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Filed pursuant to Rule 424(b)(3)
Registration No. 333-72129
PROSPECTUS
[LOGO]
POGO PRODUCING COMPANY
$150,000,000
OFFER TO EXCHANGE
10 3/8% SERIES B SENIOR SUBORDINATED NOTES DUE 2009
FOR ALL OUTSTANDING 10 3/8% SERIES A SENIOR SUBORDINATED NOTES DUE 2009
THE NEW NOTES
o will be freely tradeable and otherwise substantially identical to the
outstanding notes
o will accrue interest from January 15, 1999 at the rate of 10 3/8% per
annum, payable semi-annually in arrears on each February 15 and August 15,
beginning August 15, 1999.
o will be unsecured and will rank equally with the outstanding notes and our
other unsecured senior subordinated indebtedness.
o will not be listed on any securities exchange or on any automated dealer
quotation system
THE EXCHANGE OFFER
o expires at 5:00 p.m., New York City time, on April 5, 1999, unless extended
o is not conditioned upon any minimum aggregate principal amount of
outstanding notes being tendered
IN ADDITION, YOU SHOULD NOTE THAT
o all outstanding notes that are validly tendered and not validly withdrawn
will be exchanged for an equal principal amount of new notes that are
registered under the Securities Act of 1933
o tenders of outstanding notes may be withdrawn any time prior to the
expiration of the exchange offer
o the exchange of outstanding notes for new notes in the exchange offer will
not be a taxable event for U.S. federal income tax purposes
YOU SHOULD CONSIDER CAREFULLY THE RISK FACTORS BEGINNING ON PAGE 14 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 THE NEW NOTES OR DETERMINED IF THIS
PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
THE DATE OF THIS PROSPECTUS IS FEBRUARY 16, 1999.
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TABLE OF CONTENTS
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Forward-Looking Statements.....................................................2
Where You Can Find More Information............................................3
Incorporation of Certain Documents by Reference................................3
Certain Definitions............................................................4
Prospectus Summary.............................................................5
Risk Factors..................................................................14
Private Placement.............................................................24
Use of Proceeds...............................................................24
Capitalization................................................................24
Selected Financial Data.......................................................25
Selected Reserve and Operating Data...........................................27
Management's Discussion and Analysis of
Financial Condition and Results of Operations.................................29
Business and Properties.......................................................45
Management and Board of Directors.............................................66
The Exchange Offer............................................................68
Description of the Notes......................................................78
Outstanding Notes Registration Rights Agreement..............................121
Book Entry; Delivery and Form................................................122
Certain Federal Income Tax Consequences......................................124
Plan of Distribution.........................................................125
Transfer Restrictions on Outstanding Notes...................................126
Legal Matters................................................................126
Experts......................................................................126
Index to Consolidated Financial Statements...................................F-1
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This prospectus is part of a registration statement we filed with the
Securities and Exchange Commission. You should rely only on the information or
representations provided in this prospectus. We have not authorized any person
to provide information other than that provided in this prospectus. We have not
authorized anyone to provide you with different information. We are not making
an offer of these securities in any jurisdiction where the offer is not
permitted. You should not assume that the information in this prospectus is
accurate as of any date other than the date on the front of this document.
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FORWARD-LOOKING STATEMENTS
Certain of the statements contained or incorporated by reference in this
prospectus are forward-looking statements. The use of any of the words
"anticipate," "estimate," "expect," "may," "project," "believe" and similar
expressions are intended to identify uncertainties. Although we believe the
expectations reflected in those forward- looking statements are reasonable,
they do involve certain assumptions, risks and uncertainties, and we cannot
assure that those expectations will prove to have been correct. Our actual
results could differ materially from those anticipated in these forward-looking
statements as a result of the risk factors set forth below and other factors
set forth in or incorporated by reference in this prospectus. These factors
include:
o the cyclical nature of the oil and natural gas industries
o uncertainties associated with the United States and worldwide
economies
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o current and potential governmental regulatory actions in countries
where we own an interest
o substantial competitor production increases resulting in oversupply
and declining prices
o our ability to implement cost reductions
o our ability to raise additional capital or sell assets
o operating interruptions (including leaks, explosions, fires,
mechanical failure, unscheduled downtime, transportation
interruptions, and spills and releases and other environmental risks)
o fluctuations in foreign currency exchange rates in areas of the world
where we own an interest, particularly Southeast Asia
o covenant restrictions in our indebtedness
o the impact of the Year 2000 problem
Many of those factors are beyond our ability to control or predict.
Management cautions against putting undue reliance on forward-looking
statements or projecting any future results based on such statements or present
or prior earnings levels.
All subsequent written and oral forward-looking statements
attributable to us and persons acting on our behalf are qualified in their
entirety by the cautionary statements contained in this section and elsewhere
in this prospectus.
WHERE YOU CAN FIND MORE INFORMATION
This prospectus incorporates important business and financial
information about us that we have not included in or delivered with this
prospectus. This information is available without charge upon written or oral
request. You should make any request to Gerald A. Morton, Pogo Producing
Company, 5 Greenway Plaza, Suite 2700, Houston, Texas 77046-0504, telephone
number: (713) 297-5000. To ensure timely delivery, you should request the
information no later than March 26, 1999. See "Incorporation of Certain
Documents by Reference."
We file annual, quarterly and special reports, proxy statements and
other information with the Securities and Exchange Commission (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 with the
SEC at its public reference facilities at 450 Fifth Street, N.W., Washington,
D.C. 20549. You can also obtain copies of the documents at prescribed rates by
writing to the Public Reference Section of the SEC at 450 Fifth Street, N.W.,
Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further
information on the operation of the public reference facilities. You can also
obtain information about us at the offices of the New York Stock Exchange, 20
Broad Street, New York, New York 10005.
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
We "incorporate by reference" into this prospectus certain information
we file with the SEC, which means that we can disclose important information to
you by referring you to those documents. The information incorporated by
reference is an important part of this prospectus and information that we
subsequently file with the SEC will automatically update this prospectus. We
incorporate by reference the documents listed below (collectively, the
"Reports") and any filings we make with the SEC under Sections 13(a), 13(c), 14
or 15(d) of the Exchange Act after the date of this prospectus and before the
termination of the offering made under this prospectus:
o Our Annual Report on Form 10-K for the year ended December 31, 1997
(the "Annual Report")
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o Our Quarterly Reports on Form 10-Q for the quarters ended March 31,
1998, June 30, 1998, and September 30, 1998, as amended
You may request a copy of these filings (other than an exhibit to a filing
unless that exhibit is specifically incorporated by reference into that filing)
at no cost, by writing to or telephoning us at the following address:
Pogo Producing Company
Corporate Secretary
5 Greenway Plaza, Suite 2700
Houston, Texas 77046-0504
(713) 297-5017
CERTAIN DEFINITIONS
As used in this prospectus, "Mcf" means thousand cubic feet, "MMcf"
means million cubic feet, "Bcf" means billion cubic feet, "Bbl" means barrel,
"MBbls" means thousand barrels and "MMBbls" means million barrels. "BOE" means
barrel of oil equivalent, "Mcfe" means thousand cubic feet of natural gas
equivalent, "MMcfe" means million cubic feet of natural gas equivalent and
"Bcfe" means billion cubic feet of natural gas equivalent. Natural gas
equivalents and crude oil equivalents are determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids
("NGL"). "EBITDA" means income from continuing operations before provision for
income taxes, interest expense, depreciation, depletion and amortization, and
dry hole and impairment costs. References to "$" and "dollars" refer to United
States dollars. All estimates of reserves contained in this prospectus, unless
otherwise noted, are reported on a "net" basis. Information regarding
production, acreage and numbers of wells are set forth on a gross basis, unless
otherwise noted.
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PROSPECTUS SUMMARY
This summary may not contain all the information that is important to
you. You should read the entire prospectus, including the financial data and
related notes, before making an investment decision. The terms "the Company",
"we", "our", "ours" and "us" as used in this prospectus refer to "Pogo
Producing Company" and its subsidiaries and predecessors as a combined entity.
We acquired Arch Petroleum Inc. and its subsidiaries ("Arch") on
August 17, 1998, in a stock-for-stock, tax-free merger which was accounted for
using the purchase method of accounting. Company financial and operating data
as of dates and for periods after August 17, 1998, include financial and
operating data for Arch.
You should carefully consider the information set forth under the
heading "Risk Factors." This prospectus contains certain forward-looking
statements which involve risks and uncertainties. Our actual results may differ
significantly from the results discussed in the forward-looking statements. See
"Forward-Looking Statements."
The term "outstanding notes" refers to the 10 3/8% Series A Senior
Subordinated Notes due 2009 that were issued January 15, 1999. The term "new
notes" refers to the 10 3/8% Series B Senior Subordinated Notes due 2009
issuable in the exchange offer. The term "notes" refers to the outstanding
notes and the new notes collectively.
