,158 85,036 46,556 46,257
General and administrative
expenses .......................... 7,480 5,444 14,880 19,822 18,633 8,526 7,199
Outsourcing fees ..................... 6,369 5,857 10,249 11,984 9,461 7,199 6,846
Interest expense ..................... 12,560 15,389 36,009 27,357 32,471 14,444 16,400
Dividends on TECONS(4) ............... -- -- 165 6,613 6,613 3,306 3,306
Loss on sales of assets, net ......... -- 645 -- -- -- -- --
Other expense ........................ 2,387 45 1,069 3,019 5,726 1,846 2,836
-------- -------- -------- -------- --------- -------- --------
Total costs and expenses .......... 128,961 131,236 271,085 374,618 379,600 153,247 153,198
-------- -------- -------- -------- --------- -------- --------
</TABLE>
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<PAGE> 27
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------
1994(1) 1995(1) 1996(1) 1997(1) 1998
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT RATIOS AND PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
(Loss) income before income taxes,
minority interest, and
extraordinary item ....................... (7,239) 6,730 57,972 (17,340) (126,897)
Income tax (benefit) expense ............... (2,865) 2,582 23,965 (6,656) (32,625)
Minority interest in earnings (loss) of
subsidiary ............................... 52 16 (271) (8) --
---------- ---------- ---------- ---------- ----------
(Loss) income before extraordinary item .... (4,426) 4,132 34,278 (10,676) (94,272)
Extraordinary loss on early extinguishment
of debt net of income tax benefit of
$2,037(5) ................................ -- -- -- 3,024 --
---------- ---------- ---------- ---------- ----------
Net (loss) income .......................... $ (4,426) $ 4,132 $ 34,278 $ (13,700) $ (94,272)
Dividends on preferred stock ............... 1,750 1,472 939 -- --
---------- ---------- ---------- ---------- ----------
(Loss) income attributable to common
stockholders ............................. $ (6,176) $ 2,660 $ 33,339 $ (13,700) $ (94,272)
========== ========== ========== ========== ==========
(Loss) income per common share--basic ...... $ (0.57) $ 0.24 $ 1.99 $ (0.69) $ (4.76)
========== ========== ========== ========== ==========
Weighted average common shares
outstanding .............................. 10,763 11,057 16,755 19,796 19,795
========== ========== ========== ========== ==========
(Loss) income per common share--diluted .... $ (0.57) $ 0.23 $ 1.84 $ (0.69) $ (4.76)
========== ========== ========== ========== ==========
Weighted average common and dilutive
potential common shares outstanding ...... 10,763 11,355 18,596 19,796 19,795
========== ========== ========== ========== ==========
STATEMENT OF CASH FLOWS DATA:
Net cash flows provided by (used in)
operating activities ..................... $ 58,513 $ 37,194 $ 126,921 $ 165,462 $ 35,833
Net cash flows (used in) provided by
investing activities ..................... $ (100,158) $ (32,582) $ (546,002) $ (169,478) $ (148,335)
Net cash flows provided by (used in)
financing activities ..................... $ 29,929 $ (2,294) $ 426,952 $ (412) $ 110,697
OTHER FINANCIAL DATA:
Capital expenditures ....................... $ 105,048 $ 41,445 $ 582,346 $ 195,895 $ 163,274
EBITDAX(6) ................................. $ 55,363 $ 70,354 $ 168,373 $ 182,440 $ 73,181
Ratio of earnings to fixed charges(7) ...... -- 1.4x 2.6x -- --
Ratio of EBITDAX to interest expense(8) .... 4.4x 4.6x 4.7x 6.7x 2.3x
Ratio of total debt to EBITDAX(9) .......... 2.2x 1.7x 1.7x 1.7x 5.8x
Book value per common share--diluted ....... 10.92 10.86 18.58 16.40 11.71
BALANCE SHEET DATA:
Working capital (deficit) .................. $ 6,396 $ 15,757 $ 22,338 $ 9,257 $ 111,629
Total assets ............................... 272,444 262,359 817,643 804,286 817,685
Total debt(9) .............................. 119,541 116,709 292,446 309,656 422,302
Stockholders' equity ....................... 117,557 123,349 345,439 324,739 231,878
</TABLE>
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
-------------------------
1998 1999
---------- ----------
(UNAUDITED)
<S> <C> <C>
(Loss) income before income taxes,
minority interest, and
extraordinary item ....................... (24,074) 26,305
Income tax (benefit) expense ............... (9,870) 10,521
Minority interest in earnings (loss) of
subsidiary ............................... -- --
---------- ----------
(Loss) income before extraordinary item .... (14,204) 15,784
Extraordinary loss on early extinguish
of debt net of income tax benefit of
$2,037(5) ................................ -- --
---------- ----------
Net (loss) income .......................... $ (14,204) $ 15,784
Dividends on preferred stock ............... -- --
---------- ----------
(Loss) income attributable to common
stockholders ............................. $ (14,204) $ 15,784
========== ==========
(Loss) income per common share--basic ...... $ (0.72) $ 0.80
========== ==========
Weighted average common shares
outstanding .............................. 19,759 19,848
========== ==========
(Loss) income per common share--diluted .... $ (0.72) $ 0.79
========== ==========
Weighted average common and dilutive
potential common shares outstanding ...... 19,759 19,915
========== ==========
STATEMENT OF CASH FLOWS DATA:
Net cash flows provided by (used in)
operating activities ..................... $ 21,917 $ (13,156)
Net cash flows (used in) provided by
investing activities ..................... $ (94,603) $ 99,642
Net cash flows provided by (used in)
financing activities ..................... $ 69,842 $ (40,250)
OTHER FINANCIAL DATA:
Capital expenditures ....................... $ 100,414 $ 100,021
EBITDAX(6) ................................. $ 40,886 $ 21,955
Ratio of earnings to fixed charges(7) ...... -- 2.3x
Ratio of EBITDAX to interest expense(8) .... 2.8x 1.3x
Ratio of total debt to EBITDAX(9) .......... N/A N/A
Book value per common share--diluted ....... 15.79 12.44
BALANCE SHEET DATA:
Working capital (deficit) .................. $ 2,598 $ 55,917
Total assets ............................... 851,387 790,274
Total debt(9) .............................. 380,754 382,051
Stockholders' equity ....................... 311,933 247,782
</TABLE>
- ---------------------
(1) Effective January 1, 1998, we changed our method of accounting for our
investments in oil and gas properties from the full cost to the successful
efforts method. All prior years' financial statements presented in this
prospectus have been restated to reflect this change.
(2) We incurred an impairment of $68.9 million at December 31, 1998 and $30.0
million at December 31, 1997 on certain fields due to decreased crude oil
prices.
(3) The provision for impairment of assets held for sale reflects a charge we
took to write down our midstream assets to their fair value in 1997. These
assets are primarily gas pipelines and processing plants. The impairment
represents our estimate of the difference between the book value of these
assets and the amount we expect to receive when we sell the assets.
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<PAGE> 28
(4) TECONS are the Company-Obligated Mandatorily Redeemable Convertible
Preferred Securities of our financing subsidiary Nuevo Financing I. The
principal assets of Nuevo Financing I are $115.0 million of our 5 3/4%
convertible subordinated debentures due December 15, 2026. Interest we pay
on the 5 3/4% debentures to Nuevo Financing I are paid by Nuevo Financing
I as dividends on the TECONS.
(5) During 1997, we redeemed our 12 1/2% senior subordinated notes prior to
maturity and recorded $3.0 million as our extraordinary loss on early
extinguishment of debt, net of income tax benefit.
(6) The term "EBITDAX" means earnings before interest, dividends on TECONS,
taxes, depreciation, depletion and amortization, property impairment,
gain/loss on sale and exploration costs. EBITDAX is included because it is
commonly used as a measure of a company's ability to incur indebtedness.
EBITDAX should not be used as a substitute for cash flow from operating
activities or other income or cash flow information prepared in accordance
with generally accepted accounting principals as an indication of
profitability or liquidity. EBITDAX may not be comparable to similarly
titled items of other companies.
(7) When we calculate our ratio of earnings to fixed charges, earnings means
income or loss before income taxes and fixed charges. Fixed charges means
the sum of the following:
o interest expense;
o dividends on the TECONS;
o amortization of debt issuance costs; and
o the portion of operating leases deemed to be representative of
interest.
Earnings were not sufficient to cover fixed charges for 1994, 1997 and
1998 by $ 7.2 million, $19.5 million and $127.5 million, respectively, and
for the six months ended June 30, 1998 by $24.6 million.
(8) For purposes of this calculation, interest expense does not include
dividends or interest payments on the TECONS.
(9) Total debt does not include the TECONS.
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<PAGE> 29
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
We are an independent oil and gas company. Our properties are concentrated
in California, where we are the largest independent producer, with properties
located both onshore and offshore. Our onshore California properties are located
primarily in the San Joaquin, Los Angeles and Ventura Basins. Our offshore
California properties are located in the Santa Barbara Channel and offshore Long
Beach. We also own properties in the onshore Gulf Coast region and
internationally offshore the Republics of Congo and Ghana in West Africa and
onshore in Tunisia. Since our inception in 1990, we have expanded our operations
through a series of disciplined, low-cost acquisitions of oil and gas properties
and the subsequent exploitation and development of these properties. We have
complemented these efforts with strategic divestitures and an opportunistic
exploration program which provides exposure to prospects with the potential to
add substantially to the growth of our shareholder value.
On January 1, 1998, we changed the method we use to account for our
investments in oil and gas properties from full cost to the successful efforts
method. We believe that the change to the successful efforts method improves
earnings quality and results in a balance sheet which more closely approximates
the underlying economic value of our assets. In accordance with accounting
rules, we have restated all prior year financial statements to give effect to
the change to successful efforts accounting. The effect, after tax, of the
change in accounting method as of December 31, 1997, was a reduction to retained
earnings of $64.1 million. See the notes to our financial statements for
additional information on the successful efforts method of accounting.
RESULTS OF OPERATIONS
Our results of operations are significantly affected by the prices we
receive for our oil and gas production and the costs we incur to produce oil and
gas. The following table shows our oil and gas production, average oil and gas
prices and average costs incurred. The sales prices in the following table
includes the effect of hedges.
<TABLE>
<CAPTION>
SIX MONTHS
ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------------ -----------------------
1996 1997 1998 1998 1999
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Production Data:
Oil (MBBLS) (1) ......................... 13,344 17,409 18,806 9,364 8,757
Gas (MMcf) .............................. 34,775 35,625 32,521 16,736 8,227
Average Sales Price Per Unit:
Oil (per Bbl) ........................... $ 15.84 $ 14.86 $ 9.25 $ 9.48 $ 9.07
Gas (per Mcf) ........................... 2.08 2.06 2.00 2.01 1.87
Cost Per BOE:
Operating expenses, including severance
taxes ................................. $ 4.86 $ 5.14 $ 5.56 $ 5.41 $ 5.71
Depreciation, depletion and
amortization .......................... 3.72 4.23 3.45 3.77 4.49
</TABLE>
- -------------------------
(1) Includes natural gas liquids.
Our results of operations have also been affected by our acquisitions and
sales of oil and gas properties. In April 1996, we acquired properties in
California which currently form our core
-27-
<PAGE> 30
operating areas. In January 1999, we sold substantially all of our natural gas
properties in East Texas for proceeds of $192.0 million. We placed $100 million
of these proceeds in an escrow account to effect a like-kind exchange for
federal tax purposes if we acquired oil and gas properties within six months
following the East Texas sale. We closed the Star acquisition on June 28, 1999
for $61.4 million with a portion of the funds in escrow.
Comparison of Six Months Ended June 30, 1999 and 1998
Revenues
Oil and gas revenues for the six months ended June 30, 1999 were $95.1
million, or 23% lower than oil and gas revenues of $123.0 million for the same
period in 1998. This decrease was primarily due to lower realized oil and gas
prices in the first half of 1999, reduced oil volumes due to reduced capital
spending and the sale of several non-core assets in 1999 and reduced gas volumes
as a result of the sale of the East Texas natural gas properties on January 6,
1999. The following is a description of our oil and gas revenues by operating
area.
East: Oil and gas revenues for the six months ended June 30, 1999 were
$7.7 million, or 68% lower than oil and gas revenues of $24.2 million for
the same period in 1998. The decrease results primarily from lower natural
gas production due to the sale of the East Texas natural gas properties as
well as lower realized natural gas prices.
West: Oil and gas revenues for the six months ended June 30, 1999 were
$76.5 million, or 16% lower than oil and gas revenues of $90.7 million for
the same period in 1998. This decrease is primarily due to a 7% lower
realized oil price in the first half of 1999 as well as reduced oil volumes
due to reduced capital spending. The realized oil price of $8.47 per barrel
for the six months ended June 30, 1999, includes a hedging loss of $1.28
per barrel of oil produced..
International: Oil revenues for the six months ended June 30, 1999 were
$10.9 million as compared to $8.1 million for the same period in 1998. The
34% increase results from a 19% increase in oil production along with a 13%
increase in oil price realizations to $12.86 per barrel.
Gain on sale for the six months ended June 30, 1999 was $80.3 million. Such
gain was recognized in connection with the sale of the East Texas natural gas
properties for proceeds of $191.1 million, as adjusted for final accounting,
along with the sale of several non-core assets. Gain on sale for the six months
ended June 30, 1998 was $1.7 million, which relates to the sale of our interest
in the Coke field in Chapel Hill, Texas.
Interest and other income for the six months ended June 30, 1999, includes
$2.4 million associated with interest earned on the $100.0 million in proceeds
from the sale of the East Texas natural gas properties funded into an escrow
account to provide "like-kind exchange" tax treatment in the event we acquired
domestic producing oil and gas properties in the first half of 1999. The escrow
account was liquidated in late June and early July 1999, in connection with our
June 1999 acquisition of certain California oil properties from Texaco, Inc. and
repayment of a portion of bank debt, respectively.
Expenses
Lease operating expenses for the six months ended June 30, 1999 totaled
$57.9 million, or 12% lower than $65.8 million for the six months ended June 30,
1998. Lease operating expenses per BOE were $5.71 in the first half of 1999,
compared to $5.41 in the same period in 1998. The following is a description of
our lease operating expenses by operating area.
-28-
<PAGE> 31
East: Lease operating expenses for the six months ended June 30, 1999
totaled $1.6 million, or 75% lower than $6.3 million for the six months
ended June 30, 1998. The decrease is primarily attributable to the sale of
the East Texas natural gas properties in January of 1999. Lease operating
expenses per BOE were $2.36 in the first half of 1999, compared to $3.07 in
the same period in 1998.
West: Lease operating expenses for the six months ended June 30, 1999
totaled $50.0 million, or 7% lower than $53.9 million for the six months
ended June 30, 1998. Lease operating expenses per BOE were $5.80 in the
first half of 1999, compared to $5.74 in the same period in 1998. In the
first quarter of 1998, poor weather conditions in California caused
landslides and power outages, which resulted in $2.3 million of
incremental, unusual costs. Reduced workover costs onshore in 1999 also
contributed to the lower lease operating expenses year over year.
International. Lease operating expenses for the six months ended June
30, 1999 totaled $6.3 million, or14% higher than $5.6 million for the six
months ended June 30, 1998. Lease operating expenses per BOE were $7.44 in
the first half of 1999, compared to $7.79 in the same period in 1998.
Gas plant operating expenses were $2.3 million for the six months ended
June 30, 1999 as compared to $1.4 million for the six months ended June 30,
1998. The 64% increase in gas plant expenses in 1999 compared to 1998 is due to
increased ad valorem taxes.
Exploration costs, which are composed of geological and geophysical costs,
dry hole costs, delay rentals and expensed project costs, were $10.0 million and
$2.3 million for the six months ended June 30, 1999 and 1998, respectively. For
the six months ended June 30, 1999, exploration costs are comprised of:
o $7.3 million in dry hole costs;
o $1.5 million in geological and geophysical costs;
o $0.3 million in delay rentals; and
o $0.9 million in expensed project cost.
For the six months ended June 30, 1998, exploration costs were comprised of:
o $0.1 million in dry hole costs;
o $2.0 million in geological and geophysical costs; and
o $0.2 million in delay rentals.
East: During the first half of 1999, we plugged and abandoned the
DeBord #1 well in our East area. The dry hole costs associated with this
well were $0.6 million. The first half of 1999 also includes $0.2 million
of geological and geophysical costs associated with a prospect in South
Louisiana. Exploration costs in the first half of 1999 were $0.5 million.
West: During the first half of 1999, we decided to plug and abandon the
Cree Fee #1 well in the Midway Peak prospect area onshore California. The
dry hole costs associated with this well were $6.5 million. Exploration
costs in the first half of 1998 were $0.5 million.
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<PAGE> 32
International: During the first half of 1999, $1.0 million in
geological and geophysical costs were expensed associated with the Accra
Keta and the East Cape Three Points prospects in Ghana. Exploration costs
of $1.3 million in the first half of 1998 relates to geological and
geophysical costs in Ghana.
Depreciation, depletion and amortization of $46.3 million for the six
months ended June 30, 1999 reflects a slight decrease from $46.6 million in the
same period in 1998, due primarily to decreased production volumes offset by a
higher depletion rate per BOE on our oil and gas properties. The weighted
average depletion rate per BOE in the first half of 1999 was $4.57 versus $3.83
in the first half of 1998. Several factors contributed to the change in the
average depletion rate per BOE. First, the property mix changed as the lower
cost East Texas natural gas properties were sold in January. Second, our year
end reserves decreased by approximately 12% from the previous year primarily as
a result of lower crude oil prices utilized in computing estimated net proved
reserves at year end 1998. Finally, the impairment of $68.9 million recognized
in the fourth quarter of 1998 reduced the capitalized costs to be depleted and
partially offset the increase in the depletion rate per BOE. The following is a
description of depreciation, depletion and amortization by operating area.
East: Depreciation, depletion and amortization of $4.3 million for the
six months ended June 30, 1999 reflects a 34% decrease from $6.5 million in
the same period in 1998, due primarily to decreased production volumes as a
result of the sale of the East Texas natural gas properties in January
1999.
West: Depreciation, depletion and amortization of $37.3 million for the
six months ended June 30, 1999 reflects a 1% increase from $36.8 million in
the same period in 1998, due primarily to an increased average depletion
rate per BOE offset by decreased production volumes.
International: Depreciation, depletion and amortization of $3.9 million
for the six months ended June 30, 1999 reflects a 56% increase from $2.5
million in the same period in 1998, due primarily to an increased average
depletion rate per BOE as well as increased production volumes.
General and administrative expenses, together with outsourcing fees,
totaled $7.2 million and $8.5 million in the six months ended June 30, 1999 and
1998, respectively. The 16% decrease is due primarily to a reduction in bonus
accruals, engineering costs and third-party consulting studies.
Interest expense of $16.4 million incurred in the six months ended June 30,
1999 reflects an increase of 14% as compared to interest expense of $14.4
million in the six months ended June 30, 1998. The increase is primarily
attributable to our issuance of $100.0 million of 87/8% Senior Subordinated
Notes due 2008 in June of 1998, which we used to repay lower-interest bank debt.
In March 1999, we discovered that a non-officer employee had fraudulently
authorized and diverted for personal use funds totaling $5.9 million, $4.3
million in 1998 and the remainder in the first quarter of 1999, that were
intended for international exploration. Accordingly, we have reclassified the
amounts lost in 1998 and 1999 from exploration costs to other expense. Based on
our review of the facts, management is confident that only one employee was
involved in the matter and that all misappropriated funds have been identified.
Our board engaged a certified fraud examiner to conduct an in-depth review of
the fraudulent transactions to determine the scope of the fraud, the possibility
of recovery of amounts lost from insurance, from the terminated employee and/or
from third parties, and to make recommendations regarding what, if any, new
internal control procedures should be implemented.
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<PAGE> 33
Net Income
Net income of $15.8 million, $0.80 per common share -- basic and $0.79 per
common share --diluted, was generated for the six months ended June 30, 1999, as
compared to a net loss of $14.2 million, ($0.72) per common share -- basic and
diluted, in the same period in 1998.
Comparison of Years Ended December 31, 1996, 1997 and 1998
Revenues
We have experienced significant oil and gas revenue volatility in recent
years. Low oil prices are primarily responsible for the decreased revenues in
1998, while our acquisitions of producing properties and development drilling
programs are primarily responsible for the increased revenues during 1997 and
1996. During this three year period, the volatility of oil and gas prices
directly impacted revenues. To reduce our exposure to changes in oil and gas
prices, we periodically utilize derivative financial instruments. As a result of
such hedging transactions, oil and gas revenues were increased by $0.6 million
in 1998, and were reduced by $6.0 million and $2.5 million in 1997 and 1996,
respectively.
Oil and gas revenues for 1998 of $240.0 million were 28% lower than 1997
oil and gas revenues of $332.0 million, primarily due to a 38% decrease in
average realized oil prices from $14.86 per barrel in 1997 to $9.25 per barrel
in 1998. Also contributing to this decline in oil and gas revenues were
decreases in natural gas production and realized gas prices. Our gas production
decreased 9% from 35.6 Bcf in 1997 to 32.5 Bcf in 1998. Average realized gas
prices decreased 3% from $2.06 per Mcf in 1997 to $2.00 per Mcf in 1998. The
decline in oil and gas revenues was partially offset by a 9% increase in our oil
production from 17.1 MMBbls in 1997 to 18.5 MMBbls in 1998. The following is a
description of our oil and gas revenues by operating area.
East: Oil and gas revenues decreased 24% from $61.5 million in 1997 to
$46.9 million in 1998. This decrease is primarily due to a 10% decrease in
gas production from 20.8 Bcf in 1997 to 18.8 Bcf in 1998, as well as a 13%
decrease in the average realized price of gas from $2.08 per Mcf in 1997 to
$1.80 per Mcf in 1998.
West: Oil and gas revenues decreased 28% from $247.7 million in 1997 to
$177.3 million in 1998. This decrease is primarily due to a 39% decrease in
the average realized price of oil from $14.73 per Bbl in 1997 to $8.98 per
Bbl in 1998, which was partially offset by an 11% increase in oil
production from 14.7 MMBbls in 1997 to 16.3 MMBbls in 1998.
International: Oil and gas revenues decreased 31% from $22.8 million in
1997 to $15.8 million in 1998. This decrease was primarily due to a 26%
decrease in the average realized price of oil from $14.66 per Bbl in 1997
to $10.82 per Bbl in 1998, as well as a decrease in oil production of 6%
from 1.6 MMBbls in 1997 to 1.5 MMBbls in 1998.
Oil and gas revenues for 1997 of $332.0 million were 19% higher than 1996
oil and gas revenues of $279.9 million, primarily due to 30% increase in oil
production (including natural gas liquids) from 13.3 MMBbls in 1996 to 17.4
MMBbls in 1997. This increase in oil volumes is attributable to the fact that
1997 included an entire year of operating results for the California properties
we acquired in April 1996, compared to only nine months in 1996. These
California properties accounted for 75% of total oil and gas revenues in 1997.
The increase in production was partially offset by the disruption of Point
Pedernales production due to an oil spill in September 1997 and a decrease in
the average realized prices of oil and gas in 1997. Our average realized price
for oil in 1997 was $14.86 per barrel, a 6% decrease from $15.84 in 1996. Our
average realized price for gas in 1997 was $2.06, a 1%
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<PAGE> 34
decrease from $2.08 in 1996. The following is a description of our oil and gas
revenues by operating area.
East: Oil and gas revenues decreased 18% from $74.9 million in 1996 to
$61.5 million in 1997. This decrease is due to:
o a 6% decrease in gas production from 22.2 Bcf in 1996 to 20.8 Bcf
in 1997;
o a 36% decrease in oil production from 1.4 MMBbls in 1996 to 878
MBBLS in 1997;
o a 7% decrease in the average realized price of oil from $20.39 per
Bbl in 1996 to $18.95 per Bbl in 1997; and
o a slight decrease in the average realized price of gas from $2.13
per Mcf in 1996 to $2.08 per Mcf in 1997.
West: Oil and gas revenues increased 34% from $184.3 million in 1996 to
$247.7 million in 1997. This increase is primarily due to the fact that
1997 included an entire year of operating results for the California
properties, compared to only nine months in 1996.
International: Oil and gas revenues increased 10% from $20.7 million in
1996 to $22.8 million in 1997. This increase is primarily due to a 10%
increase in oil production from 1.4 MMBbls in 1996 to 1.6 MMBbls in 1997.
Gas plant revenues in 1998 of $2.7 million were 82% lower than 1997
revenues of $14.8 million. This decrease is due to the sale of our interest in
the Benedum Plant System in May 1997. Gas plant revenues in 1997 of $14.8
million were 57% lower than 1996 revenues of $34.8 million due to the sale of
our investment in the Benedum Plant System in May 1997. We recognized a $2.3
million pre-tax gain on the sale.
Pipeline and other revenues in 1998 of $2.7 million were 53% lower than
1997 revenues of $5.8 million. This decrease is primarily due to the sale of our
interests in the Richfield Gas Storage facility in February 1998 and Bright Star
Gathering, Inc. in July 1998. Pipeline and other revenues in 1997 of $5.8
million were 15% lower than 1996 revenues of $6.8 million, as a result of lower
throughput during 1997 compared to 1996.
Gain on sale of assets for 1998 was $5.8 million. This gain on sale of
assets includes:
o a $4.1 million gain on the sale of our interest in the Sansinena
field in California in the third quarter of 1998; and
o a $1.7 million gain on the sale of our interest in the Coke field
in Chapel Hill, Texas in the first quarter of 1998.
The net gain on sale of assets for 1997 was $1.4 million, which is
comprised of:
o a $1.4 million gain on the sale of our interest in Second Bayou,
Weeks Island, Louisiana;
o a $2.3 million gain on our interest in the Benedum Plant System;
o a $1.6 million loss on the sale of our interest in the South
Timbalier field; and
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<PAGE> 35
o a $0.7 million loss on the sale of other non-core properties.
The net gain on sale of assets for 1996 was $6.0 million, which is
comprised of a $9.2 million gain on the sale of our interest in the Giddings
field and East Texas Austin Chalk holdings in June 1996, which was offset by a
$3.2 million loss on the sale of other non-core properties.
Expenses
Lease operating expenses for 1998 totaled $134.7 million, as compared to
$120.0 million and $93.1 million for 1997 and 1996, respectively. The annual
increases of 12% in 1998 and 29% in 1997 are generally reflective of higher
production and costs associated with our California properties, which
constituted 77%, 73% and 66% of total production in 1998, 1997 and 1996,
respectively. In 1998, we experienced an increase in workovers of $11.2 million
as compared to the same period in 1997, as well as poor weather conditions in
the first quarter of 1998 in California that caused landslides and power
outages, which resulted in $2.3 million of incremental, unusual costs. In 1997,
lease operating expenses were incurred for an entire year versus only nine
months in 1996, since the California properties acquired from Unocal were
acquired in April 1996. The following is a description of the lease operating
expenses by operating area.
East: Lease operating expenses decreased slightly from $11.9 million in
1997 to $11.6 million in 1998. Lease operating expenses for our eastern oil
and gas operations decreased 16% from $14.1 million in 1996 to $11.9
million in 1997, primarily due to a 14% decrease in oil and gas production.
West: Lease operating expenses increased 16% from $96.1 million in 1997
to $111.2 million in 1998. This increase was due to an increase in
workovers as compared to the same period in 1997, as well as poor weather
conditions in the first quarter of 1998 in California that caused
landslides and power outages which resulted in $2.3 million of incremental,
unusual costs. Lease operating expenses for the west increased 41% from
$68.1 million in 1996 to $96.1 million in 1997, since we owned the
California properties for an entire year in 1997 versus only nine months in
1996.
International: Lease operating expenses decreased slightly from $12.0
million in 1997 to $11.9 million in 1998. Lease operating expenses for our
foreign oil and gas operations increased 10% from $10.9 million in 1996 to
$12.0 million in 1997 due to a 10% increase in production.
Gas plant operating expenses of $3.2 million in 1998 decreased 76% from
$13.4 million in 1997, which decreased 54% from $29.3 million in 1996. These
decreases are due to the sale of our investment in the Benedum Plant System in
May 1997.
Pipeline and other operating expenses for 1998 totaled $2.0 million, as
compared to $5.2 million and $6.1 million in 1997 and 1996, respectively. The
61% decrease in 1998 is primarily due to the sale of our interests in the
Richfield Gas Storage facility in February 1998 and Bright Star Gathering, Inc.
in July 1998. The 14% decrease in 1997 is due to lower throughput in 1997 as
compared to 1996.
Exploration costs, including geological and geophysical costs, dry hole
costs and delay rentals, were $16.6 million, $11.1 million and $4.6 million for
the years ended December 31, 1998, 1997 and 1996, respectively. Exploration
costs for the year ended 1998 included:
o $13.0 million of dry hole costs ($7.3 million of which relates to
exploration activity in Ghana, West Africa);
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<PAGE> 36
o $2.1 million of geological and geophysical costs ($1.5 million of
which relates to activity in Ghana);
o $0.9 million of delay rentals; and
o $0.6 million of other exploration costs.
Exploration costs for the year ended 1997 included:
o $9.3 million of dry hole costs;
o $0.7 million of geological and geophysical costs;
o $1.0 million of delay rentals; and
o $0.1 million of other exploration costs.
Exploration costs for the year ended 1996 included:
o $3.1 million of dry hole costs;
o $1.2 million of geological and geophysical costs;
o $0.2 million of delay rentals; and
o $0.1 million of other exploration costs.
Depreciation, depletion and amortization of $85.0 million in 1998 decreased
17% from $102.2 million in 1997, which increased 35% from $75.7 million in 1996.
The decrease in 1998 is primarily due to the year-end 1997 impairment of $30.0
million related to the excess of capitalized costs over future net revenues, as
well as the reclassification of the East Texas natural gas properties to assets
held for sale as of July 1, 1998, at which point the properties were no longer
depleted. The increase in 1997 is attributable to increased production volumes
in 1997, due to the acquisition of the California properties from Unocal in
April 1996.
We recorded provisions for impairment of oil and gas properties in 1998 and
1997 in the amounts of $68.9 million and $30.0 million, respectively. These
impairments were recorded as a result of declines in the price of oil, which
caused capitalized costs to be in excess of future net revenues. No such
impairment was recognized during 1996.
In December 1997, we recorded a $23.9 million provision for impairment on
assets held for sale, in connection with our plans to dispose of our non-core
gas gathering, pipeline and gas storage assets during 1998, including all such
assets except our California gas plants. A positive revision to this charge was
made in the fourth quarter of 1998 in the amount of $3.7 million to reflect the
estimated current fair market value of the Illini pipeline.
General and administrative expenses totaled $18.6 million, $19.8 million,
and $14.9 million in 1998, 1997 and 1996, respectively. The 6% decrease in 1998
is primarily due to a reduction in employee bonuses in 1998 and a $1.7 million
severance expense incurred in the third quarter of 1997 associated with the
resignation of our president and chief executive officer. These decreases were
offset in part by non-recurring costs incurred in 1998 associated with outside
engineering costs and third-party consulting studies associated with the
re-negotiation of our outsourcing agreements. The
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<PAGE> 37
33% increase in 1997 compared to 1996 is primarily due to additional general and
administrative costs associated with a full year of operations from the
California properties acquired from Unocal in 1996 and the $1.7 million
severance payment referred to above.
Outsourcing fees were $9.5 million, $12.0 million, and $10.2 million in
1998, 1997 and 1996, respectively. The 21% decrease in 1998 is primarily due to
decreased operating cash flows as a result of low realized oil prices. The 17%
increase in 1997 is primarily due to the fact that we had a full year of
operations from the California properties in 1997 as compared to 1996.
Interest expense of $32.5 million for 1998 increased 19% from $27.4 million
in 1997, primarily as a result of additional borrowings under the our bank
credit facility and the issuance in June 1998 of $100.0 million of 8 7/8% notes.
Interest expense for 1997 decreased 24% from $36.0 million in 1996, primarily as
a result of our redemption of the 12 1/2% notes, as well as decreased debt under
the bank credit facility due to the repayment of a portion of the debt
outstanding under this facility with the proceeds from the issuance of the
TECONS in late 1996.
Dividends on the TECONS increased from $0.2 million in 1996 to $6.6 million
in 1998 and 1997. The TECONS pay dividends at a rate of 5.75% and were issued in
December 1996.
In March 1999, we discovered that an employee had fraudulently authorized
and diverted for personal use funds totaling $5.9 million, $4.3 million in 1998
and the remainder in 1999, that were intended for international exploration.
Accordingly, we have reclassified the amounts lost in 1998 from exploration
costs to other expense. Based on its review of the facts, management is
confident that only one employee was involved in the matter and that all
misappropriated funds have been identified. The board of directors has engaged a
certified fraud examiner to conduct an in-depth review of the fraudulent
transactions to determine the scope of the fraud, the possibility of recovery of
amounts lost from insurance, from the terminated employee and/or from third
parties, and to make recommendations regarding what, if any, new internal
control procedures should be implemented.
Income tax benefit of $32.6 million was recognized in 1998, compared to a
benefit of $8.7 million in 1997 and expense of $24.0 million in 1996. Our
effective income tax rate was (25.7)%, (38.8)% and 41.3% in 1998, 1997 and 1996,
respectively. At December 31, 1998, we determined that it was more likely than
not that a portion of the deferred tax assets will not be realized and the
valuation allowance was increased by $16.9 million to a total valuation
allowance of $17.6 million.
Extraordinary Loss
In June 1997, we recorded an extraordinary loss on the early extinguishment
of our 12 1/2% notes in the amount of $3.0 million, net of the related tax
benefit of $2.0 million. No extraordinary items were recorded in 1998 or 1996.
Net Income (Loss)
A net loss of $94.3 million was generated in 1998, as compared to a net
loss of $13.7 million in 1997 and net income of $34.3 million in 1996. Net
income after deducting dividends paid on the 7% preferred stock was $33.3
million in 1996. There was no 7% preferred stock outstanding during 1998 or
1997; as such, no preferred dividends were paid in 1998 or 1997.
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<PAGE> 38
PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT EXPENDITURES
Our expenditures to acquire properties, and for exploration and development
for the three years ended December 31, 1998 and for the six months ended June
30, 1999 are set forth in the following table:
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED
------------------------------------ JUNE 30,
1996 1997 1998 1999
---------- ---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Acquisitions ....... $ 492,603 $ 10,206 $ 10,733 $ 61,416
Development ........ 73,610 156,328 116,631 30,552
Exploration ........ 16,133 29,361 35,910 6,143
---------- ---------- ---------- ----------
$ 582,346 $ 195,895 $ 163,274 $ 98,111
========== ========== ========== ==========
</TABLE>
Our capital budget for 1999 includes $40.0 million for exploitation and
development, $28.0 million of which is budgeted to be spent in California, $5.0
million in the Gulf Coast area and $7.0 million internationally. Our capital
budget for 1999 also includes $17.0 million for exploration, $7.0 million of
which is targeted for California, $2.0 million for the Gulf Coast area and $8.0
million internationally. Our capital budget for 1999 does not include any
amounts for acquisitions, which could be material. As of June 30, 1999, we had
spent approximately 48% of our capital budget for exploitation and 46% for
exploration. In addition, in June 1999 we closed the Star acquisition for $61.4
million.
Our 1999 capital budget is significantly smaller than our capital budgets
for 1998 and 1997, primarily because of the depressed oil prices. Although oil
prices have recently improved, we have not increased our 1999 capital budget.
CAPITAL RESOURCES AND LIQUIDITY
Since our inception, we have grown and focused our operations through a
series of disciplined, low cost acquisitions of oil and gas properties and the
subsequent exploitation and development of these properties. We have
complemented these efforts with an opportunistic exploration program which
provides exposure to prospects that have the potential to add substantially to
our growth. The funding of these activities has historically been provided by
operating cash flows, bank financing, private and public placements of debt and
equity securities, property divestitures and joint ventures with industry
participants. Net cash provided by operating activities was $35.8 million,
$165.5 million, and $126.9 million in 1998, 1997 and 1996, respectively. We
invested $157.4 million, $195.1 million and $516.0 million in oil and gas
properties in 1998, 1997 and 1996, respectively. Additionally, we spent $2.8
million, $1.7 million and $21.1 million on gas plant and other facilities in
1998, 1997 and 1996, respectively. Included in the oil and gas capital
expenditures for 1998 is approximately $81.5 million for development drilling
activity in California.
In our 1999 capital budget, approximately $40.0 million is allocated to
exploitation and development projects and approximately $17.0 million is
directed to prospect generation and exploration. Exploitation spending is
anticipated to consist of $28.0 million in California, $5.0 million in the Gulf
Coast region, and $7.0 million internationally. We plan to allocate exploration
spending of $7.0 million in California, $2.0 million in the Gulf Coast region,
and $8.0 million internationally. Changes in our cash flow from operations due
to oil and gas price fluctuations may cause us to revise our capital expenditure
plans.
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<PAGE> 39
As of June 30, 1999, we had unused commitments under our bank revolving
credit facility of $91.0 million and cash balances of $51.6 million. Effective
January 6, 1999, the borrowing base on our bank credit facility was reduced from
$380.0 million to $200.0 million, reflecting the sale on that date of our East
Texas properties, and a significant decline in current and projected oil prices
since the previous determination.
We plan to sell some of our surface real estate assets in Orange County,
California, during 1999 and use a portion of the proceeds to fund a portion of
our 1999 capital program. We believe our working capital, cash provided by
operating activities, property divestitures, project financing resources and the
bank credit facility are sufficient to meet these capital commitments.
MARKET RISK DISCLOSURE -- HEDGING
We are exposed to market risk, including adverse changes in commodity
prices and interest rates.
Commodity Price Risk. We produce and sell crude oil, natural gas and
natural gas liquids. As a result, our operating results are significantly
affected by fluctuations in commodity prices caused by changing market forces.
We periodically seek to reduce our exposure to price volatility by hedging our
production through swaps, options and other commodity derivative instruments. We
use hedge accounting for these instruments when available, and we report
settlements of gains or losses on these contracts as a component of oil and gas
revenues and operating cash flows in the period realized. These agreements
expose us to counterparty credit risk to the extent that the counterparty is
unable to meet its settlement commitments to us.
Changes in prices for California crude oil production, especially sour
heavy oil production, do not closely follow changes in the prices of oil futures
prices on the NYMEX or other established futures markets. The difference we
receive for our California production and the NYMEX prices or prices on other
established futures markets is referred to as basis differential. The volatility
of the basis differential makes it difficult to effectively hedge our California
production.
For the second half of 1999, we are party to crude oil swaps on an average
of 30,000 Bbls per day, or 67% of our estimated crude oil production, at an
average NYMEX price of $16.35 per Bbl. For calendar year 2000, we have entered
into crude oil swaps on 16,500 Bbls per day, or 30% of our estimated crude oil
production, at an average NYMEX price of $17.94 per Bbl. In addition, for
calendar year 2000, we have hedged an additional 30% of our estimated crude oil
production through the purchase of put options on 16,500 Bbls per day at a NYMEX
price of $16.00 per Bbl, and the sale of call options on 16,500 Bbls per day at
an average NYMEX price of $21.21 per Bbl. There was no net cost to us for these
options.
Interest Rate Risk. We may enter into financial instruments such as
interest rate swaps to manage the impact of changes in interest rates. In 1999,
we entered into an agreement which has the effect of hedging the price at which
we may repurchase $16.4 million in principal amount of our 9 1/2% notes and
converts the interest rate under the portion of the 9 1/2% notes subject to the
agreement to a floating rate for a period of one year. The floating rate in June
1999 was 5.6%. The counterparty to this agreement is Bank of America, N.A.
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<PAGE> 40
Our exposure to changes in interest rates primarily results from our
short-term and long-term debt with both fixed and floating interest rates. The
following table sets forth the principal amounts and the related average
interest rates by year of maturity for our debt obligations at June 30, 1999:
<TABLE>
<CAPTION>
FAIR VALUE
1999 2000 2001 2002 2003 THEREAFTER TOTAL LIABILITY
---------- ------ ----- ----- ---------- ---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Long-term debt, including
current maturities:
Variable rate ............. $ 2,051 -- -- -- $ 120,000 -- $ 122,051 $ 122,051
Average interest rate ..... 5.2% -- -- -- 5.4% -- 5.4%
Fixed rate ................ -- -- -- -- -- $ 260,000 $ 260,000 $ 258,602
Average interest rate ..... -- -- -- -- -- 9.3% 9.3%
</TABLE>
RECENT ACCOUNTING STANDARDS
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." This statement,
as amended, establishes standards of accounting for and disclosures of
derivative instruments and hedging activities. This statement requires all
derivative instruments to be carried on the balance sheet at fair value and is
effective for us beginning January 1, 2001, however, early adoption is
permitted. We have not yet determined the impact of this statement on our
financial condition or results of operations or whether we will adopt the
statement early.
OTHER MATTERS
Inflation. Inflation has not had a material impact on our operations and is
not expected to have a material impact on us in the future.
Gas Balancing Positions. It is customary in the industry for various
working interest partners to sell more or less than their entitled share of
natural gas. The settlement or disposition of gas balancing positions is not
anticipated to adversely impact our financial condition.
Year 2000. See the discussion of the year 2000 issue under "Business and
Properties -- Year 2000."
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<PAGE> 41
BUSINESS AND PROPERTIES
We are an independent oil and gas company. Our properties are concentrated
in California, where we are the largest independent producer, with properties
located both onshore and offshore. Our onshore California properties are located
primarily in the San Joaquin, Los Angeles and Ventura Basins. Our offshore
California properties are located in the Santa Barbara Channel and offshore Long
Beach. We also own properties in the onshore Gulf Coast region and
internationally offshore the Republics of Congo and Ghana in West Africa and
onshore in Tunisia. Since our inception in 1990, we have expanded our operations
through a series of disciplined, low-cost acquisitions of oil and gas properties
and the subsequent exploitation and development of these properties. We have
complemented these efforts with strategic divestitures and an opportunistic
exploration program which provides exposure to prospects with the potential to
add substantially to the growth of our shareholder value.
RECENT DEVELOPMENTS
East Texas Sale. In January 1999, we sold properties in East Texas for
$192.0 million. Reserves attributable to the East Texas properties were
primarily natural gas. The estimated net proved reserves of these properties
were 329 Bcfe on December 31, 1998. We placed $100.0 million of the proceeds of
this sale in an escrow account to facilitate like-kind exchange tax treatment
for any properties we acquire in the first six months of 1999. Of these escrowed
proceeds, $61.4 million was used to fund the Star acquisition. We used the
remaining net proceeds from this sale plus amounts remaining in escrow after the
Star acquisition to pay down our bank credit facility.
Star Acquisition. In June 1999, we acquired oil properties located onshore
and offshore California for $61.4 million. The acquired properties had estimated
net proved reserves at June 30, 1999 of 33.7 MMBOE and will increase our
production from California by approximately 5.0 MBOE per day. All of these
properties are additional interests in or near our existing properties. The
acquisition includes interests in the Cymric, the East Coalinga, the Dos Cuadras
and other fields we operate.
Recovery of Oil Prices. The price for crude oil on the New York Mercantile
Exchange for near month contracts increased from $12.09 per Bbl at December 31,
1998 to $19.29 per Bbl at June 30, 1999. Our estimated net proved reserves would
have increased 61.8 MMBOE during the first six months of 1999, without including
the effect of acquisitions and divestitures.
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<PAGE> 42
PRINCIPAL PROPERTIES
The following table sets forth information about our principal oil and gas
properties. This table does not include our properties in East Texas which we
sold on January 6, 1999.
<TABLE>
<CAPTION>
PRE-TAX
ESTIMATED DISCOUNTED
NET PROVED RESERVES, AS OF PRESENT
JUNE 30, 1999 VALUE AT 1998 NET PRODUCTION
--------------------------- JUNE 30, ---------------------------
OIL GAS BOE 1999 OIL GAS BOE
(MBbls) (MMcf) (MBOE) (M$) (MBbls) (MMcf) (MBOE)
------- ------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
U. S. Properties:
California Fields:
Cymric Fields ............... 49,189 4,974 50,018 150,740 3,905 1,604 4,172
Midway-Sunset Field ......... 43,162 -- 43,162 108,479 2,900 -- 2,900
Brea Olinda Field ........... 32,959 21,126 36,480 86,112 826 136 849
Belridge Field .............. 12,059 947 12,217 54,003 608 198 641
Santa Clara Field ........... 17,723 30,515 22,809 47,509 940 649 1,048
Point Pedernales
Field ..................... 14,134 8,360 15,527 32,840 2,385 990 2,550
Huntington Beach
Field ..................... 9,532 1,015 9,701 31,564 753 77 766
Dos Cuadras Field ........... 6,921 3,064 7,432 16,082 388 290 436
East Dos Cuadras
Field ..................... 6,162 8,134 7,518 14,101 334 354 393
Other ....................... 25,753 35,725 31,707 55,357 3,401 9,407 4,969
------- ------- ------- ------- ------- ------- -------
Total California ....... 217,594 113,860 236,571 596,787 16,440 13,705 18,724
Other U.S. Fields ............. 497 9,334 2,052 13,673 817 5,766 1,778
------- ------- ------- ------- ------- ------- -------
Total U.S. ............. 218,091 123,194 238,623 610,460 17,257 19,471 20,502
------- ------- ------- ------- ------- ------- -------
International Properties:
Yombo Field, Congo .......... 17,208 -- 17,208 75,040 1,461 -- 1,461
Masseko Field, Congo ........ 7,878 -- 7,878 8,609 -- -- --
------- ------- ------- ------- ------- ------- -------
Total
International ........ 25,086 -- 25,086 83,649 1,461 -- 1,461
------- ------- ------- ------- ------- ------- -------
Company Total (excluding
Star Acquisition
Fields) ................... 243,177 123,194 263,709 694,109 18,718 19,471 21,963
======= ======= ======= ======= ======= ======= =======
Star Acquisition
Fields .................... 29,089 27,519 33,676 141,893 N/A N/A N/A
------- ------- ------- ------- ------- ------- -------
Company Total ............... 272,266 150,713 297,385 836,002 N/A N/A N/A
======= ======= ======= ======= ======= ======= =======
</TABLE>
PRODUCING PROPERTIES
California Properties
We acquired substantially all of our California properties from Unocal in
April 1996. We acquired additional properties in California from Texaco, Inc. in
the Star acquisition in June 1999.
Cymric Field. The Cymric Field, discovered in 1909, is located in the
southern San Joaquin Basin in Kern County, California. We own an average 99%
working (88% average net revenue) interest in properties in the field, and
operate 12 leases in the field, totaling 4,700 acres and containing 614 active
wells (544 producers, 70 injectors). Production is from two zones, the Tulare
formation at depths from 400 to 1,700 feet and the Antelope Shale at depths from
1,000 to 4,500 feet.
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<PAGE> 43
Between April 1996 and December 1998, we drilled 205 wells, of which 109
were Tulare completions (including 11 horizontal Tulare wells), 53 were Thermal
Antelope completions, and 42 were deeper fracture stimulated Antelope
completions. We also have used multiple completion technology in producing the
Thermal Antelope which can triple the production from a well while increasing
the costs by only half. Production has increased by 76% from 6.8 MBBLS per day
at the time of the acquisition to 11.9 MBBLS per day in December 1998.
Additionally, our estimated net proved reserves increased in this field as of
June 30, 1999 by 21.5 MMBOE since April 1996. We plan to drill an additional 10
wells during 1999, including four horizontal wells and six injection wells.
In the Star acquisition described under "Recent Developments" we acquired
additional interests in the Cymric Field.
Midway Sunset Field. The Midway Sunset Field, discovered in the 1890's, is
located in the southern San Joaquin Basin in Kern County, California. We own a
100% working (97% average net revenue) interest in our properties in the field.
We operate seven leases in the field, totaling 1,120 acres and containing 536
(497 producers, 39 injectors) active wells. Production is from five zones with
the Potter Sand and the Thermal Diatomite accounting for over 95% of total
production.
Between April 1996 and December 1998, we drilled 119 wells, of which 55
were Potter completions (including 11 horizontal Potter wells), 39 were Thermal
Diatomite completions, seven were injection wells and 18 were Sub Potter sand
completions. We have also used multiple completion technology in producing the
Thermal Diatomite. Production increased by 29% from 5.9 MBBLS per day at the
time of the acquisition in April 1996 to 7.6 MBBLS per day for December 1998.
Our estimated net proved reserves increased in this field as of June 30, 1999 by
12.7 MMBOE since April 1996. We plan to drill an additional 10 vertical wells
during 1999.
Brea Olinda Field. The Brea Olinda Field, discovered in 1880, is located in
Orange County near the City of Brea, California. We operate three fee properties
with a 100% working and net revenue interest containing 189 active wells. We
also have royalty interests in an additional 57 wells in this field. Production
is from multiple-pay zones in the Miocene and Pliocene sandstones at depths of
up to 6,500 feet.
In 1996, following our acquisition of the property, 11 wells were
recompleted, a new gas plant start-up was accomplished and two infill producers
plus one waterflood injector were drilled. In 1997, we drilled seven infill
producers and seven waterflood injectors and initiated water injection in three
fault blocks. In 1998, we drilled three additional infill producers, continued
waterflood expansion, and installed an electrical generation unit to power our
field operations.
Belridge Field. The Belridge Field, discovered in 1911, is located in the
southern San Joaquin Basin in Kern County, California. We own a 100% working and
net revenue interest in two leases in the field. In addition, we own a royalty
interest in the productive zones above 2,000 feet on one of the leases.
Between April 1996 and December 1998, we began redevelopment of the Tulare
sands on one of the leases. This lease was idle at the time of the acquisition.
We have drilled 54 wells in the Tulare sand including 10 horizontal and 28
injection wells. All of these wells were drilled during 1997 and 1998. Activity
also continues in the ongoing development of the non-operated royalty property.
We plan to drill an additional 20 wells in the field during 1999 including five
horizontal wells. We also began a continuous steam injection program in 1998 as
part of the redevelopment of the previously idle property. Our estimated net
proved reserves increased in this field as of June 30, 1999 by 8.3 MMBOE since
April 1996.
Santa Clara Field. The Santa Clara Field is located seven miles offshore of
Ventura County in the Santa Barbara Channel. We operate the platform (Gilda)
with a 100% working (83.33% net revenue) interest. The field was developed in
1991 with production from the Pico, upper Repetto, lower Repetto, and Monterey
reservoirs.
Since April 1996, we have drilled and completed seven wells. Our estimated
net proved reserves increased in this field as of June 30, 1999 by 10 MMBOE
since April 1996.
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<PAGE> 44
Point Pedernales Field. We acquired a 12% working (10% net revenue)
interest in the Point Pedernales Field in July 1994 and an additional 68%
working (57% net revenue) interest in the field as part of the acquisition of
the California properties in April 1996. We operate the field which is located
3.5 miles offshore Santa Barbara County, California, in federal waters. There
are 14 wells in the field, producing from a 12-pile 72 slot platform (Irene) in
240 feet of water. Production is from the Monterey Shale at depths from 3,500 to
5,150 feet.
In 1997, both a successful infill well and an exploratory well were
completed in the Point Pedernales Field. The successful exploratory well proved
the existence of the Tranquillon Ridge Field, located to the southeast of the
Point Pedernales Field, primarily in California state waters. We believe this
new field contains substantial recoverable reserves, and can be developed using
existing Point Pedernales infrastructure. We are in discussions with state
regulators for the purpose of acquiring a lease to develop this field.
We experienced an oil spill due to a pipeline leak at the end of September
1997. Repairs were performed and the field was back on production before the end
of December 1997. Also in 1997 and early 1998, two wells were recompleted to
provide additional gas production.
Huntington Beach Field. The Huntington Beach Field in Orange County is
located beneath the city of Huntington Beach extending offshore into state
waters. We operate the platform which is located 2 1/4 miles offshore and was
installed in 1964. We own a 100% working (82.7% net revenue) interest.