POGO PRODUCING COMPANY
We are an independent oil and gas exploration and production company
with a well balanced portfolio of domestic and international properties. Our
properties produced approximately 60% natural gas and 40% oil over the nine
months ended September 30, 1998. As of December 31, 1997, approximately 52% of
our proved reserves were located in the United States where we currently own
interests in 105 lease blocks (comprising 455,600 gross acres) in the offshore
Gulf of Mexico and approximately 378,000 gross acres onshore, primarily in
Texas, New Mexico and Louisiana. Our remaining proved reserves, as of December
31, 1997, were located in the Gulf of Thailand where we currently own interests
in 734,000 gross acres. We also own interests in approximately 150,000 gross
acres in Western Canada, and we were recently awarded a license on 113,000 gross
acres in the U.K. sector of the North Sea. Our 1997 year-end worldwide proved
reserves totaled 64,045 MBbls of liquid hydrocarbons and 478,373 MMcf of natural
gas or 862,643 MMcfe (including reserves we acquired in the Arch acquisition).
For the twelve months ended September 30, 1998, our total revenues were
$230,641,000 and EBITDA was $126,171,000.
Our exploration strategy is to concentrate our efforts on selected
areas where we believe that our expertise, competitive acreage position, or
ability to quickly take advantage of new opportunities offers the potential for
achieving a significant return on our investment. We have established a record
of increasing our proven hydrocarbon reserves over the last seven years,
principally through the exploration, exploitation and development of our
properties and, to a lesser extent, the selective acquisition of additional
interests in producing properties in which we already have an interest. An
important measure of our success is our record for replacing the oil and gas
which we produce each year. From 1993 through 1997, we replaced each year's
production with new proved reserves at the following rates:
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PERCENTAGE OF
PRODUCTION
YEAR REPLACED
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1993............................................ 204%
1994............................................ 153%
1995............................................ 305%
1996............................................ 187%
1997............................................ 188%
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Our cost for replacing these reserves averaged $5.43 per BOE over the
five year period. As a result of our continuing successful exploration,
exploitation and development activities, we currently believe that we have
replaced our 1998 worldwide production (excluding the reserves we acquired in
the Arch acquisition). We believe that another measure of our success is the
number of successful wells that we have participated in drilling. Since
December 31, 1993, we have participated in drilling 508 gross wells, 89% of
which were successful.
COMPETITIVE STRENGTHS
We believe we are well positioned to continue to build upon our
historical success by capitalizing on our strengths, including the following:
o Diversified Portfolio of Core Properties. We benefit from a portfolio
of existing properties which provide geographic diversification while
being of sufficient size and potential to enable us to concentrate
our resources and regional expertise. For example, as of December 31,
1997, 90% of our proved liquid hydrocarbon reserves and 82% of our
proved natural gas reserves were located in six operating areas in
four geographic regions. This concentration of core properties
permits us to maintain a focused exploration and development program
by using the substantial geological and operating expertise that we
have gained over years of participating in these areas. We also use
the experience that we gain in our core areas to evaluate new
opportunities in areas with similar characteristics. For example, we
used the experience we gained in the Gulf of Mexico to develop our
concession in the Gulf of Thailand. Since our Thailand concession was
granted in August 1991, we have discovered over 375 Bcfe of proven
reserves (as of December 31, 1997) on this acreage net to our
interest.
o Significant Further Potential From Existing Properties. We believe
that our existing properties continue to hold significant further
potential for increased production and the discovery of additional
reserves. For example, we expect a significant increase in our
production rates when the Benchamas Field comes onstream in the third
quarter of 1999. In addition, we currently expect to spend
approximately $170,000,000 during 1999 to develop our existing
properties, including drilling approximately 110 gross wells.
o Balanced Risk Profile; Prudent Exposure to Higher Return
Opportunities. We seek to manage our risk exposure by maintaining a
prudent level of participation in our projects. We seek to operate
properties where we believe that our working interest percentage,
expertise or ability to control the timing or cost of a project
provides a competitive advantage to us and our partners. On
properties where we are not the operator, we try to have a meaningful
working interest so that we can influence operating and development
decisions regarding them. Generally, we seek a higher level of
participation in projects which we view as having potentially high
rates of return and relatively low anticipated exploration and
development costs, such as our operations in southeastern New Mexico
and West Texas. Conversely, we will generally seek a lower level of
participation in projects that have high drilling costs, a long lead
time until production can come onstream, or where development costs
may be disproportionately high, such as wells in intermediate water
depths (600 to 4,400 feet) in the Gulf of Mexico or wells that are
unusually deep or are considered highly risky. We currently operate
all or a portion of 27 of the 105 lease blocks in which we own
interests in the Gulf of Mexico.
o Technical Expertise. We have an experienced staff of engineers and
geoscientists that comprise over 40% of our total full-time
personnel. Our personnel's expertise, augmented by data from over 500
gross wells drilled since December 31, 1993, more than 4,800,000
acres of 3-D seismic data and 112,700 miles of 2-D seismic data,
create a knowledge base which we use to establish our drilling
priorities and associated capital budget.
BUSINESS STRATEGY
Our business strategy is to maximize profitability and shareholder
value by:
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o increasing hydrocarbon production levels, leading to increased
revenues, cash flow and earnings
o replacing and expanding our proven hydrocarbon reserves base
o maintaining appropriate levels of debt and interest, and controlling
overhead and operating costs
o expanding exploration and production activities into new and
promising geographic areas consistent with our expertise
To implement our business strategy, we currently are principally
focused in the following four geographic areas:
DOMESTIC OPERATIONAL AREAS
Gulf of Mexico. As of December 31, 1997, approximately 31% of our
total proved oil and gas reserves and approximately 59% of our domestic proved
oil and gas reserves were located in the Gulf of Mexico, where we have explored
for nearly 30 years. Most of these proved reserves are concentrated in four
significant producing areas, including eight fields in the Eugene Island area
located off the Louisiana coast. This concentration allows us to closely manage
costs and to develop detailed geologic and other information relating to these
areas. We believe that the Gulf of Mexico will continue to provide us with
substantial opportunities to expand our hydrocarbon reserves and increase our
deliverability by using our extensive inventory of 3-D seismic data (covering
the equivalent of 600 federal Gulf of Mexico lease blocks) to locate low risk
exploration and development projects, and by using advanced drilling
technology, including horizontal drilling, to accelerate development of these
projects. For example, within the last several years we have acquired interests
in 15 lease blocks in intermediate water depths (ranging from 600 feet to 4,400
feet). We have participated in drilling six wells on these lease blocks, all of
which have been successful. Together with our partners, we are currently
developing three projects on these blocks, two of which should commence
producing during the first quarter of 1999, and the other should come onstream
in the first quarter of 2000.
Permian Basin. As of December 31, 1997, approximately 12% of our total
proved oil and gas reserves, and approximately 24% of our domestic proved oil
and gas reserves were located in the Permian Basin where we have explored for
over 20 years. According to the most recently published annual figures, we are
the ninth largest producer of crude oil in New Mexico. We believe that we will
continue to be one of the most active companies drilling for oil and gas in the
southeastern New Mexico portion of the Permian Basin, where we have interests
in over 101,000 gross acres. Our primary drilling objective in this region is
the Brushy Canyon (Delaware) formation, which produces oil at depths of
approximately 6,000 to 9,000 feet. Commencing in late 1989 and continuing
through December 31, 1998, we (excluding Arch) and our partners drilled 389
wells in the Permian Basin area, of which 96% were completed as productive. We
generally achieve rapid cost recovery on our Permian Basin wells because of
relatively low capital costs and high initial rates of production. We currently
expect our Permian Basin operations to continue to be a source of significant
future oil production.
Onshore Gulf Coast Region. We have maintained an active presence in
the Onshore Gulf Coast region for over 20 years. Over the last several years,
we have committed considerable resources to increasing our presence in
promising areas where we believe that our technological expertise, acreage
position and comparatively low operating costs provide a competitive advantage.
Commencing in 1994, we have participated in nine proprietary and several
speculative 3-D seismic surveys in the Onshore Gulf Coast region. Since that
time, we have participated in the drilling of 58 new wells based in part on
prospects developed from those surveys. Successful drilling, based in large
part on these surveys, has enabled us to more than double our proven reserves
in this region from approximately 25 Bcfe as of December 31, 1995, to
approximately 68 Bcfe as of December 31, 1997.
INTERNATIONAL OPERATIONAL AREAS
Gulf of Thailand. In August 1991, together with our joint venture
partners, we were awarded a license to explore for oil and gas on the Kingdom
of Thailand's Block B8/32 Concession in the Gulf of Thailand. Through
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December 31, 1998, we have drilled 108 exploratory and development wells and
acquired 3-D seismic surveys covering approximately 673,650 acres. At December
31, 1997, approximately 48% of the Company's total proved oil and gas reserves
were located on the concession.
The first portion of the concession that we developed was the Tantawan
Field. Through December 31, 1998, we have drilled 19 exploration wells and 31
development wells in the Tantawan Field. Production from the Tantawan Field
began in early February 1997. During the third quarter of 1998, production
averaged 76.2 MMcf of natural gas per day and 5,605 Bbls of crude oil and
condensate per day (35.3 MMcf per day and 2,598 Bbls per day net to our working
interest). We plan to drill additional development wells in the Tantawan Field
during the first quarter of 1999. We are currently developing a second field on
the concession that is known as the Benchamas Field. The Benchamas Field does
not appear to be as highly faulted and the depositional environment of the
reservoir rock appears to be different from what we found in the Tantawan
Field. We currently believe this means the reservoirs in the Benchamas Field
will be larger and more contiguous than those in the Tantawan Field. Through
December 31, 1998, we have drilled 21 exploration wells and 28 development
wells in the Benchamas Field. Recently we announced the results of three wells
in this field, the Benchamas 22, 19 and A-7 wells. The Benchamas 22 well
contained 278 feet of hydrocarbon bearing sands. The Benchamas 19 well
contained 257 feet of hydrocarbon bearing sands, and the Benchamas A-7
contained 435 feet of hydrocarbon bearing sands. Drilling and platform
construction continue in the Benchamas Field, where we currently expect to
begin producing in the third quarter of 1999. The government of the Kingdom of
Thailand has also granted us a production license to develop a third field on
the concession known as the Maliwan Field. We have also started exploring in
another part of the concession known as the Jarmjuree area, where we drilled
three wells which located hydrocarbons during the third quarter of 1998. We
currently plan to drill additional appraisal wells in the Maliwan Field during
1999, as well as more exploratory wells on other parts of the concession that
have not yet been designated as production licenses.
Rutherford-Moran Oil Corporation, the parent company of Thai Romo Ltd.,
one of our partners in our Thailand concession, has recently announced that it
has agreed to be acquired by Chevron Corporation. The acquisition is subject to
conditions, several of which are outside of Rutherford-Moran's control. One of
these conditions is that Chevron reach agreement with us on a new joint
operating agreement that would include the transfer of operatorship on the
Thailand concession from our subsidiary to a subsidiary of Chevron. Although we
have held discussions with Chevron on this subject, we do not know whether we
can reach a mutually satisfactory agreement with Chevron.
In addition to developing our concession in the Gulf of Thailand, we
continue to actively evaluate potentially high return projects in other areas
of the world with relatively stable political and financial climates, such as
Canada and certain European and ASEAN ("Association of Southeast Asian
Nations") countries. As a result of our acquisition of Arch in August 1998, we
own interests in approximately 150,000 gross acres located primarily in Alberta
and British Columbia. In another promising development, in December 1998, the
United Kingdom's Department of Trade and Industry announced that we, together
with two partners, had been awarded two blocks in the Central Graben area of
the North Sea covering approximately 113,000 gross acres. The license to
explore these two blocks is for an initial six-year term.
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Our principal executive offices are located at 5 Greenway Plaza, Suite
2700, Houston, Texas 77046, telephone (713) 297-5000.
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SUMMARY OF THE EXCHANGE OFFER
On January 15, 1999, we completed the private offering of the
outstanding notes.
We entered into a registration rights agreement with the initial
purchasers in the private offering in which we agreed to deliver to you this
prospectus and to complete the exchange offer within 180 days after the date we
issued the outstanding notes. You are entitled to exchange in the exchange
offer your outstanding notes for new notes with substantially identical terms.
You should read the discussion under the headings "--Summary of the
Terms of the New Notes" beginning on page 12 and "Description of the Notes"
beginning on page 78 for further information regarding the new notes.
We summarize the terms of the exchange offer below. You should read
the discussion under the headings "The Exchange Offer" beginning on page 68 for
further information regarding the exchange offer and resale of the new notes.
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The Exchange Offer......................... We are offering to exchange up to $150 million aggregate principal
amount of new notes for up to $150 million aggregate principal
amount of the outstanding notes. Outstanding notes may be
exchanged only in integral multiples of $1,000.
Expiration Date............................ The Exchange Offer will expire at 5:00 p.m., New York City time, on
April 5, 1999, or such later date and time to which we extend it.
Withdrawal of Tenders...................... You may withdraw your tender of outstanding notes at any time prior
to the expiration date, unless previously accepted for exchange. We
will return to you, without charge, promptly after the expiration or
termination of the exchange offer any outstanding notes that you
tendered but that were not accepted for exchange.
Conditions to the Exchange Offer........... We will not be required to accept outstanding notes for exchange if the
exchange offer would be unlawful or would violate any interpretation
of the staff of the SEC. The exchange offer is not conditioned upon
any minimum aggregate principal amount of outstanding notes being
tendered. Please read the section "The Exchange Offer--Conditions
to the Exchange Offer" beginning on page 70 for more information
regarding the conditions to the exchange offer.
Procedures for Tendering
Outstanding Notes....................... If your outstanding notes are held through The Depositary Trust
Company and you wish to participate in the exchange offer, you may
do so through the automated tender offer program of The Depositary
Trust Company. If you tender under this program, you will agree to
be bound by the letter of transmittal that we are providing with this
prospectus as though you had signed the letter of transmittal. By
signing or agreeing to be bound by the letter of transmittal, you will
represent to us that, among other things:
o any new notes that you receive will be acquired in the ordinary
course of your business
o you have no arrangement or understanding with any person or
entity to participate in the distribution of the new notes
o if you are not a broker-dealer, you are not engaged in and do not
intend to engage in the distribution of the new notes
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o if you are a broker-dealer that will receive new notes for your own
account in exchange for outstanding notes that were acquired as a
result of market-making activities, you will deliver a prospectus, as
required by law, in connection with any resale of such new notes
o you are not our "affiliate," as defined in Rule 405 of the Securities Act
of 1933, or, if you are our affiliate, you will comply with any
applicable registration and prospectus delivery requirements of the
Securities Act of 1933
Special Procedures for
Beneficial Owners......................... If you own a beneficial interest in outstanding notes that are registered in the name
of a broker, dealer, commercial bank, trust company or other nominee, and you
wish to tender the outstanding notes in the exchange offer, you should contact
the registered holder promptly and instruct the registered holder to tender on
your behalf.
Guaranteed Delivery Procedures............. If you wish to tender your outstanding notes and cannot comply, prior
to the expiration date, with the applicable procedures under the
automated tender program of The Depositary Trust Company, you
must tender your outstanding notes according to the guaranteed
delivery procedures described in "The Exchange Offer--Guaranteed
Delivery Procedures" beginning on page 74.
Certain U.S. Federal Income
Tax Considerations...................... The exchange of outstanding notes for new notes in the exchange offer
will not be a taxable event for U.S. federal income tax purposes.
Please read "Certain Federal Income Tax Consequences" beginning on page
124.
Use of Proceeds............................ We will not receive any cash proceeds from the issuance of new notes.
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THE EXCHANGE AGENT
We have appointed State Street Bank and Trust Company as exchange
agent for the exchange offer. You should direct questions and requests for
assistance, requests for additional copies of this prospectus or of the letter
of transmittal and requests for the notice of guaranteed delivery to the
exchange agent addressed as follows:
FOR DELIVERY BY MAIL: FOR OVERNIGHT DELIVERY ONLY OR BY HAND:
State Street Bank and Trust Company State Street Bank and Trust Company
Corporate Trust Department Corporate Trust Department
P.O. Box 778 4th Floor, Two International Place
Boston, MA 02102-0078 Boston, MA 02110
Attn: Kellie Mullen Attn: Kellie Mullen
FOR FACSIMILE TRANSMISSION (FOR ELIGIBLE INSTITUTIONS ONLY):
(617) 664-5739
To Confirm Receipt:
(617) 664-5314
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SUMMARY OF TERMS OF THE NEW NOTES
The new notes will be freely tradeable and otherwise substantially
identical to the outstanding notes. The new notes will not have registration
rights or provisions for additional interest. The new notes will evidence the
same debt as the outstanding notes, and the outstanding notes are and the new
notes will be governed by the same indenture.
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Notes Offered............................ $150,000,000 aggregate principal amount of 10 3/8% Series B
Senior Subordinated Notes due 2009.
Maturity Date............................ February 15, 2009.
Interest Payment Dates................... February 15 and August 15 of each year, commencing August 15, 1999.
Optional Redemption...................... We may redeem any or all of the new notes at any time on or after
February 15, 2004. We will pay a redemption price equal to the principal
amount of the notes we redeem plus a make-whole premium, which is
described under "Description of the Notes -- Redemption; Optional
Redemption" on page 79. We will also pay accrued and unpaid interest.