Production is from two separate sands in the Upper Miocene reservoir.
In 1997, we initiated a waterflood expansion and began a production
enhancement program that added incremental production of over 900 Bbls per day.
In 1999, we plan to continue both the waterflood expansion and production
enhancements.
Other U.S. Properties
North Frisco City Field. We discovered the North Frisco City Field in 1991.
It is located in Monroe County, Alabama. We operate the field which is
productive in the Haynesville sand at 12,000 feet. We own an approximate 22%
working (17% net revenue) interest. The field was unitized in 1994 in order to
initiate a pressure maintenance project. This successful pressure maintenance
project is expected to maintain production at current levels and should increase
the ultimate recovery from the field from 25% to 50% of original oil in place.
Our average daily production was 761 Bbls of oil per day and 856 Mcf of natural
gas per day during 1998.
Giddings Field. We currently own an interest in 12 producing wells in the
Giddings field, located in Grimes and Austin Counties, Texas and have an average
46.9% working (35.2% net revenue) interest in these wells. Production is derived
from the highly fractured Austin Chalk formation at approximate depths of
between 12,800 and 15,300 feet. All of these wells are horizontally drilled and
have been prolific producers with rates as high as 30 MMcf per day. We own a
total of 6,078 acres in our Turkey Creek Prospect area. We recently drilled the
Eller 1-H well on our 12,500 acre Nelsonville Prospect in Austin County. The
well initially produced natural gas at 30 MMcf per day. We own a 50% working
interest in this acreage. Our net average daily production was 8.8 MMcf per day
and 30 Bbls per day for 1998.
International
Republic of Congo. In February 1995, we acquired a 43.8% working (32.5% net
revenue) interest in the Congo Marine I Exploration Permit covering the Yombo
and Masseko Fields offshore Congo. Our interest currently consists of a 50%
working (37.5% average net revenue) interest. The permit area is located 30
miles offshore in 360 feet of water. The Yombo Field has 22 producing wells and
two water injection wells on two platforms that produce from the Tchala and
Sendji formations between 2,800 and 8,000 feet. Estimated net proved reserves in
the Yombo Field were 17.2 MMBbls on December 31, 1993, the effective date of its
acquisition by us. Since that date, net production has been 8.3 MMBbls and
estimated net proved reserves have increased to 25.1 MMBbls as of June 30, 1999,
52% of which are proved developed. As part of the acquisition, we also acquired
a converted super tanker with storage capacity of over one million barrels of
oil for use as a floating production, storage and offloading vessel. Our
production is converted to fuel oil on the vessel and sold on the
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<PAGE> 45
basis of #6 fuel oil with less than 1% sulphur content. CMS NOMECO Oil and Gas
Co. is the operator of the concession.
During 1996, we completed a six-well development drilling program and a
successful exploratory well to the Lower Sendji formation in the Yombo Field.
The exploratory well has produced 1.3 MMBOE through December 1998 and currently
produces at 1.2 MBbls per day. In 1997, we drilled a successful exploratory well
to evaluate the Lower Sendji and subsalt section underlying the Masseko
structure located several miles to the west of the Yombo Field, as well as to
further delineate the Tchala and Upper Sendji zones which were discovered but
not developed by a previous operator. This well tested at rates of over 3.0
MBbls per day in the Middle Sendji and successfully delineated the shallow
horizons. The operator has obtained preliminary platform and facility designs.
The Masseko structure had estimated net proved reserves of 7.6 MMBbls at
December 31, 1998.
During 1998, the operator continued expansion of the waterflood projects to
enhance production from both the Tchala and Upper Sendji formations. Incremental
production increases of 1.0 MBbls per day have been achieved to date. In August
1998, a platform rig began drilling in the field. A total of five new wells and
three sidetrack wells are expected to be drilled by July 1999. Production for
December 1998 averaged 4.2 MBbls per day. Current production is approximately
6.0 MBbls per day.
EXPLORATION PROSPECTS
Our exploration efforts focus on a mixture of low-risk step-out
opportunities associated with known producing areas and high potential "impact"
prospects. We seek to reduce the risk normally associated with high potential
prospects through the utilization of advanced technology and by participating
with other experienced industry partners.
During 1998, we drilled 18 gross exploration wells, of which eight (44%)
were successful. Our most significant discoveries were at the McKittrick Front
700, the Twisselman 6-14 and the Mongoose #3, all located in California. We plan
to participate in two exploration wells in 1999 and have budgeted $16.0 million
for exploration in 1999. Both 1999 exploration wells will be drilled in
California.
In 1999, we will continue to evaluate our East Cape Three Points (1.7
million acres) and Accra-Keta (2.7 million acres) Blocks offshore the Republic
of Ghana in West Africa. We operate both blocks and hold 75% and 100% working
interests, respectively. Our 1998 exploration well on the East Cape Three Points
block encountered non-commercial quantities of hydrocarbons; however, additional
prospects remain to be evaluated and will be a focus of 1999 efforts. We have
several prospects in the Accra-Keta Block. These will be further evaluated by
new seismic data to be acquired in 1999, with the drilling of an exploration
well planned for 2000.
An exploratory well on the Chott Fejaj Permit in Tunisia, in which we
participated, encountered non-commercial quantities of hydrocarbons. Encouraged
by the results of the well, the partners in the well obtained a renewal of the
permit in order to allow deepening of the well. Current plans are to farmout the
deepening of the well to an industry partner in 2000.
During the second quarter of 1999, we abandoned our Cree Fee 1A exploration
well in the Midway Peak Prospect in Kern County, California. We owned an 80%
working interest in the well which was drilled to approximately 17,150 feet. Dry
hole costs for this well (net to us) were $6.5 million through May 1999. The
cost of the Cree Fee 1A exploration well was included in our 1998 budget and is
not a part of our 1999 budget.
In addition, a substantial portion of our exploration activity in the
balance of 1999 will focus on identifying, evaluating and pursuing high-quality
exploration opportunities in West Africa and North Africa.
Our California properties also include an average 12% working (10% net
revenue) interest in nine tested but undeveloped tracts located offshore
California in the vicinity of the Point Pedernales Field. The oil and gas
industry has voluntarily suspended development activities on these and other
undeveloped offshore tracts pending completion of a study aimed at proposing a
set of streamlined development rules that can be agreed upon by federal, state
and local regulators. The completion of
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<PAGE> 46
the study is scheduled for the third quarter 1999. We believe these tracts
contain substantial recoverable oil reserves and plan to participate in the
development of the fields when the suspension is lifted.
OIL AND GAS RESERVES
The following table shows information about our estimated net proved and
proved developed reserves of oil and gas.
<TABLE>
<CAPTION>
DECEMBER 31, JUNE 30,
--------------------------------------------------------- -----------------
1996 1997 1998 1999
----------------- ----------------- ----------------- -----------------
OIL GAS OIL GAS OIL GAS OIL GAS
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
------- ------- ------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Proved reserves ...... 186,053 394,630 227,264 390,691 190,141 403,256 272,266 150,713
Proved developed
reserves ........... 138,815 236,013 153,012 266,179 133,319 308,667 202,074 121,042
</TABLE>
The following table sets forth the pre-tax discounted present value of our
oil and gas reserves:
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------ JUNE 30,
1996 1997 1998 1999
---------- ---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Pre-tax discounted present value:
United States ...................... $1,251,378 $ 832,808 $ 277,963 $ 752,353
International ...................... 107,203 68,299 21,970 83,649
---------- ---------- ---------- ----------
Total ...................... $1,358,581 $ 901,107 $ 299,933 $ 836,002
========== ========== ========== ==========
</TABLE>
In general, estimates of reserves and of the future net cash flows
attributable to the reserves are based upon a number of variable factors and
assumptions, such as historical production from the properties, the assumed
effects of regulation by governmental agencies and assumptions concerning future
oil and gas prices and future operating costs, all of which may vary
considerably from actual results. All such estimates are to some degree
speculative, and classifications of reserves are only attempts to define the
degree of speculation involved. For these reasons, estimates of the economically
recoverable oil and natural gas reserves attributable to any particular group of
properties, classifications of such reserves based on risk of recovery and
estimates of the future net cash flows expected therefrom, prepared by different
engineers or by the same engineers at different times, may vary substantially.
The actual production, revenues, severance and excise taxes, development and
operating expenditures with respect to our reserves will vary from estimates,
and such variances could be material. Information set forth herein regarding the
quantities of and cash flows attributable to our oil and gas reserves are
forward looking statements. See "Forward-Looking Statements."
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<PAGE> 47
ACREAGE
The following table sets forth information about the properties we owned on
December 31, 1998. Undeveloped acreage is considered to be those acres 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 or not
such acreage contains proved reserves.
<TABLE>
<CAPTION>
GROSS NET
--------- ---------
<S> <C> <C>
Developed acreage ...................... 284,158 138,566
Undeveloped acreage .................... 4,835,338 4,161,276
---------- ----------
Total ........................ 5,119,496 4,299,842
========== ==========
</TABLE>
Undeveloped acreage primarily consists of interests in the Republic of
Ghana.
PRODUCTIVE WELLS
The following table sets forth our gross and net interests in productive
oil and gas wells as of December 31, 1998. Productive wells are producing wells
and wells capable of production.
<TABLE>
<CAPTION>
GROSS NET
----- -----
<S> <C> <C>
Oil wells .............................. 2,500 2,122
Gas wells .............................. 352 139
----- -----
Total ........................ 2,852 2,261
===== =====
</TABLE>
DRILLING ACTIVITY
The number of gross and net exploratory and development wells we drilled is
described below.
Exploratory Wells
<TABLE>
<CAPTION>
GROSS NET
----------------------------------- --------------------------------------
NON- NON-
PRODUCTIVE PRODUCTIVE TOTAL PRODUCTIVE PRODUCTIVE TOTAL
---------- ---------- ----- ---------- ---------- -----
<S> <C> <C> <C> <C> <C> <C>
1996........................ 6 7 13 3.40 2.09 5.49
1997........................ 9 5 14 6.63 2.33 8.96
1998........................ 8 6 14 4.09 3.58 7.67
</TABLE>
Development Wells
<TABLE>
<CAPTION>
GROSS NET
----------------------------------- --------------------------------------
NON- NON-
PRODUCTIVE PRODUCTIVE TOTAL PRODUCTIVE PRODUCTIVE TOTAL
---------- ---------- ----- ---------- ---------- -----
<S> <C> <C> <C> <C> <C> <C>
1996.................... 149 1 150 125.24 1.00 126.24
1997.................... 236 1 237 217.52 1.00 218.52
1998.................... 155 -- 155 134.43 -- 134.43
</TABLE>
GAS PLANT, PIPELINES AND OTHER FACILITIES
In 1997 we decided to sell the gas gathering, processing and other
mid-stream assets we owned which were not related to our core oil and gas
assets. Following this decision, we made the following divestitures:
o in May 1997, we sold our 95% interest in the Benedum Gas Plant for
$25.0 million;
o in February 1998, we sold our 48.5% interest in the Richfield Gas
Storage Facility for $2.2 million; and
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<PAGE> 48
o in July 1998, we sold our 80% interest in Bright Star Gathering,
Inc. for $1.5 million.
We have also entered into an agreement to sell our interest in the Illini
Gas Pipeline which we expect to close in 1999.
We continue to own three gas processing plants in California, which process
gas from our California properties.
LEGAL PROCEEDINGS
We have been named as a defendant in the lawsuit Gloria Garcia Lopez and
Husband, Hector S. Lopez, Individually, and as successors to Galo Land & Cattle
Company v. Mobil Producing Texas & New Mexico, et al. currently pending in the
79th Judicial District Court of Brooks County, Texas.
This suit was filed on August 30, 1996. The plaintiffs allege:
o underpayment of royalties and claim damages, on a gross basis
against all working interest owners, of $27.7 million plus $26.2
million in interest for the period from 1985 to date;
o that their production was improperly commingled with gas produced
from an adjoining lease, resulting in damages, including interest
of $40.8 million (gross); and
o numerous other claims that may result in unspecified damages.
Our working interest in these properties is 20%. We, along with the other
defendants in this case, deny these allegations and are vigorously contesting
these claims. We do not believe that the final outcome of this matter will have
a material adverse impact on our operating results, financial condition or
liquidity.
Although from time to time we are involved in other legal proceedings
relating to the ordinary course of our business, we do not believe that any of
these proceedings, individually or in the aggregate, are material to us.
CONTINGENT PAYMENT TO UNOCAL
In connection with the acquisition of the properties located in California
from Unocal in 1996, we agreed to make a contingent payment for the years 1998
through 2004 if oil prices exceed thresholds set forth in our agreement with
Unocal. The contingent payment will equal 50% of the difference between the
actual average annual price received on a field-by-field basis (capped by a
maximum price) and a minimum price, less taxes, multiplied by the actual number
of barrels of oil sold during the respective year. The minimum price of $17.75
per Bbl under the agreement (determined based on near month delivery of West
Texas intermediate crude oil on the NYMEX) is escalated at 3% per year and the
maximum price of $21.75 per Bbl on the NYMEX is escalated at 3% per year.
Minimum and maximum prices will be netted down to the field level using a fixed
differential equal to approximately the differential between actual sales prices
and NYMEX prices in effect in 1995 ($4.34 per Bbl weighted average for all the
properties acquired from Unocal). We will accumulate credits to offset the
contingent payment when prices are $0.50 per Bbl below the minimum price. We
accumulated $45.5 million in price credits as of June 30, 1999, which will be
used to reduce future amounts owed under the contingent payment.
YEAR 2000
Like all other enterprises that utilize computer technology, we face a
threat of business disruption from the year 2000 issue. The year 2000 issue or
Y2K refers to the inability of computer and other information technology systems
to properly process date and time information, stemming from the outdated
programming practice of using two digits rather than four to represent the year
in a date. The consequence of Y2K is that computer and embedded processing
systems are at risk of malfunctioning, particularly during the transition from
1999 to 2000.
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<PAGE> 49
The effects of Y2K are exacerbated by the interdependence of computer and
telecommunication systems throughout the world. This interdependence also exists
among us and our vendors, customers and business partners, as well as with
regulators in the United States and host governments abroad.
The risks associated with Y2K that are expected to affect our business,
fall into three general areas:
o failure of the computer systems which control our financial
reporting and administrative systems;
o failure of the embedded systems in our field process control units
which control the production of oil and gas from our fields; and
o failure of computer systems of third parties with whom we do
business or on whom we rely to conduct our business.
We intend to address each of these three areas through a readiness process
that seeks to:
o increase the awareness of the issue among all employees;
o identify areas of potential risk;
o assess the relative impact of these risks and our ability to
manage them;
o remediate high priority risks wherever possible; and
o engage in contingency planning for identifiable risks that cannot
be remediated.
Our board of directors has assigned the oversight of Y2K to the audit
committee. From the audit committee, all responsibility for the readiness effort
runs through our chief executive officer, and from our chief executive office
through our chief financial officer (for financial and administrative systems)
and the vice president of exploitation (for embedded systems in field process
control units). The officers routinely update the audit committee and the entire
board on their efforts to increase readiness for Y2K.
We outsource a substantial portion of our administration and operations to
Torch Energy Advisors Incorporated. We have worked with Torch to jointly develop
a plan to address risks associated with Y2K as it is expected to affect our
business. Torch provides our financial and administrative systems and operates a
substantial portion of our properties. As used in the remainder of this Y2K
discussion, references to us may include the Torch employees assisting us in our
Y2K readiness program. As of August 1, 1999, we are in various stages of
implementation of the plan, as summarized below.
Financial and Administrative Systems
Awareness. We have conducted numerous Y2K informational programs with our
employees and Torch employees who provide input to or utilize the output of our
financial and administrative systems. Employees at all levels of our
organization have been asked to participate in the identification of potential
Y2K risks which might otherwise go unnoticed by higher level employees and
officers. As a result of these programs, we believe awareness of the Y2K issue
is high among our employees and employees of Torch.
Risk Identification. We believe that our significant financial and
administrative systems exposure is the Y2K status of the accounting and land
administration software that we use to collect and manage data for internal
management decision making and for external financial reporting purposes. Other
concerns include network hardware and software, desktop computing hardware and
software, telecommunications and office space readiness.
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<PAGE> 50
Risk Assessment. The failure to identify and correct a material Y2K problem
in our financial and administrative systems could result in inaccurate or
untimely financial information for management decision-making or financial
reporting purposes. The severity of any such problems will impact the time
period during which the quality of management information comes under question.
At this time, we believe that any Y2K disruptions associated with our financial
and administrative systems will not have a material effect on us.
Remediation. Following upgrades to our accounting software, we achieved
full Y2K compliance for our Oracle-based financial and administrative systems in
July 1999. In addition, Torch has inventoried all network and desktop software
applications used by us and believes them to be generally Y2K compliant. The
costs of all such risk assessments and remediation are borne by Torch under the
terms of our outsourcing agreements.
Contingency Planning. If there are significant unanticipated disruptions in
our financial and administrative systems, a number of accounting processes that
are currently automated will need to be performed manually. Based on current
information, we have not concluded that contingency arrangements for temporary
staffing to accommodate such situations will be warranted.
Embedded Systems
Awareness. Our Y2K program has involved all levels of management of field
assets from production foremen and higher. As a result, we believe awareness of
the issue is high among our field personnel.
Risk Identification. As is the case with most oil and gas companies,
operation of our properties is highly automated. We have completed a
comprehensive inventory of embedded computer components within the process
control systems of our operated oil and natural gas fields and processing
plants. We identified approximately 1,900 embedded components in these
computerized systems. We researched the manufacturer and/or installer of each
component to determine the anticipated compliance or non-compliance of the
component. To date, almost all of our embedded components researched have been
deemed either date insensitive or Y2K compliant. The Y2K compliance status for
approximately 16% of our embedded components have not yet been identified, and
research is continuing on these components. However, the complexity of embedded
systems is such that a small minority of non-compliant components, even a single
non-compliant component, can corrupt an entire system.
Risk Assessment. The failure to identify and correct a Y2K problem could
result in outcomes ranging from errors in data reporting, to curtailments or
shutdowns in production, to environmental pollution or safety incidents. In an
attempt to prevent such failures, we conducted system-level testing of assets
owned at June 30, 1999. The component -level evaluation is complete, with the
status of 16% of components still unknown and research on these components
continuing. The system-level evaluation is virtually complete with approximately
90% of all critical systems owned at June 30, 1999 fully tested. Testing on the
remaining systems is expected to be completed by September 30, 1999. For
properties acquired after June 30, 1999, evaluation is ongoing and the extent of
testing required is to be determined. To assist in this effort, we and Torch
Operating Company have retained consultants who are knowledgeable and
experienced in the assessment of Y2K issues impacting field operations. We
completed risk assessment of all mission critical systems in the second quarter
of 1999 for all of our properties owned as of June 30, 1999. Remediation will
extend to September 30, 1999 for properties owned at June 30, 1999. Costs
incurred through June 30, 1999, were not material to our results of operations,
and cost of the assessment is not expected to be material to our future
financial results. Because of the complexity of the risks inherent in the Y2K
problem, at this time we are unable to express any degree of confidence that
there will not be material production disruptions associated with Y2K
non-compliance. Depending on the magnitude of any such disruptions and the time
required to correct them, such failures could materially and adversely impact
our results of operations, liquidity and financial condition.
Remediation. We have prioritized the remediation of embedded components and
systems that are either known to be Y2K non-compliant or that have higher risk
of Y2K failures. We intend to give first priority to the remediation of any
situation with potential impacts to human health and safety or the environment,
and will further prioritize remediation targets by the anticipated financial
impact.
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<PAGE> 51
We are testing, upgrading and re-testing those embedded components and systems
in field process control units deemed to pose the greatest risk. It is important
to note that in some circumstances, the procedures that are used to test
embedded components for Y2K compliance themselves pose a risk of damaging the
component or corrupting the system, thereby accelerating the consequences of Y2K
failures. Accordingly, in some situations, it may be deemed the most prudent
decision not to test certain embedded components and systems. The amount of
capital that we budgeted for these anticipated costs to remediate or replace
embedded components and systems that pose the greatest risk of Y2K
non-compliance is approximately $1.6 million and is not considered to be
material to our liquidity or financial condition. However, it is expected that
some additional risks may be identified during 1999, so there can be no
assurances that actual capital spending on Y2K remediation will not
significantly exceed any amounts originally budgeted.
Contingency Planning. If material production disruptions occur as a result
of Y2K failures in field operations, our operating cash flow will be impacted.
This contingency is being factored into deliberations on capital budgeting,
liquidity and capital adequacy. It is our intention to maintain adequate
financial flexibility to sustain us during any such period of cash flow
disruption. We are currently evaluating all alternatives and assessing our
levels of risks based on the testing performed to date. We should have a better
understanding of these issues by the end of the third quarter, which will enable
us to execute the best contingency plan given the aforementioned risks.
Third Party Exposures
Awareness. We have conducted numerous Y2K informational programs with our
employees and the employees of Torch who have significant interaction with our
outside vendors, customers, and business partners. All of these employees have
been asked to participate in the identification of potential third party Y2K
risks, which might otherwise go unnoticed by higher level employees and
officers. We believe that awareness of the issue is high.
Risk Identification. Our most significant third party Y2K exposure is to
the refinery customers who purchase our oil production, on the customer side,
and from electricity and other utility companies supplying field operations, on
the supplier side. Other significant concerns include the readiness of third
party crude oil and natural gas pipeline facilities involved in the
transportation of our products, the integrity of global telecommunication
systems, the readiness of commercial banks to execute electronic fund transfers,
and the ability of the financial community to maintain an orderly market in our
securities.
Risk Assessment. Refineries are extremely complex operations containing
hundreds or thousands of computerized processes. The failure on the part of a
refining customer to identify and correct a material Y2K problem could result in
material disruptions in the sale of our production to that refinery. In many
cases, our production may not be easily shifted to other markets, and the result
can range from reduced realizations on crude oil produced, curtailed production
or even shut-in production. Failures of pipelines that connect our production to
markets may have similar effects. Although we have made inquiries to key third
parties on the subject of Y2K readiness and will continue to do so, we have no
ability to require responses to such inquiries or to independently verify their
accuracy. Accordingly, we are unable to express any degree of confidence that
there will not be material production disruptions associated with third party
Y2K non-compliance. Depending on the magnitude of any such disruptions and the
time required to correct them, such failures could materially and adversely
impact our results of operations, liquidity and financial condition.
Remediation. Where we perceive significant risk of Y2K non-compliance that
may have a material impact on our operations, and where our relationship with a
vendor, customer or business partner permits, we may pursue joint testing during
1999. Joint testing would occur following upgrades and other remediation to
hardware, software and communication links, as applicable, with the intent of
determining that the remediated system being tested will perform as expected on
December 31, 1999.
Contingency Planning. Should material production disruptions occur as a
result of Y2K failures of third parties, our operating cash flow will be
impacted. This contingency is being factored into deliberations on capital
budgeting, liquidity and capital adequacy. It is our intention to maintain
adequate financial flexibility to sustain us during any such period of cash flow
disruption. We are currently evaluating all alternatives and assessing our
levels of risks based on the testing performed to date and our confidence in the
Y2K readiness programs of major/critical suppliers and customers. We should have
a better understanding of these issues by the end of the third quarter, which
will enable us to execute the best contingency plan given the aforementioned
risks.
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MARKETS
The markets for hydrocarbons continue to be quite volatile. Our financial
condition, operating results, future growth and the carrying value of our oil
and gas properties are substantially dependent on prevailing prices of oil and
gas. Our ability to maintain or increase our borrowing capacity and to obtain
additional capital on attractive terms is also substantially dependent upon oil
and gas prices. Prices for oil and gas are subject to large fluctuations in
response to relatively minor changes in the supply of and demand for oil and
gas, market uncertainty and a variety of additional factors beyond our control.
These factors include weather conditions in the United States, the condition of
the United States economy, the actions of the Organization of Petroleum
Exporting Countries, governmental regulation, political stability in the Middle
East and elsewhere, the foreign supply of oil and gas, the price of foreign oil
imports and the availability of alternate fuel sources. Any substantial and
extended decline in the price of oil or gas would have an adverse effect on our
carrying value of our proved reserves, our borrowing capacity, our ability to
obtain additional capital, and our revenues, profitability and cash flows from
operations.
Properties characterized by the production of San Joaquin Valley heavy oil,
which we define as those fields which produce primarily 15 (degrees) API quality
crude oil or heavier through thermal operations, constituted 28% of our total
1998 output.
In addition, properties which produce primarily other grades of relatively
heavy oil, generally, 19 (degrees) API or heavier but produced through non-
thermal operations, constituted 2% of our total 1998 output.
The market for California heavy oil differs from the established market
indices for oil elsewhere in the U.S., due principally to the higher
transportation and refining costs associated with heavy oil.
Our Yombo Field production in our Marine I Permit offshore the Congo
produces a relatively heavy crude oil, 16-20 (degrees) API gravity, which is
processed into a low-sulfur No. 6 fuel oil product for sale to worldwide
markets. Production from this property constituted 6% of our total 1998 output.
The market for residual fuel oil differs from the markets for WTI and other
benchmark crudes due to its primary use as an industrial or utility fuel versus
the higher value transportation fuel component, which is produced from refining
most grades of crude oil.
Sales to Tosco, formerly Unocal, accounted for 60%, 62% and 52% of 1998,
1997 and 1996 oil and gas revenues, respectively. Also in 1998, sales to Torch
Energy L.L.C. accounted for 10% of total 1998 oil and gas revenues. The loss of
any single significant customer or contract could have a material adverse short-
term effect on us; however, we do not believe that the loss of any single
significant customer or contract would materially affect our business in the
long-term.
Under the terms of a $30.0 million volumetric production payment, we were
committed to deliver 10.7 BCF of natural gas through December 1998. As of
December 31, 1998, we had fulfilled our obligation under this commitment. There
are no other significant delivery commitments, and substantially all of our oil
and gas production is sold at market responsive pricing through a marketing
affiliate of Torch Energy Advisors Incorporated. From time to time, we may enter
into crude oil and natural gas price swaps or other similar transactions to
hedge our exposure to price fluctuations.
REGULATION
Oil and Gas Regulation
The availability of a ready market for oil and gas production depends upon
numerous factors beyond our control. These factors include state and Federal
regulation of oil and gas production and transportation, as well as regulations
governing environmental quality and pollution control, state limits on allowable
rates of production by a well or proration unit, the amount of oil and gas
available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive fuels.
For example, a productive gas well may be "shut-in" because of an over-supply of
gas or lack of an available gas pipeline in the areas in which we may conduct
operations. State and Federal regulations generally are intended to prevent
waste of oil and gas, protect rights to produce oil and gas between owners in a
common reservoir, control the amount of oil and gas produced by assigning
allowable rates of production and control contamination of the environment.
Pipelines and gas plants also are subject to the jurisdiction of various
Federal, state and local agencies.
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<PAGE> 53
Our sales of natural gas are affected by the availability, terms and costs
of transportation. The rates, terms and conditions applicable to the interstate
transportation of gas by pipelines are regulated by the Federal Energy
Regulatory Commission under the Natural Gas Acts, as well as under Section 311
of the Natural Gas Policy Act. Since 1985, the Federal Energy Regulatory
Commission has implemented regulations intended to increase competition within
the gas industry by making gas transportation more accessible to gas buyers and
sellers on an open-access, non-discriminatory basis.
Our sales of oil are also affected by the availability, terms and costs of
transportation. The rates, terms, and conditions applicable to the interstate
transportation of oil by pipelines are regulated by the Federal Energy
Regulatory Commission under the Interstate Commerce Act. In this connection, the
Federal Energy Regulatory Commission has implemented a simplified and generally
applicable ratemaking methodology for interstate oil pipelines to fulfill the
requirements of Title VIII of the Energy Policy Act of 1992 comprised of an
indexing system to establish ceilings on interstate oil pipeline rates. The
Federal Energy Regulatory Commission will also, under defined circumstances,
permit alternative ratemaking methodologies for interstate oil pipelines such as
the use of cost of service rates, settlement rates, and market-based rates.
Market-based rates will be permitted to the extent the oil pipeline can
demonstrate that it lacks significant market power in the market in which it
proposes to charge market-based rates.
Environmental Regulation
General. Our activities are subject to existing Federal, state and local
laws and regulations governing environmental quality and pollution control. It
is anticipated that, absent the occurrence of an extraordinary event, compliance
with existing Federal, state and local laws, rules and regulations regulating
the release of materials in the environment or otherwise relating to the
protection of the environment will not have a material effect upon our
operations, capital expenditures, earnings or competitive position.
Our activities with respect to exploration, drilling and production from
wells, natural gas facilities, including the operation and construction of
pipelines, plants and other facilities for transporting, processing, treating or
storing natural gas and other products, are subject to stringent environmental
regulation by state and Federal authorities including the Environmental
Protection Agency, the Department of Transportation and the Federal Energy
Regulatory Commission. Such regulation can increase the cost of planning,
designing, installing and operating such facilities. In most instances, the
regulatory requirements relate to water and air pollution control measures.
Waste Disposal. We currently own or lease, and have in the past owned or
leased, numerous properties that have been used for production of oil and gas
for many years. Although we have utilized operating and disposal practices that
were standard in the industry at the time, hydrocarbons or other wastes may have
been disposed of or released on or under the properties we owned or leased. In
addition, many of these properties have been operated by third parties over whom
we had no control as to such entities' treatment of hydrocarbons or other wastes
or the manner in which such substances may have been disposed of or released.
State and Federal laws applicable to oil and gas wastes and properties have
become more strict. Under these new laws, we could be required to remove or
remediate previously disposed wastes, including wastes disposed of or released
by prior owners or operators, or property contamination, including groundwater
contamination, or to perform remedial plugging operations to prevent future
contamination.
We may generate wastes, including hazardous wastes that are subject to the
Federal Resource Conservation and Recovery Act and comparable state statutes.
The Environmental Protection Agency has limited the disposal options for certain
hazardous wastes and is considering the adoption of stricter disposal standards
for nonhazardous wastes. Furthermore, certain wastes generated by our oil and
gas operations that are currently exempt from treatment as "hazardous wastes"
may in the future be designated as "hazardous wastes," and therefore be subject
to more rigorous and costly operating and disposal requirements.
Superfund. The Federal Comprehensive Environmental Response, Compensation
and Liability Act, also known as the "Superfund" law, imposes joint and several
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons with respect to the release of a "hazardous
substance" into the environment. These persons include the current owner and
operator of a facility and persons that disposed of or arranged for the disposal
of the hazardous substances found at a facility. The Federal Comprehensive
Environmental Response, Compensation and Liability Act also authorizes the
Environmental Protection Agency and, in some cases, third parties,
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<PAGE> 54
to take actions in response to threats to the public health or the environment
and to seek to recover from the responsible classes of persons the costs of such
action. In the course of our operations, we may have generated and may generate
wastes that fall within the Superfund's definition of "hazardous substances". We
may also be an owner of facilities on which "hazardous substances" have been
released by previous owners or operators. We may be responsible under the
Federal Comprehensive Environmental Response, Compensation and Liability Act for
all or part of the costs to clean up facilities at which such wastes have been
released. Neither we nor, to our knowledge, our predecessor partnerships have
been named a potentially responsible person under the Federal Comprehensive
Environmental Response, Compensation and Liability Act nor do we know of any
prior owners or operators of our properties that are named as potentially
responsible parties related to their ownership or operation of such property.
Air Emissions. Our operations are subject to local, state and Federal
regulations for the control of emissions of air pollution. Administrative
enforcement actions for failure to comply strictly with air pollution
regulations or permits are generally resolved by payment of monetary fines and
correction of any identified deficiencies. Alternatively, regulatory agencies
could require us to forego construction, modification or operation of certain
air emission sources, although we believe that in the latter cases we would have
enough permitted or permittable capacity to continue our operations without a
material adverse effect on any particular producing field.
Oil Pollution Act. The Oil Pollution Act of 1990 and regulations thereunder
impose certain duties and liabilities on "responsible parties" related to the
prevention of oil spills and damages resulting from such spills in United States
waters. A "responsible party" includes the owner or operator of a facility or
vessel, or the lessee or permittee of the area in which a facility covered by
the Oil Pollution Act is located. The Oil Pollution Act assigns joint and
several liability to each responsible party for oil removal costs and a variety
of public and private damages. Few defenses exist to the liability imposed by
the Oil Pollution Act.
The Oil Pollution Act of 1990 also imposes ongoing requirements on a
responsible party, including proof of financial responsibility to cover at least
some costs in a potential spill. Certain amendments to the Oil Pollution Act
that were enacted in 1996 require owners and operators of offshore facilities
that have a worst case oil spill potential of more than 1,000 barrels to
demonstrate financial responsibility in amounts ranging from $10.0 million in
specified state waters to $35.0 million in federal Outer Continental Shelf
waters, with higher amounts, up to $150.0 million in certain limited
circumstances, where the Mineral Management Service believes such a level is
justified by the risks posed by the quantity or quality of oil that is handled
by the facility. On March 25, 1997, the Mineral Management Service promulgated a
proposed rule implementing these Oil Pollution Act financial responsibility
requirements. We believe that we currently have established adequate proof of
financial responsibility for our offshore facilities. However, we cannot predict
whether the financial responsibility requirements under the Oil Pollution Act
amendments or the proposed rule will result in the imposition of substantial
additional annual costs to us in the future or otherwise materially adversely
affect us. The impact of the financial responsibility requirements is not
expected to be any more burdensome to us than it will be to our similarly or
less capitalized competitors.
We believe that we are in substantial compliance with current applicable
environmental laws and regulations and that continued compliance with existing
requirements will not have a material adverse impact on us.
COMPETITION
We operate in the highly competitive areas of oil and gas exploration,
development and production. The availability of funds and information relating
to a property, the standards established by us for the minimum projected return
on investment and the availability of alternate fuel sources are factors that
affect our ability to compete in the marketplace. Our competitors include major
integrated oil companies and a substantial number of independent energy
companies, many of which possess greater financial and other resources than we
possess.
PERSONNEL
At December 31, 1998, we employed 58 full time employees who represent our
executive officers and key operating, exploration, financial and accounting
management. We outsource certain administrative and operational functions to
Torch Energy Advisors Incorporated, which maintains a large technical,
operating, accounting and administrative staff. Pursuant to an agreement with
Torch, Torch administered certain of our business activities for a monthly fee
based on a fixed
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<PAGE> 55
percentage of operating cash flow and total assets during 1998. Torch and our
combined personnel consisted of 861 employees at December 31, 1998.
BENEFICIAL OWNERSHIP OF OUR COMMON STOCK
The following tables show the ownership of our common stock by (i) anyone
who is known by us to beneficially own 5% of more of our outstanding of common
stock, (ii) each of our non-employee directors, (iii) our five most highly
compensated executive officers and (iv) all of our executive officers and
directors taken together as a group. Unless otherwise indicated, each person
named in the following table has the sole power to vote and dispose of the
shares listed next to their name. Information in the tables has been obtained
from filings made with the SEC or, in the case of our directors and executive
officers, has been provided by such individual. Unless otherwise indicated, the
information provided below is based on information available to us as of April
5, 1999.
OUR 5% STOCKHOLDERS
<TABLE>
<CAPTION>
NUMBER OF SHARES PERCENT
---------------- -----------
<S> <C> <C>
Franklin Resources, Inc. 2,781,639 13.1(1)
777 Mariners Island Boulevard
San Mateo, California 94404
Relational Investors, LLC 1,914,300 9.6(2)
David H. Batchelder
Joel L. Reed
Ralph V. Whitworth
Suite 220
4330 La Jolla Village Drive
San Diego, California 92122
State Street Research & Management Company 1,482,700 7.5(3)
One Financial Center, Thirtieth Floor
Boston, Massachusetts 02111
Crabbe Huson Group, Inc. 1,039,400 5.2(4)
121 Southwest Morrison, Suite 1400
Portland, Oregon 97204
</TABLE>
MEMBERS OF OUR BOARD OF DIRECTORS WHO ARE NOT EMPLOYEES
<TABLE>
<CAPTION>
SHARES BENEFICIALLY OWNED
----------------------------------
UNDER STOCK
OUTSTANDING OPTIONS** TOTAL PERCENT
------------- ------------ ------- ---------
<S> <C> <C> <C> <C>
Isaac Arnold, Jr............................. 50,820(5) 52,500 103,320 *
David H. Batchelder.......................... 1,914,300(2) -- 1,914,300 9.6
Thomas D. Barrow............................. 30,800(6) 52,500 83,300 *
Charles M. Elson............................. 2,778 7,500 10,278 *
Robert L. Gerry III.......................... 6,500 272,500 279,000 1.4
Gary R. Petersen............................. 2,500 15,000 17,500 *
David Ross III............................... 10,000 7,500 17,500 *
Robert W. Shower............................. 10,000 7,500 17,000 *
</TABLE>
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<PAGE> 56
OUR EXECUTIVE OFFICERS
<TABLE>
<CAPTION>
SHARES BENEFICIALLY OWNED
----------------------------------------------------------------------------
UNDER UNDER
UNDER STOCK DEFERRED RESTRICTED
OUTSTANDING 401(k) PLAN OPTIONS** COMPENSATION STOCK TOTAL PERCENT
------------ ----------- ---------- ------------ ---------- -------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Douglas L. 5,100 8,134 435,000 15,214 -- 463,448 2.3%
Foshee............
Michael P. -- 1,839 25,000 5,317 -- 32,156 *
Darden............
Robert S. 5,726(7) 1,940 70,000 11,059 2,000 90,725 *
Gaston............
Dennis A. 428(8) 2,431 81,855 12,394 4,000 101,108 *
Hammond...........
Robert M. 3,684(9) 1,802 69,650 11,441 4,000 90,577 *
King..............
</TABLE>
ALL DIRECTORS AND EXECUTIVE OFFICERS TOGETHER
<TABLE>
<CAPTION>
TOTAL PERCENT
--------- -------
<S> <C>
3,220,712 16.2%
</TABLE>
- ----------
* Under 1%
** Stock options include only options which may be exercised within 60 days.
(1) Of the shares reported for Franklin Resources, Inc., Franklin Advisers,
Inc. is reported to have sole voting power over 2,427,139 shares and
Franklin Advisers Services, Inc. has sole voting power over 94,000. In
addition, Franklin Advisers, Inc. is reported to have sole dispositive
power over 2,427,139 shares and Franklin Advisers Services, Inc. is
reported to have sole dispositive over 354,500 shares. Franklin Advisers,
Inc. and Franklin Advisers Services, Inc. are both wholly owned investment
advisory subsidiaries of Franklin Resources, Inc. Each of Messrs. Charles
B. Johnson and Rupert H. Johnson, Jr. own in excess of 10% of the
outstanding common stock of Franklin Resources, Inc. As the principal
shareholders of Franklin Resources, Inc., each of Messrs. Charles B.
Johnson and Rupert H. Johnson, Jr. may be deemed for certain purposes to be
beneficial owners of the shares beneficially owned by Franklin Resources,
Inc. Shares beneficially owned by Franklin Resources, Inc. include
1,338,939 shares which may be received upon conversion of our outstanding
term convertible securities ("TECONS").
(2) Relational Investors, LLC, reported sole dispositive and voting power with
respect to all 1,914,300 shares. These shares are owned by an account
managed at Relational Investors, LLC and by the following limited
partnerships of which Relational Investors, LLC is the sole general
partner: Relational Investors, L.P., Relational Fund Partners, L.P.,
Relational Coast Partners, L.P. and Relational Partners, L.P. Each of
Messrs. Batchelder, Whitworth and Reed are managing members of Relational
Investors, LLC, and may be deemed for certain purposes to beneficially own
shares beneficially owned by Relational Investors, LLC.
(3) State Street Research & Management Company ("State Street") is an
investment adviser registered under the Investment Advisers Act of 1940.
State Street has sole dispositive power with respect to all 1,482,700
shares and sole voting power with respect to 1,373,800 shares. In its
report filed with the SEC, State Street disclaims any beneficial interest
in such shares.
(4) Crabbe Huson Group, Inc. is a registered investment advisor. It does not
directly own any shares of our common stock. Crabbe Huson Group reported
the shared power to vote 941,500 shares of common stock and the shared
power to dispose of or direct the disposition of 1,039,400 shares.
(5) Includes 5,820 shares owned indirectly by The Arnold Corporation, of which
Mr. Arnold owns an approximate 25% equity interest.
(6) Includes indirect ownership of 6,200 shares owned by individual retirement
accounts for Mr. Barrow and his wife, his minor children or a corporation
he controls.
(7) Includes 200 shares owned by Mr. Gaston's spouse and 2,526 shares that
would be received upon conversion of 3,000 convertible preferred shares.
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<PAGE> 57
(8) Includes 168 shares of common stock that would be received upon conversion
of 200 convertible preferred shares.
(9) Includes 1,684 shares of common stock that would be received upon
conversion of 2,000 convertible preferred shares.
MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth the names and ages of our current executive
officers and directors. In 1999 we amended our certificate of incorporation to
provide for the annual election of directors.
<TABLE>
<CAPTION>
NAME Age Company Position
- --------------------------- --- ----------------
<S> <C> <C>
Douglas L. Foshee.......... 39 Chairman of the Board of Directors, President and Chief Executive Officer
Robert M. King............. 38 Senior Vice President and Chief Financial Officer
Dennis A. Hammond.......... 43 Vice President-- Engineering
Michael P. Darden.......... 41 Vice President-- Business Development
Sandra D. Kraemer.......... 31 Controller and Corporate Secretary
Bruce K. Murchison......... 49 General Counsel
Isaac Arnold, Jr........... 62 Director
Thomas D. Barrow........... 55 Director
David H. Batchelder........ 49 Director
Charles M. Elson........... 39 Director
Robert L. Gerry III........ 61 Director
Gary R. Petersen........... 52 Director
David Ross III............. 58 Director
Robert W. Shower........... 61 Director
</TABLE>
BIOGRAPHICAL INFORMATION
Directors
Mr. Foshee joined our board of directors in August 1997 concurrent with his
assumption of the position of president and chief executive officer. In December
1997, Mr. Foshee was also appointed chairman of our board of directors. Mr.
Foshee served from 1993 until 1997 in various capacities for Torch Energy
Advisors Incorporated, including vice president special projects, executive vice
president acquisitions and financial analysis, president, chief operating
officer, and ultimately chief executive officer. Prior to his tenure at Torch,
Mr. Foshee was employed by ARCO International Oil and Gas Company in various
positions in finance and new business ventures. His finance background also
includes seven years in commercial banking, primarily as an energy lender for
major financial institutions. Mr. Foshee serves on the board of Small Steps
Nurturing Center, and is a member of the Independent Petroleum Association of
America, the National Petroleum Council, and the Council of Overseers for the
Jones Graduate School at Rice University. Mr. Foshee received his B.B.A. from
Southwest Texas State University in 1982 and his M.B.A. from the Jesse H. Jones
Graduate School at Rice University in 1992. He is also a graduate of the
Southwestern Graduate School of Banking at Southern Methodist University (1991).
Mr. Arnold has, since 1984, been chairman of the board of Quintana
Petroleum Corporation, a privately held production company which does not
compete with us. He is also chairman of the board of Legacy Trust Company. He
has been a director of Cullen Center Bank & Trust since its inception in 1969
and is a director of Cullen/Frost Bankers, Inc. Mr. Arnold is a trustee of the
Museum of Fine Arts of Houston and The Texas Heart Institute. Mr. Arnold
received his B.B.A. from the University of Houston in 1959.
Mr. Barrow is president of Barrow Energy Corporation, a position he has
held since its formation in 1988. Barrow Energy is a privately held company in
the business of exploring for oil and gas primarily in East Texas which does not
compete with us. Mr. Barrow is also a director of Bargo Energy Company, a small
public oil and gas company. Bargo does not compete with us.
Mr. Batchelder has been chairman and chief executive officer of Batchelder
& Partners, Inc., a financial advisory and investment banking firm, since 1988.
He also has been a managing member of Relational Investors LLC, the general
partner of an active investment fund, since March 1996. Mr. Batchelder is also a
director of Morrison Knudson Corporation and Apria Healthcare Group Inc. Mr.
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Batchelder received a B.S. in accounting from Oklahoma State University in 1971
and is a certified public accountant.
Mr. Elson has been a professor of law at Stetson University College of Law
since 1990 and serves as of counsel to the law firm of Holland & Knight (since
1995). He is a member of the American Law Institute and the Advisory Council and
Commissions on Director Compensation, Audit Committees, and Director
Professionalism of the National Association of Corporate Directors. Mr. Elson is
widely regarded as an expert on corporate governance and has served on panels
and blue ribbon commissions on such issues as executive compensation, director
compensation, director professionalism, chief executive officer succession and
others. He is a trustee of Talledega College and a Salvatori Fellow of the
Heritage Foundation. Mr. Elson currently serves as a director of Sunbeam
Corporation, a consumer products company, a position he has held since 1996. He
also served as a director of Circon Corporation, a medical products
manufacturer, from 1996 until its sale in 1999. Mr. Elson received his B.A. from
Harvard College in 1981 and his J.D. from the University of Virginia in 1985.
Mr. Gerry has, since 1997, been chairman of the board of directors and
chief executive officer of VAALCO Energy, Inc., a public independent oil and gas
company which does not compete with us. From 1994 to 1997, Mr. Gerry was our
vice chairman. Prior to that, he was our president and chief operating officer
since our formation in 1990. Mr. Gerry currently serves as a trustee of Texas
Children's Hospital.
Mr. Petersen is a co-founder and has been a partner of EnCap Investments,
Inc., a firm which provides capital in the form of both debt and equity to the
energy industry. From 1984 to 1988, he served as senior vice president and
manager of the corporate finance division of the energy banking group for
RepublicBanc Houston. From 1979 to 1984, he was executive vice president and a
director of Nicklos Oil and Gas Company. He also served as a group vice
president in the petroleum and minerals division of RepublicBanc Dallas. He is a
member of the board of Harken Energy Corporation, Energy Capital Investment
Company, Equus II Incorporated and the Petroleum Club of Houston. Mr. Petersen
received his B.B.A from Texas Tech University in 1968 and his M.B.A. from Texas
Tech University in 1970.
Mr. Ross is a private investor. From 1987 to 1993, Mr. Ross was chairman
and chief executive officer of Sterling Consulting Group, which provided
corporate planning, treasury management and economic evaluation to the oil and
gas industry. He was a principal of The Sterling Group, a firm specializing in
leveraged buyouts, from 1986 to 1987. He currently serves on the Council of
Overseers and is an Adjunct Professor of Finance at the Jesse H. Jones Graduate
School of Administration at Rice University, where he has served since 1994 and
1979, respectively. Mr. Ross is a member of the board of Cooper Cameron
Corporation, an oilfield services equipment manufacturer. He also serves as vice
president and a board member of Da Camera of Houston, a nonprofit arts
organization. Mr. Ross received his B.A. from Yale University in 1962 and his
M.B.A. from Harvard University in 1970.
Mr. Shower served as executive vice president and chief financial officer
of Seagull Energy Corporation, an oil and gas company, from 1994 until his
retirement in 1996. From 1992 to 1994, he served as Seagull's senior vice
president and chief financial officer. From 1991 to 1992, Mr. Shower served as
senior vice president, corporate development, for Albert Fisher, Inc., a company
engaged in produce distribution. Mr. Shower served for 10 years as chief
financial officer for the Williams Companies and also served on its board from
1977 to 1986. Mr. Shower currently serves on the boards of Lear Corporation, one
of the world's largest automotive suppliers; Breed Technologies, a worldwide
leader in automotive occupant safety systems; Highlands Insurance Group, Inc.;
and Edge Petroleum Corporation, a technology-oriented exploration company. Mr.
Shower received his B.S. from the University of Tulsa in 1960. He also attended
the Program for Management Development at Harvard Business School in 1972.
Executive Officers
Robert M. King joined us as senior vice president and chief financial
officer in January 1996. Prior to that, Mr. King was vice president, corporate
development and treasurer of Seagull Energy Corporation, which he joined in 1990
after having spent over seven years in energy finance with The First National
Bank of Chicago and Mellon Bank, N.A. Mr. King has a B.A. in economics and
political science from Southern Methodist University and an M.B.A. in finance
from the Cox School of Business at Southern Methodist University.
Dennis A. Hammond joined us as vice president -- engineering in 1990. In
1983, he was a co-founder of IDM Engineering, Inc., a petroleum engineering
consulting firm. He has held various
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reservoir engineering positions with Chevron and Pogo Producing Company. He
holds a B.S. degree in petroleum engineering from Texas A&M University and is a
registered professional engineer in the State of Texas. Mr. Hammond is a member
of the Society of Petroleum Engineers and the American Petroleum Institute.
Michael P. Darden joined us as vice president -- business development in
May 1998. Prior to that he was special counsel for Baker & Botts, L.L.P., a law
firm, since 1993, where his practice focused on international and domestic oil
and gas ventures, asset acquisitions and sales, and energy-based financings. Mr.
Darden was employed by Hunt Oil Company from 1990 to 1993 where he was senior
international counsel. From 1988 to 1990, he was employed by BHP Petroleum
(Americas) Inc. as attorney-international/offshore and from 1986 to 1988 he was
employed by Tenneco Oil Company as senior international negotiator. Mr. Darden
has worked extensively on petroleum projects outside the United States and in
all regions of the world. His experience encompasses petroleum projects at all
stages, working with governments, industry partners, contractors, suppliers,
lenders and insurers. Mr. Darden received a B.B.A. in Petroleum Land Management
from The University of Texas in 1980 and a J.D. from the University of Houston
Law Center in 1986.
Sandra D. Kraemer has been our controller since 1993 and our corporate
secretary since 1997. Prior to 1993, she was employed by Torch Energy Advisors
Incorporated since 1991. From 1990 to 1991, Ms. Kraemer was employed by Price
Waterhouse in its audit department, specializing in the oil and gas industry.
She graduated summa cum laude from Stephen F. Austin State University with a
B.B.A. in accounting in 1990 and is a certified public accountant.
Bruce K. Murchison has been our general counsel since June 1999. Prior to
that, Mr. Murchison was a consultant to Plains Resources senior management
regarding transactional matters. From 1994 to 1998, he was president of Celeron
Corporation. Prior to that, he was general counsel of Celeron for six years.
From 1991 to 1994, in addition to his general counsel responsibilities at
Celeron, Mr. Murchison served as chief operating officer of All American
Pipeline Company. He began his career with Goodyear as an attorney in 1985. From
1981 to 1985, Mr. Murchison practiced corporate law and litigation at Texaco
Inc. Mr. Murchison received his J.D. degree from St. John's School of Law in
1981.
All of our executive officers and directors are United States citizens.
TRANSACTIONS WITH RELATED PERSONS
We outsource a part of our non-strategic business activities to Torch
Energy Advisors Incorporated and its subsidiaries under an administrative
services agreement. Prior to 1999, the agreements with Torch provided for a
monthly fee based on a fixed percentage of our operating cash flows and total
assets. The administrative services under the agreement with Torch in effect
prior to 1999 included providing us with accounting, legal, land, tax, and
insurance professionals as well as office space, equipment, supplies, and
assistance in managing human resources. Torch also processes our accounting
records, prepares any reports or other documents required by governmental
authorities, analyzes economic and other data related to our business and
otherwise provides general administrative services and advise to us. Torch also
markets a portion of our U.S. oil and gas production and operates most of our
U.S. oil and gas wells. For the years ended December 31, 1996, 1997 and 1998,
we paid Torch fees for administrative services of $22.4 million, $40.1 million
and $37.3 million, respectively. Effective January 1, 1999, we substantially
changed our agreements with Torch in part to base Torch's compensation on its
achieving benchmarks of performance.
On April 9, 1996, we acquired upstream oil and gas properties located
onshore and offshore California from Union Oil Company of California ("Unocal")
for an adjusted purchase price of $480.5 million in cash and from Torch and
certain of its wholly owned subsidiaries for a net adjusted purchase price of
$35.7 million, payable by the issuance to Torch of 1,275,000 shares of our
common stock.