Possible Subsidiary
Guarantees............................... None of our subsidiaries will guarantee the new notes initially. If our
existing or future restricted subsidiaries guarantee any of our other
indebtedness, however, they will be required by the indenture governing
the new notes to jointly and severally guarantee the new notes on a senior
subordinated basis. We do not intend to cause any subsidiary to take any
action that would require it to guarantee the new notes. Any subsidiary
guarantees of the new notes that may be issued will be limited to the
extent of any payment that would not constitute a fraudulent transfer or
conveyance under federal or state law. See "Risk Factors -- Future
subsidiary guarantees may be affected by fraudulent conveyance laws"
on page 22 and "Description of the Notes -- Possible Subsidiary
Guarantees of the Notes" beginning on page 82.
Change of Control........................ Upon certain change of control events, each holder of notes may require
us to purchase all or a portion of its notes at a purchase price equal to
101% of the principal amount of those notes, together with accrued and
unpaid interest, if any, to the date of purchase. See "Description of the
Notes -- Certain Covenants; Change of Control" beginning on page 88.
Ranking.................................. The new notes will be our general unsecured senior subordinated
obligations. They will be subordinated in right of payment to all our
existing and future Senior Indebtedness. The new notes will rank equally
with all our existing and future senior subordinated indebtedness and
senior in right of payment to all our existing and future Subordinated
Indebtedness. The terms "Senior Indebtedness" and "Subordinated
Indebtedness" are defined with respect to the notes in "Description of the
Notes -- Certain Definitions" which begins on page 99.
Certain Covenants........................ The indenture governing the outstanding notes and the new notes
contains covenants that, among other things, limit our ability, and the
ability of our restricted subsidiaries to:
</TABLE>
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<TABLE>
<CAPTION>
<S> <C>
o incur additional indebtedness
o make certain investments
o pay dividends on, redeem or repurchase our capital stock
o issue and sell our restricted subsidiaries' capital stock
o engage in transactions with affiliates
o create certain liens
o dispose of asset sales proceeds
o guarantee indebtedness
o incur senior subordinated indebtedness that does not
rank equal to the notes
o merge, consolidate and sell assets
These covenants have various
exceptions and qualifications, which
are described under "Description of
the Notes -- Certain Covenants" which
begins on page 83.
Right under Registration
Rights Agreement......................... If we fail to complete the exchange offer as required by the registration
rights agreement, we will be obligated to pay additional interest to
holders of the outstanding notes.
Please read "Outstanding Notes Registration Rights Agreement" beginning on page
121 for more information regarding your rights as a holder of outstanding notes.
Absence of a Public Market
for the Notes............................ The new notes will be a new issue of securities for which there is
currently no market. Although the initial purchasers of the outstanding
notes have informed us that they each currently intend to make a market
in the new notes issued in the exchange offer, they are not obligated to do so.
Any such market making may be discontinued at any time without notice. Accordingly,
we cannot assure you as to the development or liquidity of any market for the notes.
Risk Factors............................. You should consider carefully the risks described in "Risk Factors,"
beginning on page 14.
</TABLE>
SELECTED FINANCIAL DATA
Please read "Selected Financial Data" beginning on page 25 for our selected
financial date for the five-year period ended December 31, 1997, and the nine
month periods ended September 30, 1998 and 1997.
SELECTED RESERVE AND OPERATING DATA
Please read "Selected Reserve and Operating Data" beginning on page 27 for
our selected reserve and operating data for the five-year period ended December
31, 1997, and the nine month periods ended September 30, 1998 and 1997.
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<PAGE> 14
RISK FACTORS
Your investment in the notes involves certain risks. You should carefully
consider the following Risk Factors before making an investment decision.
VOLATILITY OF OIL AND GAS MARKETS AFFECTS US
Market prices are volatile
Our profitability and cash flow depend greatly on the market prices of oil
and natural gas. Those market prices have historically been seasonal, cyclical
and volatile. They depend on many factors, including weather, economic,
political and regulatory conditions that we cannot control. Commencing in 1997,
the average prices for our production have generally declined. Oil prices have
reached lows that, on a historic inflation adjusted basis, are almost
unprecedented. In the past, we have at times curtailed production to mitigate
the effects of low market prices. We may do so again. The significant drop in
oil or gas prices has had a serious adverse effect on our cash flow and
continued low prices could seriously affect our operations and financial
condition and could in some cases result in a further reduction in funds
available under our bank credit agreement.
Hedging transactions may not prevent losses
We cannot predict future oil and gas prices with certainty. Accordingly, we
sometimes execute contracts on a portion of our production to hedge against
market price changes. In the past, we have not entered hedging transactions
exceeding 50% of our total oil and gas production on an energy equivalent basis
for any given period. Hedging transactions are intended to limit the negative
effect of further price declines, but could also limit our participation in
significant price increases for the covered period. We cannot be certain that
hedging transactions will reduce the effect of any substantial declines in oil
and gas prices. As of December 31, 1998, we were not a party to any natural gas
futures contracts, crude oil swap agreements or other commodity hedging
agreements.
WE ARE SUBJECT TO UNCERTAINTIES IN RESERVE ESTIMATES AND FUTURE NET REVENUES
There is substantial uncertainty in estimating quantities of proved
reserves and projecting future production rates and the timing of development
expenditures. No one can measure underground accumulations of oil and gas in an
exact way. Accordingly, oil and gas reserve engineering requires subjective
estimations of those accumulations. Estimates of other engineers might differ
widely from those of our reserve engineers, Ryder Scott. Accuracy of reserve
estimates depends on the quality of available data and on engineering and
geological interpretation and judgment. Ryder Scott may make material changes
to reserve estimates based on the results of actual drilling, testing, and
production. As a result, our reserve estimates often differ from the quantities
of oil and gas we ultimately recover. Also, we make certain assumptions
regarding future oil and gas prices, production levels, and operating and
development costs that may prove incorrect. Any significant variance from these
assumptions could greatly affect our estimates of reserves and future net
revenues. The reserve estimates and estimates of future net income included in
this prospectus were prepared as of December 31, 1997. See "Business and
Properties -- Exploration and Production Data; Reserves." As a result of
current low oil and natural gas prices, estimates of our future net revenues,
as of December 31, 1998, will be significantly lower than they were at year-end
1997. See "Selected Reserve and Operating Data."
WE ARE SUBJECT TO OPERATING AND UNINSURED RISKS
We must continually acquire or explore for and develop new oil and natural
gas reserves to replace those produced and sold. Our hydrocarbon reserves and
revenues will decline if we are not successful in our drilling, acquisition or
exploration activities. Although we have historically maintained our reserves
base primarily through successful exploration and development operations, we
cannot assure that future efforts will be similarly successful. Casualty risks
and other operating risks could cause reserves and revenues to decline.
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We are subject to various casualty risks
Our onshore and offshore operations are subject to the following
inherent casualty risks:
o blowouts, cratering, and explosions
o uncontrollable flows of oil, natural gas or well fluids
o fires
o pollution and other environmental risks
o hazards of marine and helicopter operations (capsizing, collision
and adverse weather and sea conditions)
We could suffer substantial financial losses due to any of the
following:
o injury or loss of life
o severe damage to and destruction of property and equipment
o pollution and other environmental damage
o suspension of operations
We may not have enough insurance to cover some operating risks
We carry insurance which we believe is in accordance with customary
industry practices, but we are not fully insured against all casualty risks
incident to our business.
We are subject to various other operating risks
Numerous risks affect drilling our activities, including the risk of
drilling non-productive wells or dry holes. The cost of drilling, completing
and operating wells and of installing production facilities and pipelines is
often uncertain. Also, our drilling operations could diminish or cease because
of any of the following:
o title problems
o weather conditions
o noncompliance with governmental requirements
o shortages or delays in the delivery or availability of equipment or
fabrication yards
Moreover, effective marketing of our natural gas production depends on a number
of factors, such as the following:
o existing market supply of and demand for natural gas
o the proximity of our reserves to pipelines
o the available capacity of such pipelines
o government regulations
The marketing of oil and gas production similarly depends on the availability
of pipelines and other transportation, processing and refining facilities, and
the existence of adequate markets. As a result, even if hydrocarbons are
discovered in commercial quantities, a substantial period of time may elapse
before commercial production commences. If pipeline facilities in an area are
insufficient, we may have to wait for the construction or expansion of pipeline
capacity before we can market production from that area. See "-- We face
additional risks related to our operations in the Kingdom of Thailand" and
"Business and Properties -- Miscellaneous" and "-- Government Regulation."
WE DEPEND ON OTHER OPERATORS
Even on properties we do not operate, we try to maintain significant
influence over the nature and timing of exploration and development activities
to the extent we can. However, we have limited influence over operations on
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<PAGE> 16
a significant percentage of our oil and gas properties, including control over
the maintenance of safety and environmental standards. For those properties:
o operators could refuse to initiate exploration or development
projects (in which case we may propose desired exploration or
development activities)
o if we proceed with any of those projects the operator has refused to
initiate, we may not receive any funding from the operator with
respect to that project
o the operators may initiate exploration or development projects on a
slower schedule than we prefer
o the operator may propose to drill more wells or build more
facilities on a project than we have funds for, which may mean that
we cannot participate in those projects or share in a substantial
share of the revenues from those projects
Any of these events could significantly affect our anticipated exploration and
development activities. See "Business and Properties -- Miscellaneous."
WE HAVE SUBSTANTIAL CAPITAL REQUIREMENTS
We have substantial anticipated capital requirements. Our ongoing capital
requirements consist primarily of the following items:
o funding the remainder of our 1998 capital and exploration budget
o the capital and exploration budget for 1999
o other allocations for acquisition, development, production,
exploration and abandonment of oil and gas reserves
o costs associated with our Thailand operations
o future dividend payments
From 1996 to 1997, we increased our capital and exploration expenditures from
$206.2 million to $229.5 million (excluding purchased reserves and interest
capitalized). We budgeted $230 million for capital and exploration expenditures
in 1998 (excluding purchased reserves and interest capitalized). Substantially
all of our 1998 capital and exploration budget has been spent or incurred. Our
1999 capital and exploration budget has been established by our Board of
Directors at $170 million (excluding purchased reserves and interest
capitalized).
We plan to finance anticipated ongoing expenses and capital requirements
with funds generated from the following sources:
o available cash and cash investments
o cash provided by operating activities
o funds available under our bank credit agreement after the
application of proceeds from the notes offering
o our uncommitted bank line of credit and banker's acceptances
o capital we believe we can raise through debt and convertible
preferred equity offerings
o asset sales
We believe the funds provided by these sources will be sufficient to meet our
1999 cash requirements. However, the uncertainties and risks associated with
future performance and revenues, as described in this section, will ultimately
determine our liquidity and ability to meet our anticipated capital
requirements. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Liquidity and Capital Resources; Capital
Structure; Credit Agreement and Uncommitted Credit Line."
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<PAGE> 17
WE FACE SIGNIFICANT COMPETITION
The oil and gas industry is highly competitive. We compete with major oil
companies, other independent oil and gas concerns and individual producers and
operators. Many of these competitors have much greater financial and other
resources than us. Moreover, the oil and gas industry competes with other
industries in supplying the energy and fuel needs of industrial, commercial and
other consumers. Increased competition causing oversupply or depressed prices
could greatly affect our operations revenues.
THE RIGHT TO RECEIVE PAYMENTS ON THE NOTES IS JUNIOR TO OUR SENIOR DEBT; THE
NOTES ARE STRUCTURALLY SUBORDINATED TO OBLIGATIONS OF OUR SUBSIDIARIES
The notes are senior subordinated obligations. Accordingly, the notes are
subordinated to all of our existing and future senior indebtedness, including
indebtedness under our bank credit agreement. We expect to incur additional
senior indebtedness from time to time in the future under our bank credit
agreement or otherwise. The indenture governing the notes limits, but does not
prohibit, the incurrence of any other indebtedness by us or our subsidiaries,
including senior indebtedness. The terms "senior indebtedness" and
"indebtedness" are defined in the "Description of the Notes -- Certain
Definitions" section of this prospectus.
Assuming we had issued the outstanding notes and applied the proceeds on
September 30, 1998, we would have had approximately $23,179,000 principal
amount of outstanding senior indebtedness. Upon any distribution of assets,
liquidation, dissolution, reorganization or any similar proceeding by or
relating to us, the holders of our senior indebtedness would be entitled to
receive payment in full before the holders of the notes would be entitled to
receive any payment. The terms and conditions of the subordination provisions
pertinent to the notes are described in more detail in "Description of the
Notes -- Subordination."
The notes are effectively subordinated to claims of creditors of our
subsidiaries (other than us) that are not guarantors of the notes, including
lessors, trade creditors, taxing authorities, creditors holding guarantees and
tort claimants. In the event of a liquidation, reorganization or similar
proceeding relating to a subsidiary that is not a guarantor of the notes, these
persons generally will have priority as to the assets of that subsidiary over
our claims and equity interest and, thereby indirectly, holders of our
indebtedness, including the notes. Currently, none of our subsidiaries
guarantee the notes. However, under certain circumstances, our payment
obligations under the notes may in the future be required to be jointly and
severally guaranteed by our existing or future subsidiaries. See "Description
of the Notes -- Possible Subsidiary Guarantees of the Notes."
THE NOTES ARE UNSECURED
In addition to being subordinate to all of our senior indebtedness, the
notes are not secured by any of our assets. Under certain circumstances, our
obligations under our bank credit agreement may become secured by some of our
oil and gas properties. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources; Capital
Structure." If the bank obligations become secured, and then we become
insolvent, are liquidated, or payment under our bank credit agreement is
accelerated, the lenders under our bank credit agreement would be entitled to
exercise the remedies available to a secured lender under applicable law. Under
these circumstances our bank lenders would have a secured claim on some of our
assets before the holders of these notes. Because the notes are unsecured,
there could be no assets remaining for the holders of the notes or any
remaining assets could be insufficient to pay off the notes.
OUR SUBSIDIARIES HAVE INDEBTEDNESS AND MAY INCUR ADDITIONAL INDEBTEDNESS
At September 30, 1998, our subsidiaries (principally Thaipo Ltd. ("Thaipo")
and Arch) had total combined assets of $370,029,000 (exclusive of net
receivables to us) and liabilities of $39,313,000 (exclusive of net payables to
us). Both the combined assets and liabilities are exclusive of assets and
liabilities associated with transactions treated as operating leases in our
consolidated financial statements. Among other obligations, Thaipo has
guaranteed its pro rata portion of obligations under an eleven and a half year
bareboat charter of a Floating Production, Storage and
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Offloading system used for development of the Tantawan production area. The
portion of the obligations under the bareboat charter guaranteed by Thaipo is
currently estimated at $11,122,000 per year for the first ten years. Thaipo has
also entered into a ten year bareboat charter of a Floating Storage and
Offloading system for the Benchamas Field at an estimated annual cost of
approximately $5,215,000, commencing in mid-1999. The documents governing such
obligations state that we have no liability for those obligations. In addition,
our subsidiaries may incur other liabilities in the future. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Liquidity and Capital Resources; Other Material Long-Term Commitments."
The indenture governing the notes limits our and our subsidiaries' ability
to incur additional indebtedness and liens and to enter into agreements that
would restrict the ability of our subsidiaries to make distributions, loans or
other payments to us. That indenture will also impose limits on our ability to
transfer assets to unrestricted subsidiaries or acquire unrestricted
subsidiaries. However, these limitations are subject to various qualifications.
Subject to certain limitations, we and our subsidiaries may incur secured
indebtedness. For additional details of these provisions and the applicable
qualifications, see "Description of the Notes -- Subordination" and " --
Certain Covenants."
WE ARE HIGHLY LEVERAGED
Assuming we had issued the outstanding notes and applied the proceeds on
September 30, 1998, our long-term debt (including the current portion) would
have been $388,179,000 and shareholders' equity would have been $283,824,000.
We believe that our cash flow from operations, together with funds available
under our bank credit agreement after it is paid down with the net proceeds we
receive from these notes, and other anticipated sources of liquidity, including
additional debt and convertible preferred securities that we may offer in the
future and proceeds from asset sales, will be adequate to meet our anticipated
requirements for working capital, capital expenditures, interest payments and
scheduled principal payments. However, our ability to meet our debt service
obligations will be dependent upon our future performance. Our future
performance, in turn, will be subject to general economic conditions and to
financial, business and other factors affecting our operations, many of which
are beyond our control.
WE ARE SUBJECT TO VARIOUS COVENANT RESTRICTIONS
We and our subsidiaries will be subject to significant operating and
financial restrictions contained in the instruments governing the notes and our
other indebtedness. Such restrictions will affect, and in many respects
significantly limit or prohibit, among other things, our ability to:
o incur additional indebtedness
o make various investments
o pay dividends on, redeem or repurchase our capital stock
o issue and sell our restricted subsidiaries' capital stock
o engage in transactions with affiliates
o create certain liens
o dispose of asset sales proceeds
o guarantee indebtedness
o incur senior subordinated indebtedness that does not rank equal to
the notes
o merge, consolidate and sell assets
In addition, our bank credit agreement requires us to maintain various
financial ratios. These restrictions could also limit our ability to obtain
financing in the future, make needed capital expenditures, withstand a future
downturn in our business or the economy in general or conduct necessary
corporate activities. If we or our subsidiaries fail to comply with these
restrictions, we may be in default under the terms of such indebtedness, even
if we are otherwise able to meet our debt service obligations. In the event of
a default, the holders of such indebtedness could elect to declare all such
indebtedness, together with accrued interest, to be due and payable and a
significant portion of our other indebtedness (including the notes) may become
immediately due and payable. We cannot assure you that we
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would be able to make such payments or borrow sufficient funds from alternative
sources to make such payments. Even if we were to obtain additional financing,
such financing may be on terms unfavorable to us.