Torch originated the acquisition of the oil and gas properties from
Unocal. In consideration of the services rendered by Torch in connection with
the acquisition of the Unocal properties, we paid Torch $10.0 million. In
addition, we paid the brokers' fees and commissions incurred in connection with
the acquisition of the properties from Unocal as well as all third party costs
and out-of-pocket expenses incurred by Torch. Brokers' fees and commissions
incurred in connection with the Unocal properties consisted of cash payments in
the amount of $6.0 million and warrants to purchase 150,000 shares of our
common stock. The warrants were initially exercisable at $28.00 per share and
have a term of five years. Third party costs and out-of-pocket costs incurred by
Torch were $3.6 million. Of the foregoing payments to brokers, EnCap
Investments Inc. received $1.2 million in cash and 30,000 warrants. Gary R.
Petersen, a member of our board of directors, was a partner of EnCap
Investments, Inc. when the warrants and fees were received.
Prior to August 1997, Douglas L. Foshee was chief executive officer and a
stockholder of Torch. Upon his appointment as our chief executive officer, Mr.
Foshee resigned as an officer and employee of Torch and sold his ownership
interest in Torch to Torch.
In 1992, NuStar Joint Venture, a joint venture of which we own 95%,
entered into a credit agreement with a group of lenders whereby NuStar borrowed
$12 million from EnCap Investments, Inc., an entity affiliated with Gary R.
Petersen, one of our directors. Proceeds of the loan were used to finance the
acquisition of operating assets. Under the terms of the loan agreement, 80% of
the operating cash flows of NuStar were dedicated to the repayment of principal
and interest on a quarterly basis. The indebtedness bears interest at the fixed
rate of 8.5% per annum. The credit agreement provided that dedicated payments
of operating cash flows increased to 100% if scheduled principal reductions
were not achieved during the term of the credit agreement. In 1996 and 1997,
our debt payments made to EnCap totaled $108,356 and $64,108 respectively. The
loan was repaid in full in 1997 in connection with the sale of our interest in
NuStar.
In January 1995, we loaned International Testing Services, Inc., a company
involved in the safety testing of oil and gas pipelines, the sum of $500,000.
The president of International Testing is John B. Connally III, a former
director until his resignation in January 1998. The loan bears interest at the
rate of 2.5% over the prime rate. The loan was initially due on July 1, 1995 and
was extended to May 1997. The loan is unsecured and subordinated to certain
existing indebtedness. Outstanding principal on the loan as of January 15, 1998
was $500,000. International Testing filed for bankruptcy protection in 1998. The
loan was written off for financial reporting purposes in December 1997. In
connection with the loan, we acquired a five-year warrant to acquire 350,000
shares of International Testing common stock, the exercise price of which is
substantially in excess of the current market price of such common stock.
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EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following summary compensation table sets forth cash compensation for
the past three years for our chief executive officer and our four other most
highly compensated officers in 1998.
<TABLE>
<CAPTION>
LONG-TERM
RESTRICTED COMPENSATION-
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS STOCK AWARDS OPTIONS
- ----------------------------------------- ---- ------ ----- ------------ -------------
<S> <C> <C> <C> <C> <C>
Douglas L. Foshee 1998 $ 375,000 $ -- $ -- 220,000(2)
Chairman, Chief Executive Officer 1997 143,466(1) 317,500 -- 330,000
and President
Robert M. King 1998 160,000 30,000 -- 66,250
Senior Vice President and 1997 160,000 130,000 79,856 32,500
Chief Financial Officer 1996 156,970 178,000 95,750 70,000
Dennis A. Hammond 1998 160,000 -- -- 66,250
Vice President--Engineering 1997 160,000 130,000 79,856 32,500
1996 140,000 162,000 95,750 40,000
Robert S. Gaston(3) 1998 160,000 -- 39,928 66,250
Vice President--Exploration 1997 160,000 130,000 47,875 32,500
1996 150,000 75,000 15,000
Michael D. Darden 1998 99,950(4) 100,000(5) -- 91,250
Vice President
Business Development
</TABLE>
- ------------------
(1) Mr. Foshee became an employee in August 1997. Information regarding Mr.
Foshee is for periods during which he was employed by Nuevo.
(2) Mr. Foshee was granted 100,000 options in August 1998 as part of his
employment agreement.
(3) Mr. Gaston resigned on June 30, 1999.
(4) Mr. Darden became an employee in May 1998. Information regarding Mr. Darden
is for the periods during which he was employed by us.
(5) Mr. Darden was hired by us in May 1998 and was paid a signing bonus of
$100,000. Mr. Darden contributed 75% of his bonus to the company's deferred
compensation plan in order to purchase shares of our common stock.
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1998 STOCK OPTION GRANTS
The following table sets forth information concerning grants of options to
purchase our common stock made during 1998 to the executive officers named in
the summary compensation table. The exercise price of options granted to our
executive officers is the closing price of the common stock on the date of
grant.
<TABLE>
<CAPTION>
% OF TOTAL
NUMBER OF OPTIONS PER SHARE GRANT DATE
OPTIONS GRANTED TO EXERCISE EXPIRATION PRESENT
NAME GRANTED EMPLOYEES PRICE DATE VALUE(1)
- ----------------------------------- --------- ----------- ------------ ---------- ---------------
<S> <C> <C> <C> <C> <C>
Douglas L. Foshee.................. 130,000(2) 11.6% $ 21.31 08/11/08 $ 1,391,000
81,000 7.2% 11.13 12/14/08 451,980
9,000 0.8% 16.13 12/14/08 39,690
Robert M. King..................... 16,250 1.5% 21.31 08/11/08 173,875
45,000 4.0% 11.13 12/14/08 251,100
5,000 0.4% 16.13 12/14/08 22,050
Dennis A. Hammond.................. 16,250 1.5% 21.31 08/11/08 173,875
45,000 4.0% 11.13 12/14/08 251,100
5,000 0.4% 16.13 12/14/08 22,050
Robert S. Gaston(3)................ 16,250 1.5% 21.31 08/11/08 173,875
45,000 4.0% 11.13 12/14/08 251,100
5,000 0.4% 16.13 12/14/08 22,050
Michael P. Darden.................. 25,000 2.2% 35.88 05/11/08 450,250
16,250 1.5% 21.31 08/11/08 173,875
45,000 4.0% 11.13 12/14/08 251,100
5,000 0.4% 16.13 12/14/08 22,050
</TABLE>
- ---------------------------
(1) We calculated the granted date present value using the "Black Scholes"
model, a widely accepted method of valuing options. This valuation model is
hypothetical; the actual value, if any, depends on the excess of the market
price of the shares over the exercise price on the date the option is
exercised. If the market price does not increase above the exercise price,
compensation to the grantee will be zero. The Black-Scholes option pricing
model is a mathematical formula used for estimating option values that
incorporates various assumptions. The "Grant Date Present Value" set out in
the above table is based on the following assumptions: (a) a ten-year
option term; (b) 50.9% expected future annual stock volatility for the
options; (c) a risk-free rate of return of 5.0% for the options granted;
and (d) no expected dividend yield. The above model does not include any
reduction in value for non-transferability, forfeiture or vesting of
options.
(2) Mr. Foshee was granted 100,000 options in August of 1998 as part of his
employment agreement.
(3) Mr. Gaston resigned on June 30, 1999.
During 1998, we repriced options owned by our employees who are not
executive officers. These options had been granted over a number of years. Under
the SEC's rules for preparing the option grant table, we treat all of the
repriced options as having been granted in 1998. As a result, the amounts set
forth under "% of total options granted to employees" are lower for the named
executive officers than they would have been had we not repriced options.
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<PAGE> 62
The following table shows the number of options owned by our named
executives. Options in the column marked "unexercisable" are subject to vesting
and will be forfeit if the named executive's employment with us is terminated
for certain reasons. The value of unexercised options is calculated using an
$11.50 per share closing for our stock on December 31, 1998. None of our named
executives exercised options in 1998.
<TABLE>
<CAPTION>
VALUE OF UNEXERCISED IN-THE-MONEY
NUMBER OF UNEXERCISED OPTIONS OPTIONS AT DECEMBER 31, 1998(1)
----------------------------- ---------------------------------
NAME EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
------ ----------- ------------- ----------- -------------
<S> <C> <C> <C>
Douglas L. Foshee........................ 435,000 130,000 -- $ 30,375
Robert M. King........................... 69,650 83,750 -- 16,875
Dennis A. Hammond........................ 81,855 83,750 -- 16,875
Robert S. Gaston(2)...................... 70,000 83,750 -- 16,875
Michael P. Darden........................ 25,000 66,250 -- 16,875
</TABLE>
- ---------------------------
(1) Based on $11.50 per share which was the closing price per share of our
common stock on the New York Stock Exchange Composite Tape on December 31,
1998.
(2) Mr. Gaston resigned on June 30, 1999.
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<PAGE> 63
Executive Employment Contracts
In 1997, we entered into an employment contract with Mr. Foshee, our chief
executive officer. The agreement provided for the following compensation during
1998:
o a base salary of $375,000,
o discretionary bonuses based upon performance to be determined by
our compensation committee,
o reimbursement for membership fees to the Houston Center Club, the
Petroleum Club and the Young Presidents Organization, and
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<PAGE> 64
o a grant of options to purchase 100,000 shares of our common stock
on August 14, 1998, at a stock price equal to the closing price on
that date.
Mr. Foshee's employment agreement is terminable by either party but, in the
event that his employment is terminated for reasons other than just cause or his
voluntary resignation, we are obligated to pay him a sum equal to two times the
aggregate of:
o his salary for the twelve months immediately preceding the date
of termination (less applicable withholdings and deductions
required by law), plus
o any bonus paid to Mr. Foshee in the twelve-month period.
In the agreement, just cause is generally defined as the failure to render
services to us as provided in the agreement or the commission of fraud or other
specified illegal acts.
In 1998, we entered into a two year employment agreement with Robert M.
King providing for the following compensation during 1998:
o an annual salary of $160,000,
o reimbursement for reasonable country club dues.
Mr. King's employment agreement is terminable by either party but, in the
event his employment is terminated for reasons other than just cause or at his
option, we must pay him the greater of two times his annual salary and bonus or
$320,000. Just cause has the same meaning in Mr. King's contract as in Mr.
Foshee's.
In 1997, we entered into identical employment agreements with Dennis A.
Hammond and Robert S. Gaston providing for a monthly salary of $13,333.34,
payable in semi-monthly installments and an annual discretionary bonus, stock
option and stock bonus awards as determined by our compensation committee. Each
of Mr. Hammond's and Mr. Gaston's Employment Agreement is for no definitive term
and is terminable by either party at any time for any lawful reason. In the
event that Mr. Hammond's or Mr. Gaston's employment is terminated as a result of
a change of control, then each of Mr. Hammond and Mr. Gaston is entitled to
receive two years salary and bonus (calculated based on the average of the last
two year's bonus award) if they are not offered an equivalent job with our
successor.
Long-Term Incentive Plan Awards
We do not have a long-term incentive plan for our employees, other than the
1990 stock option plan, the 1993 stock incentive plan and the 1999 stock
incentive plan. Under the 1990 stock option plan, the 1993 stock incentive plan
and the 1999 stock incentive plan, our executive officers, directors and
employees are eligible to receive awards of stock options or of shares of stock
or other awards which have a value which increases or decreases with the price
of our stock. If a change in control occurs, all options vest and may be
exercised. Under certain circumstances, in connection with a change of control,
if the exercise price of the options is greater than the consideration to be
received in the change of control transaction, the option holder will be
entitled to receive the Black-Sholes model value of his or her options.
If a change of control occurs, all options vest and may be exercised.
Under certain circumstances, in connection with a change of control, if the
exercise price of the options is greater than the consideration to be received
in the change of control transaction, the option holder will be entitled to
receive the Black-Sholes model value of his or her options.
Deferred Compensation Plan
During 1996, we adopted the Nuevo Energy Deferred Compensation Plan to
encourage senior executive officers to personally invest in our shares.
Executives at the level of vice president and above are eligible to participate
in the plan. The plan allows our senior executives to defer all or a portion of
their annual salaries and bonuses. Currently, such deferred salaries and bonuses
must be invested in our common stock or a money market account until the
employee satisfies the stock ownership criteria established by the compensation
committee. After the stock ownership thresholds are met (the "target"), deferred
amounts may be invested in any equity indexed investment selected by the
compensation committee. Stock is acquired under the plan at a discount of 25% to
the then current market price, and is subject to restrictions on transfer.
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Director Compensation
Currently directors receive an annual cash retainer of $30,000. Directors
are given the option to elect to receive all or a portion of their retainer in
shares of restricted stock. Elections are made in 25% increments with a 33%
increase in value for the amounts invested in restricted stock, so that a
director electing to convert $7,500 in cash retainer will be awarded $10,000 in
restricted stock.
In addition to the cash retainer, directors also receive an annual
grant of 3,500 options and 2,500 shares of restricted stock. Stock options are
granted for a ten year term with an exercise price equal to the fair market
value of a share of stock on the date of grant. Restricted stock is subject to a
three year restricted period and directors have the option to rollover this
period until their retirement from the board.
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<PAGE> 66
USE OF PROCEEDS
We will not receive any cash proceeds from the issuance of the exchange
notes. In consideration for issuing the exchange notes as contemplated in this
prospectus, we will receive in exchange existing notes in like principal amount.
The existing notes surrendered in exchange for exchange notes will be retired
and canceled and cannot be reissued. Issuance of the exchange notes will not
result in a change in our amount of outstanding debt.
THE EXCHANGE OFFER
PURPOSE AND EFFECT OF THE EXCHANGE OFFER
We issued $257,310,000 in principal amount of existing notes on August
20, 1999 in exchange for $157,460,000 aggregate principal amount of our 9 1/2%
Senior Subordinated Notes due 2006 and $99,850,000 aggregate principal amount of
our 87/8% Senior Subordinated Notes due 2008. The existing notes were issued to
qualified institutional buyers and institutional accredited investors in
reliance upon the exemption from registration provided by Regulation D under the
Securities Act. In connection with the issuance of the existing notes, we agreed
with Banc of America Securities LLC and Salomon Smith Barney Inc., who acted as
co-dealer managers for the issuance of the existing notes, that promptly
following the issuance of the existing notes, we would:
o file with the SEC a registration statement related to the
exchange notes;
o use our reasonable best efforts to cause the registration
statement to become effective under the Securities Act; and
o offer to the holders of the existing notes the opportunity to
exchange their existing notes for a like principal amount of
exchange notes upon the effectiveness of the registration
statement.
A copy of the agreements with Banc of America Securities and Salomon
Smith Barney have been filed as exhibits to the registration statement of which
this prospectus is a part.
Based on existing interpretations of the Securities Act by the staff of
the SEC described in several no-action letters, and subject to the following
sentence, we believe that the exchange notes issued in the exchange offer may be
offered for resale, resold and otherwise transferred by their holders, other
than broker-dealers or our "affiliates," without further compliance with the
registration and prospectus delivery provisions of the Securities Act. However,
any holder of existing notes who is an affiliate of ours, who is not acquiring
the exchange notes in the ordinary course of such holder's business or who
intends to participate in the exchange offer for the purpose of distributing the
exchange notes:
o will not be able to rely on the interpretations by the staff
of the SEC described in the above-mentioned no-action letters;
o will not be able to tender existing notes in the exchange
offer; and
o must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with any sale
or transfer of the existing notes unless the sale or transfer
is made under an exemption from these requirements.
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We do not intend to seek our own no-action letter, and there is no
assurance that the staff of the SEC would make a similar determination regarding
the exchange notes as it has in these no-action letters to third parties. See
"Plan of Distribution."
As a result of the filing and effectiveness of the registration
statement of which this prospectus is a part, we will not be required to pay an
increased interest rate on the existing notes. Following the closing of the
exchange offer, holders of existing notes not tendered will not have any further
registration rights except in limited circumstances requiring the filing of a
shelf registration statement, and the existing notes will continue to be subject
to restrictions on transfer. Accordingly, the liquidity of the market for the
existing notes could be adversely affected.
TERMS OF THE EXCHANGE OFFER
Upon the terms and subject to the conditions stated in this prospectus
and in the letter of transmittal, we will accept all existing notes properly
tendered and not withdrawn prior to 5:00 p.m. New York City time, on the
expiration date. After authentication of the exchange notes by the trustee or an
authenticating agent, we will issue $1,000 principal amount of exchange notes in
exchange for each $1,000 principal amount of outstanding existing notes accepted
in the exchange offer. Holders my tender some or all of their existing notes in
denominations of $1,000 or any integral multiple of $1,000.
If you wish to exchange your existing notes for exchange notes in the
exchange offer, you will be required to represent that:
o you are not our affiliate, as defined in Rule 405 of the
Securities Act;
o any exchange notes will be acquired in the ordinary course of
your business;
o you have no arrangement with any person to participate in the
distribution of the exchange notes;
o if you are not a broker-dealer, that you are not engaged in
and do not intend to engage in the distribution of the
exchange notes; and
o if you are a broker-dealer that will receive exchange notes
for your own account in exchange for existing notes that were
acquired as a result of market-making or other trading
activities, that you will deliver a prospectus, as required by
law, in connection with any resale of those exchange notes.
You will make these representations to us by signing or agreeing to be bound by
the letter of transmittal.
Broker-dealers that are receiving exchange notes for their own account
must have acquired the existing notes as a result of market-making or other
trading activities in order to participate in the exchange offer. Each
broker-dealer that receives exchange notes for its own account under the
exchange offer must acknowledge that it will deliver a prospectus in connection
with any resale of the exchange notes. The letter of transmittal states that by
so acknowledging and by delivering a prospectus, a broker-dealer will not be
admitting that it is an "underwriter" within the meaning of the Securities Act.
We will be required to allow broker-dealers to use this prospectus following the
exchange offer in connection with the resale of exchange notes received in
exchange for existing notes acquired by broker-dealers for their own account as
a result of market-making or other trading activities. If required by applicable
securities laws, we will, upon written request, make this
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prospectus available to any broker-dealer for use in connection with a resale of
exchange notes for a period of 90 days after the consummation of the exchange
offer. See "Plan of Distribution."
The exchange notes will evidence the same debt as the existing notes
and will be issued under and entitled to the benefits of the same indenture. The
form and terms of the exchange notes are identical in all material respects to
the form and terms of the existing notes except that:
o the exchange notes will be issued in a transaction registered
under the Securities Act;
o the exchange notes will not be subject to transfer
restrictions; and
o provisions providing for an increase in the stated interest
rate on the existing notes will be eliminated.
As of the date of this prospectus, $257,310,000 aggregate principal
amount of the existing notes was outstanding. In connection with the issuance of
the existing notes, we arranged for the existing notes to be issued and
transferable in book-entry form through the facilities of DTC, acting as
depositary. The exchange notes will also be issuable and transferable in
book-entry form through DTC.
This prospectus, together with the accompanying letter of transmittal,
is initially being sent to all registered holders as of the close of business on
November 11, 1999. We intend to conduct the exchange offer as required by the
Exchange Act, and the rules and regulations of the SEC under the Exchange Act,
including Rule 14e-1, to the extent applicable.
Rule 14e-1 describes unlawful tender practices under the Exchange Act.
This section requires us, among other things:
o to hold our exchange offer open for twenty business days;
o to give ten days notice of any change in the terms of this
offer; and
o to issue a press release in the event of an extension of the
exchange offer.
The exchange offer is not conditioned upon any minimum aggregate
principal amount of existing notes being tendered, and holders of the existing
notes do not have any appraisal or dissenters' rights under the General
Corporation Law of the State of Delaware or under the indenture in connection
with the exchange offer. We shall be considered to have accepted existing notes
tendered according to the procedures in this prospectus when, as and if we have
given oral or written notice of acceptance to the exchange agent. See
"--Exchange Agent." The exchange agent will act as agent for the tendering
holders for the purpose of receiving exchange notes from us and delivering
exchange notes to those holders.
If any tendered existing notes are not accepted for exchange because of
an invalid tender or the occurrence of other events described in this
prospectus, certificates for these unaccepted existing notes will be returned,
at our cost, to the tendering holder of the existing notes or, in the case of
existing notes tendered by book-entry transfer, into the holder's account at DTC
according to the procedures described below, as promptly as practicable after
the expiration date.
Holders who tender existing notes in the exchange offer will not be
required to pay brokerage commissions or fees or, subject to the instructions in
the letter of transmittal, transfer taxes related to the exchange of existing
notes in the exchange offer. We will pay all charges and expenses, other
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than applicable taxes, in connection with the exchange offer. See
"--Solicitation of Tenders; Fees and Expenses."
NEITHER WE NOR OUR BOARD OF DIRECTORS MAKES ANY RECOMMENDATION TO
HOLDERS OF EXISTING NOTES AS TO WHETHER TO TENDER OR REFRAIN FROM TENDERING ALL
OR ANY PORTION OF THEIR EXISTING NOTES TO THE EXCHANGE OFFER. MOREOVER, NO ONE
HAS BEEN AUTHORIZED TO MAKE ANY RECOMMENDATION. HOLDERS OF EXISTING NOTES MUST
MAKE THEIR OWN DECISION WHETHER TO TENDER IN THE EXCHANGE OFFER AND, IF SO, THE
AMOUNT OF EXISTING NOTES TO TENDER AFTER READING THIS PROSPECTUS AND THE LETTER
OF TRANSMITTAL AND CONSULTING WITH THEIR ADVISORS, IF ANY, BASED ON THEIR OWN
FINANCIAL POSITION AND REQUIREMENTS.
EXPIRATION DATE; EXTENSIONS; AMENDMENTS
The term "expiration date" shall mean 5:00 p.m., New York City time,
on December 15, 1999, unless we, in our sole discretion, extend the exchange
offer, in which case the term "expiration date" shall mean the latest date to
which the exchange offer is extended.
We expressly reserve the right, in our sole discretion:
o to delay acceptance of any existing notes or to terminate the
exchange offer and to refuse to accept existing notes not
previously accepted, if any of the conditions described under
"--Conditions" shall have occurred and shall not have been
waived by us;
o to extend the expiration date of the exchange offer;
o to amend the terms of the exchange offer in any manner;
o to purchase or make offers for any existing notes that remain
outstanding subsequent to the expiration date;
o to the extent permitted by applicable law, to purchase
existing notes in the open market, in privately negotiated
transactions or otherwise.
The terms of the purchases or offers described in the fourth and fifth clauses
above may differ from the terms of the exchange offer.
Any delay in acceptance, termination, extension, or amendment will be
followed as promptly as practicable by oral or written notice to the exchange
agent and by making a public announcement. If the exchange offer is amended in a
manner determined by us to constitute a material change, we will promptly
disclose the amendment in a manner reasonably calculated to inform the holders
of the amendment.
Without limiting the manner in which we may choose to make public
announcements of any delay in acceptance, termination, extension, or amendment
of the exchange offer, we shall have no obligation to publish, advise, or
otherwise communicate any public announcement, other than by making a timely
release to the Dow Jones News Service.
You are advised that we may extend the exchange offer because some of
the holders of the existing notes do not tender on a timely basis. In order to
give these noteholders the ability to participate in the exchange and to avoid
the significant reduction in liquidity associated with holding an unexchanged
note, we may elect to extend the exchange offer.
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INTEREST ON THE EXCHANGE NOTES
The exchange notes will bear interest from the date of issuance of the
existing notes that are tendered in exchange for the exchange notes or the most
recent date on which interest was paid or provided for on the existing notes
surrendered for the exchange notes. Accordingly, holders of existing notes that
are accepted for exchange will not receive interest that is accrued but unpaid
on the existing notes at the time of tender. Interest on the exchange notes will
be payable semi-annually on each June 1 and December 1, commencing on December
1, 1999.
PROCEDURES FOR TENDERING
Only a holder may tender its existing notes in the exchange offer. Any
beneficial owner whose existing notes are registered in the name of his broker,
dealer, commercial bank, trust company or other nominee or are held in
book-entry form and who wishes to tender should contact the registered holder
promptly and instruct the registered holder to tender on his behalf. If the
beneficial owner wishes to tender on his own behalf, the beneficial owner must,
prior to completing and executing the letter of transmittal and delivering his
existing notes, either make appropriate arrangements to register ownership of
the existing notes in the owner's name or obtain a properly completed bond power
from the registered holder. The transfer of record ownership may take
considerable time.
The tender by a holder will constitute an agreement between the holder,
us and the exchange agent according to the terms and subject to the conditions
described in this prospectus and in the letter of transmittal.
A holder who desires to tender existing notes and who cannot comply
with the procedures set forth herein for tender on a timely basis or whose
existing notes are not immediately available must comply with the procedures for
guaranteed delivery set forth below.
THE METHOD OF DELIVERY OF EXISTING NOTES AND THE LETTER OF TRANSMITTAL
AND ALL OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT THE ELECTION AND
RISK OF THE HOLDERS. DELIVERY OF SUCH DOCUMENTS WILL BE DEEMED MADE ONLY WHEN
ACTUALLY RECEIVED BY THE EXCHANGE AGENT OR DEEMED RECEIVED UNDER THE ATOP
PROCEDURES DESCRIBED BELOW. IN ALL CASES, SUFFICIENT TIME SHOULD BE ALLOWED TO
ASSURE DELIVERY TO THE EXCHANGE AGENT PRIOR TO THE EXPIRATION DATE. NO LETTER OF
TRANSMITTAL OR EXISTING NOTES SHOULD BE SENT TO US. HOLDERS MAY ALSO REQUEST
THAT THEIR RESPECTIVE BROKERS, DEALERS, COMMERCIAL BANKS, TRUST COMPANIES OR
NOMINEES EFFECT THE TENDER FOR HOLDERS IN EACH CASE AS DESCRIBED IN THIS
PROSPECTUS AND IN THE LETTER OF TRANSMITTAL.
EXISTING NOTES HELD IN CERTIFICATED FORM
For a holder to validly tender existing notes held in physical form,
the exchange agent must receive, prior to 5:00 p.m. New York city time on the
expiration date, at its address set forth in this prospectus:
o a properly completed and validly executed letter of
transmittal, or a manually signed facsimile thereof, together
with any signature guarantees and any other documents required
by the instructions to the letter of transmittal, and
o certificates for tendered existing notes.
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EXISTING NOTES HELD IN BOOK-ENTRY FORM
We understand that the exchange agent will make a request promptly
after the date of the prospectus to establish accounts for the existing notes at
DTC for the purpose of facilitating the exchange offer, and subject to their
establishment, any financial institution that is a participant in DTC may make
book-entry delivery of existing notes by causing DTC to transfer the existing
notes into the exchange agent's account for the existing notes using DTC's
procedures for transfer.
If you desire to transfer existing notes held in book-entry form with
DTC, the exchange agent must receive, prior to 5:00 p.m. New York City time on
the expiration date, at its address set forth in this prospectus, a confirmation
of book-entry transfer of the existing notes into the exchange agent's account
at DTC, which is referred to in this prospectus as a "book-entry confirmation,"
and:
o a properly completed and validly executed letter of
transmittal, or manually signed facsimile thereof, together
with any signature guarantees and other documents required by
the instructions in the letter of transmittal; or
o an agent's message transmitted pursuant to DTC's Automated
Tender Offer Program.
TENDER OF EXISTING NOTES USING DTC'S AUTOMATED TENDER OFFER PROGRAM (ATOP)
The exchange agent and DTC have confirmed that the exchange offer is
eligible for DTC's Automated Tender Offer Program. Accordingly, DTC participants
may electronically transmit their acceptance of the exchange offer by causing
DTC to transfer existing notes held in book-entry form to the exchange agent in
accordance with DTC's ATOP procedures for transfer. DTC will then send a
book-entry confirmation, including 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, which
states that DTC has received an express acknowledgment from the participant in
DTC tendering existing notes that are the subject of that book-entry
confirmation that the participant has received and agrees to be bound by the
terms of the letter of transmittal, and that we may enforce such agreement
against such participant. If you use ATOP procedures to tender existing notes
you will not be required to deliver a letter of transmittal to the exchange
agent, but you will be bound by its terms just as if you had signed it.
SIGNATURES
Signatures on a letter of transmittal or a notice of withdrawal, as the
case may be, must be guaranteed by a member firm of a registered national
securities exchange or of the National Association of Securities Dealers, Inc.
or 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 Exchange Act, unless the existing notes tendered with the
letter of transmittal are tendered:
o by a registered holder who has not completed the box entitled
"Special Registration Instructions" or "Special Delivery
Instructions" in the letter of transmittal; or
o for the account of an institution eligible to guarantee
signatures.
If the letter of transmittal is signed by a person other than the
registered holder or DTC participant who is listed as the owner, the existing
notes must be endorsed or accompanied by appropriate bond powers which authorize
the person to tender the existing notes on behalf of the registered holder or
DTC participant who is listed as the owner, in either case signed as the name of
the registered holder(s) who appears on the existing notes or the DTC
participant who is listed as the
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owner. If the letter of transmittal or any existing notes or bond powers are
signed or endorsed 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, and
unless waived by us, evidence satisfactory to us of their authority to so act
must be submitted with the letter of transmittal.
If you tender your notes through ATOP, signatures and signature
guarantees are not required.
DETERMINATIONS OF VALIDITY
All questions as to the validity, form, eligibility, including time of
receipt, acceptance and withdrawal of the tendered existing notes will be
determined by us in our sole discretion. This determination will be final and
binding. We reserve the absolute right to reject any and all existing notes not
properly tendered or any existing notes our acceptance of which would, in the
opinion of our counsel, be unlawful. We also reserve the absolute right to waive
any irregularities or conditions of tender as to particular existing 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, any defects or irregularities in connection with tenders
of existing notes must be cured within the time we shall determine. Although we
intend to notify holders of defects or irregularities related to tenders of
existing notes, neither we, the exchange agent nor any other person shall be
under any duty to give notification of defects or irregularities related to
tenders of existing notes nor shall any of them incur liability for failure to
give notification. Tenders of existing notes will not be considered to have been
made until the irregularities have been cured or waived. Any existing notes
received by the exchange agent that we determine are not properly tendered or
the tender of which is otherwise rejected by us and as to which the defects or
irregularities have not been cured or waived by us will be returned by the
exchange agent to the tendering holder unless otherwise provided in the letter
of transmittal, as soon as practicable following the expiration date.
GUARANTEED DELIVERY PROCEDURES
Holders who wish to tender their existing notes and:
o whose existing notes are not immediately available;
o who cannot complete the procedure for book-entry transfer on a
timely basis;
o who cannot deliver their existing notes, the letter of
transmittal or any other required documents to the exchange
agent prior to the expiration date; or
o who cannot complete a tender of existing notes held in
book-entry form using DTC's ATOP procedures on a timely basis;
may effect a tender if they tender through an eligible institution described
under "--Procedures for Tendering--Signatures," or, if they tender using ATOP's
guaranteed delivery procedures.
A tender of existing notes made by or through an eligible institution
will be accepted if:
o prior to 5:00 p.m., New York City time, on the expiration
date, the exchange agent receives from an eligible institution
a properly completed and duly executed notice of guaranteed
delivery, by facsimile transmittal, mail or hand delivery,
that:
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(1) sets forth the name and address of the holder, the
certificate number or numbers of the holder's
existing notes and the principal amount of the
existing notes tendered,
(2) states that the tender is being made, and
(3) guarantees that, within five business days after the
expiration date, a properly completed and validly
executed letter of transmittal or facsimile, together
with a certificate(s) representing the existing notes
to be tendered in proper form for transfer, or a
confirmation of book-entry transfer into the exchange
agent's account at DTC of existing notes delivered
electronically, and any other documents required by
the letter of transmittal will be deposited by the
eligible institution with the exchange agent; and
o the properly completed and executed letter of transmittal or a
facsimile, together with the certificate(s) representing all
tendered existing notes in proper form for transfer, or a
book-entry confirmation, and all other documents required by
the letter of transmittal are received by the exchange agent
within five business days after the expiration date.
A tender made through DTC's Automated Tender Offer Program will be
accepted if:
o prior to 5:00 p.m., New York City time, on the expiration
date, the exchange agent receives an agent's message from DTC
stating that DTC has received an express acknowledgment from
the participant in DTC tendering the existing notes that they
have received and agree to be bound by the notice of
guaranteed delivery; and
o the exchange agent receives, within five business days after
the expiration date, either:
(1) a book-entry conformation, including an agent's
message, transmitted via DTC's ATOP procedures; or
(2) a properly completed and executed letter of
transmittal or a facsimile, together with the
certificate(s) representing all tendered existing
notes in proper form for transfer, or a book-entry
confirmation, and all other documents required by the
letter of transmittal are received by.
Upon request to the exchange agent, a notice of guaranteed delivery
will be sent to holders who wish to tender their existing notes according to the
guaranteed delivery procedures described above.
WITHDRAWAL OF TENDERS
Except as otherwise provided in this prospectus, tenders of existing
notes may be withdrawn at any time prior to 5:00 p.m., New York City time, on
the expiration date. To withdraw a tender of existing notes in the exchange
offer:
o a written or facsimile transmission of a notice of withdrawal
must be received by the exchange agent at its address listed
below prior to 5:00 p.m., New York City time, on the
expiration date; or
o you must comply with the appropriate procedures of DTC's
Automated Tender Offer Program.
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Any notice of withdrawal must:
o specify the name of the person having deposited the existing
notes to be withdrawn;
o identify the existing notes to be withdrawn, including the
certificate number or numbers and principal amount of the
existing notes or, in the case of existing notes transferred
by book-entry transfer, the name and number of the account at
the depositary to be credited;
o be signed by the same person and in the same manner as the
original signature on the letter of transmittal by which the
existing notes were tendered, including any required signature
guarantee, or be accompanied by documents of transfer
sufficient to permit the trustee for the existing notes to
register the transfer of the existing notes into the name of
the person withdrawing the tender; and
o specify the name in which any of these existing notes are to
be registered, if different from that of the person who
deposited the existing notes to be withdrawn.
All questions as to the validity, form and eligibility, including time
of receipt, of the withdrawal notices will be determined by us, whose
determination shall be final and binding on all parties. Any existing notes so
withdrawn will be judged not to have been tendered according to the procedures
in this prospectus for purposes of the exchange offer, and no exchange notes
will be issued in exchange for those existing notes unless the existing notes so
withdrawn are validly retendered. Any existing notes that have been tendered but
are not accepted for exchange will be returned to the holder of the existing
notes without cost to the holder or, in the case of existing notes tendered by
book-entry transfer into the holder's account at DTC according to the procedures
described above. This return or crediting will take place as soon as practicable
after withdrawal, rejection of tender or termination of the exchange offer.
Properly withdrawn existing notes may be retendered by following one of the
procedures described above under "--Procedures for Tendering" at any time prior
to the Expiration Date.
CONDITIONS
The exchange offer is subject only to the following conditions:
o the compliance of the exchange offer with securities laws;
o the tender of the existing notes;
o the representation by the holders of the existing notes that
they are not our affiliate, that the exchange notes they will
receive are being acquired by them in the ordinary course of
their business and that at the time the exchange offer is
completed the holder had no plan to participate in the
distribution of the exchange notes; and
o no judicial or administrative proceeding is pending or shall
have been threatened that would limit us from proceeding with
the exchange offer.
EXCHANGE AGENT
State Street Bank and Trust Company, the trustee under the indenture,
has been appointed as exchange agent for the exchange offer. In this capacity,
the exchange agent has no fiduciary duties and will be acting solely on the
basis of our directions. Requests for assistance and requests for additional
copies of this prospectus or of the letter of transmittal should be directed to
the
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exchange agent. You should send certificates for existing notes, letters of
transmittal and any other required documents to the exchange agent addressed as
follows:
<TABLE>
<S> <C>
By Mail: State Street Bank and Trust Company
Corporate Trust
P. O. Box 778
Boston, Massachusetts 02110-0778
By Hand Delivery or Overnight Courier: State Street Bank and Trust Company
2 Avenue de Lafayette
5th Floor, Corporate Trust Division
Boston, Massachusetts 02110-1724
Facsimile Transmission: (617) 662-1525
Confirm by Telephone: (617) 662-1452
</TABLE>
DELIVERY OF THE LETTER OF TRANSMITTAL TO AN ADDRESS OTHER THAN AS
LISTED ABOVE OR TRANSMISSION OF INSTRUCTIONS VIA FACSIMILE OTHER THAN AS
DESCRIBED ABOVE DOES NOT CONSTITUTE A VALID DELIVERY OF THE LETTER OF
TRANSMITTAL.
SOLICITATION OF TENDERS; FEES AND EXPENSES
We will bear the expenses of requesting that holders of existing notes
tender those notes for exchange notes. The principal solicitation under the
exchange offer is being made by mail. Additional solicitations may be made by
our officers and regular employees and our affiliates in person, by telegraph,
telephone or telecopier.
We have not retained any dealer-manager in connection with the exchange
offer and will not make any payments to brokers, dealers or other persons
soliciting acceptances of the exchange offer. We, however, will pay the exchange
agent reasonable and customary fees for its services and will reimburse the
exchange agent for its reasonable out-of-pocket costs and expenses in connection
with the exchange offer and will indemnify the exchange agent for all losses and
claims incurred by it as a result of the exchange offer. We may also pay
brokerage houses and other custodians, nominees and fiduciaries the reasonable
out-of-pocket expenses incurred by them in forwarding copies of this prospectus,
letters of transmittal and related documents to the beneficial owners of the
existing notes and in handling or forwarding tenders for exchange.
We will pay the expenses to be incurred in connection with the exchange
offer, including fees and expenses of the exchange agent and trustee and
accounting and legal fees and printing costs.
You will not be obligated to pay any transfer tax in connection with
the exchange, except if you instruct us to register exchange notes in the name
of, or request that notes not tendered or not accepted in the exchange offer be
returned to, a person other than you, you will be responsible for the payment of
any applicable transfer tax.
ACCOUNTING TREATMENT
The exchange notes will be recorded at the same carrying value as the
existing notes, as reflected in our accounting records on the date of the
exchange. Accordingly, no gain or loss for accounting purposes will be
recognized by us upon the closing of the exchange offer. We will amortize the
expenses of the exchange offer over the term of the exchange notes.
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FEDERAL INCOME TAX CONSEQUENCES
The following discussion generally summarizes the principal U.S.
federal income tax consequences of the exchange of existing notes for exchange
notes. This discussion is based upon the U.S. federal income tax laws in effect
and available on the date of this prospectus, including the Internal Revenue
Code of 1986, as amended, the related Treasury Regulations and judicial and
administrative interpretations of the Internal Revenue Code and Treasury
Regulations. All of these laws are subject to change, possibly retroactively, or
different interpretation. We cannot assure you that the Internal Revenue Service
will not challenge one or more of the tax consequences described in this
prospectus. We have not obtained, nor do we intend to obtain, a ruling from the
Internal Revenue Service with respect to the U.S. federal income tax
consequences of the exchange offer. This discussion does not purport to address
all aspects of U.S. federal income taxation that may be relevant to you in light
of your specific circumstances, or if you are subject to special treatment under
the Internal Revenue Code. This discussion also does not address the effect of
any applicable U.S. federal estate and gift tax laws or state, local or foreign
tax laws.
The exchange of existing notes for exchange notes pursuant to the
exchange offer will not be a taxable event for U.S. federal income tax purposes.
You will not recognize gain or loss upon the receipt of exchange notes. If you
are not exempt from U.S. federal income tax you will be subject to such tax on
the same amount, in the same manner and at the same time as you would have been
as a result of holding the existing notes. If you are a cash-basis holder who is
exchanging existing notes for exchange notes, you will not recognize in income
any accrued and unpaid interest on the existing notes by reason of the exchange.
The basis and holding period of the exchange notes will be the same as the basis
and holding period of the corresponding existing notes.
THIS DESCRIPTION IS INCLUDED IN THIS PROSPECTUS FOR GENERAL INFORMATION
ONLY. ACCORDINGLY, YOU SHOULD CONSULT WITH YOUR OWN TAX ADVISOR CONCERNING THE
U. S. FEDERAL INCOME TAX CONSEQUENCES OF THE EXCHANGE OFFER WITH RESPECT TO YOUR
PARTICULAR SITUATION, INCLUDING THE APPLICATION AND EFFECT OF STATE, LOCAL AND
FOREIGN INCOME AND OTHER TAX LAWS.
PARTICIPATION IN THE EXCHANGE OFFER; UNTENDERED NOTES
Participation in the exchange offer is voluntary. Holders of the
existing notes are urged to consult their financial and tax advisors in making
their own decisions on what action to take.
As a result of the making of, and upon acceptance for exchange of all
existing notes tendered under the terms of, this exchange offer, we will have
fulfilled a covenant contained in the terms of the registration agreement.
Holders of the existing notes who do not tender in the exchange offer will
continue to hold their existing notes and will be entitled to all the rights,
and subject to the limitations, applicable to the existing notes under the
indenture. Holders of existing notes will not longer be entitled to any rights
under the registration agreement that by their term terminate or cease to have
further effect as a result of the making of this exchange offer. See
"Description of the Exchange Notes." All untendered existing notes will continue
to be subject to the restrictions on transfer described in the indenture. To the
extent that existing notes are tendered and accepted in the exchange offer, the
trading market for untendered existing notes could be adversely affected. This
is because there will probably be many fewer remaining existing notes
outstanding following the exchange, significantly reducing the liquidity of the
untendered notes.
We may in the future seek to acquire untendered existing notes in the
open market or through privately negotiated transactions, through subsequent
exchange offers or otherwise. We intend to make any acquisitions of existing
notes following the applicable requirements of the Exchange Act, and the rules
and regulations of the SEC under the Exchange Act, including Rule 14e-1,
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to the extent applicable. We have no present plan to acquire any existing notes
that are not tendered in the exchange offer or to file a registration statement
to permit resales of any existing notes that are not tendered in the exchange
offer.
DESCRIPTION OF THE EXCHANGE NOTES
We will issue the exchange notes under an indenture to be entered into
between us and State Street Bank and Trust Company, as trustee. The following
description is a summary of selected provisions of the indenture and the
exchange notes. We have not restated the indenture in its entirety. We will
provide you a copy of the indenture for the exchange notes without charge if you
request it from us. You should read the indenture because the indenture, and not
this description, will control your rights as a holder of exchange notes. For
purposes of this section of this prospectus, references to the "Company,"
"Nuevo," "we," "us," "our" or "ours" means Nuevo Energy Company, excluding our
subsidiaries. The definitions of some of the terms used in the following summary
are set forth below under "--Material Definitions."
The exchange notes and the existing notes will be treated as a single
class for all purposes of the indenture, and references in this section to the
exchange notes include the existing notes.
The indenture provides for the issuance of up to $400,000,000 of notes,
We will issue a maximum principal amount of $257,310,000 of exchange notes in
exchange for the existing notes in the exchange offer. All other issuances of
notes in the future will be subject to the debt incurrence test described under
"--Material Covenants--Incurrence of Indebtedness." All of the notes will be
identical in all respects other than the price at which we issue the notes and
the date an which we issue the notes.
PRINCIPAL, MATURITY AND INTEREST OF THE EXCHANGE NOTES
The exchange notes will be our general unsecured senior subordinated
obligations. The exchange notes will mature on June 1, 2008. Interest on the
exchange notes will accrue at the rate of 9 1/2% per annum and will be payable
semiannually in arrears on June 1 and December 1. Interest payments will be made
to the person in whose names the exchange notes are registered at the close of
business on the May 15 or November 15 preceding the interest payment date.
Interest on the exchange notes will accrue from the date of issuance of the
existing notes or, if interest has already been paid on the existing notes, from
the date it was most recently paid. Interest will be computed on the basis of a
360-day year comprised of twelve 30-day months.
Principal, interest and premium on the exchange notes will be paid as
described under "--Book-Entry, Delivery and Form" below.
SUBORDINATION
The payment of the principal of, and premium and interest on, the
exchange notes will be subordinated in right of payment to the prior payment in
full of Senior Indebtedness (Section 14. 1 ). The subordination provisions
prohibit us from making payments with respect to the exchange notes if the
events described below occur. If triggered, the subordination provisions
prohibit us from paying any amounts with respect to the exchange notes,
including:
o payments of principal or interest;
o payments of any premium; and
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o repurchases of the exchange notes, including repurchases in
connection with a Change of Control or Asset Sale, as
described under "--Repurchase at the Options of
Holders--Change of Control" and "--Asset Sales."
If we:
o become subject to insolvency or bankruptcy proceedings, or any
receivership, liquidation, reorganization or similar case;
o liquidate, dissolve or otherwise wind-up our business; or
o make an assignment for the benefit of our creditors or marshal
our assets or liabilities;
the holders of Senior Indebtedness will be entitled to receive full payment of
all amounts owed to them prior to any payments being made to the holders of
exchange notes. We will not be required to repay all Senior Indebtedness in full
in connection with our consolidation or merger or our liquidation or dissolution
following the disposition of all or substantially all of our properties upon the
terms described under the subheading "--Material Covenants--Merger,
Consolidation or Sale of Assets" as a condition to any payments on the exchange
notes. If the trustee for the exchange notes receives any payment from us when
the subordination provisions prohibit payment of amounts owed on the exchange
notes, the trustee is required to return the payments to us or our receiver or
custodian for payment to holders of Senior Indebtedness. The subordination
provisions apply to payments of any nature, including payments:
o of cash;
o of property, assets or securities; and
o by way of set-off.
The subordination provisions, however, do not prohibit the payment of principal,
interest and premium on the exchange notes if the payment is made in Permitted
Junior Securities.
Additionally, we may not make any payment in respect of the exchange
notes, other than payments of Permitted Junior Securities, if a Payment Event of
Default occurs on our Specified Senior Indebtedness and the trustee receives
written notice of the default. We must resume payment in respect of the exchange
notes, including any missed payments, when we cure or obtain a waiver of the
Payment Event of Default or it otherwise ceases to exist. We must also resume
payment in respect of the exchange notes, including any missed payments, if we
pay in full or discharge the Specified Senior Indebtedness.
We also may not make any payment in respect of the exchange notes,
other than payments of Permitted Junior Securities, for the period specified
below ("Payment Blockage Period") if a Nonpayment Event of Default occurs on our
Specified Senior Indebtedness and the trustee and we receive written notice of
the default from any holder of Specified Senior Indebtedness. The Payment
Blockage Period will commence upon the earlier of the date of receipt by the
trustee or us of such notice of the default (the "Payment Blockage Notice") and
will end on the earliest of:
o 179 days after it begins;
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o the date on which the holders of Specified Senior Indebtedness
notify the trustee or us that the Non-payment Event of Default
no longer exists or that the Specified Senior Indebtedness has
been discharged; and
o the date we or the trustee receives notice from the person
initiating the Payment Blockage Period that the period has
been terminated.
We must resume making payments in respect of the exchange notes after the
Payment Blockage Period ends, including any missed payments, unless we are
otherwise prohibited by the other subordination provisions of the indenture. No
more than one Payment Blockage Period may commence during any period of 360
consecutive days. No Non-payment Event of Default that existed on the date of
delivery of a Payment Blockage Notice to the trustee can be made the basis for a
subsequent Payment Blockage Notice. (Section 14.3)
If we fail to make any payment on the exchange notes when due or within
any applicable grace period, whether or not on account of the payment blockage
provisions described above, the failure will constitute an Event of Default
under the indenture and will entitle the holders of the exchange notes to
exercise the rights described under "--Events of Default and Remedies." (Section
5.1)
As a result of such subordination provisions described above, in the
event of a distribution of assets upon our liquidation, receivership,
reorganization or insolvency, our creditors who are holders of Senior
Indebtedness may recover more, ratably, than the holders of the exchange notes,
and assets which would otherwise be available to pay obligations in respect of
the exchange notes will be available only after we have paid all Senior
Indebtedness in full, and there may not be sufficient assets remaining to pay
amounts due on any or all of the exchange notes.
The subordination provisions described above will cease to be
applicable to the exchange notes upon any Legal Defeasance or Covenant
Defeasance of the exchange notes as described under "--Legal Defeasance and
Covenant Defeasance."
SUBSIDIARY GUARANTEES OF NOTES
None of our Restricted Subsidiaries will guarantee the exchange notes
unless the Restricted Subsidiary also guarantees or secures any of our Pari
Passu Indebtedness or Subordinated Indebtedness. If one of our Restricted
Subsidiaries guarantees or secures any of our Pari Passu Indebtedness or
Subordinated Indebtedness, we will cause it to be bound by the terms of the
indenture and to unconditionally guarantee the performance of our obligations
under the indenture and the exchange notes. (Sections 10.13 and 13.1)
The obligations of each Subsidiary Guarantor will be limited to the
maximum amount as will, after giving effect to all other contingent and fixed
liabilities of such Subsidiary Guarantor and after giving effect to any
collections from or made by or on behalf of any other Subsidiary Guarantor under
its Subsidiary Guarantee or pursuant to its contribution obligations under the
indenture, result in the obligations of such Subsidiary Guarantor under its
Subsidiary Guarantee not constituting a fraudulent conveyance or fraudulent
transfer under federal or state law. Each Subsidiary Guarantor that makes a
payment or distribution under its Subsidiary Guarantee shall be entitled to a
contribution from each other Subsidiary Guarantor, if any, in a pro rata amount
based on the Adjusted Net Assets of each Subsidiary Guarantor. (Section 13.4)
Each Subsidiary Guarantor may consolidate with or merge into or sell or
otherwise dispose of all or substantially all of its properties and assets to us
or another Subsidiary Guarantor without
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limitation, except to the extent any such transaction is subject to the "Merger,
Consolidation or Sale or Assets" covenant of the indenture. Each Subsidiary
Guarantor may consolidate with or merge into or sell all or substantially all of
its properties and assets to a Person other than us or another Subsidiary
Guarantor, whether or not Affiliated with the Subsidiary Guarantor, provided
that:
o if the surviving Person is not the Subsidiary Guarantor, the
surviving Person agrees to assume the Subsidiary Guarantor's
Subsidiary Guarantee and all its obligations pursuant to the
indenture, except to the extent the following paragraph would
result in the release of such Subsidiary Guarantee; and
o such transaction does not violate any of the covenants
described under the heading "--Material Covenants" or result
in a Default or Event of Default immediately thereafter that
is continuing. (Section 13.2)
Upon the sale or other disposition, by merger or otherwise, of a
Subsidiary Guarantor of all or substantially all of its assets to a Person other
than us or another Subsidiary Guarantor and pursuant to a transaction that is
otherwise in compliance with the indenture, including as described in the
foregoing paragraph, such Subsidiary Guarantor shall be deemed released from its
Subsidiary Guarantee and the related obligations set forth in the indenture. Any
such termination shall occur only to the extent that all obligations of such
Subsidiary Guarantor under all of its guarantees of, and under all of its
pledges of assets or other security interests which secure, our or our
Restricted Subsidiaries' other Indebtedness shall also terminate upon such sale
or other disposition. In addition, all of the Subsidiary Guarantors shall be
deemed released from their respective Subsidiary Guarantees and the related
obligations set forth in the indenture in the event that all obligations of the
Subsidiary Guarantors under all of their guarantees of, and under all of their
pledges of assets or other security interests which secure our or our Restricted
Subsidiaries' other Indebtedness, excluding any Senior Indebtedness, shall also
terminate. (Section 13.3)
The obligations of each Subsidiary Guarantor under its Subsidiary
Guarantee will be subordinated to the prior payment in full of all Guarantor
Senior Indebtedness of such Subsidiary Guarantor to substantially the same
extent as the exchange notes are subordinated to Senior Indebtedness. (Section
13.8)
REDEMPTION AT THE OPTION OF NUEVO
We may not redeem the exchange notes at our option prior to June 1,
2003. Thereafter, we may redeem the exchange notes at our option, in whole or in
part, at the redemption prices expressed as percentages of principal amount set
forth below. If we redeem the notes at our option, we must also pay interest
accrued and unpaid to the applicable redemption date. The redemption prices
during the twelve-month period beginning on June 1 of the years indicated are
set forth below:
<TABLE>
<CAPTION>
YEAR PERCENTAGE
---- ----------
<S> <C>
2003 ........................................................... 104.750%
2004 ........................................................... 103.167%
2003 ........................................................... 101.583%
2006 and thereafter ............................................ 100.000%
</TABLE>
In addition, prior to June 1, 2001 we may redeem up to 33 1/3% of the
aggregate principal amount of the exchange notes originally issued at a
redemption price of 109.5% of the principal amount, plus accrued and unpaid
interest to the date of redemption, with the net proceeds of one or
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more Equity Offerings. We may not cause a redemption from the proceeds of the
Equity Offering unless:
o at least 66 2/3% of the aggregate principal amount of the
exchange notes originally issued under the indenture at any
time prior to such redemption remain outstanding after the
redemption; and
o the redemption occurs within 90 days after the closing of the
Equity Offering. (Section 11.1)
If we redeem less than all of the exchange notes, selection of exchange
notes for redemption will be made by the trustee on a pro rata basis. We will
not, however, redeem notes in principal amounts of less than $10. (Section 11.4)
We will mail notice of a redemption at least 30 and not more than 60 days before
the redemption date. The notice will describe the amount of notes being
redeemed, if less than the entire principal amount. (Section 11.5) Interest will
cease to accrue on exchange notes which are redeemed on the redemption date.