WE ARE SUBJECT TO VARIOUS GOVERNMENT REGULATIONS AND ENVIRONMENTAL RISKS
We are subject to various legal limitations
We and our subsidiaries are subject to various foreign and domestic
laws and regulations on taxation, exploration and development, and
environmental and safety matters in countries where we own or operate
properties. Many laws and regulations require drilling permits and govern the
spacing of wells, the prevention of waste, rates of production and other
matters. These statutes and regulations, and any others that are passed by the
jurisdictions where we have production could limit the total number of wells
drilled or the total allowable production from successful wells, which could
limit revenues.
We are subject to various environmental liabilities
We could incur liability to governments or third parties for any
unlawful discharge of oil, gas or other pollutants into the air, soil or water,
including responsibility for remedial costs. We could potentially discharge oil
or natural gas into the environment in any of the following ways:
o from a well or drilling equipment at a drill site
o leakage from storage tanks, pipelines or other gathering and
transportation facilities
o damage to oil or natural gas wells resulting from accidents during
normal operations
o blowouts, cratering or explosions
Environmental discharges may move through soil to water supplies or adjoining
properties, giving rise to additional liabilities. Some laws and regulations
could impose liability for failure to notify the proper authorities of a
discharge and other failures to comply with those laws. Environmental laws may
also affect the costs of our acquisitions of properties. We do not believe that
its environmental risks are materially different from those of comparable
companies in the oil and gas industry. However, we cannot assure that
environmental laws will not, in the future, result in decreased production,
substantially increased costs of operations or other adverse effects to our
combined operations and financial condition. Pollution and similar
environmental risks generally are not fully insurable. See "Business and
Properties -- Government Regulations."
OUR FOREIGN OPERATIONS SUBJECT US TO ADDITIONAL RISKS
Our ownership and operations in Thailand, Canada, and any other foreign
areas where we may choose to do business, are subject to the various risks
inherent in foreign operations. These risks may include the following:
o currency restrictions and exchange rate fluctuations
o loss of revenue, property and equipment due to expropriation,
nationalization, war, insurrection and other political risks
o risks of increases in taxes and governmental royalties
o renegotiation of contracts with governmental entities and
quasi-governmental agencies
o changes in laws and policies governing operations of foreign-based
companies
o other uncertainties arising out of foreign government sovereignty
o inability to fund foreign operations from the United States
United States laws and policies on foreign trade, taxation and investment may
also adversely affect international operations. In addition, if a dispute
arises from foreign operations, foreign courts may have exclusive jurisdiction
over the dispute, or we may not be able to subject foreign persons to the
jurisdiction of United States courts. We seek to manage these risks by
concentrating our international operations in areas where we believe that the
existing government is stable and favorably disposed towards United States oil
and gas companies.
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WE FACE ADDITIONAL RISKS RELATED TO OUR OPERATIONS IN THE KINGDOM OF THAILAND
Additional risks and uncertainties affect the marketing and sales of
hydrocarbons from our Block B8/32 Concession located in the Gulf of Thailand
(the "Thailand Concession"). We expect that all the natural gas we produce from
the Thailand Concession will be sold to The Petroleum Authority of Thailand
("PTT"), which maintains a monopoly over gas transmission and distribution in
Thailand. Two major natural gas pipelines owned and operated by PTT cross the
Thailand Concession. These pipelines may become full due to production from the
Tantawan Field, the Benchamas Field and other fields in the Gulf of Thailand.
We cannot assure, even if we are successful in exploration efforts, that we
will be able to successfully and profitably transport, process, refine and
market the oil and gas we produce.
PTT has constructed a lateral pipeline from its main pipeline to the
Tantawan production area and has agreed to take the gas produced from that area
pursuant to a gas sales agreement (the "Gas Sales Agreement"). If the Company
and our joint venture partners in the Tantawan Field fail to deliver the
required reserves or production rates of natural gas at a specified quality
level under the Gas Sales Agreement, we may be obligated to contribute to PTT's
costs for the construction of the lateral pipeline. Also, if the Tantawan joint
venturers fail to deliver the minimum daily rates under the Gas Sales
Agreement, PTT has the right to take from subsequent deliveries an amount equal
to the quantity of undelivered gas at 75% of the contract price. Commencing on
October 1, 1998, we and our joint venture partners have been delivering less
natural gas than is being nominated by PTT under the Gas Sales Agreement. We
have not been able to meet our contractual minimum delivery obligations for a
number of reasons, including declining production from existing wells, the need
to shut-in existing wells while drilling or working over additional wells from
the same platform and our decision to emphasize oil and condensate production
from the Tantawan Field. We anticipate that we will suffer a penalty on a
portion of our future production. Thai governmental royalties, other
governmental charges and income taxes also affect our operations cash flow. We
expect all gas sales to be carried out in Baht, the Thai currency. Fluctuations
in the exchange rate between Baht and dollars could also adversely affect the
anticipated profits of our operations in Thailand.
SOUTHEAST ASIA ECONOMIC ISSUES AFFECT US
We conduct a substantial portion of our oil and gas production and sales in
Southeast Asia. In recent months, Southeast Asia in general, and the Kingdom of
Thailand in particular, have experienced severe economic difficulties,
including sharply reduced economic activity, illiquidity, highly volatile
foreign currency exchange rates and unstable stock markets. The Thailand
government and other governments in the region are currently acting to address
these issues. However, the economic difficulties in Thailand and the volatility
of the Thai Baht against the U.S. dollar will continue to have a material
impact on our Thailand operations and the prices we receive for our oil and gas
production there. In early July 1997, the government of the Kingdom of Thailand
announced that the value of the Baht would be set against the dollar and other
currencies under a "managed float" program arrangement. This led to a
substantial decline in value of the Thai Baht compared to the U.S. dollar,
resulting in our experiencing foreign currency transaction losses during 1997.
During 1998, the value of the Thai Baht has generally strengthened against the
U.S. dollar, resulting in our experiencing foreign currency transaction gains.
However, we cannot predict what the Thai Baht to dollar exchange rate may be in
the future. Moreover, we anticipate that this exchange rate will remain
volatile.
LIQUIDITY AND CASH FLOW PROBLEMS OF OUR PARTNERS MAY AFFECT US
Due to the recent decline in oil and gas prices, many of our partners,
particularly the smaller ones, are experiencing liquidity and cash flow
problems. These problems may lead to their attempting to delay or slow down the
pace of drilling or project development in order to conserve cash, to a point
that we believe is detrimental to the project. In most cases, we have the
ability to influence the pace of development through our joint operating
agreements. Some partners may be unwilling or unable to pay their share of the
costs of projects as they become due. At worst, a partner may declare
bankruptcy and refuse or be unable to pay its share of the costs of a project.
We would then be required to pay this partner's share of the project costs. In
most instances, we believe that we are contractually protected from such an
event through our ability to take over the non-paying partner's share of the
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project and by applicable oil and gas lien laws and bankruptcy laws. We believe
that we would ultimately recover any sums that we are owed by non-paying
partners that do not meet their share of the costs of a project in a timely
fashion.
Rutherford-Moran Oil Corporation ("RMOC"), the parent company of Thai Romo
Ltd., one of the partners in our Thailand Concession, has been actively seeking
a sale or merger for some time. RMOC recently announced that it has agreed to be
acquired by Chevron Corporation ("Chevron"). The acquisition is subject to
conditions, several of which are outside of RMOC's control. One of these
conditions is that Chevron reach agreement with us on a new joint operating
agreement that would include the transfer of operatorship on the Thailand
concession from our subsidiary Thaipo to a subsidiary of Chevron. Although we
have held discussions with Chevron on this subject, we do not know whether we
can reach a mutually satisfactory agreement with Chevron. RMOC has also stated
that its financial resources will be exhausted in February 1999, and that its
banks have currently refused to lend it any additional funds. Chevron has agreed
to lend additional funds to RMOC if most of the conditions to the acquisition
have been satisfied, including Chevron's reaching agreement with us on a new
joint operating agreement. Thai Romo's failure to pay its share of the expenses
of our projects in the Gulf of Thailand could have a material adverse effect on
us, due to the increased capital requirements that funding Thai Romo's share of
the project development costs could have on us.
WE HAVE YEAR 2000 RISKS
Many existing computer programs and components were designed and developed
to use a two-digit field to indicate the year in an applicable date field,
which could result from the improper processing of dates for years after 1999.
This issue is commonly known as the "Year 2000 Issue." The Year 2000 Issue is a
broad business issue, which could effect financial and business applications as
well as automated systems and instrumentation of ours and third parties with
whom we do business. There can be no guarantee that third parties of business
importance to us will successfully reprogram or replace, and test, all of their
own computer hardware, software and process control systems to ensure such
systems are Year 2000 ready. Failure by us, third parties of business
importance to us and/or other constituents such as governments to become Year
2000 ready on a timely basis could have a material adverse effect on our
financial position and results of operations. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources; Other Matters; Year 2000 Readiness Disclosure."
WE MAY NOT HAVE SUFFICIENT FUNDS TO REPURCHASE THE NOTES UPON A CHANGE OF
CONTROL
Should certain change of control events occur, each holder of the notes
will have the right to require us, subject to certain conditions, to repurchase
all or any part of that holder's notes at a price equal to 101% of the
principal of those notes, plus accrued and unpaid interest, if any, to the date
of repurchase. See "Description of the Notes -- Certain Covenants; Change of
Control." Existing senior indebtedness under our bank credit agreement and
certain other of our indebtedness include, and future indebtedness may include,
change of control provisions. Under those provisions, should a specified change
of control event occur, we would be required to repurchase, or the lender could
demand the repayment of, that indebtedness. We would be required to make that
repurchase or repayment of senior indebtedness before repurchasing the notes
(or then outstanding indebtedness ranking equally with the notes that contains
similar change of control provisions). The term "Change of Control" with
respect to the notes is defined in the "Description of the Notes -- Certain
Definitions" section of this prospectus.
We cannot assure you that we will have sufficient funds available or could
obtain the financing necessary to repurchase the notes and any other
outstanding indebtedness that rank equally with or senior to the notes tendered
by holders of those obligations following a change of control. If a change of
control occurred and we did not have the funds or financing available to pay
for the notes and any other indebtedness ranking equally with, or senior to,
the notes that are tendered for repurchase, an event of default would be
triggered under the indenture governing the notes and under such other
outstanding indebtedness. Each of these defaults could have a material adverse
consequence for us and the holders of the notes.
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In addition, we have two other series of notes outstanding that contain
change of control provisions that are similar to the change of control
provisions contained in the notes. Consequently, an event triggering a change
of control repurchase obligation under the notes may also trigger a change of
control repurchase obligation under those other series of notes. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."
Also, the definition of change of control includes a phrase relating to the
sale or other disposition of the our properties and assets "substantially as an
entirety." Although there is a developing body of case law interpreting phrases
such as "substantially as an entirety," there is no precise established
definition of such phrases under applicable law. Accordingly, the ability of a
holder of the notes to require us to repurchase its notes as a result of our
sale or other disposition of less than all our properties and assets on a
consolidated basis to another person or related group of persons may be
uncertain. See "Description of the Notes -- Certain Covenants; Change of
Control."
FUTURE SUBSIDIARY GUARANTEES MAY BE AFFECTED BY FRAUDULENT CONVEYANCE LAWS
None of our subsidiaries currently guarantee the notes. If our existing or
future restricted subsidiaries guarantee any of our other indebtedness, they
will be required by the terms of the indenture governing the notes to jointly
and severally guarantee the notes on a senior subordinated basis. We do not
intend to cause any of our subsidiaries to take any action that would require
it to issue a guarantee of the notes. Various applicable fraudulent conveyance
laws have been enacted for the protection of creditors. A court may use those
laws to subordinate or avoid any guarantee of the notes issued by any of our
subsidiaries. It is also possible that under certain circumstances a court
could hold that the direct obligations of a subsidiary guaranteeing the notes
could be superior to the obligations under that guarantee.
A court could avoid or subordinate the guarantee of the notes by any of our
subsidiaries in favor of that subsidiary's other debts or liabilities to the
extent that the court determined either of the following were true at the time
the subsidiary issued the guarantee:
o that subsidiary incurred the guarantee with the intent to hinder,
delay or defraud any of its present or future creditors or that such
subsidiary contemplated insolvency with a design to favor one or
more creditors to the total or partial exclusion of others; or
o that subsidiary did not receive fair consideration or reasonably
equivalent value for issuing the guarantee and, at the time it
issued the guarantee, that subsidiary:
-- was insolvent or rendered insolvent by reason of the issuance
of the guarantee,
-- was engaged or about to engage in a business or transaction for
which the remaining assets of that subsidiary constituted
unreasonably small capital, or
-- intended to incur, or believed that it would incur, debts beyond
its ability to pay such debts as they matured.
Among other things, a legal challenge of a subsidiary's guarantee of the notes
on fraudulent conveyance grounds may focus on the benefits, if any, realized by
that subsidiary as a result of our issuance of the notes. To the extent a
subsidiary's guarantee of the notes is avoided as a result of fraudulent
conveyance or held unenforceable for any other reason, the note holders would
cease to have any claim in respect of that guarantee and would be creditors
solely of ours.
THE ABSENCE OF A TRADING MARKET AND OTHER FACTORS MAY AFFECT THE LIQUIDITY OF
THE NOTES
The new notes will be new securities for which currently there is no
trading market. We do not currently intend to apply for listing of the new
notes on any securities exchange or stock market. Although the initial
purchasers of the new notes have informed us that they currently intend to make
a market in the new notes, they are not obligated to do so. Any such market
making may be discontinued at any time without notice. The liquidity of any
market for the new notes will depend on the number of holders of those notes,
the interest of securities dealers in making a market in those securities and
other factors. Accordingly, we cannot assure you as to the development or
liquidity of
22
<PAGE> 23
any market for the new notes. Historically, the market for noninvestment grade
debt has been subject to disruptions that have caused substantial volatility in
the prices of securities similar to the new notes. We cannot assure you that
the market, if any, for the new notes will be free from similar disruptions.
Any such disruptions may adversely effect the new note holders.
23
<PAGE> 24
PRIVATE PLACEMENT
On January 15, 1999, the Company issued $150,000,000 principal amount of
the outstanding notes to the initial purchasers of those notes (the "Initial
Purchasers") at a price of 95.95% of the principal amount of those notes in a
private transaction not registered under the Securities Act of 1933, as amended
(the "Securities Act"), in reliance upon Section 4(2) of the Securities Act.
The Initial Purchasers then offered and resold the outstanding notes only to
qualified institutional buyers at an initial price to such purchasers of 97.70%
of the principal amount of those notes. We used the approximately $143,675,000
of proceeds (after deducting the Initial Purchasers' discounts and the expenses
of that offering) to repay a portion of our outstanding Senior Indebtedness.
USE OF PROCEEDS
The Company will not receive any cash proceeds from the issuance of the new
notes. In consideration for issuing the new notes, the Company will receive in
exchange a like principal amount of outstanding notes. The outstanding notes
surrendered in exchange for the new notes will be retired and canceled and
cannot be reissued. Accordingly, issuance of the new notes will not result in
any change in the Company's capitalization.
CAPITALIZATION
The following table sets forth the unaudited consolidated debt and
capitalization of the Company and its subsidiaries at September 30, 1998. The
table has also been adjusted to reflect the issuance of the outstanding notes
and the application of the net proceeds therefrom as described under "Use of
Proceeds" assuming the outstanding notes sale had occurred on September 30,
1998. This table should be read in conjunction with the consolidated financial
statements and related notes thereto included in the Company's Reports and
incorporated by reference in this prospectus. See "Incorporation of Certain
Documents by Reference."
<TABLE>
<CAPTION>
SEPTEMBER 30, 1998
------------------------
ACTUAL AS ADJUSTED
------ -----------
(IN THOUSANDS)
<S> <C> <C>
Long-term debt, including current portion:
Credit Agreement indebtedness(a) $154,000 $ 10,325
Uncommitted credit line with bank 2,000 2,000
Banker's acceptance loans 10,854 10,854
10 3/8% Senior Subordinated Notes, due 2009 -- 150,000
8 3/4% Senior Subordinated Notes, due 2007 100,000 100,000
5 1/2% Convertible subordinated notes, due 2006 115,000 115,000
-------- --------
Total long-term debt 381,854 388,179
-------- --------
Shareholders' equity:
Preferred stock, $1 par value; 2,000,000 shares authorized; no
shares issued and outstanding -- --
Common Stock, $1 par value; 100,000,000 shares authorized;
40,119,250 shares issued 40,119 40,119
Additional capital 290,133 290,133
Retained earnings (deficit) (46,104) (46,104)
Treasury stock, at cost; 15,575 shares; and other (324) (324)
-------- --------
Total shareholders' equity 283,824 283,824
-------- --------
Total capitalization $665,678 $672,003
======== ========
</TABLE>
- ----------------
(a) As of December 31, 1998, the outstanding indebtedness under the Credit
Agreement was $205,000,000.