(Section 11.7)
MANDATORY REDEMPTION
We will not be required to make mandatory redemption or sinking fund
payments with respect to the exchange notes.
REPURCHASE AT THE OPTION OF HOLDERS
Change of Control
If a Change of Control occurs, we will be obligated to make an offer to
purchase all of the outstanding exchange notes. The purchase price we are
required to offer is 101% of the aggregate principal amount plus accrued and
unpaid interest to the date of purchase. We are required to purchase all
exchange notes tendered under the offer which are not withdrawn.
In order to effect a Change of Control offer, we must mail a notice of
the Change of Control to the trustee and each holder of exchange notes no later
than 30 days after the Change of Control occurs. We are obligated to close the
purchase of notes tendered under the Change of Control offer no less than 30 and
no more than 60 days after the notice is mailed. The notice will describe the
Change of Control and the procedures that must be followed to participate in the
offer.
Our bank credit facility states that events which constitute a Change
of Control constitute a default under the bank credit facility. In addition, our
bank credit facility prohibits the repurchase of both the existing notes and the
exchange notes. Future agreements relating to our Senior Indebtedness may
contain similar provisions. In the event a Change of Control occurs at a time
when we are prohibited from purchasing exchange notes, we could seek the consent
of our lenders to the purchase of exchange notes or could attempt to refinance
the borrowings that contain a prohibition. If we do not obtain a consent or
repay the borrowings, we will be prohibited from purchasing exchange notes,
which will constitute an Event of Default under the Indenture. A default under
the indenture for the exchange notes will also be a default under the bank
credit facility and may be a default under other current and future agreements
to which we are or may become a party. In such circumstances, the subordination
provisions in the indenture may prevent payments to the holders of exchange
notes required by the Change of Control.
We will not be required to make a Change of Control offer if a third
party makes the Change of Control offer at the same purchase price, at the same
times and otherwise in substantial
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compliance with the requirements applicable to a Change of Control offer made by
us and purchases the exchange notes properly tendered and not withdrawn.
(Section 10.16)
Asset Sales
We may not, and may not permit our Restricted Subsidiaries to, engage
in any Asset Sale unless the consideration received equals the fair market value
of the assets and properties sold or otherwise disposed of as determined by our
board of directors, and the consideration is either:
o cash, Cash Equivalents, Liquid Securities or Exchanged
Properties ("Permitted Consideration"); or
o the property or assets received that do not constitute
Permitted Consideration have an aggregate fair market value of
no more than 10.0% of our Adjusted Consolidated Net Tangible
Assets.
If we do not invest the Net Cash Proceeds of Asset Sales which occur
after the date of the indenture in properties and assets that will be used in
the Oil and Gas Business within 365 days after the closing of the Asset Sale, we
must either:
o repay Indebtedness under the Credit Facility;
o repay or purchase other Indebtedness (other than Subordinated
Indebtedness or Pari Passu Indebtedness) of ourself or a
Restricted Subsidiary, provided that any related loan
commitment is permanently reduced by the amount of such
Indebtedness repaid; or
o offer to repurchase exchange notes as described below.
The amount of Net Cash Proceeds from all Asset Sales which occur after the date
of the indenture not used for one of the purposes described in this paragraph
will constitute "Excess Proceeds."
When the aggregate amount of Excess Proceeds is equal to or more than
$10 million:
o we must make an Offer to purchase the exchange notes and any
outstanding Pari Passu Indebtedness required to be repurchased
in connection with an Asset Sale, provided that the amount of
the Pari Passu Indebtedness repurchased is permanently
reduced;
o we must make an offer to purchase exchange notes in the
principal amount calculated by multiplying the Excess Proceeds
by a fraction, the numerator of which is the outstanding
principal amount of the exchange notes and the denominator of
which is the sum of the outstanding principal amount of the
exchange notes plus any Pari Passu Indebtedness that we must
offer to repurchase;
o the offer price for the exchange notes will be payable in cash
in an amount equal to 100% of the principal amount of the
exchange notes tendered, plus accrued and unpaid interest to
the date of payment; and
o if more exchange notes are tendered than we have Excess
Proceeds to purchase, we will pro rate the exchange notes
tendered.
If the amount of exchange notes tendered is less than the amount of exchange
notes we offered to purchase, we may use the Excess Proceeds not used to
repurchase exchange notes for general
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corporate purposes. The use of Excess Proceeds for general corporate purposes
must comply with the other provisions of the indenture, including the covenant
described under "--Material Covenants--Restricted Payments."
After we make an Excess Proceeds offer as described above, the amount
of Excess Proceeds will be reset to zero. We will not permit any of our
Restricted Subsidiaries to be a party to any agreement that would place any
restriction on our right to make an offer to repurchase exchange notes following
an Asset Sale. (Section 10.17)
Securities Law Compliance
We will comply with the requirements of Rule 14e-1 under the Securities
Exchange Act of 1934 and any other securities laws and regulations thereunder to
the extent such laws and regulations are applicable in connection with the
repurchase of the exchange notes as a result of a Change of Control or Asset
Sale. These rules require that we keep the offer open for 20 business days. They
also require that we notify holders of exchange notes of changes in the offer
and extend the offer for specified time periods if we amend the offer. If the
provisions of any securities laws or regulations conflict with the provisions in
the indenture relating to a Change of Control or Asset Sale offer, we will
comply with the applicable securities laws and regulations and will not be
deemed to have breached our obligations under the indenture.
MATERIAL COVENANTS
Ownership of Capital Stock
We may not permit any Restricted Subsidiary to issue any Capital Stock
other than to us or a Wholly Owned Restricted Subsidiary. Also, we may not
permit any Person other than us or a Wholly Owned Restricted Subsidiary to own
any Capital Stock of a Restricted Subsidiary, except for:
o directors' qualifying shares;
o Capital Stock of a Restricted Subsidiary organized in a
foreign jurisdiction required to be owned by the government of
the foreign jurisdiction or citizens of the foreign
jurisdiction in order for the Restricted Subsidiary to
transact business in the foreign jurisdiction;
o a sale of all or substantially all of the Capital Stock of a
Restricted Subsidiary effected in accordance with the "Asset
Sales" covenant;
o Qualifying TECONS; and
o the Capital Stock of a Restricted Subsidiary owned by a Person
at the time the Restricted Subsidiary became a Restricted
Subsidiary or which is acquired by the Person in connection
with the formation of the Restricted Subsidiary.
The Capital Stock owned by us or another Restricted Subsidiary will be treated
as an Investment for purposes of the "Restricted Payments" covenant, if the
amount of such Capital Stock represents less than a majority of the Voting Stock
of such Restricted Subsidiary. (Section 10.14)
Restricted Payments
The indenture will define the following as Restricted Payments if done
by us or any of our Restricted Subsidiaries:
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o the declaration or payment of any dividend or distribution on
our Capital Stock, including Eligible Convertible Securities
and Qualifying TECONS, other than dividends or distributions
payable solely in shares of our Qualified Capital Stock or in
options, warrants or other rights to purchase our Qualified
Capital Stock;
o the purchase or acquisition of our Capital Stock, including
Eligible Convertible Securities and Qualifying TECONS, or that
of our Affiliates, other than Capital Stock issued by a Wholly
Owned Restricted Subsidiary, or any options, warrants or other
rights to acquire such Capital Stock;
o making any principal payment on, or repurchase or other
acquisition of, any Subordinated Indebtedness prior to any
scheduled principal payment, scheduled sinking fund payment or
maturity, except using the Excess Proceeds remaining after
compliance with the provisions described under "--Repurchase
at the Option of Holders--Asset Sales," and to the extent
required by the indenture or other agreement or instrument
pursuant to which such Subordinated Indebtedness was issued;
o the declaration or payment of any dividend or other
distribution on shares of Capital Stock of any Restricted
Subsidiary, other than to us or any Wholly Owned Restricted
Subsidiary, or the purchase, redemption or other acquisition
or retirement of any Capital Stock of any Restricted
Subsidiary or any options, warrants or other rights to acquire
any such Capital Stock, other than for Capital Stock held by
us or any Wholly Owned Restricted Subsidiary; or
o making of any Investment, other than any Permitted Investment.
We may not make a Restricted Payment, unless at the time of and after
giving effect to the proposed Restricted Payment:
o no Default or Event of Default shall have occurred and be
continuing,
o we could incur $1.00 of additional Indebtedness, other than
Permitted Indebtedness, in accordance with the covenant
described under "--Incurrence of Indebtedness"; and
o the aggregate amount of all Restricted Payments declared or
made after June 8, 1999 shall not exceed the sum, without
duplication, of the following:
(1) 50% of our aggregate Consolidated Net Income accrued
on a cumulative basis during the period beginning on
April 1, 1998 and ending on the last day of our last
fiscal quarter ending prior to the date of such
proposed Restricted Payment (or, if such aggregate
Consolidated Net Income shall be a loss, minus 100%
of such loss); plus
2) the aggregate net cash proceeds or the fair market
value of any property or assets other than cash,
received after June 8, 1998 by us as capital
contributions to us, other than from any Restricted
Subsidiary; plus
(3) the aggregate net cash proceeds or the fair market
value of any property or assets other than cash,
received by us after June 8, 1998 from the issuance
or sale, other than to any of our Restricted
Subsidiaries, of our Qualified Capital Stock or any
option, warrants or rights to purchase our Qualified
Capital Stock; plus
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(4) the aggregate net cash proceeds received after June
8, 1999 by us, other than from any of our Restricted
Subsidiaries, upon the exercise of any options,
warrants or rights to purchase our Qualified Capital
Stock; plus
(5) the aggregate net cash proceeds received after June
8, 1998 by us from the issuance or sale, other than
to any of our Restricted Subsidiaries, of debt
securities or shares of Redeemable Capital Stock that
have been converted into or exchanged for our
Qualified Capital Stock, together with the aggregate
cash received by us at the time of such conversion or
exchange; plus
(6) the aggregate net cash proceeds or the fair market
value of any property or assets received after June
8, 1999 by us or our Restricted Subsidiaries,
computed on a consolidated basis, constituting a
return of capital on an Investment, other than a
Permitted Investment, made by us or any of our
Restricted Subsidiaries after June 8, 1998; plus
(7) $25.0 million.
However, we and our Restricted Subsidiaries may take the following
actions so long as, at the time thereof, no Default or Event of Default shall
have occurred and be continuing, except in the case of the first clause below,
and, in the case of the sixth clause below, we could incur $1.00 of additional
Indebtedness, excluding Permitted Indebtedness, in accordance with the covenant
described under "--Incurrence of Indebtedness":
o the payment of any dividend on any of our or any Restricted
Subsidiary's Capital Stock within 60 days after the date of
declaration thereof, if at such declaration date such
declaration complied with the covenant, and such payment shall
be deemed to have been paid on such date of declaration for
purposes of making any calculation under this covenant;
o the repurchase or other acquisition or retirement of any
shares of our or of any of our Restricted Subsidiaries'
Capital Stock, in exchange for, or out of the aggregate net
cash proceeds of, a substantially concurrent issue and sale of
our Qualified Capital Stock, other than a sale to a Restricted
Subsidiary;
o the repurchase or other acquisition or retirement for value of
any Subordinated Indebtedness, other than Redeemable Capital
Stock, in exchange for, or out of the aggregate net cash
proceeds of, a substantially concurrent issue and sale of our
Qualified Capital Stock, other than to a Restricted
Subsidiary;
o the purchase or other acquisition or retirement for value of
Subordinated Indebtedness in exchange for, or out of the
aggregate net cash proceeds of, a substantially concurrent
incurrence, other than to a Restricted Subsidiary, of
Subordinated Indebtedness so long as:
(1) the principal amount of such new Indebtedness does
not exceed the principal amount, or, if such
Subordinated Indebtedness being refinanced provides
for an amount less than the principal amount thereof
to be due and payable upon a declaration of
acceleration thereof, such lesser amount as of the
date of determination, of the Indebtedness being so
purchased, acquired or retired, plus the amount of
any premium required to be paid in connection with
such refinancing pursuant to the terms of the
Indebtedness refinanced or the amount
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of any premium reasonably determined by us as
necessary to accomplish such refinancing, plus the
amount of our expenses incurred in connection with
such refinancing,
(2) such new Indebtedness is subordinated to the exchange
notes at least to the same extent as such
Indebtedness so purchased, acquired or retired,
(3) such new Indebtedness has an Average Life to Stated
Maturity that is longer than the Average Life to
Stated Maturity of the exchange notes, and
(4) such new Indebtedness has a Stated Maturity for its
final scheduled principal payment that is at least 91
days later than the Stated Maturity for the final
scheduled principal payment of the exchange notes;
o the repurchase or other acquisition or retirement for value of
any of our or our Subsidiaries' Qualified Capital Stock held
by any of our or our Subsidiaries' current or former officers,
directors or employees pursuant to the terms of agreements,
including employment agreements, or plans approved by our
board of directors, including any such repurchase, acquisition
or retirement of such Qualified Capital Stock that is deemed
to occur upon the exercise of stock options or similar rights
if such shares represent all or a portion of the exercise
price or are surrendered in connection with satisfying Federal
income tax obligations; provided, however, that the aggregate
amount of such repurchases, acquisitions and retirements shall
not exceed the sum of:
(1) $1.0 million in any twelve-month period, and
(2) the aggregate net proceeds, if any, received by us
during such twelve-month period from any issuance of
such Qualified Capital Stock pursuant to such
agreements or plans; and
o the repurchase or other acquisition of our Qualified Capital
Stock in an amount not to exceed 50% of the net after-tax gain
from Specified Property Sales.
The actions described in the first clause of this paragraph are Restricted
Payments that will be permitted to be taken in accordance with this paragraph
but shall reduce the amount that would otherwise be available for Restricted
Payments. The actions described in the second through the sixth clauses above
will be Restricted Payments that will be permitted to be taken in accordance
with this paragraph and will not reduce the amount that would otherwise be
available for Restricted Payments.
We or any of our Restricted Subsidiaries may make a Restricted Payment,
if at the time we first incurred a commitment for the Restricted Payment the
Restricted Payment could have been made, if all commitments incurred and
outstanding are treated as if they were Restricted Payments expended by us or a
Restricted Subsidiary at the time the commitments were incurred, except that
commitments incurred and outstanding which are treated as a Restricted Payment
and which are ultimately not made shall no longer be treated as a Restricted
Payment expended by us; and provided, further, that at the time such Restricted
Payment is made no Default or Event of Default shall have occurred and be
continuing and we must be able to incur $1.00 of additional Indebtedness, other
than Permitted Indebtedness, in accordance with the "Incurrence of Indebtedness"
covenant. (Section 10.10)
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Incurrence of Indebtedness
We may not, and may not permit any of our Restricted Subsidiaries to,
create, incur, assume, guarantee or otherwise become directly or indirectly
liable for the payment of (collectively, "incur") any Indebtedness, including
any Acquired Indebtedness but excluding Permitted Indebtedness, unless at the
time of such event and after giving effect thereto on a pro forma basis:
o if such incurrence occurs on or before March 31, 2000, the
Consolidated Fixed Charge Coverage Ratio for the applicable
period would have been at least 2.0 to 1.0; and
o if such incurrence occurs after March 31, 2000, the
Consolidated Fixed Charge Coverage Ratio for the applicable
period would have been at least equal to 2.5 to 1.0. (Section
10.12)
Liens
We may not, and may not permit any Restricted Subsidiary to, directly
or indirectly, create, incur, assume or suffer to exist any Lien of any kind,
except for Permitted Liens, upon any of our or any Restricted Subsidiary's
assets or properties, whether now owned or acquired after the date of the
indenture, or any income or profits therefrom to secure any Pari Passu
Indebtedness or Subordinated Indebtedness, unless prior to or contemporaneously
therewith the exchange notes are directly secured equally and ratably, provided
that:
o if such secured Indebtedness is Pari Passu Indebtedness, the
Lien securing such Pari Passu Indebtedness shall be
subordinate and junior to, or pari passu with, the Lien
securing the exchange notes; and
o if such secured Indebtedness is Subordinated Indebtedness, the
Lien securing such Subordinated Indebtedness shall be
subordinate and junior to the Lien securing the exchange notes
at least to the same extent as such Subordinated Indebtedness
is subordinated to the exchange notes.
The foregoing covenant will not apply to any Lien securing Acquired
Indebtedness, provided that any such Lien extends only to the properties or
assets that were subject to such Lien prior to the related acquisition and was
not created, incurred or assumed in contemplation of such transaction. (Section
10.15)
Dividends and Other Payment Restrictions Affecting Restricted
Subsidiaries
We may not, and may not permit any Restricted Subsidiary to, directly
or indirectly, create or otherwise cause or suffer to exist or become effective
any consensual encumbrance or restriction of any kind on the ability of any
Restricted Subsidiary to:
o pay dividends, in cash or otherwise, or make any other
distributions on or in respect of its Capital Stock to us or
any other Restricted Subsidiary;
o pay any Indebtedness owed to us or any other Restricted
Subsidiary;
o make an Investment in us or any other Restricted Subsidiary;
or
o transfer any of its properties or assets to us or any other
Restricted Subsidiary.
However, with respect to the fourth clause of this paragraph only,
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o our Restricted Subsidiaries may have restrictions in the form
of Liens which are not prohibited as described in the "Liens"
covenant and which contain customary limitations on the
transfer of collateral; and
o our Restricted Subsidiaries may have customary restrictions
contained in asset sale agreements limiting the transfer of
such assets pending the closing of such sale.
In addition, the indenture will not prohibit the following encumbrances
and restrictions which exist pursuant to:
o the indenture, the Credit Facility or any other agreement in
effect as of the date of the indenture;
o any agreement or other instrument of a Person acquired by us
or any Restricted Subsidiary in existence at the time of such
acquisition which was not created in contemplation of the
acquisition which encumbrance or restriction is not applicable
to any other Person, or the properties or assets of any other
Person, other than the Person, or the property or assets of
the Person, so acquired;
o customary restrictions in leases and licenses relating to the
property covered thereby and entered into in the ordinary
course of business; or
o any agreement that extends, renews, refinances or replaces the
agreements containing the foregoing restrictions, if the terms
and conditions of those restrictions are not materially less
favorable to the holders of the exchange notes than those
under or pursuant to the agreements so extended, renewed,
refinanced or replaced. (Section 10.19)
Limitation on Layering Debt
We may not have any Indebtedness, including Acquired Indebtedness and
Permitted Indebtedness, that is subordinated in right of payment to Senior
Indebtedness, unless such Indebtedness also ranks equal with, or subordinated in
right of payment to, the exchange notes pursuant to subordination provisions
substantially similar to those applicable to the exchange notes.
(Section 10.11)
Merger, Consolidation or Sale of Assets
We may not, in any single transaction or series of related
transactions, consolidate or merge with or into any other Person, or sell,
assign, convey, transfer, lease or otherwise dispose of all or substantially all
of our and our Restricted Subsidiaries' properties and assets on a consolidated
basis to any person or group of Affiliated Persons, and we may not permit any of
our Restricted Subsidiaries to enter into any such transaction or series of
related transactions if such transaction or series of related transactions would
result in such a disposition of all or substantially all of our and our
Restricted Subsidiaries' properties and assets on a consolidated basis, unless
at the time and after giving effect thereto:
o either:
(1) if the transaction is a merger or consolidation, we
are the surviving Person of the merger or
consolidation, or
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(2) the Person formed by the consolidation or into which
we are merged or to which our or our Restricted
Subsidiaries' properties and assets are disposed of
(referred to as the "Surviving Entity") is a
corporation organized and existing under the laws of
the United States of America, any state thereof or
the District of Columbia and, in either case,
expressly assumes by a supplemental indenture to the
indenture executed and delivered to the trustee, in
form satisfactory to the trustee, all of our
obligations under the exchange notes and the
indenture and the indenture remains in effect;
o immediately after giving effect to the transaction or series
of transactions on a pro forma basis and treating any
Indebtedness not previously an obligation of ours or our
Restricted Subsidiaries in connection with or as a result of
such transaction as having been incurred at the time of the
transaction or series of transactions, no Default or Event of
Default shall have occurred and be continuing;
o except in the case of the consolidation or merger of any
Restricted Subsidiary with or into us, immediately after
giving effect to the transaction or series of transactions on
a pro forma basis, our or the Surviving Entity's Consolidated
Net Worth is at least equal to our Consolidated Net Worth
immediately before such transaction or transactions;
o except in the case of our consolidation or merger with or into
a Wholly Owned Restricted Subsidiary or any Restricted
Subsidiary with or into us or any of our Wholly Owned
Restricted Subsidiaries, immediately after giving effect to
the transaction or transactions on a pro forma basis assuming
that the transaction or transactions occurred on the first day
of the relevant period of fiscal quarters under the
"Incurrence of Indebtedness" covenant ending immediately prior
to the consummation of the transaction or transactions, with
the appropriate adjustments with respect to the transaction or
transactions being included in the pro forma calculation, we
or the Surviving Entity could incur $1.00 of additional
Indebtedness other than Permitted Indebtedness pursuant to
such covenant;
o if any of our or our Restricted Subsidiaries' properties or
assets would upon the transaction or series of related
transactions become subject to any Lien, other than a
Permitted Lien, the creation or imposition of such Lien shall
have been in compliance with the "Liens" covenant; and
o if we are not the continuing obligor under the Indenture, then
any Subsidiary Guarantor, unless it is the Surviving Entity,
shall have confirmed that its Subsidiary Guarantee will
continue to apply following the transaction or transactions.
If we are not the continuing or surviving corporation following any of
the foregoing transaction or transactions, the Surviving Entity shall be
substituted for us under the indenture with the same effect as if the Surviving
Entity had been named as Nuevo therein, and thereafter we will be discharged
from all obligations and covenants under the indenture and the exchange notes,
except in the case of a lease. (Article VIII)
Transactions with Affiliates
We may not, and may not permit any of our Restricted Subsidiaries to,
directly or indirectly, engage in any transaction or series of related
transactions with any of our Affiliates, other than us or a Restricted
Subsidiary, unless:
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o such transaction or series of related transactions is on terms
that are no less favorable to us or such Restricted
Subsidiary, as the case may be, than would be available in a
comparable transaction in arm's-length dealings with an
unrelated third party; and
o with respect to a transaction or series of related
transactions involving payments in excess of $1.0 million in
the aggregate, we deliver an officers' certificate to the
trustee certifying that such transaction complies with the
foregoing clause.
In addition, if the transaction or series of related transactions involves
payments in excess of $5.0 million in the aggregate, the officers' certificate
also must state that such transaction or series of related transactions has been
approved by a majority of our Disinterested Directors. If the transaction or
series of related transactions involves payments of $25.0 million or more in the
aggregate, we must also have received the written opinion of a nationally
recognized investment banking firm or appraisal firm in the United States that
such transaction or series of transactions is fair, from a financial point of
view, to us or our Restricted Subsidiary.
The foregoing restriction shall not apply to
o the provision of services and payments under any of the
existing agreements with Torch Energy Advisors Incorporated or
its subsidiaries so long as each of the agreements, including
any modifications or amendments entered into on or after the
date of the indenture, has been approved by a majority of our
Disinterested Directors;
o loans or advances to our or our Restricted Subsidiaries'
officers, directors and employees made in the ordinary course
of business and consistent with past practices in an aggregate
amount not to exceed $3,000,000 outstanding at any one time;
o the payment of reasonable and customary regular fees to our or
our Restricted Subsidiaries' directors who are not our
employees or employees of our Affiliates;
o our employee compensation and other benefit arrangements;
o indemnities of our and any Subsidiary's officers and directors
consistent with applicable bylaws and statutory provisions; or
o Restricted Payments permitted by the indenture. (Section
10.18)
Reports
We must file on a timely basis with the SEC, to the extent such filings
are accepted by the SEC and whether or not we have a class of securities
registered under the Exchange Act, the annual reports, quarterly reports and
other documents that we would be required to file if we were subject to Section
13 or 15 of the Exchange Act. These include an annual report on Form 10-K and
quarterly reports on Form 10-Q. We will also be required:
o to file with the trustee, with exhibits, and provide to each
holder of exchange notes, without cost to such holder, copies
of reports and documents, without exhibits, within 30 days
after the date on which we file the reports and documents with
the SEC or the date on which we would be required to file the
reports and documents if we were required to, and
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o if filing such reports and documents with the SEC is not
accepted by the SEC or is prohibited under the Exchange Act,
to supply at our cost copies of such reports and documents,
including any exhibits, to any holder of exchange notes,
securities analyst or prospective investor promptly upon
written request. (Section 10.09)
EVENTS OF DEFAULT AND REMEDIES
Each of the following will be an "Event of Default":
o failure to pay interest on the exchange notes when due for 30
days, whether or not prohibited by the subordination
provisions of the exchange notes;
o failure to pay the principal of or premium on the exchange
notes, whether such payment is due at Stated Maturity, upon
redemption, upon repurchase pursuant to a Change of Control
offer or an Asset Sales offer, upon acceleration or otherwise,
whether or not prohibited by the subordination provisions;
o failure to comply with the covenant described under
"--Material Covenants--Merger, Consolidation or Sale of
Assets";
o failure to comply with the covenant described under
"--Repurchase at the Option of Holders--Change of Control";
o failure to comply with the covenant described under
"--Repurchase at the Option of Holders--Asset Sales";
o failure by us or any Subsidiary Guarantor to comply with any
other covenant contained in the exchange notes, any Subsidiary
Guarantee or the indenture for a period of 60 days after
written notice of such failure given to us by the trustee or
to us and the trustee by the holders of at least 25% in
aggregate principal amount of the exchange notes then
outstanding;
o the occurrence and continuation beyond any applicable grace
period of any default in the payment of the principal of,
premium, if any, on or interest on any of our or any
Restricted Subsidiary's Indebtedness, other than the exchange
notes, for money borrowed when due, or any other default
resulting in acceleration of any of our or any Restricted
Subsidiary's Indebtedness for money borrowed, if the aggregate
principal amount of such Indebtedness exceeds $10,000,000, or,
in the case of Non-Recourse Purchase Money Indebtedness,
$40,000,000, and provided, further, that if any such default
is cured or waived or any such acceleration rescinded, or such
Indebtedness is repaid, within a period of 10 days from the
continuation of such default beyond the applicable grace
period or the occurrence of such acceleration, as the case may
be, such Event of Default under the indenture and any
consequential acceleration of the exchange notes shall be
automatically rescinded, so long as such rescission does not
conflict with any judgment or decree;
o any Subsidiary Guarantor shall for any reason cease to be, or
be asserted by us or any Subsidiary Guarantor not to be, in
full force and effect and enforceable in accordance with its
terms, except pursuant to the release or termination of such
Subsidiary Guarantee in accordance with the indenture;
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o final judgments or orders rendered against us or any
Restricted Subsidiary that are unsatisfied and that require
the payment in money, either individually or in an aggregate
amount, that is more than $10,000,000 over the coverage under
applicable insurance policies and either:
(1) commencement by any creditor of an enforcement
proceeding upon such judgment, other than a judgment
that is stayed by reason of pending appeal or
otherwise, or
(2) the occurrence of a 60-day period during which a stay
of such judgment or order, by reason of pending
appeal or otherwise, was not in effect;
o the entry of a decree or order by a court haying jurisdiction
in the premises:
(1) for relief in respect of us or any Material
Subsidiary in an involuntary case or proceeding under
any applicable federal or state bankruptcy,
insolvency, reorganization or other similar law, or
(2) adjudging us or any Material Subsidiary bankrupt or
insolvent, or approving a petition seeking
reorganization, arrangement, adjustment or
composition of us or any Material Subsidiary under
any applicable federal or state law, or appointing
under any such law a custodian, receiver, liquidator,
assignee, trustee, sequestrator or other similar
official of us or any Material Subsidiary or of a
substantial part of our or any Material Subsidiary's
consolidated assets, or ordering the winding up or
liquidation of our or any Material Subsidiary's
affairs, and the continuance of any such decree or
order for relief or any such other decree or order
unstayed and in effect for a period of 60 consecutive
days; or
o the commencement by us or any Material Subsidiary of a
voluntary case or proceeding under any applicable federal or
state bankruptcy, insolvency, reorganization or other similar
law or any other case or proceeding to be adjudicated bankrupt
or insolvent, or the consent by us or any Material Subsidiary
to the entry of a decree or order for relief in an involuntary
case or proceeding under any applicable federal or state
bankruptcy, insolvency, reorganization or other similar law or
to the commencement of any bankruptcy or insolvency case or
proceeding against us or any Material Subsidiary, or the
filing by us or any Material Subsidiary of a petition or
consent seeking reorganization or relief under any applicable
federal or state law, or the consent by us or any Material
Subsidiary under any such law to the filing of any such
petition or to the appointment of or taking possession by a
custodian, receiver, liquidator, assignee, trustee,
sequestrator or other similar official of us or any Material
Subsidiary or of any substantial part of our or any Material
Subsidiary's consolidated assets, or the making by us or any
Material Subsidiary of an assignment for the benefit of
creditors under any such law, or the admission by us or any
Material Subsidiary in writing of our or any Material
Subsidiary's inability to pay debts generally as they become
due or the taking of corporate action by us or any Material
Subsidiary in furtherance of any such action. (Section 5. 1)
If any Event of Default, other than those specified in the last two
clauses above, occurs and is continuing, the trustee, by written notice to us,
or the holders of at least 25% in aggregate principal amount of the exchange
notes then outstanding, by notice to the trustee and us, may, and the trustee
upon the request of the holders of not less than 25% in aggregate principal
amount of the exchange notes then outstanding shall, declare the principal of,
premium, if any, and accrued interest on all of the exchange notes due and
payable immediately, upon which declaration all amounts payable in
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respect of the exchange notes shall be immediately due and payable. If an Event
of Default specified in the last two clauses above occurs and is continuing,
then the principal of, premium, if any, and accrued interest on all of the
exchange notes shall automatically become and be immediately due and payable
without any declaration, notice or other act on the part of the trustee or any
holder of exchange notes.
After a declaration of acceleration under the indenture, but before a
judgment or decree for payment of the money due has been obtained by the
trustee, the holders of a majority in aggregate principal amount of the
outstanding exchange notes, by written notice to us, any Subsidiary Guarantors
and the trustee, may rescind such declaration if:
o we or any Subsidiary Guarantor has paid or deposited with the
trustee a sum sufficient to pay
(1) all sums paid or advanced by the trustee under the
indenture and the reasonable compensation, expenses,
disbursements and advances of the trustee, its agents
and counsel,
(2) all overdue interest on all exchange notes,
(3) the principal of and premium, if any, on any exchange
notes which have become due otherwise than by such
declaration of acceleration and interest thereon at
the rate borne by the exchange notes, and
(4) to the extent that payment of such interest is
lawful, interest upon overdue interest and overdue
principal at the rate borne by the exchange notes
without duplication of any amount paid or deposited
pursuant to sub-clause (2) or (3);
o the rescission would not conflict with any judgment or decree
of a court of competent jurisdiction; and
o all Events of Default, other than the nonpayment of principal
of, premium, if any, on or interest on the exchange notes that
has become due solely by such declaration of acceleration,
have been cured or waived. (Section 5.2)
No holder of the exchange notes will have any right to institute any
proceeding with respect to the indenture or any remedy thereunder, unless
o such holder has notified the trustee or a continuing Event of
Default,
o the holders of at least 25% in aggregate principal amount of
the outstanding exchange notes have made written request, and
offered reasonable indemnity, to the trustee to institute such
proceeding,
o the trustee has failed to institute such proceeding within 60
days after receipt of such notice, and
o the trustee, within such 60-day period, has not received
directions inconsistent with such written request by holders
of a majority in aggregate principal amount of the outstanding
exchange notes. (Section 5.7)
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Such limitations will not apply, however, to a suit instituted by a holder of a
exchange note for the enforcement of the payment of the principal of, premium or
interest on a exchange note on or after the respective due dates expressed in
the exchange note. (Section 5.8)
During the existence of an Event of Default, the trustee will be
required to exercise the rights and powers vested in it under the indenture and
use the same degree of care and skill in its exercise thereof as a prudent
person would exercise under the circumstances in the conduct of such person's
own affairs. Subject to the provisions of the indenture relating to the duties
of the trustee in case an Event of Default shall occur and be continuing, the
trustee will not be under any obligation to exercise any of its rights or powers
under the indenture at the request or direction of any of the holders of
exchange notes unless such holders shall have offered to the trustee reasonable
security or indemnity. (Sections 6.1 and 6.2) Subject to certain provisions
concerning the rights of the trustee, the holders of a majority in aggregate
principal amount of the outstanding exchange notes will have the right to direct
the time, method and place of conducting any proceeding for any remedy available
to the trustee, or exercising any trust or power conferred on the trustee under
the indenture. (Section 5.12)
If a Default occurs and is continuing and is known to the trustee, the
trustee shall mail to each holder of exchange notes notice of the Default within
60 days after the occurrence thereof. Except in the case of a Default in payment
of principal of, premium on or interest on any exchange notes, the trustee may
withhold the notice to the holders of exchange notes if the trustee determines
in good faith that withholding the notice is in the interest of such holders.
(Section 6.13)
We will be required to deliver to the trustee annual and quarterly
statements regarding compliance with the indenture. We also will be required,
upon becoming aware of any Default or Event of Default, to deliver to the
trustee a statement specifying such Default or Event of Default. (Section 10.8)
LEGAL DEFEASANCE AND COVENANT DEFEASANCE
Legal Defeasance
As long as we take steps to make sure that you receive all of your
payments under the exchange notes and are able to transfer the exchange notes,
we can elect to legally release ourselves and any of our Subsidiaries that may
guarantee the exchange notes from any obligations on the exchange notes (called
"legal defeasance") other than:
o the, rights of holders of outstanding notes to receive
payments in respect of the principal of, premium on and
interest on the exchange notes when these payments are due;
o our obligation to replace any temporary exchange notes,
register the transfer or exchange of any exchange notes,
replace mutilated, lost or stolen exchange notes, compensate
and reimburse the trustee, remove and appoint a successor
trustee, maintain an office or agency for payments in respect
of the notes and qualify the indenture under the Trust
Indenture Act;
o the rights, powers, trusts, duties and immunities of the
trustee, and
o the legal defeasance provisions of the indenture. (Section
12.2)
In order to accomplish legal defeasance, the following must occur:
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o We or any Subsidiary Guarantor must irrevocably deposit with
the trustee cash and/or U.S. government and/or U.S. government
agency securities that will generate enough cash to make
interest, principal and any other payments on the exchange
notes on their various due dates.
o Such defeasance shall not cause the trustee to have a conflict
of interest.
o There must be a change in current U.S. federal tax law or an
IRS ruling that lets us make that deposit without causing you
to be taxed on the exchange notes any differently than if we
did not make the deposit and just repaid the exchange notes
ourselves. Under current U.S. federal tax law, the deposit and
our legal defeasance from the notes would be treated as though
we took back your notes and gave you your share of the cash
and/or securities deposited in trust. In that event, you could
recognize gain or loss on the notes you give back to us.
o We must deliver to the trustee a legal opinion of our counsel
confirming the tax law change described above and that all of
the conditions to legal defeasance in the indenture have been
fulfilled.
We will not be able to achieve legal defeasance if there is a
continuing Default or Event of Default under the indenture or if doing so would
violate any other material agreement to which we are a party. (Section 12.4) If
we ever did accomplish legal defeasance as described above, you would have to
rely solely on the trust deposit for repayment of the exchange notes. You could
not look to us for repayment in the unlikely event of any shortfall.
Covenant Defeasance
Under current federal tax law, we can make the same type of deposit
described above and be released from covenants relating to the exchange notes.
The release from these covenants is called covenant defeasance. In that event,
you would lose the protection of these covenants but would gain the protection
of having money and/or securities set aside in trust to repay the exchange
notes. In order to achieve covenant defeasance, we must:
o Deposit in trust for the benefit of the holders of exchange
notes cash and/or U.S. government or U.S. government agency
securities that will generate enough cash to make interest,
principal and any other payments on the exchange notes on
their various due dates.
o Deliver to the trustee a legal opinion of our counsel
confirming that under current U.S. federal tax law we may make
that deposit without causing you to be taxed on the exchange
notes any differently than if we did not make the deposit and
just repaid the exchange notes ourselves. The opinion also
must state that all of the conditions to covenant defeasance
in the indenture have been fulfilled.
Further, such defeasance shall not cause the trustee to have a conflict of
interest.
We will not be able to achieve covenant defeasance if there is a
continuing Default or Event of Default under the indenture or if doing so would
violate any other material agreements to which we are a party. The indenture
describes the covenants we may fail to comply with without causing an Event of
Default if we accomplish covenant defeasance. (Sections 12.3 and 12.4)
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If we elect to make a deposit resulting in covenant defeasance, the
amount of money and/or U.S. government or U.S. government agency securities
deposited in trust would be sufficient to pay amounts due on the notes at the
time of their maturity. However, if the maturity of the exchange notes is
accelerated due to the occurrence of an Event of Default, the amount in trust
may not be sufficient to pay all amounts due on the notes. We would remain
liable for the shortfall as described in the indenture.
SATISFACTION AND DISCHARGE OF THE INDENTURE
We will have no further obligations under the indenture as to all
outstanding exchange notes, other than surviving rights of registration of
transfers of the exchange notes, when:
o all exchange notes have been delivered to the trustee for
cancellation, except lost, stolen or destroyed exchange notes
that we have replaced or paid or exchange notes for which we
have deposited in trust money and/or U.S. government
obligations; or all exchange notes have become due and payable
or, within one year, will become due and payable or be
redeemed and we have deposited with the trustee funds
sufficient to pay interest, principal and any other payments
on all outstanding exchange notes on their various due dates;
o we have paid all other sums then due and payable under the
indenture by us; and
o we have delivered to the trustee an officers' certificate and
an opinion of counsel, which, taken together, state that we
have complied with all conditions precedent under the
indenture relating to the satisfaction and discharge of the
indenture. (Section 4.1)
AMENDMENT AND WAIVER
We generally may amend the indenture with the written consent of the
holders of at least a majority in aggregate principal amount of the outstanding
exchange notes. The holders of at least a majority in aggregate principal amount
also may waive our compliance with most covenants. (Section 10.20) We must,
however, obtain the consent of each holder of exchange notes affected by an
amendment or waiver which does any of the following.
o reduces the principal amount of exchange notes that must
consent to an amendment or waiver;
o reduces the principal of or changes the Stated Maturity of any
exchange note or alter the provisions with respect to the
redemption of the exchange notes, other than provisions
relating to the covenants described above under the caption
"--Repurchase at the Option of Holders";
o reduces the rate of or changes the time for payment of
interest on any exchange note;
o waives a Default or Event of Default in the payment of
principal of, premium, if any, on or interest on the exchange
notes, except a rescission of acceleration of the exchange
notes by the holders of at least a majority in aggregate
principal amount of the exchange notes and a waiver of the
payment default that resulted from such acceleration;
o makes any exchange note payable in money other than that
stated in the exchange notes;
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o makes any change in the provisions of the indenture relating
to waivers of past Defaults or the rights of holders of
exchange notes to receive payments of principal of, premium,
if any, on or interest on the exchange notes;
o waives a redemption payment with respect to any exchange note,
other than a payment required by one of the covenants
described above under the caption "--Repurchase at the Option
of Holders";
o reduces the relative ranking of the exchange notes or any
Subsidiary Guarantees; or
o makes any change in the foregoing amendment and waiver
provisions. (Section 9.2)
In addition, without the consent of any holder of exchange notes we and
the trustee may amend the indenture:
o to cure any ambiguity, defect or inconsistency;
o to add or release any Subsidiary Guarantor pursuant to the
terms of the indenture;
o to provide for uncertificated exchange notes in addition to or
in place of certificated exchange notes;
o to provide for the assumption of our obligations to holders of
exchange notes in the case of a merger or consolidation;
o to make any change that would provide any additional rights or
benefits to the holders of exchange notes;
o to add any additional Events of Default;
o to appoint a successor trustee;
o to secure the exchange notes; or
o to comply with requirements of the SEC in order to effect or
maintain the qualification of the indenture under the Trust
Indenture Act. (Section 9.1)
We may not change the indenture in a manner that would adversely affect
the rights of the holders of Senior Indebtedness under the subordination
provisions described under "--Subordination" or the holders of Guarantor Senior
Indebtedness under the subordination provisions described under "--Subsidiary
Guarantees of Notes," unless we obtain the consent of such holders that are
required to consent to such change pursuant to the agreements evidencing such
Senior Indebtedness or Guarantor Senior Indebtedness. (Section 9.8)
CONCERNING THE TRUSTEE
State Street Bank and Trust Company will serve as trustee under the
indenture. State Street Bank and Trust Company currently serves as trustee under
the indentures for the existing notes, our 9-1/2% Senior Subordinated Notes due
2006 and our 8-7/8% Senior Subordinated Notes due 2008. Such bank also maintains
normal banking relationships with us and may perform services for and transact
other business with us from time to time in the ordinary course of business.
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The indenture and the provisions of the Trust Indenture Act
incorporated by reference into the indenture will contain limitations on the
rights of the trustee, should it become a creditor of ours, to obtain payment of
claims or to realize on certain property received by it in respect of any such
claims, as security or otherwise. The indenture will permit the trustee to
engage in other transactions. If the trustee acquires any conflicting interest
as defined in the Trust Indenture Act it must eliminate such conflict or resign.
(Sections 6.8 and 6.9)
GOVERNING LAW
The Indenture, the exchange notes and any Subsidiary Guarantees will be
governed by the laws of the State of New York. (Section 15.10)
BOOK-ENTRY, DELIVERY AND FORM
The existing notes were, and any exchange notes issued in exchange for
existing notes tendered pursuant to The Depository Trust Company's Automated
Tender Offer Program will be, issued in the form of one or more fully registered
global certificates. Each global certificate will be deposited with the trustee
who will hold the global certificate for The Depository Trust Company ("DTC").
Each global certificate will be registered in the name of DTC or its nominee.
Except as set forth below, a global certificate may be transferred, in
whole and not in part, only to another nominee of DTC or to a successor of DTC
or its nominee. (Section 3.6)
DTC has advised us as follows: It is a limited-purpose trust company
which was created to hold securities for its participating organizations and to
facilitate the clearance and settlement of transactions in such securities
between its participants through electronic book-entry changes in accounts of
its participants. Participants include securities brokers and dealers, banks,
trust companies, clearing corporations and certain other organizations. Access
to DTC's book-entry system is also available to others, such as banks, brokers,
dealers and trust companies that clear through or maintain a custodial
relationship with a participant, either directly or indirectly. Persons who are
not participants may beneficially own securities held by DTC only through
participants or indirect participants.
DTC has also advised that pursuant to procedures established by it:
o upon our issuance of the exchange notes, DTC will credit the
accounts of participants designated by the exchange agent with the
principal amount of the exchange notes exchanged for existing
notes, and
o ownership of beneficial interests in any global certificate will
be shown on, and the transfer of that ownership will be effected
only through, records maintained by DTC, with respect to
participants' interests, the participants and the indirect
participants.
The laws of some states require that certain persons take physical
delivery in definitive form of securities which they own. Consequently, the
ability to transfer beneficial interests in a global certificate is limited to
such extent.
So long as DTC or its nominee is the registered owner of a global
certificate, DTC or such nominee will be considered the sole owner or holder of
the exchange notes for all purposes under the indenture. Except as provided
below, owners of beneficial interests in a global certificate will not be
entitled to have exchange notes registered in their names, will not receive or
be entitled to receive
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physical delivery of exchange notes in definitive form and will not be
considered the owners or holders thereof under the indenture. (Section 3.6)
Neither us, the trustee, the paying agent nor the registrar of the
exchange notes will have any responsibility or liability for any aspect of the
records relating to or payments made on account of beneficial ownership
interests in a global certificate, or for maintaining, supervising or reviewing
any records relating to such beneficial ownership interests.
Principal and interest payments on a global certificate registered in
the name of DTC or its nominee will be made by us, either directly or through a
paying agent, to DTC or its nominee as the registered owner of such global
certificate. Under the terms of the indenture, we and the trustee will treat the
persons in whose names the exchange notes are registered as the owners of those
notes for the purpose of receiving payments of principal and interest on those
notes and for all other purposes whatsoever, (Section 3.8) Therefore, neither
us, the trustee nor any paying agent has any direct responsibility or liability
for the payment of principal or interest on the exchange notes to owners of
beneficial interests in a global certificate. DTC has advised us and the trustee
that its present practice is, upon receipt of any payment of principal or
interest to credit immediately the accounts of the participants with payment in
amounts proportionate to their respective holdings in principal amount of
beneficial interests in a global certificate as shown on the records of DTC.
Payments by participants and indirect participants to owners of beneficial
interests in a global certificate will be governed by standing instructions and
customary practices, as is now the cast with securities held for the accounts of
customers in bearer form or registered in "street name" and will be the
responsibility of such participants or indirect participants.
As long as the exchange notes are represented by a global certificate,
DTC's nominee will be the holder of the exchange notes and therefore will be the
only entity that can exercise a right to repayment or repurchase of the exchange
notes. See "--Repurchase at the Option of Holders--Change of Control" and
"--Asset Sales." Notice by participants or indirect participants or by owners of
beneficial interests in a global certificate held through such participants or
indirect participants of the exercise of the option to elect repayment of
beneficial interests in exchange notes represented by a global certificate must
be transmitted to DTC in accordance with its procedures on a form required by
DTC and provided to participants. In order to ensure that DTC's nominee will
timely exercise a right to repayment with respect to a particular exchange note,
the beneficial owner of such exchange note must instruct the broker or other
participant or indirect participant through which it holds an interest in such
exchange note to notify DTC of its desire to exercise a right to repayment.
Different firms have different cut-off times for accepting instructions from
their customers and, accordingly, each beneficial owner should consult the
broker or other participant or indirect participant through which it holds an
interest in a exchange note in order to ascertain the cutoff time by which such
an instruction must be given in order for timely notice to be delivered to DTC.
We will not be liable -for any delay in delivery of notices of the
exercise of the option to elect repayment.
CERTIFICATED NOTES
We will issue exchange notes in definitive form in exchange for a
global certificate if, and only if, either:
o DTC is at any time unwilling or unable to continue as depositary
and a successor depositary is not appointed by us within 90 days;
or
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o an Event of Default has occurred and is continuing and the
exchange notes registrar has received a request from DTC to issue
exchange notes in definitive form in lieu of all or a portion of
such global certificate.
In either instance, an owner of a beneficial interest in a global certificate
will be entitled to have exchange notes equal in principal amount to such
beneficial interest registered in its name and will be entitled to physical
delivery of such exchange notes in definitive form. Exchange notes so issued in
definitive form will be issued in denomination of $10 and integral multiples
thereof and will be issued in registered form only, without coupons. (Section
3.6)
MATERIAL DEFINITIONS
Set forth below are definitions of some of the terms used in the
indenture which we believe are material to an understanding of the indenture.
"Acquired Indebtedness" means Indebtedness of a Person:
o assumed in connection with an acquisition of properties or assets
from such Person; or
o outstanding at the time such Person becomes a Subsidiary of any
other Person.
Acquired Indebtedness does not include Indebtedness incurred in
connection with, or in contemplation of, such acquisition or such Person
becoming a Subsidiary. Acquired Indebtedness shall be deemed to be incurred on
the date of the related acquisition of properties or assets from any Person or
the date the acquired Person becomes a Subsidiary.
"Adjusted Consolidated Net Tangible Assets" means, without duplication,
as of the date of determination, the sum of:
o Discounted future net cash flows from our and our Restricted
Subsidiaries' proved oil and gas reserves calculated in
accordance with SEC guidelines but before any state or federal
income taxes, as estimated by a nationally recognized firm of
independent petroleum engineers in a reserve report prepared as
of the end of our most recently completed fiscal year. Discounted
future net cash flows will be increased pursuant to clauses (1)
and (2) below and decreased pursuant to clauses (3) and (4)
below, as of the date of determination, by the estimated
discounted future net cash flows, calculated in accordance with
SEC guidelines but before any state or federal income taxes and
utilizing the prices utilized in such year-end reserve report,
from:
(1) estimated proved oil and gas reserves acquired since the
date of such year-end reserve report;
(2) estimated oil and gas reserves attributable to extensions,
discoveries and other additions and upward revisions of
estimates of proved oil and gas reserves since the date of
such year-end reserve report due to exploration,
development, exploitation, production or other activities;
(3) estimated proved oil and gas reserves produced or disposed
of since the date of such year-end reserve report; and
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(4) estimated oil and gas reserves attributable to downward
revisions of estimates of proved oil and gas reserves
since the date of such year-end reserve report due to
exploration, development, exploitation, production or
other activities.
In the case of each of the determinations made pursuant to clauses (1) through
(4) above, such increases and decreases shall be as estimated by our petroleum
engineers, except that in the event there is a Material Change as a result of
such acquisitions, dispositions, or revisions, then the discounted future net
cash flows utilized for purposes of this clause shall be confirmed in writing by
a nationally recognized firm of independent petroleum engineers.
o The capitalized costs that are attributable to our and our
Restricted Subsidiaries' oil and gas properties to which no proved
oil and gas reserves are attributable, based on our books and
records as of a date no earlier than the date of our latest annual
or quarterly financial statements.
o The Net Working Capital on a date no earlier than the date of our
latest annual or quarterly financial statements.
o The greater of:
(1) the net book value on a date no earlier than the date of
our latest annual or quarterly financial statements, or
(2) the appraised value, as estimated by independent
appraisers, of our or our Restricted Subsidiaries' other
tangible assets, including, without duplication,
Investments in unconsolidated Restricted Subsidiaries, as
of the date no earlier than the date of our latest audited
financial statements.
Minus the sum of:
o Minority interests, other than a minority interest in a Finance
Person.
o Any of our or our Restricted Subsidiaries' net gas balancing
liabilities reflected in our latest audited financial statements.
o To the extent included in the first clause of this definition, the
discounted future net cash flows, calculated in accordance with
SEC guidelines but before any state or federal income taxes and
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 our and our Restricted
Subsidiaries' obligations with respect to Volumetric Production
Payments on the schedules specified with respect thereto.
o The discounted future net cash flows, calculated in accordance
with SEC guidelines but before any state or federal income taxes,
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 not
revenues specified in the first clause of this definition, would
be necessary to fully satisfy our and our Restricted Subsidiaries'
payment obligations with respect to Dollar-Denominated Production
Payments on the schedules specified with respect thereto.
"Adjusted Net Assets" of a Subsidiary Guarantor at any date means the
amount by which the fair value of the properties and assets of such Subsidiary
Guarantor exceeds the total amount of
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liabilities, including, without limitation, contingent liabilities, after giving
effect to all other fixed and contingent liabilities incurred or assumed on such
date, but excluding liabilities under its Subsidiary Guarantee, of such
Subsidiary Guarantor at such date.
"Affiliate" of any specified Person means:
o any other Person directly or indirectly controlling or controlled
by or under direct or indirect common control with such specified
Person; or
o any other Person who is a director or executive officer of:
(1) such specified Person; or
(2) 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", as used with respect to
any Person, shall mean the possession, directly or indirectly, of the power to
direct or cause the direction of the management or policies of such Person,
whether through the ownership of voting securities, by agreement or otherwise;
provided that beneficial ownership of 10% or more of the Voting Stock of a
Person shall be deemed to be control.
"Asset Sale" means any sale, issuance, conveyance, transfer, lease or
other disposition to any Person other than us or any of our Restricted
Subsidiaries, including, without limitation, by way of merger or consolidation,
(collectively, for purposes or this definition, a "transfer"), directly or
indirectly, in one or a series of related transactions, of:
o any Capital Stock of any Restricted Subsidiary held by us or any
Restricted Subsidiary, other than directors' qualifying shares and
shares owned by foreign shareholders to the extent required by
applicable local laws in the foreign countries;
o all or substantially all of our or any of our Restricted
Subsidiaries' properties and assets; or
o any other of our or any of our Restricted Subsidiaries' properties
or assets other than:
(1) a disposition of hydrocarbons or other mineral products,
inventory, accounts receivable, cash, Cash Equivalents or
other property in the ordinary course of business;
(2) any lease, abandonment, disposition, relinquishment or
farm-out of any oil and gas property in the ordinary
course of business;
(3) the liquidation of property or assets received in
settlement of debts owing to us or any Restricted
Subsidiary as a result of foreclosure, perfection or
enforcement of any Lien or debt, which debts were owing to
us or any Restricted Subsidiary in the ordinary course of
our or such Restricted Subsidiary's business; or
(4) the issuance and sale of Qualified Capital Stock by a
Finance Person.
For the purposes of this definition, the term "Asset Sale" shall not
include:
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o any transfer of properties or assets that is governed by, and made
in accordance with, the provisions described under "--Material
Covenants--Merger, Consolidation or Sale of Assets";
o any transfer of properties or assets to an Unrestricted
Subsidiary, if permitted under the "Restricted Payments" covenant
of the indenture; or
o any transfer, in one or a series of related transactions, of
properties or assets having a fair market value of less than
$2,500,000.
"Average Life" means, with respect to any Indebtedness, as at any date
of determination, the quotient obtained by dividing:
o The sum of the products of:
(1) the number of years, and any portion thereof, from the
date of determination to the date or dates of each
successive scheduled principal payment, including, without
limitation, any sinking fund or mandatory redemption
payment requirements, of such Indebtedness, multiplied by
(2) the amount of each such principal payment; by
o the sum of all such principal payments.
"Capital Stock" means, with respect to any Person, any and all shares,
interests, participations, rights in or other equivalents in the equity
interests, however designated, in such Person, and any rights other than debt
securities convertible into an equity interest, warrants or options exercisable
for, exchangeable for or convertible into such an equity interest in such
Person. Our Capital Stock includes any Qualifying TECONS and any Eligible
Convertible Securities.
"Capitalized Lease Obligation" means any obligation to pay rent or
other amounts under a lease of or other agreement conveying the right to use any
property, whether real, personal or mixed, that is required to be classified and
accounted for as a capital lease obligation under GAAP, and, for the purpose of
the indenture, the amount of such obligation at any date shall be the
capitalized amount thereof at such date, determined in accordance with GAAP.
"Cash Equivalents" means:
o any evidence of Indebtedness with a maturity of 180 days or less
issued or directly and fully guaranteed or insured by the United
States of America or any agency or instrumentality thereof,
provided that the full faith and credit of the United States of
America is pledged in support thereof;
o demand and time deposits and certificates of deposit or
acceptances with a maturity of 180 days or less of any financial
institution that is a member of the Federal Reserve System having
combined capital and surplus and undivided profits of not less
than $500,000,000;
o commercial paper with a maturity of 180 days or less issued by a
corporation that is not an Affiliate of us and is organized under
the laws of any state of the United States or the District or
Columbia and rated at least A-1 by S&P or at least P-1 by Moody's;
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o repurchase obligations with a term of not more than seven days for
underlying securities of the types described in the first clause
above entered into with any commercial bank meeting the
specifications of the second clause above;
o overnight bank deposits and bankers' acceptances at any commercial
bank meeting the qualifications specified in the second clause
above;
o deposits available for withdrawal on demand with any commercial
bank not meeting the qualifications specified in the second clause
above but which is organized under the laws of any country in
which we or any Restricted Subsidiary maintains an office or is
engaged in the Oil and Gas Business, provided that:
(1) all such deposits am required to be made in such accounts
in the ordinary course of business,
(2) such deposits do not at any one time exceed $5,000,000 in
the aggregate, and
(3) no funds so deposited remain on deposit in such bank for
more than 30 days;
o deposits available for withdrawal on demand with any commercial
bank not meeting the qualifications specified in the second clause
above but which is a lending bank under any of our or any
Restricted Subsidiary's credit facilities, provided all such
deposits do not exceed $5,000,000 in the aggregate at any one
time; and
o investments in money market funds substantially all of whose
assets comprise securities of the types described in any of the
first five clauses above.
"Change of Control" means the occurrence of any of the following
events:
o any "person" or "group" (as such terms are used in Sections 13(d)
and 14(d) of the Exchange Act) is or becomes the "beneficial
owner" (as defined in Rule 13d-3 under the Exchange Act), directly
or indirectly, of more than 50% of our total Voting Stock;
o we are merged with or into or consolidated with another Person
and, immediately after giving effect to the merger or
consolidation:
(1) less than 50% of the total voting power of the outstanding
Voting Stock of the surviving or resulting Person is then
"beneficially owned" (within the meaning of Rule 13d-3
under the Exchange Act) in the aggregate by our
stockholders immediately prior to such merger or
consolidation, and
(2) any "person" or "group" (as defined in Section 13(d)(3)
or 14(d)(2) of the Exchange Act) has become the direct or
indirect "beneficial owner" (as defined in Rule 13d-3
under the Exchange Act) of more than 50% of the total
voting power of the Voting Stock of the surviving or
resulting Person;
o we, either individually or in conjunction with one or more
Restricted Subsidiaries, sell, assign, convey, transfer, lease or
otherwise dispose of, or the Restricted Subsidiaries sell, assign,
convey, transfer, lease or otherwise dispose of, all or
substantially all of our and the Restricted Subsidiaries'
properties and assets, taken as a whole, either in one transaction
or a series of related transactions, including Capital Stock of
the Restricted Subsidiaries, to any Person other than us or a
Wholly Owned Restricted Subsidiary,
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o during any consecutive two-year period, individuals who at the
beginning of such period constituted our board of directors,
together with any new directors whose election by such board of
directors or whose nomination for election by our stockholders was
approved by a vote of a majority of the directors then still in
office who were either directors at the beginning of such period
or whose election or nomination for election was previously so
approved, cease for any reason to constitute a majority of our
board of directors then in office; or
o our liquidation or dissolution; or
o so long as any Existing Notes are outstanding, any other event
constituting a Change of Control pursuant to the Indentures for
the Existing Notes.
"Common Stock" of any Person means Capital Stock of such Person that
does not rank prior, as to the payment of dividends or as to the distribution of
assets upon any voluntary or involuntary liquidation, dissolution or winding up
of such Person, to shares of Capital Stock of any other class of such Person.
"Consolidated Exploration Expenses" means, for any period, our and our
Restricted Subsidiaries' exploration expenses for such period as determined on a
consolidated basis in accordance with GAAP.
"Consolidated Fixed Charge Coverage Ratio" means, for any period, the
ratio of:
o the sum of our and our Restricted Subsidiaries' Consolidated Net
Income, Consolidated Interest Expense, the portion of Consolidated
Exploration Expenses deducted in computing Consolidated Net
Income, Consolidated Income Tax Expense and Consolidated Non-cash
Charges deducted in computing Consolidated Net Income, in each
case, for such period, on a consolidated basis, all determined in
accordance with GAAP, decreased, to the extent included in
determining Consolidated Net Income, by the sum of:
(1) the amount of deferred revenues that are amortized during
such period and are attributable to reserves that are
subject to Volumetric Production Payments, and
(2) amounts recorded in accordance with GAAP as repayments of
principal and interest pursuant to Dollar-Denominated
Production Payments; to
o the sum of such Consolidated Interest Expense for such period.
Provided, however, that
o the Consolidated Fixed Charge Coverage Ratio shall be calculated on
the assumption that:
(1) the Indebtedness to be incurred and all other Indebtedness
incurred after the first day of the relevant period of
fiscal quarters under the covenant described under
"--Material Covenants--Incurrence of Indebtedness" through
and including the date of determination and, if
applicable, the application of the net proceeds therefrom,
and from any other such Indebtedness, including to
refinance other Indebtedness, had been incurred on the
first day of, such period and, in the case of Acquired
Indebtedness, on the assumption that the related
transaction, whether by means of purchase merger or
otherwise, also had
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occurred on such date with the appropriate adjustments
with respect to such acquisition being included in such
pro forma calculation, and
(2) any acquisition or disposition by us or any Restricted
Subsidiary of any properties or assets outside the
ordinary course of business, or any repayment of any
principal amount of any of our or any Restricted
Subsidiary's Indebtedness prior to the Stated Maturity
thereof, in either case since the first day of such period
through and including the date of determination, had been
consummated on such first day of such period;
o in making such computation, the Consolidated Interest Expense
attributable to interest on any Indebtedness required to be
computed on a pro forma basis in accordance with the covenant
described under "--Material Covenants--Incurrence of Indebtedness"
and:
(1) bearing a floating interest rate shall be computed as if
the rate in effect on the date of computation had been the
applicable rate for the entire period, and
(2) which was not outstanding during the period for which the
computation is being made but which bears, at our option,
a fixed or floating rate of interest, shall be computed by
applying, at our option, either the fixed or floating
rate;
o in making such computation, the Consolidated Interest Expense
attributable to interest on any Indebtedness under a revolving
credit facility required to be computed on a pro forma basis in
accordance with the covenant described under "--Material
Covenants--Incurrence of Indebtedness" shall be computed based
upon the average daily balance of such Indebtedness during the
applicable period, provided that such average daily balance shall
be reduced by the amount of any repayment of Indebtedness under a
revolving credit facility during the applicable period, which
repayment permanently reduced the commitments or amounts available
to be reborrowed under such facility,
o notwithstanding the second and third clauses of this proviso,
interest on Indebtedness determined on a fluctuating basis, to the
extent such interest is covered by agreements relating to Interest
Rate Protection Obligations, shall be deemed to have accrued at
the rate per annum resulting after giving effect to the operation
of such agreements;
o in making such calculation, Consolidated Interest Expense shall
exclude interest attributable to Dollar-Denominated Production
Payments; and
o if after the first day of the period referred to in the first
clause of this definition, we have retired any Indebtedness out of
the net cash proceeds of the issue and sale of our Qualified
Capital Stock within 30 days of such issuance and sale,
Consolidated Interest Expense shall be calculated on a pro forma
basis as if such Indebtedness had been retired on the first day of
such period.
For the purpose of the covenant described under "--Material
Covenants--Incurrence of Indebtedness," if we incur Indebtedness, including
Acquired Indebtedness but excluding Permitted Indebtedness:
o on any date which is on or before March 31, 2000, we will
determine our Consolidated Fixed Charge Coverage Ratio for the
full fiscal quarter or quarters, as the case may be, commencing on
April 1, 1999 and ending on or prior to such date; and
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o on any date which is after March 31, 2000, we will determine our
Consolidated Fixed Charge Coverage Ratio for the four full fiscal
quarters immediately preceding such date.
"Consolidated Income Tax Expense" means, for any period, the provision
for our and our Restricted Subsidiaries' federal, state, local and foreign
income taxes, including any state franchise taxes accounted for as income taxes
in accordance with GAAP, for such period as determined on a consolidated basis
in accordance with GAAP.
"Consolidated Interest Expense" means, for any period, without
duplication, the sum of:
o our and our Restricted Subsidiaries' interest expense for such
period as determined on a consolidated basis in accordance with
GAAP, including, without limitation, to the extent attributable to
such period:
(1) any amortization of debt discount,
(2) the net cost under Interest Rate Protection Obligations,
including any amortization of discounts,
(3) the interest portion of any deferred payment obligation
constituting Indebtedness,
(4) all commissions, discounts and other fees and charges owed
with respect to letters of credit and bankers' acceptance
financing, and
(5) all accrued interest;
o to the extent any Indebtedness of any Person other than us or a
Restricted Subsidiary is guaranteed by us or any Restricted
Subsidiary, the aggregate amount of interest paid, to the extent
not accrued in a prior period, or accrued by such other Person
during such period attributable to any such Indebtedness, in each
case to the extent attributable to that period;
o the aggregate amount of the interest component of Capitalized
Lease Obligations paid, to the extent not accrued in a prior
period, accrued and/or scheduled to be paid or accrued by us and
our Restricted Subsidiaries during such period as determined on a
consolidated basis in accordance with GAAP; and
o the aggregate amount of dividends paid, to the extent not accrued
in a prior period, or accrued on our and our Restricted
Subsidiaries' Redeemable Capital Stock, to the extent such
Redeemable Capital Stock is owned by Persons other than us or our
Restricted Subsidiaries, and to the extent such dividends are not
paid in Common Stock.
The following shall not be included in the calculation of Consolidated
Interest Expense:
o Amortization of our and our Restricted Subsidiaries' capitalized
debt issuance costs during such period;
o fees and expenses associated with the exchange offer;
o dividends on Qualifying TECONS; and
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o non-cash interest on Eligible Convertible Securities.
"Consolidated Net Income" means, for any period, our and our Restricted
Subsidiaries' consolidated net income (or loss) for such period as determined in
accordance with GAAP, adjusted by excluding:
o net after-tax extraordinary gains or losses, less all fees and
expenses relating thereto;
o net after-tax gains or losses, less all fees and expenses relating
thereto, attributable to Asset Sales;
o the net income (or net loss) of any Person, other than us or any
of our Restricted Subsidiaries, in which we or any of our
Restricted Subsidiaries has an ownership interest, except to the
extent of the amount of dividends or other distributions or
interest on indebtedness actually paid to us or any of our
Restricted Subsidiaries in cash by such other Person during such
period, regardless of whether such cash dividends, distributions
or interest on indebtedness is attributable to net income (or net
loss) of such Person during such period or during any prior
period;
o net income (or net loss) of any Person combined with us of any of
our Restricted Subsidiaries on a "pooling of interests" basis
attributable to any period prior to the date of combination;
o the net income of any Restricted Subsidiary to the extent that the
declaration or payment of dividends or similar distributions by
that Restricted Subsidiary is not at the date of determination
permitted, directly or indirectly, by operation of the terms of
its charter or any agreement, instrument, judgment, decree, order,
statute, rule or governmental regulation applicable to that
Restricted Subsidiary or its stockholders;
o fees and expenses associated with the exchange offer, to the
extent deducted in determining consolidated net income (or loss);
o dividends paid on Qualifying TECONS;
o non-cash interest on Eligible Convertible Securities, to the
extent deducted in determining consolidated net income (or loss);
o Consolidated Exploration Expenses and any writedowns or
impairments of noncurrent assets less an amount equal to the
amortization on a quarterly basis of the cumulative Consolidated
Exploration Expenses and writedowns or impairments of non-current
assets, calculated as two and one-half percent of the cumulative
net balance of such costs; and
o for purposes of calculating the Consolidated Fixed Charge Coverage
Ratio with respect to periods ending on or prior to March 31,
2000, net gains or losses on oil and natural gas price hedging
arrangements during such periods.
"Consolidated Net Worth" means, at any date, our and our Restricted
Subsidiaries' consolidated stockholders' equity less the amount of such
stockholders' equity attributable to our and our Restricted Subsidiaries'
Redeemable Capital Stock or treasury stock, as determined in accordance with
GAAP.
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"Consolidated Non-Cash Charges" means, for any period, our and our
Restricted Subsidiaries' aggregate depreciation, depletion, amortization and
other non-cash expenses reducing Consolidated Net Income for such period,
determined on a consolidated basis in accordance with GAAP, excluding any such
non-cash charge to the extent required as an accrual of or reserve for cash
charges for any future period.
"Credit Facility" means that certain Second Restated Credit Agreement
among us, certain of our Subsidiaries, Bank of America, N.A., as Administrative
Agent, Morgan Guaranty Trust Company of New York, as Documentation Agent, and
certain lenders named therein, as the same may be amended, modified,
supplemented, extended, restated, replaced, renewed or refinanced from time to
time.
"Default" means any event that is or with the passage or time or the
giving of notice or both would be an Event of Default.
"Disinterested Director" means, with respect to any transaction or
series of transactions in respect of which our board of directors is required to
deliver a resolution of the board of directors under the indenture, a member of
our board of directors who does not have any material direct or indirect
financial interest other than an interest arising solely from the beneficial
ownership of our Capital Stock in or with respect to such transaction or series
of transactions.
"Dollar-Denominated Production Payments" means production payment
obligations recorded as liabilities in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"Eligible Convertible Securities" means any security issued by us that:
o is subordinated in right of payment to the exchange notes,
o has a final Stated Maturity at least 91 days after the final
Stated Maturity of the exchange notes, and
o by its terms or by the terms of any security into which it is
convertible or by contract or otherwise requires no scheduled
payments, including principal, premium, interest and fees, prior
to its final Stated Maturity, other than payments payable only in
shares of our Common Stock or in options, warrants or other rights
to purchase our Common Stock.
"Equity Offering" means a bona fide underwritten sale to the public of
our Common Stock pursuant to a registration statement, other than on Form S-8 or
any other form relating to securities issuable under any employee benefit plan
of ours, that is declared effective by the SEC following the Issue Date.
"Event of Default" has the meaning set forth above under the caption
"--Events of Default and Remedies."
"Exchange Act" means the Securities Exchange Act of 1934, as amended
from time to time, and any successor act thereto.
"Exchanged Properties" means properties or assets used or useful in the
Oil and Gas Business received by us or a Restricted Subsidiary, whether directly
or indirectly through the acquisition of the Capital Stock of a Person holding
such assets so that such Person becomes our
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Wholly Owned Restricted Subsidiary, in trade or as a portion of the total
consideration for such other properties or assets.
"Existing TECONS" means our Obligated Mandatorily Redeemable
Convertible Preferred Securities issued by Nuevo Financing I, a statutory
business trust wholly owned by us, on December 23, 1996, in an aggregate
liquidation amount of $115.0 million.
"Finance Person" means a Subsidiary of ours, the Common Stock of which
is owned by us, that does not engage In any activity other than:
o the holding of Subordinated Indebtedness with respect to which
payments of interest on such Subordinated Indebtedness can, at the
election of the issuer thereof, be deferred for one or more
payment periods;
o the issuance of Qualifying TECONS and Common Stock and/or debt
securities; and
o any activity necessary, incidental or related to the foregoing
"GAAP" means generally accepted accounting principles, consistently
applied, that are 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 may be approved by a significant
segment of the accounting profession of the United States of America, which were
effective as of June 8, 1998.
The term "guarantee" means, as applied to any obligation:
o a guarantee, other than by endorsement of negotiable instruments
or documents for collection in the ordinary course of business,
direct or indirect, in any manner, of any part or all of such
obligation; and
o an agreement, direct or indirect, contingent or otherwise, the
practical effect of which is to assure in any way the payment or
performance, or payment of damages in the event of
non-performance, of all or any part of such obligation, including,
without limiting the foregoing, the payment of amounts drawn down
by letters of credit;
A guarantee by any Person shall not include a contractual commitment by
one Person to invest in another Person provided that such Investment is
otherwise permitted by the indenture. When used as a verb, "guarantee" shall
have a corresponding meaning.
"Guarantor Senior Indebtedness" means the principal of, premium, if
any, on, interest on, including interest accruing after the filing of a petition
initiating any proceeding pursuant to any bankruptcy law, and other amounts due
on or in connection with, including any fees, premiums, expenses, including
costs of collection, and indemnities, any Indebtedness of a Subsidiary
Guarantor, whether outstanding on the date of the indenture or thereafter
created, incurred or assumed, unless, in the case of any particular
Indebtedness, the instrument creating or evidencing the same or pursuant to
which the same is outstanding expressly provides that such Indebtedness will be
pari passu with or subordinated in right of payment to its Subsidiary Guarantee.
Notwithstanding the foregoing, Guarantor Senior Indebtedness of a Subsidiary
Guarantor will not include:
o Indebtedness of such Subsidiary Guarantor evidenced by its
Subsidiary Guarantee;
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o Indebtedness of such Subsidiary Guarantor that is expressly pari
passu with its Subsidiary Guarantee or is expressly subordinated
in right of payment to any Guarantor Senior Indebtedness of such
Subsidiary Guarantor or its Subsidiary Guarantee;
o Indebtedness of such Subsidiary Guarantor to the extent incurred
in violation of the "Incurrence of Indebtedness" covenant of the
indenture;
o Indebtedness of such Subsidiary Guarantor to us or any of our
other Subsidiaries or to any Affiliate of us or any Subsidiary of
such Affiliate; and
o any Indebtedness which when incurred and without regard to any
election under Section 1111(b) of the Federal Bankruptcy Code is
without recourse to such Subsidiary Guarantor.
"Holder" means a Person in whose name an exchange note is registered in
the Note Register.
"Indebtedness" means, with respect to any Person, without duplication:
o all liabilities of such Person for borrowed money or for the
deferred purchase price of property or services, excluding any
trade accounts payable and other accrued current liabilities
incurred in the ordinary course of business, and all liabilities
of such Person incurred in connection with any letters of credit,
bankers' acceptances or other similar credit transactions or any
agreement to purchase, redeem, exchange, convert or otherwise
acquire for value any Capital Stock of such Person, or any
warrants, rights or options to acquire such Capital Stock
outstanding on the date of the indenture or thereafter, if, and to
the extent, any of the foregoing would appear as a liability upon
a balance sheet of such Person prepared in accordance with GAAP;
o all obligations of such Person evidenced by bonds, notes,
debentures or other similar instruments, if, and to the extent,
any of the foregoing would appear as a liability upon a balance
sheet of such Person prepared in accordance with GAAP;
o all Indebtedness of such Person created or arising under any
conditional sale or other title retention agreement with respect
to property acquired by such Person even if the rights and
remedies of the seller or lender under such agreement in the event
of default are limited to repossession or sale of such property,
but excluding trade accounts payable arising in the ordinary
course of business;
o all Capitalized Lease Obligations of such Person;
o all Indebtedness referred to in the preceding clauses of other
Persons and all dividends of other Persons, the payment of which
is secured by, or for which the holder of such Indebtedness has an
existing right to be secured by, any Lien upon property,
including, without limitation, accounts and contract rights, owned
by such Person, even though such Person has not assumed or become
liable for the payment of such Indebtedness (the amount of such
obligation being deemed to be the lesser of the value of such
property or asset or the amount of the obligation so secured);
o all guarantees by such Person of Indebtedness referred to in this
definition, including, with respect to any Production Payment, any
warranties or guaranties of production or payment by such Person
with respect to such Production Payment but excluding other
contractual obligations of such Person with respect to such
Production Payment;
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o all Redeemable Capital Stock of such Person valued at the greater
of its voluntary or involuntary maximum fixed repurchase price
plus accrued dividends; and
o all obligations of such Person under or in respect of currency
exchange contracts, oil or natural gas price hedging arrangements
and Interest Rate Protection Obligations.
Indebtedness shall not include either Eligible Convertible Securities
or Qualifying TECONS and Indebtedness, including guarantees thereof, relating to
Qualifying TECONS and held by a Finance Person; provided, however, Indebtedness
shall include Existing TECONS and, for purposes of the seventh clause under
"--Events of Default and Remedies" only, debt securities issued in connection
with Eligible Convertible Securities and debt securities issued in connection
with Qualifying TECONS shall be deemed to be Indebtedness. Subject to the sixth
clause of the first sentence of this definition, neither Dollar-Denominated
Production Payments nor Volumetric Production Payments shall be deemed to be
Indebtedness.
For purposes hereof, the "maximum fixed repurchase price" of any
Redeemable Capital Stock which does not have a fixed repurchase price shall be
calculated in accordance with the terms of such Redeemable Capital Stock as if
such Redeemable Capital Stock were purchased on any date on which Indebtedness
shall be required to be determined pursuant to the indenture, and if such price
is based upon, or measured by, the fair market value of such Redeemable Capital
Stock, such fair market value shall be determined in good faith by the board of
directors of the issuer of such Redeemable Capital Stock; provided, however,
that if such Redeemable Capital Stock is not at the date of determination
permitted or required to be repurchased, the "maximum fixed repurchase price"
shall be the book value of such Redeemable Capital Stock.
"Interest Rate Protection Obligations" means the obligations of any
Person pursuant to any arrangement with any other Person whereby, directly or
indirectly, such Person is entitled to receive from time to time periodic
payments calculated by applying either a floating or a fixed rate of interest on
a stated notional amount in exchange for periodic payments made by Such Person
calculated by applying a fixed or a floating rate of interest on the same
notional amount and shall include, without limitation, interest rate swaps,
caps, floors, collars and similar agreements or arrangements designed to protect
against or manage such Person's and any of its Subsidiaries' exposure to
fluctuations in interest rates.
"Investment" means, with respect to any Person, any direct or indirect
advance, loan, guarantee of Indebtedness or other extension of credit or capital
contribution by means of any transfer of cash or other property or assets to
others or any payment for property, assets or services for the account or use of
others, or any purchase or acquisition by such Person of any Capital Stock,
bonds, notes, debentures or other securities, including derivatives, or
evidences of Indebtedness issued by, any other Person. In addition, the fair
market value of the net assets of any Restricted Subsidiary at the time that
such Restricted Subsidiary is designated an Unrestricted Subsidiary shall be
deemed to be an "Investment" made by us in such Unrestricted Subsidiary at such
time, and the designation of any Unrestricted Subsidiary as a Restricted
Subsidiary shall result in a return of an "Investment" in an amount not to
exceed the lesser of (x) the book value of the Investments previously made in
such Unrestricted Subsidiary that were treated as Restricted Payments, and (y)
the fair market value of such Unrestricted Subsidiary. "Investments" shall
exclude:
o extensions of trade credit under a joint operating agreement or
otherwise in the ordinary course of business, workers'
compensation, utility, lease and similar deposits and prepaid
expenses made in the ordinary course of business;
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o Interest Rate Protection Obligations entered into in the ordinary
course of business or as required by any Permitted Indebtedness or
any other Indebtedness incurred in compliance with the "Incurrence
of Indebtedness" covenant, but only to the extent that the stated
aggregate notional amounts of such Interest Rate Protection
Obligations do not exceed 105% of the aggregate principal amount
of such Indebtedness to which such Interest Rate Protection
Obligations relate;
o bonds, notes, debentures or other securities received in
compliance with the "Asset Sales" covenant; and
o endorsements of negotiable instruments and documents for
collection in the ordinary course of business.
"Issue Date" means the date on which the exchange notes were first
issued under the indenture.
"Lien" means any mortgage, charge, pledge, statutory or other, lien,
security interest, hypothecation, assignment for security, claim, or preference
or priority or other encumbrance or similar agreement or preferential
arrangement of any kind or nature whatsoever, including, without limitation, any
agreement to give or grant a Lien or any lease, conditional sale or other title
retention agreement having substantially the same economic effect as any of the
foregoing, upon or with respect to any property of any kind. A Person shall be
deemed to own subject to a Lien any property which such Person has acquired or
holds subject to the interest of a vendor or lessor under any conditional sale
agreement, capital lease or other title retention agreement.
"Liquid Securities" means securities:
o of an issuer that is not an Affiliate of us; and
o that are publicly traded on the New York Stock Exchange, the
American Stock Exchange, the Toronto Stock Exchange, the
Australian Stock Exchange, the London Stock Exchange or the NASDAQ
National Market.
Securities meeting the requirements of the two preceding clauses shall
be treated as Liquid Securities from the date of receipt thereof until and only
until the earlier of:
o the date on which such securities, or securities exchangeable for,
or convertible into, such securities, are sold or exchanged for
cash or Cash Equivalents; and
o 180 days following the date of receipt of such securities.
If such securities, or securities exchangeable for, or convertible
into, such securities, are not sold or exchanged for cash or Cash Equivalents
within 180 days of receipt thereof, for purposes of determining whether the
transaction pursuant to which we or a Restricted Subsidiary received the
securities was in compliance with the provisions of the indenture described
under "--Repurchase at the Option or Holders--Asset Sales," such securities
shall be deemed not to have been Liquid Securities until 181 days following the
date of receipt of such securities.
"Material Change" means an increase or decrease, excluding changes that
result solely from changes in prices, of more than 30% during a fiscal quarter
in the estimated discounted future net cash flows from our and our Restricted
Subsidiaries' proved oil and gas reserves, calculated in accordance with the
first clause of the definition of Adjusted Consolidated Net Tangible Assets;
provided, however, that the following will be excluded from the calculation of
Material Change:
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o any acquisitions during the quarter of oil and gas reserves that
have been estimated by a nationally recognized firm of independent
petroleum engineers and on which a report or reports exist; and
o any disposition of properties held at the beginning of such
quarter that have been disposed of as provided in the covenant
described under the caption "--Repurchase at the Option of
Holders--Asset Sales."
"Material Subsidiary" means, at any particular time, as shown on our
and our Restricted Subsidiaries' consolidated financial statements for our most
recently completed fiscal year, any Restricted Subsidiary that, together with
its Subsidiaries:
o accounted for more than 5% of our and our Restricted Subsidiaries'
consolidated revenues for such fiscal year; or
o was the owner of more than 5% of our and our Restricted
Subsidiaries' consolidated assets at the end of such fiscal year.
"Maturity" means, with respect to any new note, the date on which any
principal of such exchange note becomes due and payable as provided therein or
in the indenture, whether at the Stated Maturity with respect to such principal
or by declaration of acceleration, call for redemption or purchase or otherwise.
"Moody's" means Moody's Investors Service, Inc. and its successors.
"Net Cash Proceeds" means, with respect to any Asset Sale, the proceeds
thereof in the form or cash or Cash Equivalents, including payments in respect
of deferred payment obligations when received in the form of cash or Cash
Equivalents except to the extent that such obligations are financed or sold with
recourse to us or any Restricted Subsidiary, net of:
o brokerage commissions and other fees and expenses, including fees
and expenses of legal counsel and investment banks related to such
Asset Sale,
o provisions for all taxes payable as a result of such Asset Sale;
o amounts required to be paid to any Person other than us or any
Restricted Subsidiary owning a beneficial interest in the assets
subject to the Asset Sale; and
o appropriate amounts to be provided by us or any Restricted
Subsidiary, as the case may be, as a reserve required in
accordance with GAAP consistently applied against any liabilities
associated with such Asset Sale and retained by us or any
Restricted Subsidiary, as the case may be, after such Asset Sale,
including, without limitation, pension and other post-employment
benefit liabilities, liabilities related to environmental matters
and liabilities under any indemnification obligations associated
with such Asset Sale, all as reflected in an Officers' Certificate
delivered to the trustee; provided, however, that any amounts
remaining after adjustments, revaluations or liquidations of such
reserves shall constitute Net Cash Proceeds.
"Net Working Capital" means, as set forth in our consolidated financial
statements prepared in accordance with GAAP:
o all of our and our Restricted Subsidiaries' current assets, less
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o all of our and our Restricted Subsidiaries' current liabilities,
except current liabilities included in Indebtedness.
"Non-payment Event of Default" means any event, other than a Payment
Event of Default, the occurrence of which, with or without notice or the passage
of time, entities one or more Persons to accelerate the maturity of any
Specified Senior Indebtedness.
"Non-Recourse Purchase Money Indebtedness" means:
o our and any Restricted Subsidiary's Indebtedness, other than
Capital Lease Obligations, incurred in connection with the
acquisition by us or such Restricted Subsidiary in the ordinary
course of business of fixed assets used in the Oil and Gas
Business, including office buildings and other real property used
by us or such Restricted Subsidiary in conducting our or its
operations; and
o any renewals and refinancings of such Indebtedness.
For Indebtedness described in the two preceding clauses to qualify as
Non-Recourse Purchase Money Indebtedness, the holders of such Indebtedness must
agree that they will look solely to the fixed assets so acquired which secure
such Indebtedness, subject to customary exceptions such as indemnifications for
environmental, title, fraud and other matters, and neither we nor any Restricted
Subsidiary may;
(1) be directly or indirectly liable for such Indebtedness; or
(2) provide credit support, including any undertaking, guarantee,
agreement or instrument that would constitute Indebtedness,
other than the grant of a Lien on such acquired fixed assets.
"Note Register" means the register maintained by or for us in which we
shall provide for the registration of the exchange notes and of transfer of the
notes.
"Oil and Gas Business" means:
o the acquisition, exploration, development, operation and
disposition of interests in oil, gas and other hydrocarbon
properties;
o the gathering, marketing, treating, processing, storage, selling
and transporting of any production from such interests or
properties;
o any business relating to or arising from exploration for or
development, production, treatment, processing, storage,
transportation or marketing of oil, gas and other minerals and
products produced in association therewith;
o any power generation and electrical transmission business in a
jurisdiction outside of North America where fuel required by such
business is supplied, directly or indirectly, from production
reserves substantially from blocks in which we or our Restricted
Subsidiaries participate; and
o any activity necessary, appropriate or incidental to the
activities described in the foregoing clauses of this definition.
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"OPIC Facility" means that certain Finance Agreement dated December 28,
1994, among The Nuevo Congo Company, The Congo Holding Company, and the Overseas
Private Investment Corporation, as such agreement may be amended, modified,
supplemented, extended, restated, replaced, renewed or refinanced from time to
time in one or more credit agreements, loan agreements, instruments or similar
agreements, as such may be further amended, modified, extended, restated,
replaced, renewed or refinanced.
"Pari Passu Indebtedness" means any of our Indebtedness that is pari
passu in right of payment to the exchange notes, including, without limitation,
the existing notes, our 8 7/8% Senior Subordinate Notes due 2008, Series B and
our 9 1/2% Senior Subordinate Notes due 2006.
"Payment Event of Default" means any default in the payment or required
prepayment of principal of, premium, if any, on or interest on any Specified
Senior Indebtedness when due, whether at final maturity, upon scheduled
installment, upon acceleration or otherwise.
"Permitted Indebtedness" means any of the following:
o Indebtedness under the Credit Facility in an aggregate principal
amount at any one time outstanding not to exceed the greater of:
(1) $400,000,000, less any amounts of principal of such
Indebtedness repaid using the Net Cash Proceeds of an
Asset Sale pursuant to the covenant described under
"--Repurchase at the Option of Holders--Asset Sales" and
any amounts of principal of such Indebtedness refinanced
pursuant to the tenth clause of this definition; or
(2) the borrowing base thereunder,
provided, both subclauses (1) and (2) shall include any guarantee of
any such Indebtedness and any fees, premiums, expenses, including costs
of collection, indemnities and other amounts payable in connection with
such Indebtedness;
o Indebtedness under the existing notes issued in the exchange offer
and any Subsidiary Guarantees relating thereto or to any exchange
notes;
o Indebtedness outstanding on June 8, 1998, including, without
limitation, the existing notes, our 8 7/8% Senior Subordinate
Notes due 2008, Series B and our 9 1/2% Senior Subordinate Notes
due 2006, and additional Indebtedness permitted to be incurred
pursuant to commitments existing under the OPIC Facility on June
8, 1998;
o our and our Restricted Subsidiaries' obligations pursuant to
Interest Rate Protection Obligations, but only to the extent that
the stated aggregate notional amounts of such obligations do not
exceed 105% of the aggregate principal amount of the Indebtedness
covered by such Interest Rate Protection Obligations; obligations
under currency exchange contracts entered into in the ordinary
course of business and hedging arrangements that we or a
Restricted Subsidiary enter into in the ordinary course of
business for the purpose of protecting our or its production
against fluctuations in oil or natural gas prices;
o our Indebtedness to a Wholly Owned Restricted Subsidiary or a
Finance Person and Indebtedness of a Restricted Subsidiary to us
or a Wholly Owned Restricted Subsidiary or a Finance Person;
provided, however, that upon any subsequent issuance or transfer
of
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any Capital Stock or any other event which results in any such
Wholly Owned Restricted Subsidiary ceasing to be a Wholly Owned
Restricted Subsidiary or such Finance Person ceasing to be a
Finance Person, as the case may be, any other subsequent transfer
of any such Indebtedness except to us or a Wholly Owned Restricted
Subsidiary or Finance Person, such Indebtedness shall be deemed,
in each case, to be incurred and shall be treated as an incurrence
for purposes of the "Incurrence of Indebtedness" covenant at the
time the Wholly Owned Restricted Subsidiary or Finance Person in
question ceased to be a Wholly Owned Restricted Subsidiary or
Finance Person, as the case may be;
o in-kind obligations relating to net gas balancing positions
arising in the ordinary course of business and consistent with
past practice;
o Indebtedness in respect of bid, performance or surety bonds issued
for our or any Restricted Subsidiary's account in the ordinary
course of business, including guaranties and letters of credit
supporting such bid, performance or surety obligations, in each
case other than for an obligation for money borrowed;
o any guarantee of Senior Indebtedness or Guarantor Senior
Indebtedness, incurred in compliance with the "Incurrence of
Indebtedness" covenant, by us or a Restricted Subsidiary;
o Non-Recourse Purchase Money Indebtedness,
o any renewals substitutions, exchanges, refinancings or
replacements (each, for purposes of this clause, a "refinancing")
by us or a Restricted Subsidiary of any Indebtedness incurred
pursuant to the provisions of the "Incurrence of Indebtedness"
covenant or pursuant to clause one, two or three of this
definition, including any successive refinancings by us or such
Restricted Subsidiary, so long as:
(1) any such new Indebtedness shall be in a principal amount
that does not exceed the principal amount, or, if such
Indebtedness being refinanced provides for an amount less
than the principal amount thereof to be due and payable
upon a declaration of acceleration thereof, such lesser
amount as of the date of determination, so refinanced plus
the amount of any premium required to be paid in
connection with such refinancing pursuant to the terms of
the Indebtedness refinanced or the amount of any premium
reasonably determined by us or such Restricted Subsidiary
as necessary to accomplish such refinancing, plus the
amount of our or such Restricted Subsidiary's expenses
incurred in connection with such refinancing,
(2) in the case or any refinancing of our Indebtedness that is
not Senior Indebtedness, such new Indebtedness is either
pari passu with the exchange notes or subordinated to the
exchange notes at least to the same extent as the
Indebtedness being refinanced,
(3) in the case of any refinancing of our Indebtedness
pursuant to clause one, such new Indebtedness is either
Pari Passu Indebtedness or Subordinated Indebtedness and
has a final Stated Maturity at least 91 days after the
final Stated Maturity of the exchange notes, and
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(4) such new Indebtedness has an Average Life equal to or
longer than the Average Life of the Indebtedness being
refinanced and a final Stated Maturity equal to or later
than the final Stated Maturity of the Indebtedness being
refinanced;
o any additional Indebtedness in an aggregate principal amount not
to exceed $25.0 million.
"Permitted Investments" means any of the following:
o Investments in Cash Equivalents;
o Investments in us or any of our Restricted Subsidiaries;
o Investments in any amount not to exceed $10,000,000 at any one
time outstanding;
o Investments by us or any of our Restricted Subsidiaries in another
Person, if as a result of such Investment:
(1) such other Person becomes a Restricted Subsidiary, or
(2) such other Person is merged or consolidated with or into,
or transfers or conveys all or substantially all of its
properties and assets to, us or a Restricted Subsidiary;
o investments and expenditures made in the ordinary course of, and
of a nature that is or shall have become customary in, the Oil and
Gas Business as a means of actively exploiting, exploring for,
acquiring, developing, processing, gathering, marketing or
transporting oil and gas through agreements, transactions,
interests or arrangements which permit a Person to share risks or
costs, comply with regulatory requirements regarding local
ownership or satisfy other objectives customarily achieved through
the conduct of Oil and Gas Business jointly with third parties,
including, without limitation:
(1) ownership interests in oil and gas properties or gathering
systems, and
(2) Investments and expenditures 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 arrangements, joint bidding
agreements, service contracts, joint venture agreements,
general or limited partnership agreements, subscription
agreements, stock purchase agreements and other similar
agreements with third parties, including Unrestricted
Subsidiaries;
o entry into any hedging arrangements in the ordinary course of
business for the purpose of protecting our or any Restricted
Subsidiary's production against fluctuations in oil or natural gas
prices;
o entry into any currency exchange contract in the ordinary course
of business;
o Investments in obligations or securities received as a result of
any Asset Sale;
o advances and loans to officers, directors and employees in the
ordinary course of business;
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o Investments pursuant to any agreement or obligation in effect on
June 8, 1998;
o Investments in obligations or securities received in settlement of
debts owing to us or a Restricted Subsidiary as a result of
bankruptcy or insolvency proceeding or upon the foreclosure,
perfection or enforcement of any Lien in favor of us or a
Restricted Subsidiary, in each case as to debt owing to us or a
Restricted Subsidiary that arose in the ordinary course of our or
any such Restricted Subsidiary's business; and
o contributions to Unrestricted Subsidiaries of our interests in 24
undeveloped federal leases offshore California, known as the
COOGER acreage, included in seven units, Bonita, Sword, Point Sal,
Gato Canyon, Lion Rock, Purisina Point and Santa Maria.
"Permitted Junior Securities" means any of our or any successor
obligor's equity securities or subordinated debt securities with respect to the
Senior Indebtedness provided for by a plan of reorganization or readjustment
that, in the case of any such subordinated debt securities, are subordinated in
right of payment to all Senior Indebtedness that may at the time be outstanding
to substantially the same degree as, or to a greater extent than, the exchange
notes are so subordinated as provided in the indenture.
"Permitted Liens" means the following types of Liens:
o Liens existing as of Juno 8, 1998, and any renewal, extension,
refunding, exchange or refinancing of any such Lien provided that
thereafter such Lien extends only to the properties that were
subject to such Lien prior to the renewal, extension, refunding,
exchange or refinancing thereof,
o Liens securing the exchange notes or the Subsidiary Guarantees
relating thereto; and
o Liens in favor of us.
"Person" means any individual, corporation, limited liability company,
partnership, joint venture, association, joint stock company, trust,
unincorporated organization or government or any agency or political subdivision
thereof.
"Preferred Stock" means, with respect to any Person, any and all
shares, interests, participations or other equivalents, however designated, of
such Person's preferred or preference stock, whether now outstanding or issued
after the date of the indenture, including, without limitation, all classes and
series of preferred or preference stock of such Person.
"Production Payments" means, collectively, Dollar-Denominated
Production Payments and Volumetric Production Payments.
"Qualified Capital Stock" of any Person means any and all Capital Stock
of such Person other than Redeemable Capital Stock, provided that, with respect
to us, Qualified Capital Stock includes, without limitation, any Qualifying
TECONS and any Eligible Convertible Securities.
"Qualifying TECONS" means preferred trust securities or similar
securities issued by a Finance Person after June 8, 1998.
"Redeemable Capital Stock" means any Capital Stock that, either by its
terms, by the terms of any security into which it is convertible or exchangeable
or by contract or otherwise, is, or upon the happening of an event or passage of
time would be, required to be redeemed prior to the final
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Stated Maturity of the exchange notes or is redeemable at the option of the
holder thereof at any time prior to such final Stated Maturity, or is
convertible into or exchangeable for debt securities at any time prior to such
final Stated Maturity; provided, however, that Redeemable Capital Stock shall
not include any security by virtue of the fact that it may be exchanged or
converted at the option of the holder or at our option for our Common Stock,
"Restricted Subsidiary" means any Subsidiary of ours, whether existing
on or after the date of the indenture, unless such Subsidiary is an Unrestricted
Subsidiary or is designated as an Unrestricted Subsidiary pursuant to the terms
of the indenture.
"S&P" means Standard and Poor's Ratings Services, a division of The
McGraw-Hill Companies, Inc., and its successors.
"Senior Indebtedness" means the principal of, premium, if any, on,
interest on, including interest accruing after the filing of a petition
initiating any proceeding pursuant to any bankruptcy law, and other amounts due
on or in connection with, including any fees, premiums, expenses, including
costs of collection, and indemnities, any of our Indebtedness, whether
outstanding on the date of the indenture or thereafter created, incurred or
assumed, unless, in the case of any particular Indebtedness, the instrument
creating or evidencing the same or pursuant to which the same is outstanding
expressly provides that such Indebtedness will be pari passu with or
subordinated in right of payment to the exchange notes. Notwithstanding the
foregoing, "Senior Indebtedness" will not include:
o Indebtedness evidenced by the exchange notes;
o our Indebtedness that is Pari Passu Indebtedness or is expressly
subordinated in right of payment to any other of our Indebtedness;
o Indebtedness that is represented by Redeemable Capital Stock,
o our Indebtedness to the extent incurred in violation of the
covenant described under "--Material Covenants--Incurrence of
Indebtedness;"
o our Indebtedness to any of our Subsidiaries or any other Affiliate
of ours or any subsidiary of such Affiliate; and
o Indebtedness which when incurred and without regard to any
election under Section 1111(b) of the Federal Bankruptcy Code is
without recourse to us.
"Specified Property Sales" means the sales of any of our and our
Restricted Subsidiaries'
o East Texas Oil and gas properties sold in January 1999 and
described under "Summary--Recent Developments;" and
o real properties, other than our or our Restricted Subsidiaries'
mineral interests, owned on the date of the indenture and located
in the Counties of Fresno, Kern, Kings, Los Angeles, Orange, Santa
Barbara, and Ventura in the State of California.
"Specified Senior Indebtedness" means:
o all of our Senior Indebtedness in respect of the Credit Facility
and any renewals, amendments, extensions, supplements,
modifications, deferrals, refinancings, or
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replacements (each, for purposes of this definition, a
"refinancing") thereof by us, including any successive
refinancings thereof by us; and
o any other Senior Indebtedness and any refinancings thereof by us
having a principal amount of at least $10,000,000 as of the date
of determination and provided that the agreements, indentures or
other instruments evidencing such Senior Indebtedness or pursuant
to which such Senior Indebtedness was issued specifically
designates such Senior Indebtedness as "'Specified Senior
Indebtedness" for purposes of the indenture.
For purposes of this definition, a refinancing of any Specified Senior
Indebtedness shall be treated as a Specified Senior Indebtedness only if the
Indebtedness issued in such refinancing ranks or would rank pari passu with the
Specified Senior Indebtedness refinanced and only if Indebtedness issued in such
refinancing is permitted by the covenant described under "--Material
Covenants--Incurrence of Indebtedness."
"Stated Maturity" means, when used with respect to any note or any
installment of interest thereon, the date specified in such new note as the
fixed date on which the principal of such exchange note or such installment of
interest is due and payable, and, when used with respect to any other
Indebtedness or any installment of interest thereon, means the date specified in
the instrument evidencing or governing such Indebtedness as the fixed date on
which the principal of such Indebtedness or such installment of interest is due
and payable.
"Subordinated Indebtedness" means our Indebtedness which is expressly
subordinated in right of payment to the exchange notes.
"Subsidiary" means, with respect to any Person:
o a corporation a majority of whose Voting Stock is at the time,
directly or indirectly, owned by such Person, by one or more
Subsidiaries of such Person or by such Person and one or more
Subsidiaries thereof; or
o any other Person other than a corporation, including, without
limitation, a joint venture, in which such Person, one or more
Subsidiaries thereof or such Person and one or more Subsidiaries
thereof, directly or indirectly, at the date of determination
thereof, have at least majority ownership interest entitled to
vote in the election of directors, managers, trustees or other
Persons performing similar functions.
"Subsidiary Guarantee" means an unconditional, unsecured, senior
subordinated guarantee of the exchange notes by any Restricted Subsidiary
pursuant to the terms of the indenture.
"Subsidiary Guarantor" means, unless released from their Subsidiary
Guarantees as permitted by the indenture, any Restricted Subsidiary that becomes
a guarantor of the exchange notes in compliance with the provisions of the
indenture and executes a supplemental indenture in which such Restricted
Subsidiary agrees to be bound by the terms of the indenture.
"Unrestricted Subsidiary" means:
o any Subsidiary of ours that at the time of determination will be
designated an Unrestricted Subsidiary by our board of directors as
provided below; and
o any Subsidiary of an Unrestricted Subsidiary.
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Our board of directors may designate any Subsidiary of ours as an
Unrestricted Subsidiary so long as:
o neither we nor any Restricted Subsidiary is directly or indirectly
liable pursuant to the terms of any Indebtedness of such
Subsidiary;
o no default with respect to any Indebtedness of such Subsidiary
would permit, upon notice, lapse of time or otherwise, any holder
of any of our or any Restricted Subsidiary's other Indebtedness to
declare a default on such other Indebtedness or cause the payment
thereof to be accelerated or payable prior to its Stated Maturity;
o neither we nor any Restricted Subsidiary has made an Investment in
such Subsidiary unless such Investment was made pursuant to, and
in accordance with, the "Restricted Payments" covenant, other than
Investments of the type described in the fourth and twelfth
clauses of the definition of Permitted Investment; and
o such designation shall not result in the creation or imposition of
any Lien on any of our or any Restricted Subsidiary's properties,
other than any Permitted Lien or any Lien the creation or
imposition of which shall have been in compliance with the "Liens"
covenant.
With respect to the first clause of the second paragraph of this
definition, we or a Restricted Subsidiary may be liable for Indebtedness of an
Unrestricted Subsidiary if:
o such liability constituted a Permitted Investment or a Restricted
Payment permitted by the "Restricted Payments" covenant, in each
case at the time of incurrence; or
o the liability would be a Permitted Investment at the time of
designation of such Subsidiary as an Unrestricted Subsidiary.
Any such designation by our board of directors shall be evidenced to
the trustee by filing a board resolution with the trustee giving effect to such
designation. Our board of directors may designate any Unrestricted Subsidiary as
a Restricted Subsidiary if, immediately after giving effect to such designation:
o no Default or Event of Default shall have occurred and be
continuing;
o we could incur $1.00 of additional Indebtedness, other than
Permitted Indebtedness, under the "Incurrence of Indebtedness"
covenant; and
o if any of our or any of our Restricted Subsidiaries' properties or
assets would upon such designation become subject to any Lien,
other than a Permitted Lien, the creation or imposition of such
Lien shall have been in compliance with the "Liens" covenant.
"Volumetric Production Payments" means production payment obligations
recorded as deferred revenue in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"Voting Stock" means any class or classes of Capital Stock pursuant to
which the holders thereof have the general voting power under ordinary
circumstances to elect at least a majority of the board of directors, managers
or trustees of any Person, irrespective of whether or not, at the time, stock of
any other class or classes shall have, or might have, voting power by reason of
the happening of any contingency.
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"Wholly Owned Restricted Subsidiary" means any Restricted Subsidiary to
the extent:
o all of the Capital Stock or other ownership interests in such
Restricted Subsidiary, other than any directors' qualifying shares
mandated by applicable law, is owned directly or indirectly by us;
or
o such Restricted Subsidiary is organized in a foreign jurisdiction
and is required by the applicable laws and regulations of such
foreign jurisdiction to be partially owned by the government of
such foreign jurisdiction or individual or corporate citizens of
such foreign jurisdiction in order for such Restricted Subsidiary
to transact business in such foreign jurisdiction, provided that
we, directly or indirectly, own the remaining Capital Stock or
ownership interest in such Restricted Subsidiary and, by contract
or otherwise, control the management and business of such
Restricted Subsidiary and derive the economic benefits of
ownership of such Restricted Subsidiary to substantially the same
extent as if such Restricted Subsidiary were a wholly owned
Subsidiary.
REGISTRATION RIGHTS
We have entered into a registration agreement with the dealer managers
under which we have agreed, for the benefit of the holders of the existing
notes, at our cost, to use our reasonable best efforts:
o to file with the SEC the registration statement of which this
prospectus is a part related to the exchange offer of the exchange
notes by November 11, 1999;
o to cause this exchange offer registration statement to be declared
effective under the Securities Act by January 17, 2000;
o to keep this exchange offer registration statement effective until
the closing of the exchange offer; and
o to cause this exchange offer to be completed by February 16, 2000.
The registration agreement shall be governed by, and construed under,
the laws of the State of New York. If you have further questions about
registration rights, you should refer to the registration agreement, a copy of
which is available upon request to us. The registration agreement is also
attached as an exhibit to this registration statement. In addition, the
information described above under "The Exchange Offer" concerning
interpretations of and positions taken by the staff of the SEC is not intended
to constitute legal advice, and prospective investors should consult their own
advisors on these matters.
PLAN OF DISTRIBUTION
Each broker-dealer that receives exchange notes for its own account in
the exchange offer must acknowledge that it will deliver a prospectus in
connection with any resale of the exchange notes. This prospectus, as it may be
amended or supplemented from time to time, may be used by a broker-dealer in
connection with resales of exchange notes received in exchange for existing
notes where the existing notes were acquired as a result of market-making
activities or other trading activities. We have agreed that, for a period of 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, if required under applicable securities laws and upon
prior written request.
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<PAGE> 124
We will not receive any proceeds from any sale of exchange notes by
broker-dealers. Exchange notes received by broker-dealers for their own account
in 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 exchange notes or a combination of these methods of resale, at
market prices prevailing at the time of resale, at prices related to those
prevailing market prices or at negotiated prices. Any 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 broker-dealer or
the purchasers of any exchange notes. Any broker-dealer that resells exchange
notes that were received by it for its own account in the exchange offer and any
broker or dealer that participates in a distribution of the exchange notes may
be deemed to be an "underwriter" within the meaning of the Securities Act and
any profit on any resale of exchange notes and any commission or concessions
received by such person may be considered underwriting compensation under the
Securities Act. The letter of transmittal states that, by acknowledging that it
will deliver and by delivering a prospectus, a broker-dealer will not be
regarded as admitting that it is an "underwriter", within the meaning of the
Securities Act.
For a period of 90 days after the consummation of the exchange offer,
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
existing notes, other than commissions or concessions of any brokers or dealers
and will indemnify the holders of the existing notes, including any
broker-dealers, against certain liabilities, including liabilities under the
Securities Act.
LEGAL MATTERS
The validity of the issuance of the exchange notes will be passed upon
by our attorneys, Haynes and Boone, L.L.P., Houston, Texas.
EXPERTS
The consolidated financial statements of Nuevo Energy Company as of
December 31, 1998 and 1997 and for each of the years in the three-year period
ended December 31, 1998 included in the prospectus and the registration
statement have been included herein in reliance upon the report of KPMG LLP,
independent certified public accountants, and upon the authority of such firm as
experts in accounting and auditing. The report of KPMG LLP refers to the
retroactive effect of a change in accounting for oil and gas properties from the
full cost method to the successful efforts method.
Information about our estimated net proved reserves and the future net
cash flows attributable to these reserves as of December 31, 1998 and 1997 was
prepared by Ryder Scott Company, L.P. and our estimated net proved reserves and
future cash flows attributable to those reserves as of December 31, 1996 was
prepared by Ryder Scott Company, L.P. and Poco Oil Co. Information about our
estimated net proved reserves and the future net cash flows attributable to
these reserves as of June 30, 1999 was prepared by our internal reserve
engineers.
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<PAGE> 125
GLOSSARY OF OIL AND GAS TERMS
TERMS USED TO DESCRIBE QUANTITIES OF OIL AND NATURAL GAS
o Bbl -- One stock tank barrel, or 42 US gallons liquid volume, of
crude oil or other liquid hydrocarbons.
o Bcf -- One billion cubic feet of natural gas.
o Bcfe -- One billion cubic feet of natural gas equivalent.
o BOE-- One barrel of oil equivalent, converting gas to oil at the
ratio of 6 Mcf of gas to 1 Bbl of oil.
o MBbl -- One thousand Bbls.
o Mcf -- One thousand cubic feet of natural gas.
o MMBbl -- One million Bbls of oil or other liquid hydrocarbons.
o MMcf -- One million cubic feet of natural gas.
o MBOE -- One thousand BOE.
o MMBOE -- One million BOE.
TERMS USED TO DESCRIBE OUR INTERESTS IN WELLS AND ACREAGE
o Gross oil and gas wells or acres -- Our gross wells or gross acres
represents the total number of wells or acres in which we own a
working interest.
o Net oil and gas wells or acres -- Determined by multiplying
"gross" oil and natural gas wells or acres by the working interest
that we own in such wells or acres represented by the underlying
properties.
TERMS USED TO ASSIGN A PRESENT VALUE TO OUR RESERVES
o Standard measure of proved reserves -- The present value,
discounted at 10%, of the pre-tax future net cash flows
attributable to estimated net proved reserves. We calculate this
amount by assuming that we will sell the oil and gas production
attributable to the proved reserves estimated in our independent
engineer's reserve report for the prices we received for the
production on the date of the report, unless we had a contract to
sell the production for a different price. We also assume that the
cost to produce the reserves will remain constant at the costs
prevailing on the date of the report. The assumed costs are
subtracted from the assumed revenues resulting in a stream of
future net cash flows. Estimated future income taxes using rates
in effect on the date of the report are deducted from the net cash
flow stream. The after-tax cash flows are discounted at 10% to
result in the standardized measure of our proved reserves. The
standardized measure of our proved reserves is disclosed in our
audited financial statements at note 16.
o Pre-tax discounted present value -- The discounted present value
of proved reserves is identical to the standardized measure,
except that estimated future income taxes are not
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<PAGE> 126
deducted in calculating future net cash flows. We disclose the
discounted present value without deducting estimated income taxes
to provide what we believe is a better basis for comparison of our
reserves to the producers who may have different tax rates.
TERMS USED TO CLASSIFY OUR RESERVE QUANTITIES
o Proved reserves -- The estimated quantities of crude oil, natural
gas and natural gas liquids which, upon analysis of geological and
engineering data, appear with reasonable certainty to be
recoverable in the future from known oil and natural gas
reservoirs under existing economic and operating conditions.
The SEC definition of proved oil and gas reserves, per Article
4-10(a)(2) of Regulation S-X, is as follows:
Proved oil and gas reserves. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids
which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions, i.e., prices and costs as
of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements,
but not on escalations based upon future conditions.
(a) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion
delineated by drilling and defined by gas-oil and/or oil-water
contacts, if any; and (B) the immediately adjoining portions not yet
drilled, but which can be reasonably judged as economically productive
on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of the
reservoir.
(b) Reserves which can be produced economically through
application of improved recovery, techniques (such as fluid injection)
are included in the "proved" classification when successful testing by
a pilot project, or the operation of an installed program in the
reservoir, provides support for the engineering analysis on which the
project or program was based.
(c) Estimates of proved reserves do not include the following: (1)
oil that may become available from known reservoirs but is classified
separately as "indicated additional reserves"; (2) crude oil, natural
gas, and natural gas liquids, the recovery of which is subject to
reasonable doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors; (3) crude oil, natural gas, and
natural gas liquids, that may occur in undrilled prospects; and (4)
crude oil, natural gas, and natural gas liquids, that may be recovered
from oil shales, coal, gilsonite and other such sources.
o Proved developed reserves -- Proved reserves that can be expected
to be recovered through existing wells with existing equipment and
operating methods.
o Proved undeveloped reserves -- Proved reserves that are expected
to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required.
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<PAGE> 127
TERMS WHICH DESCRIBE THE COST TO ACQUIRE OUR RESERVES
o Finding costs -- Our finding costs compare the amount we spent to
acquire, explore and develop our oil and gas properties, explore
for oil and gas and to drill and complete wells during a period,
with the increases in reserves during the period. This amount is
calculated by dividing the net change in our evaluated oil and
property costs during a period by the change in proved reserves
plus production over the same period. Our finding costs as of
December 31 of any year represent the average finding costs over
the three-year period ending December 31 of that year. Our finding
costs as of June 30, 1999 represent average finding costs over a
two and one half year period ending on June 30, 1999.
TERMS WHICH DESCRIBE THE PRODUCTIVE LIFE OF A PROPERTY OR GROUP OF PROPERTIES
o Reserve life index -- A measure of the productive life of an oil
and gas property or a group of oil and gas properties, expressed
in years. Reserve life index for the years ended December 31,
1996, 1997 or 1998 equal the estimated net proved reserves
attributable to a property or group of properties divided by
production from the property or group of properties for the four
fiscal quarters preceding the date as of which the proved reserves
were estimated. In order to reflect the divestiture of the East
Texas properties and the Star acquisition, our reserve life index
for June 30, 1999 was calculated by dividing estimated net proved
reserves at June 30, 1999 by our annualized pro forma production
for the first six months of 1999, assuming we closed the Star
acquisition on January 1, 1999.
TERMS USED TO DESCRIBE THE LEGAL OWNERSHIP OF OUR OIL AND GAS PROPERTIES
o Royalty interest -- A real property interest entitling the owner
to receive a specified portion of the gross proceeds of the sale
of oil and natural gas production or, if the conveyance creating
the interest provides, a specific portion of oil and natural gas
produced, without any deduction for the costs to explore for,
develop or produce the oil and natural gas. A royalty interest
owner has no right to consent to or approve the operation and
development of the property, while the owners of the working
interests have the exclusive right to exploit the mineral on the
land.
o Working interest -- A real property interest entitling the owner
to receive a specified percentage of the proceeds of the sale of
oil and natural gas production or a percentage of the production,
but requiring the owner of the working interest to bear the cost
to explore for, develop and produce such oil and natural gas. A
working interest owner who owns a portion of the working interest
may participate either as operator or by voting his percentage
interest to approve or disapprove the appointment of an operator
and drilling and other major activities in connection with the
development and operation of a property.
TERMS USED TO DESCRIBE SEISMIC OPERATIONS
o Seismic data -- Oil and gas companies use seismic data as their
principal source of information to locate oil and gas deposits,
both to aid in exploration for new deposits and to manage or
enhance production from known reservoirs. To gather seismic data,
an energy source is used to send sound waves into the subsurface
strata. These waves are reflected back to the surface by
underground formations, where they are detected by geophones which
digitize and record the reflected waves. Computers are then used
to process the raw data to develop an image of underground
formations.
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<PAGE> 128
o 2-D seismic data -- 2-D seismic survey data has been the standard
acquisition technique used to image geologic formations over a
broad area. 2-D seismic data is collected by a single line of
energy sources which reflect seismic waves to a single line of
geophones. When processed, 2-D seismic data produces an image of a
single vertical plane of sub-surface data.
o 3-D seismic -- 3-D seismic data is collected using a grid of
energy sources, which are generally spread over several miles. A
3-D survey produces a three dimensional image of the subsurface
geology by collecting seismic data along parallel lines and
creating a cube of information that can be divided into various
planes, thus improving visualization. Consequently, 3-D seismic
data is a more reliable indicator of potential oil and natural gas
reservoirs in the area evaluated.
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<PAGE> 129
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
NUMBER
----------
<S> <C>
Condensed Consolidated Balance Sheets as of June 30, 1999
(Unaudited) and December 31, 1998............................................................ F-2
Unaudited Condensed Consolidated Statements of Operations
for the Six Months Ended June 30, 1999 and 1998............................................. F-3
Unaudited Condensed Consolidated Statements of Cash Flows
for the Six Months Ended June 30, 1999 and 1998.............................................. F-4
Unaudited Notes to Condensed Consolidated Financial
Statements................................................................................... F-5
Independent Auditors' Report................................................................... F-11
Consolidated Balance Sheets as of December 31, 1998 and 1997
(Restated)................................................................................... F-12
Consolidated Statements of Operations for the Years Ended
December 31, 1998, 1997 (Restated) and 1996 (Restated)....................................... F-13
Consolidated Statements of Changes in Stockholders' Equity
for the Years Ended December 31, 1998, 1997 (Restated) and
1996 (Restated).............................................................................. F-14
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1998, 1997 (Restated) and 1996 (Restated)....................................... F-15
Notes to Consolidated Financial Statements..................................................... F-16
</TABLE>
F-1
<PAGE> 130
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
ASSETS
JUNE 30, DECEMBER 31,
1999 1998
----------- -----------
(UNAUDITED)
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents ......................................................... $ 53,639 $ 7,403
Accounts receivable ............................................................... 26,555 25,096
Product inventory ................................................................. 4,992 5,998
Assets held for sale .............................................................. 10,000 120,055
Prepaid expenses and other ........................................................ 5,157 2,700
----------- -----------
Total current assets ...................................................... 100,343 161,252
----------- -----------
PROPERTY AND EQUIPMENT, at cost:
Land .............................................................................. 51,038 51,038
Oil and gas properties (successful efforts method) ................................ 1,025,896 959,348
Gas plant facilities .............................................................. 17,786 17,112
Other facilities .................................................................. 9,130 6,696
----------- -----------
1,103,850 1,034,194
Accumulated depreciation, depletion and amortization .............................. (446,966) (417,622)
----------- -----------
656,884 616,572
----------- -----------
DEFERRED TAX ASSETS, net ............................................................ 22,010 27,534
OTHER ASSETS ........................................................................ 11,037 12,327
----------- -----------
$ 790,274 $ 817,685
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable .................................................................. $ 18,318 $ 24,393
Accrued interest .................................................................. 4,211 4,161
Accrued liabilities ............................................................... 19,846 17,917
Current maturities of long-term debt .............................................. 2,051 3,152
----------- -----------
Total current liabilities ................................................. 44,426 49,623
----------- -----------
OTHER LONG-TERM LIABILITIES ......................................................... 3,066 2,034
LONG-TERM DEBT, net of current maturities ........................................... 380,000 419,150
COMPANY-OBLIGATED MANDATORILY REDEEMABLE CONVERTIBLE
PREFERRED SECURITIES OF NUEVO FINANCING I ......................................... 115,000 115,000
STOCKHOLDERS' EQUITY:
Common stock, $.01 par value, 50,000,000 shares authorized, 20,308,462 shares
issued at June 30, 1999 and December 31, 1998 .................................. 203 203
Additional paid-in capital ........................................................ 355,720 355,600
Treasury stock, at cost, 449,255 and 473,876 shares, at June 30, 1999 and
December 31, 1998, respectively ................................................ (19,053) (19,335)
Stock held by benefit trust, 71,630 and 47,759 shares, at
June 30, 1999 and December 31, 1998, respectively .............................. (2,014) (1,732)
Accumulated deficit ............................................................... (87,074) (102,858)
----------- -----------
Total stockholders' equity ................................................ 247,782 231,878
----------- -----------
$ 790,274 $ 817,685
=========== ===========
</TABLE>
See accompanying notes to condensed consolidated financial statements.
F-2
<PAGE> 131
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
-----------------------
1999 1998
--------- ---------
<S> <C> <C>
REVENUES:
Oil and gas revenues .......................................... $ 95,052 $ 123,045
Gas plant revenues ............................................ 1,288 1,405
Pipeline and other revenues ................................... 4 1,722
Gain on sale of assets, net ................................... 80,312 1,677
Interest and other income ..................................... 2,847 1,324
--------- ---------
179,503 129,173
--------- ---------
COSTS AND EXPENSES:
Lease operating expenses ...................................... 57,876 65,774
Gas plant operating expenses .................................. 2,336 1,423
Pipeline and other operating expenses ......................... 143 1,842
Exploration costs ............................................. 9,999 2,331
Depreciation, depletion and amortization ...................... 46,257 46,556
General and administrative expenses ........................... 7,199 8,526
Outsourcing fees .............................................. 6,846 7,199
Interest expense .............................................. 16,400 14,444
Dividends on Guaranteed Preferred Beneficial Interests in
Company's Convertible Debentures (TECONS) .................. 3,306 3,306
Other expense ................................................. 2,836 1,846
--------- ---------
153,198 153,247
--------- ---------
Income (loss) before income taxes ............................... 26,305 (24,074)
Provision (benefit) for income taxes ............................ 10,521 (9,870)
--------- ---------
NET INCOME (LOSS) ............................................... $ 15,784 $ (14,204)
========= =========
EARNINGS (LOSS) PER SHARE:
Earnings (loss) per common share-- Basic ...................... $ 0.80 $ (0.72)
========= =========
Weighted average common shares outstanding .................... 19,848 19,759
========= =========
Earnings (loss) per common share-- Diluted .................... $ 0.79 $ (0.72)
========= =========
Weighted average common and dilutive potential common
shares outstanding ......................................... 19,915 19,759
========= =========
</TABLE>
See accompanying notes to condensed consolidated financial statements.
F-3
<PAGE> 132
NUEVO ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
------------------------
1999 1998
--------- ---------
<S> <C> <C>
Cash flows from operating activities:
Net income (loss) ................................................................. $ 15,784 $ (14,204)
Adjustments to reconcile net income (loss) to net cash
(used in) provided by operating activities:
Depreciation, depletion and amortization ....................................... 46,257 46,556
Gain on sale of assets, net .................................................... (80,312) (1,677)
Dry hole costs ................................................................. 7,297 138
Amortization of other costs .................................................... 811 758
Appreciation of deferred compensation plan ..................................... 111 --
Deferred revenues .............................................................. -- (1,227)
Deferred taxes ................................................................. 5,521 (10,245)
Other .......................................................................... 120 --
--------- ---------
(4,411) 20,099
Change in assets and liabilities:
Accounts receivable ............................................................ (1,459) 11,240
Accounts payable and accrued liabilities ....................................... (5,606) (5,149)
Other .......................................................................... (1,680) (4,273)
--------- ---------
Net cash (used in) provided by operating activities ................................. (13,156) 21,917
--------- ---------
Cash flows from investing activities:
Additions to oil and gas properties ............................................... (35,497) (90,329)
Acquisitions of oil and gas properties ............................................ (61,416) (7,810)
Additions to gas plant facilities ................................................. (674) (1,091)
Additions to other facilities ..................................................... (2,434) (1,184)
Proceeds from sales of properties ................................................. 199,663 5,811
--------- ---------
Net cash provided by (used in) investing activities ................................. 99,642 (94,603)
--------- ---------
Cash flows from financing activities:
Proceeds from borrowings .......................................................... 120,090 193,000
Deferred financing costs .......................................................... -- (2,636)
Payments of long-term debt ........................................................ (160,340) (121,902)
Treasury stock sale ............................................................... -- 100
Proceeds from issuance of common stock ............................................ -- 1,280
--------- ---------
Net cash (used in) provided by financing activities ................................. (40,250) 69,842
--------- ---------
Net increase (decrease) in cash and cash equivalents .............................. 46,236 (2,844)
Cash and cash equivalents at beginning of period .................................. 7,403 9,208
--------- ---------
Cash and cash equivalents at end of period .......................................... $ 53,639 $ 6,364
========= =========
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (net of amounts capitalized) .......................................... $ 15,646 $ 14,389
Income taxes ................................................................... $ 2,250 $ 475
</TABLE>
See accompanying notes to condensed consolidated financial statements.
F-4
<PAGE> 133
NUEVO ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accompanying unaudited condensed consolidated financial statements have
been prepared in accordance with instructions to Form 10-Q and, therefore, do
not include all disclosures required by generally accepted accounting
principles. However, in the opinion of management, these statements include all
adjustments, which are of a normal recurring nature, necessary to present fairly
the financial position at June 30, 1999 and December 31, 1998 and the results of
operations and changes in cash flows for the periods ended June 30, 1999 and
1998. These financial statements should be read in conjunction with the
financial statements and notes to the financial statements in the 1998 Form 10-K
of Nuevo Energy Company (the "Company") that was filed with the Securities and
Exchange Commission.
Use of Estimates
In order to prepare these financial statements in conformity with generally
accepted accounting principles, management of the Company has made a number of
estimates and assumptions relating to the reporting of assets and liabilities,
the disclosure of contingent assets and liabilities and reserve information
(which affects the depletion calculation). Actual results could differ from
those estimates.
Comprehensive Income
Comprehensive income includes net income and all changes in an enterprise's
other comprehensive income including, among other things, foreign currency
translation adjustments, and unrealized gains and losses on certain investments
in debt and equity securities. There are no differences between comprehensive
income (loss) and net income (loss) for the periods presented.
Derivative Financial Instruments
The Company utilizes derivative financial instruments to reduce its
exposure to changes in the market price of natural gas and crude oil. Commodity
derivatives utilized as hedges include futures, swap and option contracts, which
are used to hedge natural gas and oil prices. Commodity price and basis swaps
are sometimes used to hedge the basis differential between the derivative
financial instrument index price and the commodity field price. In order to
qualify as a hedge, price movements in the underlying commodity derivative must
be highly correlated with the hedged commodity. Settlement of gains and losses
on price swap contracts are realized monthly, generally based upon the
difference between the contract price and the average closing New York
Mercantile Exchange ("NYMEX") price and are reported as a component of oil and
gas revenues and operating cash flows in the period realized.
Gains and losses on option and futures contracts that qualify as a hedge of
firmly committed or anticipated purchases and sales of oil and gas commodities
are deferred on the balance sheet and recognized in income and operating cash
flows when the related hedged transaction occurs. Premiums paid on option
contracts are deferred in other assets and amortized into oil and gas revenues
over the terms of the respective option contracts. Gains or losses attributable
to the termination of a derivative financial instrument are deferred on the
balance sheet and recognized in revenue when the hedged crude oil and natural
gas is sold. There were no such deferred gains or losses at June 30, 1999 or
December 31, 1998. Gains or losses on derivative financial instruments that do
not qualify as a hedge are recognized in income currently.
As a result of hedging transactions, oil and gas revenues were reduced by
$9.0 million and increased by $0.1 million in the second quarter of 1999 and
1998, respectively. During the first six months of 1999 and 1998, oil and gas
revenues were reduced by $8.8 million and increased by $0.2 million,
respectively, as a result of these transactions.
The Company entered into a swap arrangement with a major financial
institution that effectively converts the interest rate on $16.4 million
notional amount of the 9 1/2% Senior Subordinated Notes due 2006 to a variable
LIBOR-based rate through February 25, 2000. Based on LIBOR rates in effect at
June 30, 1999, this amounted to a net reduction in the carrying cost of the 9
1/2% Senior Subordinated Notes due 2006 from 9.5% to 5.64%, or 386 basis points.
In addition, the swap arrangement also effectively hedges the price at which
these Notes can be repurchased by the Company at 101.16% of their face amount.
Based on the market price of 101.23% for the Notes at June 30, 1999, an early
termination of this arrangement would result in a payment of approximately
$11,000 from the institution to Nuevo.
F-5
<PAGE> 134
For the second half of 1999, the Company is party to crude oil swaps on an
average of 31,500 barrels of oil ("Bbls") per day, or 65% of its estimated
crude oil production, at an average NYMEX price of $16.35 per Bbl. For calendar
year 2000, the Company has entered into crude oil swaps on 16,500 Bbls per day,
or 30% of its estimated crude oil production, at an average NYMEX price of
$17.94 per Bbl. In addition, for calendar year 2000, the Company has hedged an
additional 30% of its estimated crude oil production through the purchase of put
options on 16,500 Bbls per day at a NYMEX price of $16.00 per Bbl, and the sale
of call options on 16,500 Bbls per day at an average NYMEX price of $21.21 per
Bbl. There was not net cost to the Company for these options.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities". This
statement, as amended by SFAS No. 137, establishes standards of accounting for
and disclosures of derivative instruments and hedging activities. This statement
requires all derivative instruments to be carried on the balance sheet at fair
value and is effective for the Company beginning January 1, 2001, however, early
adoption is permitted. The Company has not yet determined the impact of this
statement on its financial condition or results of operations or whether it will
adopt the statement early.
Reclassifications
Certain reclassifications of prior year amounts have been made to conform
to the current presentation.
2. PROPERTY AND EQUIPMENT
The Company utilizes the successful efforts method of accounting for its
investments in oil and gas properties. Under successful efforts, oil and gas
lease acquisition costs and intangible drilling costs associated with
exploration efforts that result in the discovery of proved reserves and costs
associated with development drilling, whether or not successful, are capitalized
when incurred. When a proved property is sold, ceases to produce or is
abandoned, a gain or loss is recognized. When an entire interest in an unproved
property is sold for cash or cash equivalent, gain or loss is recognized, taking
into consideration any recorded impairment. When a partial interest in an
unproved property is sold, the amount received is treated as a reduction of the
cost of the interest retained.
Unproved leasehold costs are capitalized pending the results of exploration
efforts. Significant unproved leasehold costs are reviewed periodically and a
loss is recognized to the extent, if any, that the cost of the property has been
impaired. An impairment of unproved leasehold costs of $8.1 million was
recognized as of December 31, 1998. Exploration costs, including geological and
geophysical expenses, exploratory dry holes and delay rentals, are charged to
expense as incurred.
Costs of productive wells, development dry holes and productive leases are
capitalized and depleted on a unit-of-production basis over the life of the
remaining proved reserves. Capitalized drilling costs are depleted on a
unit-of-production basis over the life of the remaining proved developed
reserves. Estimated costs (net of salvage value) of dismantlement, abandonment
and site remediation are computed by the Company's independent reserve engineers
and are included when calculating depreciation and depletion using the
unit-of-production method.
The Company reviews proved oil and gas properties on a depletable unit
basis whenever events or circumstances indicate that the carrying value of those
assets may not be recoverable. For each depletable unit determined to be
impaired, an impairment loss equal to the difference between the carrying value
and the fair value of the depletable unit is recognized. Fair value, on a
depletable unit basis, is estimated to be the present value of the undiscounted
expected future net revenues computed by application of estimated future oil and
gas prices, production and expenses, as determined by management, to estimated
future production of oil and gas reserves over the economic life of the
reserves. If the carrying value exceeds the undiscounted future net revenues, an
impairment is recognized equal to the difference between the carrying value and
the discounted estimated future net revenues of that depletable unit. The
Company considers probable reserves and escalated commodity pricing in its
estimate of future net revenues. A fair value impairment of $60.8 million was
recognized as of December 31, 1998.
Interest costs associated with non-producing leases and exploration and
development projects are capitalized only for the period that activities are in
progress to bring these projects to their intended use. The capitalization rates
are based on the Company's weighted average cost of funds used to finance
expenditures.
3. DEFERRED TAX ASSETS
As a result of the net loss generated during 1998, the Company has deferred
tax assets, net of valuation allowances, of $22.0 million and $27.5 million as
of June 30, 1999 and December 31, 1998, respectively. The Company believes that
sufficient future taxable income will be generated and has concluded that these
net deferred tax assets will more likely than not be realized.
F-6
<PAGE> 135
4. INDUSTRY SEGMENT INFORMATION
As of December 31, 1998, the Company adopted SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information", which was issued by
the FASB in June 1997. This statement establishes standards for reporting
information about operating segments in annual financial statements and requires
that enterprises report selected information about operating segments in interim
periods.
Historically, the Company's operations were concentrated primarily in two
segments: the exploration and production of oil and natural gas and gas plant,
pipeline and gas storage operations. The Company's non-core gas gathering,
pipeline and gas storage assets were reclassified to assets held for sale as of
December 31, 1997, consistent with the Company's intention to dispose of these
assets during 1998 and 1999. The Company completed the sale of its Bright Star
gas gathering system in July 1998 and the Richfield gas storage assets in
February 1998, at their approximate carrying values, and has signed a letter of
intent with a third party to sell the remaining asset, the Illini pipeline.
Closing of the Illini pipeline sale is expected by the end of 1999, pending
finalization of a purchase and sale agreement and certain regulatory approvals.
The Company's policy is to record revenues and expenses associated with these
assets, which are no longer being depreciated, until they are sold.
<TABLE>
<CAPTION>
FOR THE SIX MONTHS
ENDED
JUNE 30,
------------------------
1999 1998
--------- ---------
<S> <C> <C>
Sales to unaffiliated customers:
Oil and gas-- East ............................. $ 7,682 $ 24,218
Oil and gas-- West ............................. 76,455 90,689
Oil and gas-- International .................... 10,915 8,138
Gas plant, pipelines and other ................. 1,292 3,127
--------- ---------
Total sales ............................ 96,344 126,172
Gain on sale of assets, net ............ 80,312 1,677
Other revenues ................................. 2,847 1,324
--------- ---------
Total revenues ......................... $ 179,503 $ 129,173
========= =========
Operating profit before income taxes:
Oil and gas-- East(a) .......................... $ 81,141 $ 12,644
Oil and gas-- West ............................. (18,165) (552)
Oil and gas-- International .................... (806) (1,288)
Gas plant, pipelines and other ................. (1,786) (538)
--------- ---------
60,384 10,266
Unallocated corporate expenses ................... 14,373 16,590
Interest expense ................................. 16,400 14,444
Dividends on TECONS .............................. 3,306 3,306
--------- ---------
Income (loss) before income taxes .............. $ 26,305 $ (24,074)
========= =========
Depreciation, depletion and amortization:
Oil and gas-- East ............................. $ 4,307 6,467
Oil and gas-- West ............................. 37,344 36,817
Oil and gas-- International .................... 3,855 2,529
Gas plant, pipelines and other ................. 412 400
--------- ---------
$ 45,918 $ 46,213
========= =========
</TABLE>
- ----------
(a) Includes an $80.3 million net gain on sale of the East Texas gas properties
for the six months ended June 30, 1999.
F-7
<PAGE> 136
5. LONG-TERM DEBT
Long-term debt consists of the following (amounts in thousands):
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
--------- -----------
<S> <C> <C>
9 1/2% Senior Subordinated Notes due 2006(a) .......... $ 160,000 $ 160,000
8 7/8% Senior Subordinated Notes due 2008(a) ........... 100,000 100,000
Bank credit facility (b) .............................. 120,000 158,400
OPIC credit facility .................................. 2,051 3,902
--------- ---------
Total debt .................................. 382,051 422,302
Less: current maturities .............................. (2,051) (3,152)
--------- ---------
Long-term debt ........................................ $ 380,000 $ 419,150
========= =========
</TABLE>
- ----------
(a) In July 1999, the Company authorized a new issuance of $260.0 million of 9
1/2% senior subordinated notes due June 1, 2008. The Company has offered to
exchange the new notes for its outstanding $160.0 million of 9 1/2% senior
subordinated notes due 2006 and $100.0 million of 8 7/8% senior
subordinated due 2008. In connection with the exchange offers, the Company
has solicited consents to proposed amendments to the indentures under which
the old note were issued. These amendments delete most of the covenants in
the old indentures. The purpose of the exchange offers is to combine the
Company's two existing issues of senior subordinated notes into a single
new issue in the aggregate principal amount of $260.0 million. The purpose
of the consent solicitations is to streamline the Company's covenant
structure and to provide the Company with additional flexibility to pursue
its operating strategy. The exchange offers were conditioned on receipt of
tenders of at least a majority of the outstanding principal amount of each
of the old notes and satisfaction of other customary conditions. As of
August 9, 1999, tenders had been received from holders of a majority of
each issue of the old notes. Accordingly, the Company and the trustee for
the old notes executed supplemental indentures containing the proposed
amendments relating to the consent solicitations. In addition to the
consideration equal to 3% of the outstanding principal amount of the 9 1/2%
notes exchanged that the Company will pay to the holders of the 9 1/2%
notes who tendered in the exchange offer, which will be accounted for as
deferred financing costs, the Company expects to incur approximately $4.0
million of expenses during the third quarter of 1999, in connection with
this exchange offer.
(b) Nuevo's Restated Credit Agreement dated June 30, 1999, provides for secured
revolving credit availability of up to $400.0 million (subject to a
semi-annual borrowing base determination) from a bank group led by Bank of
America, N.A. and Morgan Guaranty Trust Company of New York, until its
expiration on April 1, 2003. Effective January 6, 1999, the borrowing base
on the Company's credit facility was reduced from $380.0 million to $200.0
million, reflecting the sale on that date of the Company's East Texas
natural gas reserves, and also reflecting a significant decline in current
and projected oil prices since the previous determination. The Company and
its banks have begun discussions regarding the reset of the borrowing base
to be effective as of October 15, 1999. Given the significant increase in
crude oil prices since the prior determination, management anticipates a
material increase in the borrowing base. The restatement of the Credit
Agreement also provided Nuevo with relief under the covenant requiring
minimum levels of EBITDA / Fixed Charge coverage. The Company was in
compliance with all covenants as of June 30, 1999, and does not anticipate
any issues of non-compliance arising in the foreseeable future. At June 30,
1999, outstanding borrowings under the revolving credit agreement were
$109.0 million. Additionally, Nuevo had $11.0 million of outstanding
borrowings under an uncommitted line of credit. Accordingly, $91.0 million
of committed revolving credit capacity was unused and available at June 30,
1999.
6. EARNINGS (LOSS) PER SHARE COMPUTATION
SFAS No. 128 requires a reconciliation of the numerator (income) and
denominator (shares) of the basic earnings per share ("EPS") computation to the
numerator and denominator of the diluted EPS computation. In the six-month
period ended June 30, 1998, weighted average potential dilutive common shares of
451,000 are not included in the calculation of diluted loss per share due to
their anti-dilutive effect. The Company's reconciliation is as follows:
<TABLE>
<CAPTION>
FOR THE SIX MONTHS ENDED JUNE 30,
------------------------------------------------
1999 1998
--------------------- ----------------------
INCOME SHARES LOSS SHARES
-------- ------ -------- ------
<S> <C> <C> <C> <C>
Earnings (loss) per common share-- Basic ......... $ 15,784 19,848 $(14,204) 19,759
Effect of dilutive securities:
Stock options .................................. -- 67 -- --
-------- ------ -------- ------
Earnings (loss) per common share-- Diluted ....... $ 15,784 19,915 $(14,204) 19,759
======== ====== ======== ======
</TABLE>
7. CONTINGENCIES
The Company has been named as a defendant in the Gloria Garcia Lopez and
Husband, Hector S. Lopez, Individually, and as successors to Galo Land & Cattle
Company v. Mobil Producing Texas & New Mexico, et al. in the 79th Judicial
District Court of Brooks County, Texas. The plaintiffs allege: i) underpayment
of royalties and claim damages, on a gross basis, of $27.7 million plus $26.2
million in interest for the period from 1985 to date;
F-8
<PAGE> 137
ii) that their production was improperly commingled with gas produced from an
adjoining lease, resulting in damages, including interest of $40.8 million
(gross); and iii) numerous other claims that may result in unspecified damages.
Nuevo's working interest in these properties is 20%. The Company, along with the
other defendants in this case, denies these allegations and is vigorously
contesting these claims. Management does not believe that the final outcome of
this matter will have a material adverse impact on the Company's operating
results, financial condition or liquidity.
The Company has been named as a defendant in certain other lawsuits
incidental to its business. Management does not believe that the outcome of such
litigation will have a material adverse impact on the Company's operating
results or financial condition. However, these actions and claims in the
aggregate seek substantial damages against the Company and are subject to the
inherent uncertainties in any litigation. The Company is defending itself
vigorously in all such matters.
In March 1999, the Company discovered that a non-officer employee had
fraudulently authorized and diverted for personal use Company funds totaling
$5.9 million, $4.3 million in 1998 and the remainder in 1999, that were intended
for international exploration. Accordingly, the Company has reclassified the
amounts lost in 1998 and 1999 to other expense. Based on its review of the
facts, management is confident that only one employee was involved in the matter
and that all misappropriated funds have been identified. The Board has engaged a
Certified Fraud Examiner to conduct an in-depth review of the fraudulent
transactions to determine the scope of the fraud, the possibility of recovery of
amounts lost from insurance, from the terminated employee and/or from third
parties, and to make recommendations regarding what, if any, new internal
control procedures should be implemented.
In September 1997, there was a spill of crude oil into the Santa Barbara
Channel from a pipeline that connects the Company's Point Pedernales field with
shore-based processing facilities. The volume of the spill was estimated to be
163 barrels of oil. The costs of the clean up and the cost to repair the
pipeline either have been or are expected to be covered by insurance, less the
Company's deductibles, which in total are $120,000. Repairs were completed by
the end of 1997, and production recommenced in December 1997. The Company also
has exposure to certain costs that may not be recoverable from insurance,
including fines, penalties, and damages. Such costs are not quantifiable at this
time, but are not expected to be material to the Company's operating results,
financial condition or liquidity.
The Company's international investments involve risks typically associated
with investments in emerging markets such as an uncertain political, economic,
legal and tax environment and expropriation and nationalization of assets. In
addition, if a dispute arises in its foreign operations, the Company may be
subject to the exclusive jurisdiction of foreign courts or may not be successful
in subjecting foreign persons to the jurisdiction of the United States. The
Company attempts to conduct its business and financial affairs so as to protect
against political and economic risks applicable to operations in the various
countries where it operates, but there can be no assurance that the Company will
be successful in so protecting itself. A portion of the Company's investment in
the Republic of Congo in West Africa ("Congo") is insured through political risk
insurance provided by the Overseas Private Investment Corporation ("OPIC"). The
Company is currently investigating its options for political risk insurance in
the Republic of Ghana in West Africa ("Ghana").
The Company and its partners underwent a tax examination related to their
ownership interests in the Yombo field offshore the Republic of Congo, for the
years 1994 through 1997. On June 25, 1999, the Company and its partners settled
this tax assessment for a total of $1.0 million, of which the Company's share
was $400,000.
In connection with their respective acquisitions of two subsidiaries owning
interests in the Yombo field offshore West Africa (each a "Congo subsidiary"),
the Company and a wholly-owned subsidiary of CMS NOMECO Oil & Gas Co. ("CMS")
agreed with the seller not to claim certain tax losses incurred by such
subsidiaries prior to the acquisitions. Pursuant to the agreement, the Company
and CMS may be liable to the seller for the recapture of these tax losses
utilized by the seller in years prior to the acquisitions if certain triggering
events occur. A triggering event will not occur, however, if a subsequent
purchaser enters into certain agreements specified in the consolidated return
regulations intended to ensure that such losses will not be claimed. The
Company's potential direct liability could be as much as $50.0 million if a
triggering event with respect to the Company occurs, and the Company believes
that CMS's liability (for which the Company would be jointly liable with an
indemnification right against CMS) could be as much as $67.0 million. The
Company does not expect a triggering event to occur with respect to it or CMS
and does not believe the agreement will have a material adverse effect upon the
Company.
8. ACQUISITIONS
In June 1999, the Company acquired oil properties located onshore and
offshore California for $61.4 million from Texaco, Inc. To purchase these
assets, the Company sued funds from a $100.0 million interest-bearing escrow
account that provided "like-kind exchange" tax treatment for the purchase of
domestic oil and gas producing properties. The escrow account was created with
proceeds from the Company's January 1999 sale of its East Texas natural gas
assets (see discussion in Note 9 below). Following the Texaco transaction, the
$41.0 million remaining
F-9
<PAGE> 138
in the escrow account, which included $2.4 million of interest income, was used
to repay a portion of the outstanding bank debt in early July 1999.
The acquired properties had estimated net proved reserves at June 30, 1999
of 33.7 million barrels of oil equivalent (BOE") and will increase the Company's
production from California by approximately 5.0 thousand BOE per day. All of
these properties are additional interests in the Company's existing properties
or are located near its existing properties. The acquisition includes interests
in Cymric, East Colainga, Dos Cuadras and other fields the Company operates.
9. DIVESTITURES
On January 6, 1999, the Company completed the sale of its East Texas
natural gas assets to an affiliate of Samson Resources Company for an adjusted
purchase price of approximately $191.0 million. Of the proceeds, $100.0 million
was set aside to fund an escrow account, as discussed above in Note 8. The
remainder of the proceeds were used to repay outstanding senior bank debt. The
Company realized an $80.3 million adjusted pre-tax gain on the sale of the East
Texas natural gas assets resulting in the realization of $14.6 million of the
Company's deferred tax asset. A $5.2 million gain on settled hedge transactions
was realized in connection with the closing this sale in 1999. The effective
date of the sale is July 1, 1998. The Company reclassified these assets to
assets held for sale and discontinued depleting these assets during the third
quarter of 1998. Estimated net proved reserves associated with these properties
totaled approximately 329.0 billion cubic feet of natural gas equivalent at
January 1, 1999.
F-10
<PAGE> 139
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Nuevo Energy Company:
We have audited the accompanying consolidated balance sheets of Nuevo
Energy Company and subsidiaries as of December 31, 1998 and 1997, and the
related consolidated statements of operations, changes in stockholders' equity
and cash flows for each of the years in the three-year period ended December 31,
1998. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Nuevo Energy
Company and subsidiaries as of December 31, 1998 and 1997, and the results of
their operations and their cash flows for each of the years in the three-year
period ended December 31, 1998, in conformity with generally accepted accounting
principles.
As discussed in Note 2 to the consolidated financial statements, the
Company has given retroactive effect to the change in accounting for oil and gas
properties from the full cost method to the successful efforts method in 1998.
/s/ KPMG LLP
Houston, Texas
March 25, 1999
F-11
<PAGE> 140
NUEVO ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
(AMOUNTS IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
ASSETS:
DECEMBER 31,
------------------------
1998 1997*
----------- ----------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents ............................................................................ $ 7,403 $ 9,208
Accounts receivable .................................................................................. 25,096 38,196
Product inventory .................................................................................... 5,998 1,627
Assets held for sale ................................................................................. 120,055 6,950
Prepaid expenses and other ........................................................................... 2,700 2,879
----------- ----------
Total current assets .......................................................................... 161,252 58,860
----------- ----------
PROPERTY AND EQUIPMENT, at cost:
Land ................................................................................................. 51,038 51,411
Oil and gas properties (successful efforts method) ................................................... 959,348 984,273
Gas plant facilities ................................................................................. 17,112 15,500
Other facilities ..................................................................................... 6,696 7,831
----------- ----------
1,034,194 1,059,015
Accumulated depreciation, depletion and amortization ................................................. (417,622) (324,904)
----------- ----------
616,572 734,111
----------- ----------
DEFERRED TAX ASSETS, net ............................................................................... 27,534 --
OTHER ASSETS ........................................................................................... 12,327 11,315
----------- ----------
$ 817,685 $ 804,286
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY:
CURRENT LIABILITIES:
Accounts payable ..................................................................................... $ 24,393 $ 17,062
Accrued interest ..................................................................................... 4,161 4,285
Accrued drilling costs ............................................................................... 8,380 12,781
Accrued lease operating costs ........................................................................ 4,694 8,891
Other accrued liabilities ............................................................................ 4,843 2,868
Current maturities of long-term debt ................................................................. 3,152 3,716
----------- ----------
Total current liabilities ..................................................................... 49,623 49,603
----------- ----------
LONG-TERM DEBT, NET OF CURRENT MATURITIES .............................................................. 419,150 305,940
DEFERRED TAX LIABILITIES ............................................................................... -- 4,986
OTHER LONG-TERM LIABILITIES ............................................................................ 2,034 4,018
COMPANY-OBLIGATED MANDATORILY REDEEMABLE CONVERTIBLE
PREFERRED SECURITIES OF NUEVO FINANCING I ............................................................ 115,000 115,000
CONTINGENCIES
STOCKHOLDERS' EQUITY:
Preferred stock, $1.00 par value, 10,000,000 shares authorized; 7% Cumulative Convertible
Preferred Stock, none issued and outstanding at December 31, 1998 and 1997 ........................ -- --
Common stock, $.01 par value, 50,000,000 shares authorized, 20,308,462 and
20,237,537 shares issued at December 31, 1998 and 1997, respectively ............................. 203 202
Additional paid-in capital ........................................................................... 355,600 354,296
Treasury stock, at cost, 473,876 and 497,372 shares, at December 31, 1998 and 1997, respectively ..... (19,335) (19,929)
Stock held by benefit trust, 47,759 and 45,119 shares, at December 31, 1998 and 1997, respectively ... (1,732) (1,244)
Accumulated deficit
(102,858) (8,586)
----------- ----------
Total stockholders' equity .................................................................... 231,878 324,739
----------- ----------
$ 817,685 $ 804,286
=========== ===========
</TABLE>
- ----------------
* Restated
See Notes to Consolidated Financial Statements.
F-12
<PAGE> 141
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1998 1997* 1996*
--------- --------- ---------
<S> <C> <C> <C>
REVENUES:
Oil and gas revenues ............................................... $ 240,010 $ 331,973 $ 279,859
Gas plant revenues ................................................. 2,665 14,826 34,802
Pipeline and other revenues ........................................ 2,700 5,772 6,774
Gain on sale of assets, net ........................................ 5,768 1,372 6,008
Interest and other income .......................................... 1,560 3,335 1,614
--------- --------- ---------
252,703 357,278 329,057
--------- --------- ---------
COSTS AND EXPENSES:
Lease operating expenses ........................................... 134,704 120,042 93,062
Gas plant operating expenses ....................................... 3,202 13,356 29,311
Pipeline and other operating costs ................................. 2,028 5,243 6,105
Exploration costs .................................................. 16,562 11,082 4,571
(Revision of) provision for impairment on assets held for sale ..... (3,740) 23,942 --
Provision for impairment of oil and gas properties ................. 68,904 30,000 --
General and administrative expenses ................................ 18,633 19,822 14,880
Outsourcing fees ................................................... 9,461 11,984 10,249
Depreciation, depletion and amortization ........................... 85,036 102,158 75,664
Interest expense ................................................... 32,471 27,357 36,009
Dividends on Guaranteed Preferred Beneficial Interests in
Company's Convertible Debentures (TECONS) ....................... 6,613 6,613 165
Other expense ...................................................... 5,726 3,019 1,069
--------- --------- ---------
379,600 374,618 271,085
--------- --------- ---------
(Loss) income before income taxes, minority interest and
extraordinary item ................................................. (126,897) (17,340) 57,972
Income tax (benefit) expense ......................................... (32,625) (6,656) 23,965
Minority interest in loss of subsidiary .............................. -- (8) (271)
--------- --------- ---------
(Loss) income before extraordinary item .............................. (94,272) (10,676) 34,278
Extraordinary loss on early extinguishment of debt, net of
income tax benefit of $2,037 ....................................... -- 3,024 --
--------- --------- ---------
Net (loss) income .................................................... (94,272) (13,700) 34,278
Dividends on preferred stock ......................................... -- -- 939
--------- --------- ---------
Net (loss) income available to common stockholders ................... $ (94,272) $ (13,700) $ 33,339
========= ========= =========
(Loss) earnings per common share -- Basic:
(Loss) income before extraordinary item (net of dividends
on preferred stock) ............................................. $ (4.76) $ (0.54) $ 1.99
Extraordinary loss on early extinguishment of debt, net of
income tax benefit .............................................. -- (0.15) --
--------- --------- ---------
Net (loss) income .................................................. $ (4.76) $ (0.69) $ 1.99
========= ========= =========
Weighted average Common shares outstanding ........................... 19,795 19,796 16,755
========= ========= =========
(Loss) earnings per Common share-- Diluted:
(loss) income before extraordinary item ............................ $ (4.76) $ (0.54) $ 1.84
Extraordinary loss on early extinguishment of debt, net of
income tax benefit .............................................. -- (0.15) --
--------- --------- ---------
Net (loss) income .................................................. $ (4.76) $ (0.69) $ 1.84
========= ========= =========
Weighted average Common and dilutive potential Common shares
outstanding ........................................................ 19,795 19,796 18,596
========= ========= =========
</TABLE>
- ------------------
* Restated
See Notes to Consolidated Financial Statements.
F-13
<PAGE> 142
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
COMMON STOCK PREFERRED STOCK ADDITIONAL STOCK HELD RETAINED TOTAL
-------------- --------------- PAID-IN TREASURY BY BENEFIT EARNINGS STOCKHOLDERS'
SHARES AMOUNT SHARES AMOUNT CAPITAL STOCK TRUST (DEFICIT) EQUITY
------ ------ ------ ------- ----------- --------- ---------- --------- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
January 1, 1996* .................. 11,717 $ 117 15 $ 15 $ 151,442 $ -- $ -- $ (28,225) $ 123,349
Issuance of Common Stock .......... 6,384 64 -- -- 172,147 -- -- -- 172,211
Exercise of stock options and
related tax benefit ............. 587 6 -- -- 14,718 -- -- -- 14,724
Issuance of non-employee stock
options ......................... -- -- -- -- 244 -- -- -- 244
Issuance of warrants .............. -- -- -- -- 1,575 -- -- -- 1,575
Conversion of Preferred Stock ..... 1,164 12 (15) (15) -- -- -- -- (3)
Preferred Stock dividends ......... -- -- -- -- -- -- -- (939) (939)
Net income* ....................... -- -- -- -- -- -- -- 34,278 34,278
------ ------ ---- ------ --------- --------- -------- ------- ---------
December 31, 1996* ................ 19,852 199 -- -- 340,126 -- -- 5,114 345,439
====== ====== ==== ====== ========= ========= ======== ======= =========
Exercise of stock options and
related tax benefit ............. 386 3 -- -- 11,332 -- -- -- 11,335
Stock put options ................. -- -- -- -- 1,630 -- -- -- 1,630
Employee stock awards ............. -- -- -- -- 1,208 -- -- -- 1,208
Purchase of Treasury Shares ....... -- -- -- -- -- (21,173) -- -- (21,173)
Stock held by benefit trust ....... -- -- -- -- -- 1,244 (1,244) -- --
Net loss* ......................... -- -- -- -- -- -- -- (13,700) (13,700)
------ ------ ---- ------ --------- --------- -------- ------- ---------
December 31, 1997* ................ 20,238 202 -- -- 354,296 (19,929) (1,244) (8,586) 324,739
====== ====== ==== ====== ========= ========= ======== ======= =========
Exercise of stock options and
related tax benefit ............. 70 1 -- -- 1,304 -- -- -- 1,305
Stock held by benefit trust ....... -- -- -- -- -- 488 (488) -- --
Sale of Treasury Shares ........... -- -- -- -- -- 106 -- -- 106
Net loss .......................... -- -- -- -- -- -- -- (94,272) (94,272)
------ ------ ---- ------ --------- --------- -------- ------- ---------
December 31, 1998 ................. 20,308 $ 203 -- -- $ 355,600 $ (19,335) $ (1,732) $(102,858) $ 231,878
====== ====== ==== ====== ========= ========= ======== ======= =========
</TABLE>
- --------------
* Restated
See Notes to Consolidated Financial Statements.
F-14
<PAGE> 143
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1998 1997* 1996*
--------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income ............................................................................ $ (94,272) $ (13,700) $ 34,278
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization .................................................. 85,036 102,158 75,664
Dry hole costs ............................................................................ 12,962 9,311 3,145
Amortization of debt financing costs ...................................................... 1,643 1,513 1,370
Amortization of deferred revenue .......................................................... (1,625) (3,203) (4,104)
(Revision of) provision for impairment on assets held for sale ............................ (3,740) 23,942 --
Provision for impairment of oil and gas properties ........................................ 68,904 30,000 --
Gain on sale of assets, net ............................................................... (5,768) (1,372) (6,008)
Loss on early extinguishment of debt ...................................................... -- 5,061 --
Employee stock awards ..................................................................... -- 1,208 --
Deferred taxes ............................................................................ (32,520) (9,249) 22,465
Depreciation of deferred compensation liability ........................................... (1,138) -- --
Minority interest ......................................................................... -- (8) (271)
--------- --------- ---------
29,482 145,661 126,539
Changes in assets and liabilities, net of acquisition effects:
Accounts receivable .......................................................................... 13,051 578 (21,086)
Gas imbalances ............................................................................... 333 20 (198)
Accounts payable ............................................................................. 6,634 1,663 14,574
Accrued liabilities .......................................................................... (5,813) 13,719 11,316
Other ........................................................................................ (7,854) 3,821 (4,224)
--------- --------- ---------
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES ...................................... 35,833 165,462 126,921
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to land ............................................................................ -- -- (51,638)
Additions to oil and gas properties .......................................................... (157,352) (195,108) (515,985)
Proceeds from sale of gas plant .............................................................. -- 24,992 --
Proceeds from sales of properties ............................................................ 11,830 2,385 42,700
Additions to gas plant and other facilities .................................................. (2,813) (1,747) (21,079)
--------- --------- ---------
NET CASH FLOWS USED IN INVESTING ACTIVITIES .......................................... (148,335) (169,478) (546,002)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings ..................................................................... 240,900 234,000 408,000
Debt issuance costs .......................................................................... (3,360) -- (10,920)
Net proceeds from issuance of common stock ................................................... -- -- 138,327
Payments of long-term debt ................................................................... (128,254) (217,503) (232,359)
Preferred stock dividends .................................................................... -- -- (939)
Proceeds from exercise of stock options ...................................................... 1,305 6,074 10,003
Proceeds from issuance of Company-Obligated Mandatorily Redeemable
Convertible Preferred Securities of Nuevo Financing I ..................................... -- -- 115,000
Premium on early extinguishment of debt ...................................................... -- (3,440) --
Proceeds from sale of stock put options ...................................................... -- 1,630 --
Proceeds from sale of treasury stock ......................................................... 106 -- --
Purchase of treasury shares .................................................................. -- (21,173) --
Cash distribution to minority interest owner ................................................. -- -- (160)
--------- --------- ---------
NET CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES ............................ 110,697 (412) 426,952
--------- --------- ---------
Net (decrease) increase in cash and cash equivalents ........................................... (1,805) (4,428) 7,871
Cash and cash equivalents at beginning of year ................................................. 9,208 13,636 5,765
--------- --------- ---------
Cash and cash equivalents at end of year ....................................................... $ 7,403 $ 9,208 $ 13,636
========= ========= =========
</TABLE>
- ------------------
* Restated
See Notes to Consolidated Financial Statements.
F-15
<PAGE> 144
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION
Nuevo Energy Company ("Nuevo") was formed as a Delaware corporation on
March 2, 1990, to acquire the businesses of certain public and private
partnerships (collectively "Predecessor Partnerships"). On July 9, 1990, the
plan of consolidation ("Plan of Consolidation") was approved by limited partners
owning a majority of units of limited partner interests in the partnerships
whereby the net assets of the Predecessor Partnerships, which were subject to
such Plan of Consolidation, were exchanged for Common Stock of Nuevo ("Common
Stock"). All references to the "Company" include Nuevo and its majority and
wholly-owned subsidiaries, unless otherwise indicated or the context indicates
otherwise.
The Company is primarily engaged in the exploration for, and the
acquisition, exploitation, development and production of crude oil and natural
gas. The Company's principal oil and gas properties are located domestically
onshore and offshore California, in East Texas and the onshore Gulf Coast
region; and internationally offshore West Africa.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements include the accounts of Nuevo and its
majority and wholly-owned subsidiaries. The Company's 48.5% general partner
interest in Richfield Gas Storage Partnership was pro rata consolidated through
February 1998, at which time the Company's interest was sold. The consolidated
financial statements also include Bright Star Gathering, Inc., which was 80%
owned by the Company until it was sold in July 1998. NuStar Joint Venture and
its 66.7% investment in the Benedum Plant System, of which the Company owned a
95% interest, was pro rata consolidated through May 2, 1997, at which time the
Company's interest was sold. Minority interests have been deducted from results
of operations and stockholders' equity in the appropriate periods. All
significant intercompany accounts and transactions have been eliminated in
consolidation.
Change in Accounting Method
Effective January 1, 1998, the Company elected to convert from the full
cost method to the successful efforts method of accounting for its investments
in oil and gas properties. The Company believes that the successful efforts
method of accounting is preferable, as it will provide a fair presentation of
the Company's development activities in its core California business and the
drilling success of its selective exploration activities, and reflect an
impairment in the carrying value of its oil and gas properties only when there
has been a permanent decline in their fair value. Accordingly, all prior year
financial statements have been restated to conform with successful efforts
accounting. The effect, after tax, of the change in accounting method as of
December 31, 1997, was a reduction to retained earnings of $64.1 million,
primarily attributable to a decrease in net property and equipment and the
deferred tax liability of $99.2 million and $38.0 million, respectively. The
change in accounting method resulted in a decrease in net income of $32.5
million ($1.64 per share -- basic and diluted) and $0.4 million ($0.02 per share
- -- basic and diluted) during 1997 and 1996, respectively. Had the Company not
converted to the successful efforts method, the results of operations for the
three months ended March 31, 1998, would have included a pre-tax full cost
ceiling write-down of approximately $250.0 million.
F-16
<PAGE> 145
Oil and Gas Properties
The Company utilizes the successful efforts method of accounting for its
investments in oil and gas properties. Under successful efforts, oil and gas
lease acquisition costs and intangible drilling costs associated with
exploration efforts that result in the discovery of proved reserves and costs
associated with development drilling, whether or not successful, are capitalized
when incurred. When a proved property is sold, ceases to produce or is
abandoned, a gain or loss is recognized. When an entire interest in an unproved
property is sold for cash or cash equivalent, gain or loss is recognized, taking
into consideration any recorded impairment. When a partial interest in an
unproved property is sold, the amount received is treated as a reduction of the
cost of the interest retained.
Unproved leasehold costs are capitalized pending the results of exploration
efforts. Significant unproved leasehold costs are reviewed periodically and a
loss is recognized to the extent, if any, that the cost of the property has been
impaired. An impairment of unproved leasehold costs of $8.1 million was
recognized as of December 31, 1998. Exploration costs, including geological and
geophysical expenses, exploratory dry holes and delay rentals, are charged to
expense as incurred.
Costs of productive wells, development dry holes and productive leases are
capitalized and depleted on a unit-of-production basis over the life of the
remaining proved reserves. Capitalized drilling costs are depleted on a
unit-of-production basis over the life of the remaining proved developed
reserves. Estimated costs (net of salvage value) of dismantlement, abandonment
and site remediation are computed by the Company's independent reserve engineers
and are included when calculating depreciation and depletion using the
unit-of-production method.
The Company reviews proved oil and gas properties on a depletable unit
basis whenever events or circumstances indicate that the carrying value of those
assets may not be recoverable. For each depletable unit determined to be
impaired, an impairment loss equal to the difference between the carrying value
and the fair value of the depletable unit is recognized. Fair value, on a
depletable unit basis, is estimated to be the present value of the undiscounted
expected future net revenues computed by application of estimated future oil and
gas prices, production and expenses, as determined by management, to estimated
future production of oil and gas reserves over the economic life of the
reserves. If the carrying value exceeds the undiscounted future net revenues, an
impairment is recognized equal to the difference between the carrying value and
the discounted estimated future net revenues of that depletable unit. The
Company considers probable reserves and escalated commodity pricing in its
estimate of future net revenues. Fair value impairments of $60.8 million and
$30.0 million were recognized as of December 31, 1998 and 1997, respectively; no
such impairment was recognized during 1996.
Interest costs associated with non-producing leases and exploration and
development projects are capitalized only for the period that activities are in
progress to bring these projects to their intended use. The capitalization rates
are based on the Company's weighted average cost of funds used to finance
expenditures.
Any reference to oil and gas reserve information in the Notes to
Consolidated Financial Statements is unaudited.
F-17
<PAGE> 146
Environmental Liabilities
Environmental expenditures that relate to current or future revenues are
expensed or capitalized as appropriate. Expenditures that relate to an existing
condition caused by past operations, and do not contribute to current or future
revenue generation, are expensed. Liabilities are recorded when environmental
assessments and/or clean-ups are probable, and the costs can be reasonably
estimated. Generally, the timing of these accruals coincides with the Company's
commitment to a formal plan of action.
Gas Plant and Other Facilities
Gas plant and other facilities include the costs to acquire certain gas
plant and other facilities and to secure rights-of-way. Capitalized costs
associated with gas plant and other facilities are amortized primarily over the
estimated useful lives of the various components of the facilities utilizing the
straight-line method. The estimated useful lives of such assets range from three
to thirty years. The Company reviews these assets for impairment whenever events
or changes in circumstances indicate that their carrying amounts may not be
recoverable.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities". This statement, as amended,
establishes standards of accounting for and disclosures of derivative
instruments and hedging activities. This statement requires all derivative
instruments to be carried on the balance sheet at fair value and is effective
for the Company beginning January 1, 2001, however, early adoption is permitted.
The Company has not yet determined the impact of this statement on its financial
condition or results of operations or whether it will adopt the statement early.
Comprehensive Income
The Company adopted SFAS No. 130, "Reporting Comprehensive Income",
effective January 1, 1998. Comprehensive income includes net income and all
changes in an enterprise's other comprehensive income including, among other
things, foreign currency translation adjustments, and unrealized gains and
losses on certain investments in debt and equity securities. The implementation
of this statement had no impact on the Company, as there are no differences
between comprehensive (loss) income and net (loss) income for the periods
presented.
Gas Balancing Positions
The Company uses the entitlement method for recording sales of natural gas.
Under the entitlement method, revenue is recorded based on the Company's net
revenue interest in production. Deliveries of natural gas in excess of the
Company's net revenue interests are recorded as liabilities and under-deliveries
are recorded as assets. Production imbalances are recorded at the lower of the
sales price in effect at the time of production or the current market value.
Substantially all such amounts are anticipated to be settled with production in
future periods.
F-18
<PAGE> 147
Derivative Financial Instruments
The Company utilizes derivative financial instruments to reduce its
exposure to changes in the market prices of natural gas and crude oil. Commodity
derivatives utilized as hedges include futures, swap and option contracts, which
are used to hedge natural gas and oil prices. Commodity price and basis swaps
are sometimes used to hedge the basis differential between the derivative
financial instrument index price and the commodity field price. In order to
qualify as a hedge, price movements in the underlying commodity derivative must
be highly correlated with the hedged commodity. Settlement of gains and losses
on price swap contracts are realized monthly, generally based upon the
difference between the contract price and the average closing New York
Mercantile Exchange ("NYMEX") price and are reported as a component of oil and
gas revenues and operating cash flows in the period realized.
Gains and losses on option and futures contracts that qualify as a hedge of
firmly committed or anticipated purchases and sales of oil and gas commodities
are deferred on the balance sheet and recognized in income when the related
hedged transaction occurs. Premiums paid on option contracts are deferred in
other assets and amortized into oil and gas revenues over the terms of the
respective option contracts. Gains or losses attributable to the termination of
a derivative financial instrument are deferred on the balance sheet and
recognized in revenue when the hedged crude oil and natural gas is sold. There
were no such deferred gains or losses at December 31, 1998 or 1997. Gains or
losses on derivative financial instruments that do not qualify as a hedge are
recognized in income currently.
As a result of such hedging transactions, oil and gas revenues were
increased by $0.6 million in 1998, and were reduced by $6.0 million and $2.5
million in 1997 and 1996, respectively.
Earnings per Share ("EPS")
Basic EPS is computed by dividing income available to common stockholders
by the weighted-average number of common shares outstanding for the period.
Diluted EPS reflects the potential dilution that could occur if securities or
other contracts to issue Common Stock were exercised or converted into Common
Stock or resulted in the issuance of Common Stock that then shared in the
earnings of the entity. For the years ended December 31, 1998 and 1997, the
Company did not have any potentially dilutive securities, as net losses were
incurred during these periods. For the year ended December 31, 1996, the
Company's potentially dilutive securities included dilutive stock options.
Potential dilution may also occur in future periods due to the Company-Obligated
Mandatorily Redeemable Convertible Preferred Securities of Nuevo Financing I
("TECONS").
Stock-Based Compensation
The Company applies the intrinsic value method for accounting for stock and
stock-based compensation described by Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees". Had the Company applied the fair
value method described by SFAS No. 123, "Accounting for Stock-Based
Compensation", it would have incurred compensation expense for stock-based
compensation in 1998, 1997 and 1996. (See Note 8 for the SFAS No. 123 pro forma
effects on income and earnings per share.)
Income Taxes
Deferred taxes are accounted for under the asset and liability method of
accounting for income taxes. Under this method, deferred income taxes are
recognized for the tax consequences of "temporary differences" by applying
enacted statutory tax rates applicable to future years to
F-19
<PAGE> 148
differences between the financial statement carrying amounts and the tax basis
of existing assets and liabilities. The effect on deferred taxes of a change in
tax rates is recognized in income in the period the change occurs.
Statements of Cash Flows
For cash flow presentation purposes, the Company considers all highly
liquid money market instruments with an original maturity of three months or
less to be cash equivalents. Interest paid in cash, net of amounts capitalized,
for 1998, 1997 and 1996 was $31.6 million, $28.2 million and $30.6 million,
respectively. Net amounts paid (refunded) in cash for income taxes for 1998,
1997 and 1996 were $1,332,000, ($45,000) and $1,500,000, respectively.
Product Inventory
Inventory relating to quantities of processed fuel oil and natural gas
liquids in storage as of the balance sheet date is carried at current market
pricing. The Company recognizes revenue for fuel oil sales when the sale is
completed and risk of loss transfers to a third party purchaser. Fuel oil in
inventory is stated at year end market prices less transportation costs; the
Company recognizes changes in the market value of inventory from one period to
the next as oil revenues.
Use of Estimates
In order to prepare these financial statements in conformity with generally
accepted accounting principles, management of the Company has made a number of
estimates and assumptions relating to the reporting of assets and liabilities
and the disclosure of contingent assets and liabilities, as well as reserve
information, which affects the depletion calculation. Actual results could
differ from those estimates.
Reclassifications
Certain reclassifications of prior period amounts have been made to conform
to the current presentation.
3. ACQUISITIONS
In April 1998, the Company acquired a third party's interest in the Yombo
field in the Republic of Congo, West Africa ("Congo") for $7.8 million. Such
acquisition added 3.4 million barrels of oil equivalent to the Company's reserve
base and increased the Company's net working interest in the Congo from 43.75%
to 50.0%.
In July 1996, the Company completed the acquisition of certain East Texas
oil and gas properties for a net purchase price of $9.3 million in cash. The
acquisition of these properties was effective as of December 1, 1995, and the
purchase price was reduced by the net cash flows from production between such
date and closing. In December 1996, the holders of the preferential rights on
these properties exercised such rights for a cash payment of $8.0 million,
acquiring properties constituting approximately half of the estimated proved
reserves related to this acquisition.
In April 1996, the Company consummated the acquisition of (i) certain
upstream oil and gas properties located onshore and offshore California ("Unocal
Properties") of Union Oil Company of California ("Unocal") for an adjusted
purchase price of $490.2 million in cash plus a contingent payment based on
future realized oil prices, and (ii) certain California oil properties ("Point
F-20
<PAGE> 149
Pedernales Properties", and together with the Unocal Properties, the "California
Properties") from Torch Energy Advisors Incorporated ("Torch") and certain of
its wholly-owned subsidiaries for a net adjusted purchase price of $35.7 million
in Common Stock of the Company. The acquisition of the California Properties was
effective as of October 1, 1995, and the purchase price was reduced by the net
cash flows from production between such date and closing. The acquisition was
recorded using the purchase method, effective April 1, 1996 for accounting
purposes.
4. DIVESTITURES
On January 6, 1999, the Company completed the sale of its East Texas
natural gas assets to an affiliate of Samson Resources Company for an adjusted
purchase price of $192.0 million. Of the proceeds, $100.0 million was set aside
to fund an escrow account to provide "like-kind exchange" tax treatment in the
event the Company acquires domestic producing oil and gas properties in the
first half of 1999. The remainder of the proceeds were used to repay outstanding
senior bank debt. A $5.2 million gain on settled hedge transactions was realized
in connection with the closing of this sale in 1999. The effective date of the
sale is July 1, 1998. The Company reclassified these assets to assets held for
sale and discontinued depleting these assets during the third quarter of 1998.
Estimated net proved reserves associated with these properties totaled
approximately 329.0 billion cubic feet of natural gas equivalent at January 1,
1999. The following condensed balance sheet reflects the pro forma effects of
the sale of the East Texas assets:
CONDENSED BALANCE SHEET
<TABLE>
<CAPTION>
PRO FORMA
DECEMBER 31, ADJUSTMENTS DECEMBER 31,
1998 (SALE OF E. TX) 1998
----------- --------------- -----------
(UNAUDITED) (UNAUDITED)
<S> <C> <C> <C>
ASSETS:
Current assets ............................ $ 161,252 $ (10,055) $ 151,197
Net property and equipment ................ 616,572 -- 616,572
Deferred tax assets, net .................. 27,534 (15,222) 12,312
Other assets .............................. 12,327 -- 12,327
--------- --------- ---------
$ 817,685 $ (25,277) $ 792,408
========= ========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY:
Current liabilities ....................... $ 49,623 $ (9,530) $ 40,093
Long-term debt ............................ 419,150 (82,633) 336,517
Deferred tax liabilities .................. -- -- --
Deferred revenue .......................... -- -- --
Other long-term liabilities ............... 2,034 -- 2,034
TECONS .................................... 115,000 -- 115,000
Stockholders' equity ...................... 231,878 66,886 298,764
--------- --------- ---------
$ 817,685 $ (25,277) $ 792,408
========= ========= =========
</TABLE>
During the third quarter of 1998, the Company sold its interest in the
Sansinena field in California, and recorded a gain on the sale of $4.1 Million.
During the first quarter of 1998, the Company sold its interest in the Coke
Field in Chapel Hill, Texas, and recorded a $1.7 Million gain on this sale.
In december 1997, the Company announced its intention to dispose of the
remainder of its non- core gas gathering, pipeline and storage assets during
1998. Such assets include: the Company's 48.5% interest in the Richfield Gas
Storage facility, which was sold in February 1998 at its
F-21
<PAGE> 150
approximate carrying value; an 80% interest in Bright Star Gathering, Inc.,
which was sold in July 1998 at its approximate carrying value; and the Illini
pipeline. The Company recorded a non-cash, pre-tax charge to fourth quarter 1997
earnings of $23.9 million, reflecting the estimated loss on the disposition of
these assets. A positive revision to this charge was made in the fourth quarter
of 1998 in the amount of $3.7 Million to reflect the estimated current fair
value of the Illini pipeline. The Company entered into a sale agreement during
1998 to sell the Illini pipeline to a third party. Such sale is currently
pending and awaiting regulatory approval. The Company's results of operations
for the year ended December 31, 1998, included the operating results from these
assets through the disposition date, as applicable; however, these assets were
not depreciated during 1998. The Company will retain its California gas plants,
as these plants are strategic assets for the Company's oil and gas activities in
California.
In May 1997, Nuevo Liquids, a wholly-owned subsidiary of the Company, sold
its 95% interest in the Nustar Joint Venture, which held the Company's
investment in the Benedum Plant System, for proceeds of $25.0 million. The
effective date of the sale was January 1, 1997. Proceeds from the sale were used
to reduce outstanding debt under the Company's revolving credit facility, as
well as project debt related to the Benedum Gas Plant in the amount of $5.9
Million. The Company recorded a pre-tax gain of $2.3 million relating to the
sale.
During the first quarter of 1997, the Company sold its interest in the
Second Bayou Field in Cameron Parish, Louisiana and recorded a gain of $1.4
million. During the third quarter of 1997, the Company recognized a loss of $1.6
million on the sale of South Timbalier Block 8. In addition, the Company
disposed of several non-core properties at a combined net loss of $679,000.
In June 1996, the Company sold 177 producing wells and the majority of its
acreage in the Giddings field and East Texas Austin Chalk holdings for $27.3
million recognizing a gain of $9.2 million. The Company retained ownership of
seven wells and surrounding acreage in the Turkey Creek prospect area of the
Austin Chalk trend. The Company also sold several non-core properties at a
combined loss of $3.2 million.
5. PRODUCTION PAYMENTS
In April 1994, the Company entered into a four-year commitment for a $30.0
million volumetric production payment for the development of certain infill
drilling locations in the Oak Hill field in East Texas. The proceeds from this
agreement financed the capital expenditures for well drilling, fracturing and
completing and for surface facility installations. Each advance under the
production payment obligates the Company to deliver a fixed volume of natural
gas, based upon prevailing market conditions at the time of the advance. During
1994, the Company received $18.4 million, committing the Company to deliver 10.7
BCF of natural gas through December 1998. As of December 31, 1998, the Company
had fulfilled its obligation under this commitment. The cash advances were
reflected as deferred revenues on the Company's December 31, 1997 consolidated
balance sheet and were amortized into revenue as the natural gas volumes were
delivered. No such advances were received in 1998, 1997 or 1996.
6. OUTSOURCING SERVICES
Torch, the Company's outside service provider, is primarily in the business
of providing management and advisory services relating to oil and gas assets for
institutional and public investors and maintains a large technical, operating,
accounting and administrative staff.
F-22
<PAGE> 151
In early 1999, Nuevo signed new outsourcing agreements with Torch and its
subsidiaries, effective January 1, 1999, to provide the following services: (i)
oil and gas administration (accounting, information technology and land
administration); (ii) human resources; (iii) corporate administration (legal,
graphics, support, and corporate insurance); (iv) crude oil marketing; (v)
natural gas marketing; (vi) land leasing, and (vii) field operations. Each of
the new agreements is stand alone, with different terms ranging from one to five
years. In addition, the Company executed a Master Services Agreement with Torch,
which contains all the overall terms and conditions governing each individual
service agreement. Several functions, such as mergers and acquisitions and
internal audit, will be brought in-house. The Company is still in the process of
finalizing the field operations agreement with Torch, but anticipates signing
this agreement in late March 1999.
Prior to January 1, 1999, the Company's outsourcing services were governed
by an agreement with Torch (the "Torch Agreement") whereby Torch administered
certain business activities of the Company for a monthly fee. The Torch
Agreement required Torch to administer the business activities of the Company
for a monthly fee equal to the sum of one-twelfth of 2% on the first $250
million of assets and one-twelfth of 1% on assets in excess of $250 million,
excluding certain gas plant facilities and cash, plus 2% of monthly operating
cash flows (as defined) during the period in which the services were rendered.
In addition, the Torch Agreement contained a provision whereby 20% of the
overhead fees on Torch operated properties were credited against the monthly fee
paid to Torch, as well as a provision whereby the monthly fee was credited for
one-twelfth of $900,000. For the years ended December 31, 1998, 1997 and 1996,
outsourcing fees paid to Torch amounted to $9.5 million, $12.0 million and $10.2
million, respectively.
A subsidiary of Torch markets oil, natural gas and natural gas liquids from
certain oil and gas properties and gas plants in which the Company owns an
interest. In 1998, 1997 and 1996, such marketing fees were $2.0 million, $2.9
million and $2.8 million, respectively.
Torch operates certain oil and gas interests owned by the Company. The
Company is charged, on the same basis as other third parties, for all customary
expenses and cost reimbursements associated with these activities. Operator's
fees charged for these activities for the years ended December 31, 1998, 1997
and 1996, was $25.5 million, $24.8 million and $8.8 million, respectively.
In consideration of the services rendered by Torch in connection with the
origination of the 1996 acquisition of the Unocal Properties, the Company agreed
to pay Torch $10.0 million in twelve equal monthly installments after the
closing of the acquisition.
7. RELATED PARTY TRANSACTIONS
A broker's fee of 30,000 warrants was granted to a company, of which a
director of the Company is a partner, for services associated with the
acquisition of the Unocal Properties. These warrants were exercised in the first
quarter of 1997.
Included in general and administrative expenses for 1997 was a $1.7 million
severance payment to the Company's former President and Chief Executive Officer.
F-23
<PAGE> 152
8. STOCKHOLDERS' EQUITY
Common and Preferred Stock
The Certificate of Incorporation of the Company authorizes the issuance of
up to 50,000,000 shares of Common Stock and 10,000,000 shares of Preferred
Stock, the terms, preferences, rights and restrictions of which are established
by the Board of Directors of the Company. All shares of Common Stock have equal
voting rights of one vote per share on all matters to be voted upon by
stockholders. Cumulative voting for the election of directors is not permitted.
Certain restrictions contained in the Company's loan agreements limit the amount
of dividends that may be declared. Under the terms of the most restrictive
indenture of the 87/8% Senior Subordinated Notes and the 9 1/2% Senior
Subordinated Notes described in Note 10, the Company and its restricted
subsidiaries had no funds available for the payment of dividends at December 31,
1998. However, the Company had unrestricted liquidity available through its
unrestricted subsidiaries at December 31, 1998.
On December 23, 1996, the Company and United Investors Management Company
("United") and The 1818 Fund, L.P. ("The 1818 Fund") closed the offering of
2,138,605 shares of Common Stock (the "Shares"). United sold 1,275,000 shares
and The 1818 Fund sold 863,605 shares. The price to the public of the Shares was
$47.50 per share. All of the Shares sold by United were outstanding and 112 of
the Shares sold by The 1818 Fund were outstanding prior to the offering. The
remaining 863,493 of the Shares sold by The 1818 Fund were issued upon
conversion of the remaining 11,220 shares of 7% Preferred Stock of the Company.
The Company did not receive any proceeds from the issuance of these shares. As a
result of this conversion by The 1818 Fund of its shares of 7% Preferred Stock,
there are no longer any shares of the 7% Preferred Stock outstanding.
During April 1996, the Company partially financed the acquisition of the
Unocal Properties with the proceeds from the sale to the public of 5,109,200
shares of Common Stock (the "Common Stock Offering"). The purchase of the Point
Pedernales Properties was financed by the issuance to Torch of 1,275,000 shares
of the Company's Common Stock valued at the public offering price of $28.00 per
share in the Common Stock Offering.
F-24
<PAGE> 153
EPS Computation
SFAS No. 128, "Earnings per Share", requires a reconciliation of the
numerator (income) and denominator (shares) of the basic EPS computation to the
numerator and denominator of the diluted EPS computation. In 1998 and 1997,
weighted average potential dilutive common shares of 331,000 and 670,000 are not
included in the calculation of diluted loss per share due to their anti-dilutive
effect. The Company's reconciliation is as follows (amounts in thousands):
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------
1998 1997* 1996*
---------------------- ---------------------- ---------------------
LOSS SHARES LOSS SHARES INCOME SHARES
-------- ------ -------- ------ -------- ------
<S> <C> <C> <C> <C> <C> <C>
(Loss) income before
extraordinary item ................... $(94,272) $(10,676) $ 34,278
Less: Dividends on Preferred
Stock ................................ -- -- (939)
-------- -------- --------
(Loss) earnings before
extraordinary item per
Common share-- Basic ................. (94,272) 19,795 (10,676) 19,796 33,339 16,755
Effect of dilutive securities:
Convertible Preferred
Stock ................................ -- -- -- -- 939 --
Stock options .......................... -- -- -- -- -- 1,841
-------- ------ -------- ------ -------- ------
(Loss) earnings before
extraordinary item per
Common share--Diluted ................ $(94,272) 19,795 $(10,676) 19,796 $ 34,278 18,596
======== ====== ======== ====== ======== ======
</TABLE>
- ---------------
* Restated
Treasury Stock Repurchases
In March 1997, the Board of Directors of the Company authorized the open
market repurchase of up to one million shares of outstanding Common Stock during
1997, at times and prices deemed attractive by management. During April 1997,
the Company repurchased 500,000 shares of Common Stock in open market
transactions, at an average purchase price of $38.94 per share, plus 42,491
shares acquired from the cancellation of warrants issued during 1996. In
December 1997, the Board of Directors authorized the open market repurchase of
an additional 500,000 shares of Common Stock during 1998, however, no such
repurchase occurred during 1998.
Put Options
In May 1997, the Company sold put options on its Common Stock to a third
party. The options gave the purchaser the right to sell to the Company 500,000
shares of its Common Stock at prices ranging from $40.26 to $41.04 per share
through December 31, 1997. The contract gave the Company the choice of net cash,
net shares, or physical settlement. Any repurchased shares would have been
treated as Treasury Stock. The Company generated $1.6 million in option premium
from these transactions, which is reflected in additional paid-in capital on the
balance sheet. As of December 31, 1997, 400,000 of these options had expired
with the Company's share prices above the strike price, and 100,000 of these
options were settled on December 31, 1997, for a nominal amount of net cash.
F-25
<PAGE> 154
Shareholder Rights Plan
In March 1997, the Company adopted a Shareholder Rights Plan to protect the
Company's shareholders from coercive or unfair takeover tactics. Under the
Shareholder Rights Plan, each outstanding share and each share of subsequently
issued Common Stock has attached to it one Right. Generally, in the event a
person or group ("Acquiring Person") acquires or announces an intention to
acquire beneficial ownership of 15% or more of the outstanding shares of Common
Stock without the prior consent of the Company, or the Company is acquired in a
merger or other business combination, or 50% or more of its assets or earning
power is sold, each holder of a Right will have the right to receive, upon
exercise of the Right, that number of shares of common stock of the acquiring
company, which at the time of such transaction will have a market price of two
times the exercise price of the Right. The Company may redeem the Right for $.01
at any time before a person or group becomes an Acquiring Person without prior
approval. The Rights will expire on March 21, 2007, subject to earlier
redemption by the Board of Directors of the Company.
Executive Compensation Plan
During July 1997, the Board of Directors of the Company adopted a plan to
encourage senior executives to personally invest in the shares of the Company,
and to regularly review executives' ownership versus targeted ownership
objectives. These incentives include a deferred compensation plan (the "Plan")
that gives key executives the ability to defer all or a portion of their
salaries and bonuses and invest in Common Stock of the Company at a discount to
market prices or make other investments at the employee's discretion. Stock
acquired at a discount will be held in a benefit trust and restricted for a two-
year period. The stock held in the benefit trust is accounted for as a liability
of the Company and is marked-to-market, with any necessary adjustment to general
and administrative expense. The Company recorded a benefit related to deferred
compensation of $0.6 million in 1998 and an expense of $0.8 million in 1997. The
Plan does not permit investment in a diversified equity portfolio until and
unless targeted levels of Common Stock ownership in the Company are achieved and
maintained. Target levels of ownership are based on multiples of base salary and
are administered by the Compensation Committee of the Board of Directors. The
Plan applies to all executives at a level of Vice-President and above.
Stock Incentive Plan
In 1990, the Company established its 1990 Stock Option Plan ("Stock Option
Plan"), with respect to its Common Stock, and in 1993, the Board of Directors
adopted the Nuevo Energy Company 1993 Stock Incentive Plan ("Stock Incentive
Plan"). The purpose of the Stock Option Plan and the Stock Incentive Plan is to
provide directors and key employees of the Company and its subsidiaries
performance incentives and to provide a means of encouraging stock ownership in
the Company by such persons.
The maximum number of shares subject to options under the Stock Incentive
Plan is 2,500,000 shares. Options are granted under the Stock Incentive Plan on
the basis of the optionee's contribution to the Company. No option may exceed a
term of more than ten years. Options granted under the Stock Incentive Plan may
be either incentive stock options or options that do not qualify as incentive
stock options. The Company's compensation committee is authorized to designate
the recipients of options, the dates of grants, the number of shares subject to
options, the option price, the terms of payment upon exercise of the options,
and the time during which the options may be exercised. Options granted are
exercisable, in full, six months following the date of the grant.
F-26
<PAGE> 155
A summary of activity in the stock option plans during the three years
ended 1998 is set forth below:
<TABLE>
<CAPTION>
WEIGHTED-
AVERAGE
OPTIONS EXERCISE PRICE
--------- --------------
<S> <C> <C>
Outstanding at January 1, 1996 ............................. 1,835,837 $17.97
Granted .................................................. 518,100 $38.10
Exercised ................................................ (587,799) $17.03
---------
Outstanding at December 31, 1996 ........................... 1,766,138 $24.24
Granted .................................................. 652,875 $41.89
Exercised ................................................ (328,550) $18.59
Canceled ................................................. (1,000) $47.88
---------
Outstanding at December 31, 1997 ........................... 2,089,463 $30.61
Granted .................................................. 1,124,800* $16.27
Exercised ................................................ (70,925) $18.35
Canceled ................................................. (466,975)* $36.19
---------
Outstanding at December 31, 1998 ........................... 2,676,363 $23.94
=========
</TABLE>
- ------------
* Reflects the cancellation and re-issuance of 401,850 non-executive employee
stock options on December 14, 1998.
The Company had 1,756,263 options and 1,493,088 options exercisable at
December 31, 1998 and 1997, respectively. Detail of stock options outstanding
and options exercisable at December 31, 1998 follows:
<TABLE>
<CAPTION>
OUTSTANDING EXERCISABLE
------------------------------------ ---------------------
WEIGHTED- WEIGHTED- WEIGHTED-
AVERAGE AVERAGE AVERAGE
REMAINING EXERCISE EXERCISE
RANGE OF EXERCISE PRICES NUMBER LIFE (YEARS) PRICE NUMBER PRICE
- ------------------------------ --------- ------------ --------- --------- ---------
<S> <C> <C> <C> <C> <C>
$11.00 to $12.38 ............. 738,934 9.54 $ 11.18 43,334 $ 11.64
$16.13 to $22.13 ............. 1,046,429 4.84 $ 19.52 821,929 $ 19.21
$29.00 to $39.93 ............. 322,000 6.46 $ 32.73 322,000 $ 32.73
$41.50 to $47.88 ............. 569,000 7.83 $ 43.70 569,000 $ 43.70
--------- ---------
Total .............. 2,676,363 1,756,263
========= =========
</TABLE>
F-27
<PAGE> 156
The weighted-average fair value of options granted during 1998, 1997 and
1996, was $7.55, $12.89 and $11.52, respectively. The fair value of each option
grant is estimated on the date of grant using the Black-Scholes option-pricing
model with the following weighted-average assumptions: expected stock price
volatility of 50.9% in 1998, 35.2% in 1997 and 33.6% in 1996; risk free interest
of 5% in 1998, 5.75% in 1997, and 6% in 1996, and average expected option lives
of 3 years. Had compensation expense for stock-based compensation been
determined based on the fair value at the date of grant, the Company's net
income, earnings available to Common Stockholders and earnings per share would
have been reduced to the pro forma amounts indicated below (amounts in
thousands, except per share data):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------
1998 1997* 1996*
----------- ----------- -----------
<S> <C> <C> <C> <C>
Net (loss) income ..................................... As reported $ (94,272) $ (13,700) $ 34,278
Pro forma $ (103,434) $ (16,315) $ 32,028
Net (loss) income available to Common
Stockholders ........................................ As reported $ (94,272) $ (13,700) $ 33,339
Pro forma $ (103,434) $ (16,315) $ 31,089
(Loss) earnings per Common share --
Basic ............................................... As reported $ (4.76) $ (0.69) $ 1.99
Pro forma $ (5.23) $ (0.82) $ 1.86
(Loss) earnings per Common share --
Diluted ............................................. As reported $ (4.76) $ (0.69) $ 1.84
Pro forma $ (5.23) $ (0.82) $ 1.72
</TABLE>
- ----------------
* Restated
9. COMPANY-OBLIGATED MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED SECURITIES
OF NUEVO FINANCING I
On December 23, 1996, the Company and Nuevo Financing I, a statutory
business trust formed under the laws of the state of Delaware, (the "Trust"),
closed the offering of 2,300,000 Term Convertible Securities, Series A,
("TECONS") on behalf of the Trust. The price to the public of the TECONS was
$50.00 per TECONS. Distributions on the TECONS began to accumulate from December
23, 1996, and are payable quarterly on March 15, June 15, September 15, and
December 15, at an annual rate of $2.875 per TECONS. Each TECONS is convertible
at any time prior to the close of business on December 15, 2026, at the option
of the holder into shares of Common Stock at the rate of .8421 shares of Common
Stock for each TECONS, subject to adjustment. The sole asset of the Trust as the
obligor on the TECONS is $115.0 million aggregate principal amount of 5.75%
Convertible Subordinated Debentures of the Company due December 15, 2026.
F-28
<PAGE> 157
10. LONG-TERM DEBT
Long-term debt is comprised of the following at December 31, 1998 and 1997
(amounts in thousands):
<TABLE>
<CAPTION>
1998 1997
--------- ---------
<S> <C> <C>
8 7/8% Senior Subordinated Notes, net of discount (a) .......... $ 100,000 $ --
9 1/2% Senior Subordinated Notes (b) ............................ 160,000 160,000
OPIC credit facility (at 5.55% and 6.04% at December 31,
1998 and 1997, respectively, plus a guaranty fee of 2.75%)
(c) ........................................................... 3,902 7,605
Bank credit facility (at 5.94% and 6.125%) at December 31,
1998 and 1997)(d) ............................................. 158,400 142,000
Other ........................................................... -- 51
--------- ---------
Total debt ............................................ 422,302 309,656
Less current maturities ......................................... (3,152) (3,716)
--------- ---------
Long-term debt .................................................. $ 419,150 $ 305,940
========= =========
</TABLE>
- ----------
(a) In June 1998, the Company issued $100.0 million, 8 7/8% Senior Subordinated
Notes due June 1, 2008 (the "8 7/8% Notes"). Interest on the 8 7/8% Notes
accrues at the rate of 8 7/8% per annum and is payable semi-annually in
arrears on June 1 and December 1. The 8 7/8% Notes are redeemable, in whole
or in part, at the option of the Company, on or after June 1, 2003, under
certain conditions. The Company is not required to make mandatory
redemption or sinking fund payments with respect to the 8 7/8% Notes. The
indenture contains covenants that, among other things, limit the Company's
ability to incur additional indebtedness, limits restricted payments, limit
issuances and sales of capital stock by restricted subsidiaries, limit
dispositions of proceeds of asset sales, limit dividends and other payment
restrictions affecting restricted subsidiaries, and restricts mergers,
consolidations or sales of assets. The 8 7/8% Notes are guaranteed by
certain of Nuevo's subsidiaries. The 8 7/8% Notes are unsecured general
obligations of the Company, and are subordinated in right of payment to all
existing and future senior indebtedness of the Company. In the event of a
defined change in control, the Company will be required to make an offer to
repurchase all outstanding 8 7/8% Notes at 101% of the principal amount
thereof, plus accrued and unpaid interest to the date of redemption.
(b) In April 1996, the Company financed a portion of the purchase price of the
Unocal Properties with proceeds from the sale to the public of a principal
amount of $160.0 million, 9 1/2% Senior Subordinated Notes due April 15,
2006 (the "9 1/2% Notes"). Interest on the 9 1/2% Notes accrues at the rate
of 9 1/2% per annum and is payable semi-annually in arrears on April 15 and
October 15. The 9 1/2% Notes are redeemable, in whole or in part, at the
option of the Company, on or after April 15, 2001, under certain
conditions. The Company is not required to make mandatory redemption or
sinking fund payments with respect to the 9 1/2% Notes. The indenture
contains covenants that, among other things, limit the Company's ability to
incur additional indebtedness, limits restricted payments, limit issuances
and sales of capital stock by restricted subsidiaries, limit dispositions
of proceeds of asset sales, limit dividends and other payment restrictions
affecting restricted subsidiaries, and restricts mergers, consolidations or
sales of assets. The 9 1/2% Notes were guaranteed by certain of Nuevo's
subsidiaries until February 1998, at which time such subsidiaries were
released as guarantors. The 9 1/2% Notes are unsecured general obligations
of the Company, and are subordinated in right of payment to all existing
and future senior indebtedness of the Company. In the event of a defined
change in control, the Company will be required to make an offer to
repurchase all outstanding 9 1/2% Notes at 101% of the principal amount
thereof, plus accrued and unpaid interest to the date of redemption.
(c) In February 1995, in connection with the purchase of the stock of Amoco
Congo Production Company, the Company negotiated with the Overseas Private
Investment Corporation ("OPIC") and an agent bank for a non-recourse credit
facility in the amount of $25.0 million. The security for such facility is
the assets and stock of the Nuevo Congo Company ("NCC"). The initial
drawdown on the facility was $8.8 million to finance a portion of the
purchase price. The remaining funds under the credit facility will be used
to finance 75% of the development drilling program in the Congo. A portion
of the remaining outstanding commitment, $6.0 million, was drawn down in
January 1996 to fund the first phase of the development drilling program in
the Congo. The interest rate associated with such credit facility is the
London Interbank Offered Rate ("LIBOR") plus 20 basis points and a guaranty
fee of 2.75% of the outstanding loan balance, payable quarterly. At
December 31, 1998, the interest rate was 5.55%, plus the guarantee fee of
2.75%. The loan agreement requires a sixteen-quarter repayment period.
F-29
<PAGE> 158
(d) Nuevo's Amended and Restated Credit Agreement, (the "Agreement"), dated as
of February 13, 1998, provides for unsecured revolving credit availability
of up to $400 million (subject to a periodic borrowing base determination)
from a bank group led by NationsBank of Texas, N.A. and Morgan Guaranty
Trust Company of New York, until its expiration on April 1, 2003.
The borrowing base determination establishes the maximum borrowings that
may be outstanding under the credit facility, and is determined by a
two-thirds vote of the banks (three-fourths in the event of an increase in
the borrowing base), each of which bases its judgment on (i) the present
value of the Company's oil and gas reserves based on its own assumptions
regarding future prices, production, costs, risk factors and discount
rates, and (ii) on projected cash flow coverage ratios calculated under
varying scenarios. If amounts outstanding under the credit facility exceed
the borrowing base, as redetermined from time to time, the Company would be
required to repay such excess over a defined period of time.
Effective January 6, 1999 the borrowing base was reduced from $380 million
to $200 million, reflecting the sale on that date of the Company's East
Texas natural gas reserves, and also reflecting a significant decline in
projected oil prices since the previous determination.
Amounts outstanding under the credit facility bear interest at a rate equal
to the London Interbank Offered Rate ("LIBOR") plus an amount which
increases as borrowing base utilization increases. At December 31, 1998 the
Company's interest rate under the credit facility was LIBOR plus .375%, or
5.94%. Outstandings under this facility at year end were $158.4 million,
and at January 6, 1999 were reduced by $82.6 million from a portion of the
proceeds of the East Texas sale.
The Credit Agreement has customary covenants including, but not limited to,
covenants with respect to the following matters: (i) limitations on certain
restricted payments and investments; (ii) limitations on guarantees and
indebtedness; (iii) limitations on prepayments of subordinated and certain
other indebtedness; (iv) limitations on mergers and consolidations, on
certain types of acquisitions and on the issuance of certain securities by
subsidiaries; (v) limitations on liens; (vi) limitations on sales of
properties; (vii) limitations on transactions with affiliates; (viii)
limitations on derivative contracts; and (ix) limitations on debt in
subsidiaries. The Company is also required to maintain certain financial
ratios and conditions, including without limitation an EBITDA (earnings
before interest, taxes, depreciation, depletion, amortization and
exploration expenses) to fixed charge coverage ratio, a net worth
requirement, and a funded debt to capitalization ratio. As a result of
reduced revenues due to falling oil prices, the Company has obtained
amendments for relief from the EBITDA fixed charge coverage test through
March 31, 2000. The Company is in compliance with this test and all other
covenants of the Agreement at December 31, 1998. The Company is currently
in negotiation with its banks regarding other terms of the Agreement,
including pricing, security, the frequency of borrowing base determinations
and certain other covenants. Management believes the outcome of such
negotiations will result, over time, in improved borrowing base
availability and greater certainty of the commitment of this facility
during difficult periods in the oil and gas industry.
In June 1997, the Company redeemed its 12 1/2% Senior Subordinated Notes at
a total cost of $78.0 million, representing $75.0 million face value of the
debt plus a 4% premium of $3.0 million. In addition to the premium, the
Company wrote off approximately $2.0 million of unamortized discount and
deferred financing costs. The redemption resulted in an extraordinary loss
on early extinguishment of debt in the amount of $3.0 million, net of the
related tax benefit of $2.0 million. The Company used proceeds from its
bank facility to fund the redemption.
The amount of scheduled debt maturities during the next five years and
thereafter is as follows (amounts in thousands):
<TABLE>
<S> <C>
1999................ $ 3,152
2000................ 750
2001................ --
2002................ --
2003................ 158,400
Thereafter.......... 260,000
---------
Total Debt $ 422,302
=========
</TABLE>
Based upon the quoted market price, the fair value of the 8 7/8% Notes
was estimated to be $90.6 million at December 31, 1998, and the fair
value of the 9 1/2% Notes was estimated to be $160.2 million and $170.3
million at December 31, 1998 and 1997, respectively. For the OPIC
credit facility and other debt, for which no quoted prices are
available, management believes the carrying value of the debt
materially represents the fair value of the debt at December 31, 1998
and 1997.
F-30
<PAGE> 159
11. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS
NCC is a U.S. corporation with foreign branch operations in the Congo. The
functional currency of NCC is the U.S. Dollar and its income is taxed in the
United States. The Company's Congo investment involves risks typically
associated with investments in emerging markets such as an uncertain political,
economic, legal and tax environment, and expropriation and nationalization of
assets. The Company's investment is insured through political risk insurance
provided by OPIC.
The OPIC credit facility, discussed in Note 10, requires the Company to
provide consolidating financial statements that separately show NCC. Also shown
separately is Nuevo Congo LTD. ("NCL") which is the company that holds Nuevo's
additional interest in the Yombo field in the Congo (see Note 3) that was
acquired in 1998. These condensed consolidating financial statements are
presented below:
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 1998
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
NUEVO NCC NCL CONSOLIDATED
-------- -------- -------- ------------
<S> <C> <C> <C> <C>
Total current assets ................... $145,906 $ 12,870 $ 2,476 $161,252
Net property and equipment ............. 568,509 39,112 8,951 616,572
Deferred tax assets, net ............... 27,059 475 -- 27,534
Total other assets ..................... 12,308 19 -- 12,327
-------- -------- -------- --------
Total assets ................. $753,782 $ 52,476 $ 11,427 $817,685
======== ======== ======== ========
Total current liabilities .............. $ 18,006 $ 31,163 $ 454 $ 49,623
Long-term debt ......................... 418,400 750 -- 419,150
Other long-term liabilities ............ 2,034 -- -- 2,034
Mandatorily Redeemable Convertible
Preferred Securities of Nuevo
Financing I .......................... 115,000 -- -- 115,000
Total stockholders' equity ............. 200,342 20,563 10,973 231,878
-------- -------- -------- --------
Total liabilities and
stockholders' equity ....... $753,782 $ 52,476 $ 11,427 $817,685
======== ======== ======== ========
</TABLE>
F-31
<PAGE> 160
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 1997
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
NUEVO* NCC* CONSOLIDATED*
--------- --------- -------------
<S> <C> <C> <C>
Total current assets ............................. $ 51,318 $ 7,542 $ 58,860
Net property and equipment ....................... 701,000 33,111 734,111
Total other assets ............................... 11,220 95 11,315
--------- --------- ---------
Total assets ........................... $ 763,538 $ 40,748 $ 804,286
========= ========= =========
Total current liabilities ........................ $ 44,177 $ 5,426 $ 49,603
Long-term debt ................................... 302,038 3,902 305,940
Deferred tax liabilities ......................... 4,771 215 4,986
Other long-term liabilities ...................... (5,642) 9,660 4,018
Mandatorily Redeemable Convertible Preferred
Securities of Nuevo Financing I ................ 115,000 -- 115,000
Total stockholders' equity ....................... 303,194 21,545 324,739
--------- --------- ---------
Total liabilities and stockholders'
equity ............................... $ 763,538 $ 40,748 $ 804,286
========= ========= =========
</TABLE>
- ----------------
* Restated
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1998
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
NUEVO NCC NCL CONSOLIDATED
--------- --------- --------- ------------
<S> <C> <C> <C> <C>
Revenues .......................... $ 236,758 $ 14,607 $ 1,338 $ 252,703
Expenses .......................... 362,103 16,279 1,218 379,600
--------- --------- --------- ---------
(Loss) income before income
taxes ........................... (125,345) (1,672) 120 (126,897)
Income tax benefit ................ (31,935) (690) -- (32,625)
--------- --------- --------- ---------
Net (loss) income ................. $ (93,410) $ (982) $ 120 $ (94,272)
========= ========= ========= =========
</TABLE>
F-32
<PAGE> 161
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1997
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
NUEVO* NCC* CONSOLIDATED*
--------- --------- -------------
<S> <C> <C> <C>
Revenues .............................................. $ 334,446 $ 22,832 $ 357,278
Expenses .............................................. 358,079 16,531 374,610
--------- --------- ---------
(Loss) income before income taxes and extraordinary
item ................................................ (23,633) 6,301 (17,332)
Income tax (benefit) expense .......................... (6,883) 227 (6,656)
--------- --------- ---------
(Loss) income before extraordinary item ............... (16,750) 6,074 (10,676)
Extraordinary loss on early extinguishment of debt,
net of tax benefit .................................. 3,024 -- 3,024
--------- --------- ---------
Net (loss) income ..................................... $ (19,774) $ 6,074 $ (13,700)
========= ========= =========
</TABLE>
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1996
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
NUEVO* NCC* CONSOLIDATED*
-------- -------- -------------
<S> <C> <C> <C>
Revenues ......................................... $308,380 $ 20,677 $329,057
Expenses ......................................... 256,568 14,246 270,814
-------- -------- --------
Income before income taxes ....................... 51,812 6,431 58,243
Income tax expense (benefit) ..................... 23,969 (4) 23,965
-------- -------- --------
Net income ....................................... 27,843 6,435 34,278
Dividends on preferred stock ..................... 939 -- 939
-------- -------- --------
Net earnings available to common stockholders .... $ 26,904 $ 6,435 $ 33,339
======== ======== ========
</TABLE>
- ------------
* Restated
F-33
<PAGE> 162
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1998
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
NUEVO NCC NCL CONSOLIDATED
--------- --------- --------- ------------
<S> <C> <C> <C> <C>
Cash flows from operating activities:
Net (loss) income ................................... $ (93,410) $ (982) $ 120 $ (94,272)
Non-cash adjustments ................................ 119,473 4,281 -- 123,754
Change in assets and liabilities .................... (8,015) 14,923 (557) 6,351
--------- --------- --------- ---------
Net cash provided by (used
in) operating activities .................. 18,048 18,222 (437) 35,833
--------- --------- --------- ---------
Cash flows from investing activities:
additions to oil and gas properties ................. (137,430) (10,971) (8,951) (157,352)
Proceeds from sale of properties .................... 11,830 -- -- 11,830
Additions to other properties and other ............. (2,813) -- -- (2,813)
--------- --------- --------- ---------
Net cash used in investing activities ....... (128,413) (10,971) (8,951) (148,335)
--------- --------- --------- ---------
Cash flows from financing activities:
proceeds from borrowings ............................ 240,900 -- -- 240,900
Payments of long-term debt .......................... (124,551) (3,703) -- (128,254)
Contribution to (from) Nuevo ........................ (10,852) -- 10,852 --
Other ............................................... (1,949) -- -- (1,949)
--------- --------- --------- ---------
Net cash provided by (used
in) financing activities .................. 103,548 (3,703) 10,852 110,697
--------- --------- --------- ---------
Net increase (decrease) in cash & cash
equivalents ......................................... (6,817) 3,548 1,464 (1,805)
Cash and cash equivalents at beginning
of year ............................................. 7,417 1,791 -- 9,208
--------- --------- --------- ---------
Cash and cash equivalents at end of
year ................................................ $ 600 $ 5,339 $ 1,464 $ 7,403
========= ========= ========= =========
</TABLE>
F-34
<PAGE> 163
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1997
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
NUEVO* NCC* CONSOLIDATED*
--------- --------- -------------
<S> <C> <C> <C>
Cash flows from operating activities:
Net (loss) income ................................... $ (19,774) $ 6,074 $ (13,700)
Non-cash adjustments ................................ 155,749 3,612 159,361
Change in assets and liabilities .................... 12,846 6,955 19,801
--------- --------- ---------
Net cash provided by operating
activities ................................ 148,821 16,641 165,462
--------- --------- ---------
Cash flows from investing activities:
Additions to oil and gas properties ................. (182,261) (12,847) (195,108)
Proceeds from sale of properties .................... 27,377 -- 27,377
Additions to other properties and other ............. (1,747) -- (1,747)
--------- --------- ---------
Net cash used in investing activities ....... (156,631) (12,847) (169,478)
--------- --------- ---------
Cash flows from financing activities:
Proceeds from borrowings ............................ 234,000 -- 234,000
Payments of long-term debt .......................... (213,800) (3,703) (217,503)
Other ............................................... (16,909) -- (16,909)
--------- --------- ---------
Net cash provided by (used in) financing
activities ................................ 3,291 (3,703) (412)
--------- --------- ---------
Net (decrease) increase in cash and cash
equivalents ......................................... (4,519) 91 (4,428)
Cash and cash equivalents at beginning of year ........ 11,936 1,700 13,636
--------- --------- ---------
Cash and cash equivalents at end of year .............. $ 7,417 $ 1,791 $ 9,208
========= ========= =========
</TABLE>
- ----------
* Restated
F-35
<PAGE> 164
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1996
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
NUEVO* NCC* CONSOLIDATED*
--------- --------- -------------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income ............................................... $ 27,843 $ 6,435 $ 34,278
Non-cash adjustments ..................................... 89,792 2,469 92,261
Change in assets and liabilities ......................... (6,483) 6,865 382
--------- --------- ---------
Net cash provided by operating activities ........ 111,152 15,769 126,921
--------- --------- ---------
Cash flows from investing activities:
Additions to oil and gas properties ...................... (496,516) (19,469) (515,985)
Proceeds from sale of properties ......................... 42,700 -- 42,700
Additions to other properties and other .................. (72,717) -- (72,717)
--------- --------- ---------
Net cash used in investing activities ............ (526,533) (19,469) (546,002)
--------- --------- ---------
Cash flows from financing activities:
Proceeds from borrowings ................................. 402,000 6,000 408,000
Proceeds from issuance of Company-Obligated
Mandatorily Redeemable Convertible Preferred
Securities of Nuevo Financing I ....................... 115,000 -- 115,000
Payments of long-term debt ............................... (229,406) (2,953) (232,359)
Other .................................................... 136,311 -- 136,311
--------- --------- ---------
Net cash provided by financing
activities ..................................... 423,905 3,047 426,952
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents ....... 8,524 (653) 7,871
Cash and cash equivalents at beginning of year ............. 3,412 2,353 5,765
--------- --------- ---------
Cash and cash equivalents at end of year ................... $ 11,936 $ 1,700 $ 13,636
========= ========= =========
</TABLE>
12. INCOME TAXES
Income tax (benefit) expense is summarized as follows (amounts in
thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------
1998 1997* 1996*
-------- -------- --------
<S> <C> <C> <C>
Current
Federal ............................................. $ (105) $ (135) $ 1,200
State ............................................... -- 421 300
-------- -------- --------
(105) (556) 1,500
-------- -------- --------
Deferred
Federal ............................................. (24,172) (7,449) 17,465
State ............................................... (8,348) (1,800) 5,000
-------- -------- --------
(32,520) (9,249) 22,465
-------- -------- --------
Total income tax (benefit) expense .......... $(32,625) $ (8,693) $ 23,965
======== ======== ========
</TABLE>
- --------------
* Restated
A deferred tax benefit related to the exercise of employee stock options of
approximately $5.3 million and $4.7 million was allocated directly to additional
paid-in capital in 1997 and 1996, respectively. A current tax benefit of $2.0
million was allocated to the extraordinary loss in 1997.
F-36
<PAGE> 165
Total income tax (benefit) expense differs from the amount computed by
applying the Federal income tax rate to (loss) income before income taxes,
minority interest and extraordinary item. The reasons for these differences are
as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1998 1997* 1996*
----- ----- -----
<S> <C> <C> <C>
Statutory Federal income tax rate ............................... (35.0)% (35.0)% 35.0%
(Decrease) increase in tax rate resulting from:
State income taxes, net of Federal benefit .................... (4.3) (4.0) 5.9
Non-realization of tax benefits related to provision for
impairment on assets held for sale ......................... -- 3.60 --
Increase in valuation allowance ............................... 13.4 -- --
Nondeductible travel and entertainment and other .............. 0.2 (3.4) 0.4
------ ------ ------
(25.7)% (38.8)% 41.3%
====== ====== ======
</TABLE>
The tax effects of temporary differences that result in significant
portions of the deferred income tax assets and liabilities and a description of
the financial statement items creating these differences are as follows (amounts
in thousands):
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-----------------------
1998 1997*
-------- --------
<S> <C> <C>
Net operating loss carryforwards ...................... $ 45,610 $ 10,267
Alternative minimum tax credit carryforwards .......... 1,054 1,337
State income taxes .................................... 1,520 --
Capital loss carryforwards ............................ 2,365 700
-------- --------
Total deferred income tax assets ............ 50,549 12,304
Less: valuation allowance ................... (17,646) (700)
-------- --------
Net deferred income tax assets .............. 32,903 11,604
-------- --------
Property and equipment ................................ (5,369) (12,694)
State income taxes .................................... -- (3,896)
-------- --------
Total deferred income tax liabilities ....... (5,369) (16,590)
-------- --------
Net deferred income tax asset (liability) ............. $ 27,534 $ (4,986)
======== ========
</TABLE>
- ---------------
* Restated
At December 31, 1998, the Company had a net operating loss carry forward
for regular tax of approximately $130.3 million, which will expire in future
years beginning in 2006 through 2012. The alternative minimum tax credit carry
forward of $1.1 million does not expire and may be applied to reduce regular
income tax to an amount not less than the alternative minimum tax payable in any
one year. At December 31, 1998, the Company determined that it was more likely
than not that a portion of the deferred tax assets will not be realized and the
valuation allowance was increased by $16.9 million to a total valuation
allowance of $17.6 million.
13. INDUSTRY SEGMENT INFORMATION
As of December 31, 1998, the Company adopted SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information", which was issued by
the FASB in June 1997. This statement establishes standards for reporting
information about operating segments in annual financial statements and requires
that enterprises report selected information about operating segments in interim
reports.
F-37
<PAGE> 166
The Company's operations are concentrated primarily in two segments:
exploration and production of oil and natural gas, and gas plant and other
facilities.
<TABLE>
<CAPTION>
AS OF AND FOR THE YEAR ENDED
DECEMBER 31,
---------------------------------------
1998 1997* 1996*
--------- --------- ---------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C>
Sales to unaffiliated customers:
Oil and gas -- East ............................ $ 46,885 $ 61,456 $ 74,930
Oil and gas -- West ............................ 177,315 247,723 184,261
Oil and gas -- Foreign ......................... 15,810 22,794 20,668
Gas plant, pipeline and other facilities ....... 5,365 20,598 41,576
--------- --------- ---------
Total sales ............................ 245,375 352,571 321,435
Other revenues ....................... 7,328 4,707 7,622
--------- --------- ---------
Total revenues ......................... $ 252,703 $ 357,278 $ 329,057
========= ========= =========
Operating (loss) profit before income taxes:
Oil and gas -- East ............................ $ 22,608 $ 24,745 $ 37,659
Oil and gas -- West ............................ (67,677) 40,369 72,049
Oil and gas -- Foreign ......................... (12,849) 6,172 7,247
Gas plant, pipeline and other facilities(2) .... 3,063 (22,478) 2,619
--------- --------- ---------
(54,855) 48,808 119,574
Unallocated corporate expenses ................. 32,958 32,170 25,157
Interest expense ............................... 32,471 27,357 36,009
Dividends on TECONS ............................ 6,613 6,613 165
--------- --------- ---------
Operating (loss) profit before income taxes .... $(126,897) $ (17,332) $ 58,243
========= ========= =========
Identifiable assets:
Oil and gas -- Domestic(1) ..................... $ 748,695 $ 671,603 $ 682,995
Oil and gas -- Foreign ......................... 40,700 40,139 33,147
Gas plant and other facilities ................. 14,893 17,387 66,329
--------- --------- ---------
804,288 729,129 782,471
Corporate assets and investments ............... 13,397 75,157 35,172
--------- --------- ---------
Total .................................. $ 817,685 $ 804,286 $ 817,643
========= ========= =========
Capital expenditures:
Oil and gas -- East ............................ $ 36,597 $ 32,857 $ 37,480
Oil and gas -- West(1) ......................... 96,179 148,927 525,259
Oil and gas -- Foreign ......................... 30,498 14,111 19,607
Gas plant and other facilities ................. 2,813 1,747 2,717
--------- --------- ---------
$ 166,087 $ 197,642 $ 585,063
========= ========= =========
Depreciation, depletion and amortization:
Oil and gas -- East ............................ $ 10,391 $ 14,252 $ 24,842
Oil and gas -- West ............................ 68,164 81,011 43,964
Oil and gas -- Foreign ......................... 4,971 3,385 2,473
Gas plant and other facilities ................. 812 2,830 3,812
--------- --------- ---------
$ 84,338 $ 101,478 $ 75,091
========= ========= =========
</TABLE>
- ---------------
* Restated
(1) Identifiable assets and capital expenditures for 1996 include $15.0 million
in costs associated with gas plant facilities in California, which
processes immaterial amounts of third party gas, and whose revenues from
the sale of these liquids are included in oil and gas revenues.
F-38
<PAGE> 167
(2) Gas plant and other facilities operations for 1998 include a positive
revision to a prior period charge of $3.7 million and for 1997 include a
charge for $23.9 million to record an impairment on assets held for sale
and a $2.3 million gain on sale. See Note 4.
In 1998, 1997 and 1996, the Company had one customer that accounted for
60%, 62%, and 52% of oil and gas revenues, respectively. Also in 1998, the
Company had another customer who accounted 10% of oil and gas revenues.
14. CONTINGENCIES
The Company has been named as a defendant in the lawsuit Gloria Garcia
Lopez and Husband, Hector S. Lopez, Individually, and as successors to Galo Land
& Cattle Company v. Mobil Producing Texas & New Mexico, et al. currently pending
in the 79th Judicial District Court of Brooks County, Texas. The plaintiffs
allege: (i) underpayment of royalties and claim damages, on a gross basis
against all working interest owners, of $27.7 million plus $26.2 million in
interest for the period from 1985 to date; (ii) that their production was
improperly commingled with gas produced from an adjoining lease, resulting in
damages, including interests of $40.8 million, on a gross basis; (iii) $59.7
million (gross) for alleged failure to develop and $20.0 million (gross) for
interest in the alleged failure to develop; and (iv) numerous other claims that
may result in unspecified damages. Nuevo's working interest in these properties
is 20%. The Company, along with the other defendants in this case, denies these
allegations and is vigorously contesting these claims. Management does not
believe that the outcome of this matter will have a material adverse impact on
the Company's operating results, financial condition or liquidity.
The Company has been named as a defendant in certain other lawsuits
incidental to its business. Management does not believe that the outcome of such
litigation will have a material adverse impact on the Company's operating
results or financial condition. However, these actions and claims in the
aggregate seek substantial damages against the Company and are subject to the
inherent uncertainties in any litigation. The Company is defending itself
vigorously in all such matters.
In March 1999, the Company discovered that an employee had fraudulently
authorized and diverted for personal use Company funds totaling $5.9 million,
$4.3 million in 1998 and the remainder in 1999, that were intended for
international exploration. Accordingly, the Company has reclassified the amounts
lost in 1998 from exploration costs to other expense. Based on its review of the
facts, management is confident that only one employee was involved in the matter
and that all misappropriated funds have been identified. The Board has engaged a
Certified Fraud Examiner to conduct an in-depth review of the fraudulent
transactions to determine the scope of the fraud, the possibility of recovery of
amounts lost from insurance, from the terminated employee and/or from third
parties, and to make recommendations regarding what, if any, new internal
control procedures should be implemented.
In September 1997, there was a spill of crude oil into the Santa Barbara
Channel from a pipeline that connects the Company's Point Pedernales field with
shore-based processing facilities. The volume of the spill was estimated to be
163 barrels of oil. Torch, which operates the platform and pipeline for the
Company, responded immediately by shutting down the pipeline and notified the
National Response Center and all appropriate Federal, state, and local
authorities, as well as petroleum industry environmental response consortia. The
costs of the clean up and the repair either have been or are expected to be
covered by insurance held by the Company, less the Company's deductibles of
$120,000 net to the Company. Repairs were completed by the end of 1997, and
production recommenced in December 1997. Additionally, the Company has exposure
to certain costs that may not be recoverable by insurance, including fines,
penalties, and damages. Such costs are not quantifiable at this time, but are
not expected to be material to the Company's operating results, financial
condition or liquidity.
The Company's international investments involve risks typically associated
with investments in emerging markets such as an uncertain political, economic,
legal and tax environment and expropriation and nationalization of assets. In
addition, if a dispute arises in its foreign operations, the Company may be
subject to the exclusive
F-39
<PAGE> 168
jurisdiction of foreign courts or may not be successful in subjecting foreign
persons to the jurisdiction of the United States. The Company attempts to
conduct its business and financial affairs so as to protect against political
and economic risks applicable to operations in the various countries where it
operates, but there can be no assurance that the Company will be successful in
so protecting itself. A portion of the Company's investment in the Congo is
insured through political risk insurance provided by OPIC.
The Company and its partners in the Congo are undergoing a tax examination
related to their ownership interests in the Yombo field offshore Republic of
Congo, for the years 1994 through 1997. The Congolese taxing authorities have
issued a preliminary assessment of approximately $24.0 million in taxes and
penalties for all years, in aggregate for all parties who have ownership in this
field. Nuevo's working interest in this field is 43.75% during the years under
examination. The Company, along with the other partners, is in discussions with
the Congolese taxing authorities refuting this assessment as without merit to
the items being disallowed. Management does not believe that the outcome of this
matter will have a material adverse effect upon the Company.
In connection with their respective acquisitions of two subsidiaries (each
a "Congo subsidiary") owning interests in the Yombo field offshore West Africa,
the Company and a wholly-owned subsidiary of CMS NOMECO Oil & Gas Co. ("CMS")
agreed with the seller of the subsidiaries not to claim certain tax losses
("dual consolidated losses") incurred by such subsidiaries prior to the
acquisitions. Pursuant to the agreement, the Company and CMS may be liable to
the seller for the recapture of dual consolidated losses utilized by the seller
in years prior to the acquisitions if certain triggering events occur, including
(i) a disposition by either the Company or CMS of its respective Congo
subsidiary, (ii) either Congo subsidiary's sale of its interest in the Yombo
field, (iii) the acquisition of the Company or CMS by another consolidated group
or (iv) the failure of the Company or CMS's Congo subsidiary to continue as a
member of its respective consolidated group. A triggering event will not occur,
however, if a subsequent purchaser enters into certain agreements specified in
the consolidated return regulations intended to ensure that such dual
consolidated losses will not be claimed. The Company and CMS have agreed among
themselves that the party responsible for the triggering event shall indemnify
the other for any liability to the seller as a result of such triggering event.
The Company's potential direct liability could be as much as $50.0 million if a
triggering event with respect to the Company occurs, and the Company believes
that CMS's liability (for which the Company would be jointly liable with an
indemnification right against CMS) could be as much as $67.0 million. The
Company does not expect a triggering event to occur with respect to it or CMS
and does not believe the agreement will have a material adverse effect upon the
Company.
During 1997, a new government was established in the Congo. Although the
political situation in the Congo has not to date had a material adverse effect
on the Company's operations in the Congo, no assurances can be made that
continued political unrest in West Africa will not have a material adverse
effect on the Company and its operations in the Congo in the future.
15. FINANCIAL INSTRUMENTS
The Company periodically uses derivative financial instruments to manage
oil and natural gas price risk. For 1999, the Company entered into swap
agreements on 4,500 barrels of oil per day ("BOPD") of its Congo production,
hedging the basis differential between No. 6 fuel oil and West Texas
Intermediate ("WTI") at an average differential of $2.28. The Company also
purchased a call option on 2,000 BOPD of its Congo production at a strike price
of $16.00 per barrel of oil ("BBL"), to hedge the Company's potential liability
under a price sharing agreement with a third party. These agreements expose the
Company to counterparty credit risk to the extent that the counterparty is
unable to meet its settlement commitments to the Company.
For 1999, the Company has entered into an agreement under which a portion
of the its fixed rate debt will be converted to floating rate debt. This
agreement is not held for trading purposes. As the swap provider is a major
financial institution, the Company does not anticipate non-performance by the
provider.
F-40
<PAGE> 169
Determination of Fair Values of Financial Instruments
Fair value for cash, short-term investments, receivables and payables
approximates carrying value. The following table details the carrying values and
approximate fair values of the Company's other investments, derivative financial
instruments and long-term debt at December 31, 1998 and 1997.
<TABLE>
<CAPTION>
DECEMBER 31, 1998 DECEMBER 31, 1997
--------------------------- --------------------------
APPROXIMATE APPROXIMATE
CARRYING VALUE FAIR VALUE CARRYING VALUE FAIR VALUE
-------------- ----------- -------------- -----------
(AMOUNTS IN THOUSANDS)
<S> <C> <C> <C> <C>
Other investments ........................... $ 80 $ 80 $ 434 $ 553
Derivative Instruments:
Option premium ............................ 292 241 -- --
Commodity price swaps ..................... -- (2,636) -- 506
Long-term debt (See Note 10) ............... 419,150 409,938 305,940 316,228
TECONS ...................................... 115,000 71,875 115,000 112,700
</TABLE>
16. SUPPLEMENTAL INFORMATION -- (UNAUDITED)
Oil and Gas Producing Activities:
Included herein is information with respect to oil and gas acquisition,
exploration, development and production activities, which is based on estimates
of year-end oil and gas reserve quantities and estimates of future development
costs and production schedules. Reserve quantities and future production as of
December 31, 1998 are based primarily on reserve reports prepared by the
independent petroleum engineering firm of Ryder Scott Company. Reserve
quantities and future production for previous years are based primarily upon
reserve reports prepared by Ryder Scott Company and the independent petroleum
firm of Poco Oil Company. These estimates are inherently imprecise and subject
to substantial revision.
Estimates of future net cash flows from proved reserves of gas, oil,
condensate and natural gas liquids ("NGL") were made in accordance with SFAS No.
69, "Disclosures about Oil and Gas Producing Activities". The estimates are
based on realized prices at year-end, of $8.03 per BBL and $1.79 per thousand
cubic feet of gas ("MCF"). Estimated future cash inflows are reduced by
estimated future development and production costs based on year-end cost levels,
assuming continuation of existing economic conditions, and by estimated future
income tax expense. Tax expense is calculated by applying the existing statutory
tax rates, including any known future changes, to the pre-tax net cash flows,
less depreciation of the tax basis of the properties and depletion allowances
applicable to the gas, oil, condensate and NGL production. Because the
disclosure requirements are standardized, significant changes can occur in these
estimates based upon oil and gas prices currently in effect. The results of
these disclosures should not be construed to represent the fair market value of
the Company's oil and gas properties. A market value determination would include
many additional factors including: (i) anticipated future increases or decreases
in oil and gas prices and production and development costs; (ii) an allowance
for return on investment; (iii) the value of additional reserves, not considered
proved at the present, which may be recovered as a result of further exploration
and development activities; and (iv) other business risks.
The following tables include the Company's East Texas natural gas assets,
which were sold on January 6, 1999 (see Note 4). Such assets accounted for 54.9
MBOE, or 21%, of the Company's December 31, 1998 net proved reserve estimates.
F-41
<PAGE> 170
Costs incurred (amounts in thousands) --
The following table sets forth the costs incurred in property acquisition
and development activities:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------
1998 1997* 1996*
-------- -------- --------
<S> <C> <C> <C>
DOMESTIC
Property acquisition:
Proved properties(2) ....... $ 200 $ 10,206 $452,603
Unproved properties ........ 1,320 -- 40,000
Exploration .................. 26,706 18,474 7,289
Development(1) ............... 104,550 153,104 62,847
-------- -------- --------
$132,776 $181,784 $562,739
======== ======== ========
FOREIGN
Property acquisition:
Proved properties .......... $ 7,809 $ -- $ --
Unproved properties ........ 1,404 -- --
Exploration .................. 9,204 10,887 8,844
Development .................. 12,081 3,224 10,763
-------- -------- --------
$ 30,498 $ 14,111 $ 19,607
======== ======== ========
TOTAL
Property acquisition:
Proved properties .......... $ 8,009 $ 10,206 $452,603
Unproved properties ........ 2,724 -- 40,000
Exploration .................. 35,910 29,361 16,133
Development .................. 116,631 156,328 73,610
-------- -------- --------
$163,274 $195,895 $582,346
======== ======== ========
</TABLE>
- --------------
* Restated
(1) Includes capitalized interest directly related to development activities of
$0.6 million in 1998 and $2.4 million in 1997.
(2) The acquisition of domestic proved properties for 1996 includes $15.0
million in costs associated with gas plant facilities in California.
F-42
<PAGE> 171
Capitalized costs (amounts in thousands) --
The following table sets forth the capitalized costs relating to oil and
gas activities and the associated accumulated depreciation, depletion and
amortization:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1998 1997* 1996*
--------- --------- ---------
<S> <C> <C> <C>
Domestic
Proved properties ................................ $ 877,230 $ 903,096 $ 739,260
Unproved properties .............................. 20,984 41,661 44,661
--------- --------- ---------
Total capitalized costs ........................ 898,214 944,757 783,921
Accumulated depreciation, depletion and
amortization ................................ (401,139) (315,038) (198,024)
--------- --------- ---------
Net capitalized costs .......................... $ 497,075 $ 629,719 $ 585,897
========= ========= =========
FOREIGN
Proved properties ................................ $ 59,774 $ 39,516 $ 26,677
Unproved properties .............................. 1,360 -- --
--------- --------- ---------
Total capitalized costs ........................ 61,134 39,516 26,677
Accumulated depreciation, depletion and
amortization ................................ (11,724) (6,378) (2,993)
--------- --------- ---------
Net capitalized costs .......................... $ 49,410 $ 33,138 $ 23,684
========= ========= =========
TOTAL
Proved properties ................................ $ 937,004 $ 942,612 $ 765,937
Unproved properties .............................. 22,344 41,661 44,661
--------- --------- ---------
Total capitalized costs ........................ 959,348 984,273 810,598
Accumulated depreciation, depletion and
amortization ................................ (412,863) (321,416) (201,017)
--------- --------- ---------
Net capitalized costs .......................... $ 546,485 $ 662,857 $ 609,581
========= ========= =========
</TABLE>
- ------------
* Restated
F-43
<PAGE> 172
Results of operations for producing activities (amounts in thousands) --
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1998 1997* 1996*
--------- --------- ---------
<S> <C> <C> <C>
DOMESTIC
Revenues from oil and gas producing activities ........ $ 224,200 $ 309,179 $ 259,191
Production costs ...................................... (122,816) (108,074) (82,119)
Exploration costs ..................................... (5,137) (9,813) (4,566)
Depreciation, depletion and amortization .............. (78,555) (95,263) (68,806)
Provision for impairment of oil and gas
properties .......................................... (68,529) (30,000) --
Income tax benefit (provision) ........................ 13,234 (26,449) (42,828)
--------- --------- ---------
Results of operations from producing activities
(excluding corporate overhead and interest
costs) .............................................. $ (37,603) $ 39,580 $ 60,872
========= ========= =========
FOREIGN
Revenues from oil and gas producing activities ........ $ 15,810 $ 22,794 $ 20,668
Production costs ...................................... (11,888) (11,968) (10,943)
Exploration costs ..................................... (11,425) (1,269) (5)
Depreciation, depletion and amortization .............. (4,971) (3,385) (2,473)
Provision for impairment of oil and gas
properties .......................................... (375) -- --
Income tax benefit (provision) ........................ 3,174 (2,469) (2,993)
--------- --------- ---------
Results of operations from producing activities
(excluding corporate overhead and interest
costs) .............................................. $ (9,675) $ 3,703 $ 4,254
========= ========= =========
TOTAL
Revenues from oil and gas producing activities ........ $ 240,010 $ 331,973 $ 279,859
Production costs ...................................... (134,704) (120,042) (93,062)
Exploration costs ..................................... (16,562) (11,082) (4,571)
Depreciation, depletion and amortization .............. (83,526) (98,648) (71,279)
Provision for impairment of oil and gas
properties .......................................... (68,904) (30,000) --
Income tax benefit (provision) ........................ 16,408 (28,918) (45,821)
--------- --------- ---------
Results of operations from producing activities
(excluding corporate overhead and interest
costs) .............................................. $ (47,278) $ 43,283 $ 65,126
========= ========= =========
</TABLE>
- -----------
* Restated
F-44
<PAGE> 173
Per unit sales prices and costs:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
DOMESTIC
Average sales price:
Oil (per barrel) ......................................... $ 9.10 $ 14.88 $ 15.99
Gas (per MCF) ............................................ $ 2.00 $ 2.06 $ 2.08
Average production cost per equivalent barrel .............. $ 5.33 $ 4.96 $ 4.63
FOREIGN
Average sales price:
Oil (per barrel) ......................................... $ 10.82 $ 14.66 $ 14.56
Average production cost per equivalent barrel ............ $ 8.14 $ 7.70 $ 7.71
TOTAL
Average sales price:
Oil (per barrel) ......................................... $ 9.25 $ 14.86 $ 15.84
Gas (per MCF) ............................................ $ 2.00 $ 2.06 $ 2.08
Average production cost per equivalent barrel .............. $ 5.56 $ 5.14 $ 4.86
</TABLE>
F-45
<PAGE> 174
The Company's estimated total proved and proved developed reserves of oil
and gas are as follows:
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------------
1998 1997 1996
--------------------- --------------------- ---------------------
OIL* GAS OIL* GAS OIL* GAS
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
DOMESTIC
Proved reserves at beginning of
year ................................. 202,771 390,691 165,839 394,630 9,700 301,311
Revisions of previous estimates ........ (41,399) (8,953) 10,177 (5,105) 5,581 (1,388)
Extensions and discoveries ............. 17,694 55,575 39,911 35,682 3,615 18,291
Production ............................. (17,345) (32,521) (15,854) (35,625) (11,924) (34,775)
Sales of reserves in-place ............. (1,595) (1,536) (15) (675) (2,506) (30,588)
Purchase of reserves in-place .......... 4,174 -- 2,713 1,784 161,373 141,779
------- ------- ------- ------- ------- -------
Proved reserves at end of year ......... 164,300 403,256 202,771 390,691 165,839 394,630
======= ======= ======= ======= ======= =======
Proved developed reserves --
Beginning of year .................... 143,486 266,179 122,088 236,013 8,289 142,012
======= ======= ======= ======= ======= =======
End of year .......................... 123,077 308,667 143,486 266,179 122,088 236,013
======= ======= ======= ======= ======= =======
FOREIGN
Proved reserves at beginning of
year ................................. 24,493 -- 20,214 -- 20,826 --
Revisions of previous estimates ........ (420) -- (1,313) -- (107) --
Extensions and discoveries ............. -- -- 7,147 -- 915 --
Production ............................. (1,461) -- (1,555) -- (1,420) --
Sales of reserves in-place ............. -- -- -- -- -- --
Purchase of reserves in-place .......... 3,229 -- -- -- -- --
------- ------- ------- ------- ------- -------
Proved reserves at end of year ......... 25,841 -- 24,493 -- 20,214 --
======= ======= ======= ======= ======= =======
Proved developed reserves --
Beginning of year .................... 9,526 -- 16,727 -- 14,787 --
======= ======= ======= ======= ======= =======
End of year .......................... 10,242 -- 9,526 -- 16,727 --
======= ======= ======= ======= ======= =======
TOTAL
Proved reserves at beginning of
year ................................. 227,264 390,691 186,053 394,630 30,526 301,311
Revisions of previous estimates ........ (41,819) (8,953) 8,864 (5,105) 5,474 (1,388)
Extensions and discoveries ............. 17,694 55,575 47,058 35,682 4,530 18,291
Production ............................. (18,806) (32,521) (17,409) (35,625) (13,344) (34,775)
Sales of reserves in-place ............. (1,595) (1,536) (15) (675) (2,506) (30,588)
Purchase of reserves in-place .......... 7,403 -- 2,713 1,784 161,373 141,779
------- ------- ------- ------- ------- -------
Proved reserves at end of year ......... 190,141 403,256 227,264 390,691 186,053 394,630
======= ======= ======= ======= ======= =======
Proved developed reserves --
Beginning of year .................... 153,012 266,179 138,815 236,013 23,076 142,012
======= ======= ======= ======= ======= =======
End of year .......................... 133,319 308,667 153,012 266,179 138,815 236,013
======= ======= ======= ======= ======= =======
</TABLE>
- -----------------
* Includes estimated NGL reserves.
F-46
<PAGE> 175
Discounted future net cash flows (amounts in thousands) --
The standardized measure of discounted future net cash flows and changes
therein are shown below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
DOMESTIC
Future cash inflows ................................... $ 1,989,898 $ 3,566,450 $ 4,476,523
Future production costs ............................... (1,061,638) (1,643,774) (1,739,219)
Future development costs .............................. (289,686) (329,997) (309,365)
----------- ----------- -----------
Future net inflows before income tax .................. 638,574 1,592,679 2,427,939
Future income taxes ................................... -- (427,618) (736,788)
----------- ----------- -----------
Future net cash flows ................................. 638,574 1,165,061 1,691,151
10% discount factor ................................... (360,611) (454,023) (702,996)
----------- ----------- -----------
Standardized measure of discounted future net
cash flows .......................................... $ 277,963 $ 711,038 $ 988,155
=========== =========== ===========
FOREIGN
Future cash inflows ................................... $ 260,627 $ 360,959 $ 414,383
Future production costs ............................... (134,549) (171,331) (248,222)
Future development costs .............................. (66,715) (59,985) (2,625)
----------- ----------- -----------
Future net inflows before income tax .................. 59,363 129,643 163,536
Future income taxes ................................... -- (39,243) (55,083)
----------- ----------- -----------
Future net cash flows ................................. 59,363 90,400 108,453
10% discount factor ................................... (37,393) (36,653) (33,659)
----------- ----------- -----------
Standardized measure of discounted future net
cash flows .......................................... $ 21,970 $ 53,747 $ 74,794
=========== =========== ===========
TOTAL
Future cash inflows ................................... $ 2,250,525 $ 3,927,409 $ 4,890,906
Future production costs ............................... (1,196,187) (1,815,105) (1,987,441)
Future development costs .............................. (356,401) (389,982) (311,990)
----------- ----------- -----------
Future net inflows before income tax .................. 697,937 1,722,322 2,591,475
Future income taxes ................................... -- (466,861) (791,871)
----------- ----------- -----------
Future net cash flows ................................. 697,937 1,255,461 1,799,604
10% discount factor ................................... (398,004) (490,676) (736,655)
----------- ----------- -----------
Standardized measure of discounted future net
cash flows .......................................... $ 299,933 $ 764,785 $ 1,062,949
=========== =========== ===========
</TABLE>
F-47
<PAGE> 176
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
DOMESTIC
Standardized measure -- beginning of year ........ $ 711,038 $ 988,155 $ 236,920
Sales, net of production costs ................... (101,383) (201,198) (177,072)
Purchases of reserves in-place ................... 2,278 18,293 605,210
Net change in prices and production costs ........ (466,018) (581,640) 505,108
Extensions, discoveries and improved
recovery, net of future production and
development costs .............................. 46,713 180,146 38,572
Net changes in estimated future development
costs .......................................... 79,410 87,606 10,151
Revisions of quantity estimates .................. (86,459) 33,358 79,185
Accretion of discount ............................ 83,281 125,138 26,207
Net change in income taxes ....................... 121,770 141,452 (238,071)
Sales of reserves in-place ....................... (356) (1,598) (41,969)
Changes in production rates and other ............ (112,311) (78,674) (56,086)
----------- ----------- -----------
Standardized measure -- end of year ............... $ 277,963 $ 711,038 $ 988,155
=========== =========== ===========
FOREIGN
Standardized measure -- beginning of year ........ $ 53,747 $ 74,794 $ 74,166
Sales, net of production costs ................... (3,923) (10,826) (9,725)
Purchases of reserves in-place ................... 2,750 -- --
Net change in prices and production costs ........ (56,690) (22,193) (1,557)
Extensions, discoveries and improved
recovery, net of future production and
development costs .............................. -- 5,486 4,930
Net changes in estimated future development
costs .......................................... 8,990 (6,212) 3,892
Revisions of quantity estimates .................. (750) (5,609) (598)
Accretion of discount ............................ 6,830 10,720 11,288
Net change in income taxes ....................... 14,552 17,857 6,304
Changes in production rates and other ............ (3,536) (10,270) (13,906)
----------- ----------- -----------
Standardized measure -- end of year .............. $ 21,970 $ 53,747 $ 74,794
=========== =========== ===========
TOTAL
Standardized measure -- beginning of year ........ $ 764,785 $ 1,062,949 $ 311,086
Sales, net of production costs ................... (105,306) (212,024) (186,797)
Purchases of reserves in-place ................... 5,028 18,293 605,210
Net change in prices and production costs ........ (522,708) (603,833) 503,551
Extensions, discoveries and improved
recovery, net of future production and
development costs .............................. 46,713 185,632 43,502
Net changes in estimated future development
costs .......................................... 88,400 81,394 14,043
Revisions of quantity estimates .................. (87,209) 27,749 78,587
Accretion of discount ............................ 90,111 135,858 37,495
Net change in income taxes ....................... 136,322 159,309 (231,767)
Sales of reserves in-place ....................... (356) (1,598) (41,969)
Changes in production rates and other ............ (115,847) (88,944) (69,992)
----------- ----------- -----------
Standardized measure -- end of year .............. $ 299,933 $ 764,785 $ 1,062,949
=========== =========== ===========
</TABLE>
F-48
<PAGE> 177
Selected Quarterly Financial Data (amounts in thousands, except per
share data) (unaudited):
<TABLE>
<CAPTION>
QUARTER ENDED(4)
-----------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
1998 1998 1998 1998
-------- -------- ------------ -----------
<S> <C> <C> <C> <C>
Revenues ............................... $ 67,661 $ 61,512 $ 65,966 $ 57,564
Operating earnings (loss)(1) ........... $ 4,011 $ 3,317 $ (5,369) $(66,858)
Net loss(1) ............................ $ (6,582) $ (7,622) $(11,245) $(68,823)
Loss per Common Share-- Basic .......... $ (0.33) $ (0.39) $ (0.57) $ (3.47)
Loss per Common Share-- Diluted ........ $ (0.33) $ (0.39) $ (0.57) $ (3.47)
</TABLE>
<TABLE>
<CAPTION>
QUARTER ENDED(4)(5)
-----------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
1997 1997 1997 1997
-------- -------- ------------ -----------
<S> <C> <C> <C> <C>
Revenues ............................... $102,410 $ 85,976 $ 82,120 $ 86,772
Operating earnings (loss)(2) ........... $ 39,872 $ 26,204 $ 17,410 $(34,688)
Net income (loss)(2)(3) ................ $ 14,609 $ 2,964 $ 352 $(31,625)
Earnings (loss) per Common Share --
Basic ................................ $ 0.73 $ 0.15 $ 0.02 $ (1.60)
Earnings (loss) per Common Share --
Diluted .............................. $ 0.70 $ 0.15 $ 0.02 $ (1.60)
</TABLE>
- ------------------
(1) Includes a fourth quarter charge of $68.9 million to record an impairment
of oil and gas properties and a fourth quarter $3.7 million positive
revision to a prior period impairment on assets held for sale.
(2) Includes fourth quarter charges of $23.9 million to record an impairment on
assets held for sale and $30.0 million to record an impairment of oil and
gas properties and a second quarter gain on sale of $3.0 million that was
adjusted downward by $752,000 in the third quarter (see Note 4).
(3) Includes an extraordinary loss on early extinguishment of debt of $3.0
million, net of income tax benefit, in the second quarter.
(4) Certain reclassifications of prior period amounts have been made to conform
with the current presentation.
(5) Restated.
<PAGE> 178
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS
Section 145 of the General Corporation Law of the State of Delaware,
pursuant to which the Company is incorporated, provides generally and in
pertinent part that a Delaware corporation may indemnify its directors,
officers, employees and agents (or persons serving at the request of the Company
as a director, officer, employee or agent of another entity) against expenses,
judgments, fines, and settlements actually and reasonably incurred by them in
connection with any civil, criminal, administrative, or investigative suit or
action except actions by or in the right of the corporation if, in connection
with the matters in issue, they acted in good faith and in a manner they
reasonably believed to be in or not opposed to the best interests of the
corporation, and in connection with any criminal suit or proceeding, if in
connection with the matters in issue, they had no reasonable cause to believe
their conduct was unlawful. Section 145 further provides that in connection with
the defense or settlement of any action by or in the right of the corporation, a
Delaware corporation may indemnify its directors, officers, employees and agents
(or persons serving at the request of the Company as a director, officer,
employee or agent of another entity) against expenses actually and reasonably
incurred by them if, in connection with the matters in issue, they acted in good
faith and in a manner they reasonably believed to be in or not opposed to the
best interests of the corporation, except that no indemnification may be made in
respect of any claim, issue, or matter as to which such person has been adjudged
liable to the corporation unless the Delaware Court of Chancery or other court
in which such action or suit is brought approves such indemnification. Section
145 further permits a Delaware corporation to grant its directors and officers
additional rights of indemnification through bylaw provisions and otherwise, and
or purchase indemnity insurance on behalf of its directors and officers. Article
Nine of the Certificate of Incorporation of the Company, as amended, and Article
VII of the Bylaws of the Company, as amended, provide, in general, that the
Company may indemnify its directors, officers, employees and agents (or persons
serving at the request of the Company as a director, officer, employee or agent
of another entity) to the full extent of Delaware law.
The Company has purchased directors and officers liability insurance
policy which insures, among other things, (i) the officers and directors of the
Company from any claim arising out of an alleged wrongful act by such persons
while acting as directors and officers of the Company and (ii) the Company to
the extent that the Company has indemnified the directors and officers for such
loss.
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a)
EXHIBIT
NUMBER Description
------ -----------
(1) UNDERWRITING AGREEMENT*
(2) PLAN OF ACQUISITION, REORGANIZATION, ARRANGEMENT, LIQUIDATION
OR SUCCESSION*
(4) INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS, INCLUDING
INDENTURES
4.1 Indenture dated April 1, 1996 among Nuevo Energy Company as
Issuer, various Subsidiaries as the Guarantors, and State
Street Bank and Trust Company as the Trustee - 9 1/2% Senior
Subordinated Notes due 2006. (Incorporated by reference from
Registration Statement on Form S-3 (No. 333-1504)).
- 2 -
<PAGE> 179
EXHIBIT
NUMBER Description
------ -----------
4.2 Form of Amended and Restated Declaration of Trust dated
December 23, 1996, among the Company, as Sponsor, Wilmington
Trust Company, as Institutional Trustee and Delaware Trustee,
and Michael D. Watford, Robert L. Gerry, III and Robert M.
King, as Regular Trustees. (Incorporated by reference from
Exhibit 4.1 to Current Report on Form 8-K filed on January 6,
1997).
4.3 Form of Subordinated Indenture dated as of November 25, 1996,
between the Company and Wilmington Trust Company, as Indenture
Trustee. (Incorporated by reference from Exhibit 4.2 to
Current Report on Form 8-K filed on January 6, 1997).
4.4 Form of First Supplemental Indenture dated December 23, 1996,
between the Company and Wilmington Trust Company, as Indenture
Trustee. (Incorporated by reference from Exhibit 4.3 to
Current Report on Form 8-K filed on January 6, 1997).
4.5 Form of Preferred Securities Guarantee Agreement dated as of
December 23, 1996, between the Company and Wilmington Trust
Company, as Guarantee Trustee. (Incorporated by reference from
Exhibit 4.4 to Current Report on Form 8-K filed on January 6,
1997).
4.6 Form of Certificate representing TECONS. (Incorporated by
reference from Exhibit 4.5 to Current Report on Form 8-K filed
on January 6, 1997).
4.7 Release and Termination of Subsidiary Guarantees with respect
to the 9 1/2% Senior Subordinated Notes due 2006.
(Incorporated by reference from Exhibit 4.11 to Annual Report
on Form 10-K for the year ended December 31, 1997).
4.8 Indenture dated June 8, 1998 among Nuevo Energy Company as
Issuer, various Subsidiaries as the Guarantors, and State
Street Bank and Trust Company as the Trustee - 8 7/8% Senior
Subordinated Notes due 2008. (Incorporated by reference from
Exhibit 4.1 to Registration Statement on Form S-4 (No.
333-60655) filed on August 5, 1998).
4.9 First Supplemental Indenture to the Indenture dated June 8,
1998, dated August 9, 1999 between Nuevo Energy Company and
State Street Bank and Trust Company - 8 7/8% Senior
Subordinated Notes due 2008.**
4.10 Second Supplemental Indenture to the Indenture dated April 1,
1996, dated August 9, 1999 between Nuevo Energy Company and
State Street Bank and Trust Company - 9 1/2% Senior
Subordinated Notes due 2006.**
4.11 Indenture, dated as of August 20, 1999, between Nuevo Energy
Company and State Street Bank and Trust Company, as Trustee.**
4.12 Registration Agreement dated August 20, 1999, between Nuevo
Energy Company, Banc of America Securities LLC and Salomon
Smith Barney Inc.**
- 3 -
<PAGE> 180
EXHIBIT
NUMBER Description
------ -----------
(5) OPINION REGARDING LEGALITY
5.1 Opinion of Haynes and Boone, L.L.P.**
(8) OPINION REGARDING TAX MATTERS*
(12) STATEMENTS REGARDING COMPUTATION OF RATIOS
12.1 Computation of ratio of earnings to fixed charges.**
(15) LETTER REGARDING UNAUDITED INTERIM FINANCIAL INFORMATION*
(23) CONSENTS OF EXPERTS AND COUNSEL
23.1 Consent of Haynes and Boone, L.L.P. (included in Exhibit 5.1).
23.2 Consent of KPMG LLP.**
23.3 Consent of Ryder Scott Company.**
23.4 Consent of Poco Oil Co.**
(25) STATEMENT OF ELIGIBILITY OF TRUSTEE
25.1 Statement of Eligibility and Qualification on Form T-1 of
Trustee.**
(27) FINANCIAL DATA SCHEDULE*
(99) ADDITIONAL EXHIBITS
99.1 Form of Letter of Transmittal.**
99.2 Form of Notice of Guaranteed Delivery.**
- ----------
* Inapplicable to this filing.
** Previously filed.
- 4 -
<PAGE> 181
ITEM 22. UNDERTAKINGS.
The undersigned Registrant hereby undertakes:
(1) to file, during any period in which offers or sales are being made, a
post-effective amendment to this Registration Statement:
(i) to include any prospectus required by section 10(a)(3) of the Securities Act
of 1933 (the "Securities Act");
(ii) to reflect in the prospectus any facts or events arising after the
effective date of this Registration Statement (or the most recent post-effective
amendment hereof) which, individually or in the aggregate, represent a
fundamental change in the information set forth in this Registration Statement.
Notwithstanding the foregoing, any increase or decrease in volume of securities
offered (if the total dollar value of securities offered would not exceed that
which was registered) and any deviation from the low or high end of the
estimated maximum offering range may be reflected in the form of prospectus
filed with the Securities and Exchange Commission pursuant to rule 424(b) if, in
the aggregate, the changes in volume and price represent no more than a 20%
change in the maximum aggregate offering price set forth in the "Calculation of
Registration Fee" table in this Registration Statement when it becomes
effective;
(iii) to include any material information with respect to the plan of
distribution not previously disclosed in this Registration Statement or any
material change to such information in this Registration Statement;
(2) that, for the purpose of determining any liability under the Securities
Act, each such post-effective amendment shall be deemed to be a new
registration statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be the initial
bona fide offering thereof.
(3) to remove from registration by means of a post-effective amendment any
of the securities being registered which remain unsold at the termination
of the offering.
The undersigned Registrant hereby undertakes that, for purposes of
determining any liability under the Securities Act, each filing of the
Registrant's annual report pursuant to section 13(a) or section 15(d) of the
Securities Exchange Act of 1934 (and, where applicable, each filing of an
employee benefit plan's annual report pursuant to section 15(d) of the
Securities Exchange Act of 1934) that is incorporated by reference in the
Registration Statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.
Insofar as indemnification for liabilities arising under the Securities
Act may be permitted to directors, officers and controlling persons of the
Registrant pursuant to the foregoing provisions, or otherwise, the Registrant
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Securities Act
and is, therefore, unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the Registrant of expenses
incurred or paid by a director, officer or controlling person of the Registrant
in the successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities being
registered, the Registrant will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against public
policy as expressed in the Securities Act and will be governed by the final
adjudication of such issue.
The undersigned Registrant hereby undertakes to respond to requests for
information that is incorporated by reference into the prospectus pursuant to
Items 4, 10(b), 11 or 13 of this Form, within one business day of receipt of
such request, and to send the incorporated documents by first class mail or
other equally prompt means. This includes information contained in documents
filed subsequent to the effective date of this Registration Statement through
the date of responding to the request.
- 5 -
<PAGE> 182
The undersigned Registrant hereby undertakes to supply by means of a
post-effective amendment all information concerning a transaction, and the
company being acquired involved therein, that was not the subject of and
included in this Registration Statement when it became effective.
- 6 -
<PAGE> 183
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended,
the registrant has duly caused this Amended Registration Statement on Form S-4
to be signed on its behalf by the undersigned, thereunto duly authorized, in the
City of Houston, State of Texas, on the 11th day of November, 1999.
NUEVO ENERGY COMPANY
By: /s/ Douglas L. Foshee
---------------------------------------
Douglas L. Foshee
Chairman of the Board, Chief Executive Officer and
President
- 7 -
<PAGE> 184
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE CAPACITIES DATE
--------- ---------- ----
<S> <C> <C>
/s/ Douglas L. Foshee Chairman of the Board, Chief Executive Officer and November 11, 1999
- --------------------------- President (Principal Executive Officer)
Douglas L. Foshee
/s/ Robert M. King* Senior Vice President and Chief Financial Officer November 11, 1999
- --------------------------- (Principal Accounting and Financial Officer)
Robert M. King
/s/ Isaac Arnold, Jr.* Director November 11, 1999
- ---------------------------
Isaac Arnold, Jr.
/s/ Thomas D. Barrow* Director November 11, 1999
- ---------------------------
Thomas D. Barrow
/s/ David H. Batchelder* Director November 11, 1999
- ---------------------------
David H. Batchelder
/s/ Charles M. Elson* Director November 11, 1999
- ---------------------------
Charles M. Elson
/s/ Robert L. Gerry III* Director November 11, 1999
- ---------------------------
Robert L. Gerry III
</TABLE>
- 8 -
<PAGE> 185
<TABLE>
<S> <C> <C>
/s/ Gary R. Petersen* Director November 11, 1999
- ---------------------------
Gary R. Petersen
/s/ David Ross III* Director November 11, 1999
- ---------------------------
David Ross III
/s/ Robert W. Shower* Director November 11, 1999
- ---------------------------
Robert W. Shower
</TABLE>
*By: /s/ Douglas L. Foshee
---------------------
Douglas L. Foshee
Pursuant to a previously filed
power of attorney
- 9 -
<PAGE> 186
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER Description
------ -----------
<S> <C>
(1) UNDERWRITING AGREEMENT*
(2) PLAN OF ACQUISITION, REORGANIZATION, ARRANGEMENT, LIQUIDATION
OR SUCCESSION*
(4) INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS, INCLUDING
INDENTURES
4.1 Indenture dated April 1, 1996 among Nuevo Energy Company as
Issuer, various Subsidiaries as the Guarantors, and State
Street Bank and Trust Company as the Trustee - 9 1/2% Senior
Subordinated Notes due 2006. (Incorporated by reference from
Registration Statement on Form S-3 (No. 333-1504)).
4.2 Form of Amended and Restated Declaration of Trust dated
December 23, 1996, among the Company, as Sponsor, Wilmington
Trust Company, as Institutional Trustee and Delaware Trustee,
and Michael D. Watford, Robert L. Gerry, III and Robert M.
King, as Regular Trustees. (Incorporated by reference from
Exhibit 4.1 to Current Report on Form 8-K filed on January 6,
1997).
4.3 Form of Subordinated Indenture dated as of November 25, 1996,
between the Company and Wilmington Trust Company, as Indenture
Trustee. (Incorporated by reference from Exhibit 4.2 to
Current Report on Form 8-K filed on January 6, 1997).
4.4 Form of First Supplemental Indenture dated December 23, 1996,
between the Company and Wilmington Trust Company, as Indenture
Trustee. (Incorporated by reference from Exhibit 4.3 to
Current Report on Form 8-K filed on January 6, 1997).
4.5 Form of Preferred Securities Guarantee Agreement dated as of
December 23, 1996, between the Company and Wilmington Trust
Company, as Guarantee Trustee. (Incorporated by reference from
Exhibit 4.4 to Current Report on Form 8-K filed on January 6,
1997).
4.6 Form of Certificate representing TECONS. (Incorporated by
reference from Exhibit 4.5 to Current Report on Form 8-K filed
on January 6, 1997).
4.7 Release and Termination of Subsidiary Guarantees with respect
to the 9 1/2% Senior Subordinated Notes due 2006.
(Incorporated by reference from Exhibit 4.11 to Annual Report
on Form 10-K for the year ended December 31, 1997).
4.8 Indenture dated June 8, 1998 among Nuevo Energy Company as
Issuer, various Subsidiaries as the Guarantors, and State
Street Bank and Trust Company as the Trustee - 8 7/8% Senior
Subordinated Notes due 2008. (Incorporated by reference from
Exhibit 4.1 to Registration Statement on Form S-4 (No.
333-60655) filed on August 5, 1998).
</TABLE>
<PAGE> 187
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER Description
------ -----------
<S> <C>
4.9 First Supplemental Indenture to the Indenture dated June 8,
1998, dated August 9, 1999 between Nuevo Energy Company and
State Street Bank and Trust Company - 8 7/8% Senior
Subordinated Notes due 2008.**
4.10 Second Supplemental Indenture to the Indenture dated April 1,
1996, dated August 9, 1999 between Nuevo Energy Company and
State Street Bank and Trust Company - 9 1/2% Senior
Subordinated Notes due 2006.**
4.11 Indenture, dated as of August 20, 1999, between Nuevo Energy
Company and State Street Bank and Trust Company, as Trustee.**
4.12 Registration Agreement dated August 20, 1999, between Nuevo
Energy Company, Banc of America Securities LLC and Salomon
Smith Barney Inc.**
(5) OPINION REGARDING LEGALITY
5.1 Opinion of Haynes and Boone, L.L.P.**
(8) OPINION REGARDING TAX MATTERS*
(12) STATEMENTS REGARDING COMPUTATION OF RATIOS
12.1 Computation of ratio of earnings to fixed charges.**
(15) LETTER REGARDING UNAUDITED INTERIM FINANCIAL INFORMATION*
(23) CONSENTS OF EXPERTS AND COUNSEL
23.1 Consent of Haynes and Boone, L.L.P. (included in Exhibit 5.1).
23.2 Consent of KPMG LLP.**
23.3 Consent of Ryder Scott Company.**
23.4 Consent of Poco Oil Co.**
(25) STATEMENT OF ELIGIBILITY OF TRUSTEE
25.1 Statement of Eligibility and Qualification on Form T-1 of
Trustee.**
(27) FINANCIAL DATA SCHEDULE*
</TABLE>
<PAGE> 188
<TABLE>
<CAPTION>
EXHIBIT
NUMBER Description
------ -----------
<S> <C>
(99) ADDITIONAL EXHIBITS
99.1 Form of Letter of Transmittal.**
99.2 Form of Notice of Guaranteed Delivery.**
</TABLE>
- ----------
* Inapplicable to this filing.
** Previously filed.