24
<PAGE> 25
SELECTED FINANCIAL DATA
The selected financial data presented below as of, and for each of the
years in the five-year period ended December 31, 1997, are derived from the
consolidated financial statements of the Company and its subsidiaries, which
have been audited by independent public accountants. The financial data as of,
and for the nine month periods ended September 30, 1997 and 1998, are derived
from the Company's unaudited financial statements which, in the opinion of
management, include all adjustments (which consist only of normal recurring
adjustments) necessary for a fair presentation of the financial position and
results of operations of the Company for each such interim period. This data
should be read in conjunction with the consolidated financial statements and
related notes thereto and "Management's Discussion and Analysis of Financial
Condition and Results of Operations" included elsewhere herein.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
Year Ended December 31, SEPTEMBER 30,
----------------------------------------------------- ------------------
1993 1994 1995 1996 1997 1997 1998(e)
---- ---- ---- ---- ---- ---- -------
(IN THOUSANDS, EXCEPT RATIOS AND UNIT AMOUNTS)
(Unaudited)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue:
Crude oil and condensate $ 64,042 $ 65,141 $ 76,557 $ 96,908 $ 112,603 $ 84,776 $ 59,276
Natural gas 66,173 99,093 72,032 94,589 158,500 116,117 91,411
Natural gas liquids 7,288 9,189 8,097 11,867 13,748 11,746 8,149
--------- --------- --------- --------- --------- --------- ---------
Oil and gas revenues 137,503 173,423 156,686 203,364 284,851 212,639 158,836
Pipeline and other, net (950) 133 773 778 349 1,274 842
Interest on tax refund 2,322 -- -- -- -- -- --
Gains (losses) on sales 679 52 100 (165) 1,100 1,318 (106)
--------- --------- --------- --------- --------- --------- ---------
Total 139,554 173,608 157,559 203,977 286,300 215,231 159,572
--------- --------- --------- --------- --------- --------- ---------
Operating costs and expenses:
Lease operating 26,633 29,768 35,071 37,628 63,501 45,116 51,196
General and administrative 14,550 15,984 16,400 18,028 21,412 15,746 19,843
Exploration 2,455 5,257 7,468 16,777 10,530 7,823 7,260
Dry hole and impairment 4,690 7,088 6,703 8,579 9,631 6,926 7,906
Depreciation, depletion and amortization 40,693 63,308 68,489 61,857 103,157 75,989 83,739
--------- --------- --------- --------- --------- --------- ---------
Total 89,021 121,405 134,131 142,869 208,231 151,600 169,944
--------- --------- --------- --------- --------- --------- ---------
Operating income (loss) 50,533 52,203 23,428 61,108 78,069 63,631 (10,372)
Interest charges (10,956) (10,104) (11,167) (13,203) (21,886) (15,771) (17,513)
Interest income 14 53 26 232 453 271 534
Interest capitalized 451 739 1,834 4,244 6,175 3,463 6,540
Foreign currency translation gain (loss) -- -- -- -- (7,604) (6,522) 953
--------- --------- --------- --------- --------- --------- ---------
Income (loss) before taxes and
extraordinary items 40,042 42,891 14,121 52,381 55,207 45,072 (19,858)
Income tax (expense) benefit (14,981) (15,517) (4,891) (18,800) (18,091) (15,694) 9,052
--------- --------- --------- --------- --------- --------- ---------
Income (loss) before extraordinary items 25,061 27,374 9,230 33,581 37,116 29,378 (10,806)
Extraordinary loss -- (307) -- (821) -- -- --
--------- --------- --------- --------- --------- --------- ---------
Net income (loss) $ 25,061 $ 27,067 $ 9,230 $ 32,760 $ 37,116 $ 29,378 $ (10,806)
========= ========= ========= ========= ========= ========= =========
</TABLE>
25
<PAGE> 26
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C>
OTHER FINANCIAL DATA:
EBITDA(a) $95,930 $122,652 $98,646 $131,776 $183,706 $140,295 $82,760
Capital and exploration expenditures
(excluding interest capitalized 74,600 120,800 110,400 206,200 259,500 165,000 121,800
SELECTED RATIOS:
EBITDA/Net interest expense 9.1x 13.1x 10.6x 14.7x 11.7x 11.4x 7.5x
Ratio of earnings to fixed charges(b) 4.5x 5.1x 2.1x 4.6x 3.2x 3.6x (c)
Long-term obligations/EBITDA(d) 1.4x 1.2x 1.7x 1.9x 1.9x 2.4x 4.6x
Long-term obligations/Total proved
reserves (BOE) $ 1.95 $ 2.01 $ 1.63 $ 2.24 $ 2.78 n/a n/a
</TABLE>
<TABLE>
<CAPTION>
September 30, 1998(e)
-----------------------------
Actual As Adjusted(f)
------ --------------
<S> <C> <C>
BALANCE SHEET DATA:
Total assets $823,350 $829,675
Long-term obligations, including current portion 381,854 388,179
Total shareholders' equity 283,824 283,824
</TABLE>
- ---------------------
(a) EBITDA represents income from continuing operations before income taxes,
interest expense, depreciation, depletion and amortization, and dry hole
and impairment costs. EBITDA is presented as a measure of the Company's
debt service ability, and not as an alternative to (i) operating income
(as determined in accordance with generally accepted accounting
principals) as an indicator of the Company's operating performance, or
(ii) cash flows from operating activities (as determined in accordance
with generally accepted accounting principals) as a measure of liquidity.
(b) Pre-tax earnings plus total interest charges, including amortization of
debt issue expenses, divided by total interest charges, including
amortization of debt issue expenses.
(c) For the nine-month period ended September 30, 1998, earnings were
insufficient to cover fixed charges by $26.5 million.
(d) Long-term obligations includes the current portion of long-term debt.
(e) Includes the results of Arch from August 17, 1998, the effective date of
its acquisition by the Company. The acquisition was accounted for using
the purchase method.
(f) Adjusted to give effect to the sale of the outstanding notes and the
application of the net proceeds from that sale as if it had occurred on
September 30, 1998.
26
<PAGE> 27
SELECTED RESERVE AND OPERATING DATA
The selected reserve and operating data presented below under the captions
"Production (Sales) Data" as of, and for each of the years in the five-year
period ended, December 31, 1997, and for the nine month periods ended September
30, 1997, and 1998, is unaudited and should be read in conjunction with the
consolidated financial statements and related notes thereto and "Business and
Properties -- Exploration and Production Data; Production and Sales" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations." The reserve information presented under the caption "Reserve Data"
as of, and for each of the years in the five-year period ended, December 31,
1997 has been derived from the summary reserve report prepared by Ryder Scott
and should be read in conjunction with the notes to the Company's consolidated
financial statements and "Business and Properties -- Exploration and Production
Data; Reserves." The data included in the Reports is incorporated in this
prospectus by reference. See "Incorporation of Certain Documents by Reference."
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
Year Ended December 31, SEPTEMBER 30,
-------------------------------------------------------- -----------------
1993 1994 1995 1996 1997 1997 1998
---- ---- ---- ---- ---- ---- ----
(IN THOUSANDS, EXCEPT UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
PRODUCTION (SALES) DATA:
Net daily average and weighted average
price:
Natural gas:
Mcf per day 91,700 144,800 121,000 107,700 181,700 184,500 164,400
Price per Mcf $ 1.98 $ 1.88 $ 1.63 $ 2.40 $ 2.39 $ 2.31 $ 2.04
Crude oil and condensate:
Bbls per day 9,851 11,100 11,786 11,968 15,927 15,856 16,090
Price per Bbl $ 17.81 $ 16.08 $ 17.80 $ 22.12 $ 19.37 $ 19.52 $ 13.49
Natural gas liquids:
Bbls per day 1,678 2,222 1,998 2,173 2,923 3,424 2,768
Price per Bbl $ 11.90 $ 11.33 $ 11.10 $ 14.92 $ 12.89 $ 12.57 $ 10.78
RESERVE DATA(A)(D):
Estimated proved reserves:
Crude oil, condensate and natural gas
liquids (MBbls) 28,268 33,862 45,182 49,602 58,164 -- --
Natural gas (MMcf) 232,866 242,890 328,061 360,944 401,488 -- --
Natural gas equivalents (MMcfe) 402,474 446,062 599,153 658,556 750,472 -- --
Estimated future net revenues before
income taxes, discounted at 10%(b)(c) $403,840 $382,980 $532,475 $954,545 $462,781 -- --
Estimated future net revenues after
income taxes, discounted at 10%(b) $300,260 $290,069 $377,145 $686,040 $349,465 -- --
</TABLE>
(a) Proved reserves were estimated in accordance with SEC guidelines using
oil and gas prices and production and development costs as of December 31
of each such year. These amounts exclude Arch's proved reserves. See
"Business and Properties -- Arch and its Subsidiaries; Oil and Gas
Reserves."
(b) These values were estimated in accordance with SEC guidelines. See
"Business and Properties -- Exploration and Production Data; Reserves."
27
<PAGE> 28
(c) Based on assumed Company-wide flat prices of $12.00 per Bbl for oil and
condensate and $2.00 per Mcf for gas, the Company's reservoir engineers
estimate that the present value of future net revenues before income
taxes, discounted at 10%, of the Company's proved reserves would have
been approximately $254,599,000 at December 31, 1997. This calculation
represents an internal Company estimate, is presented for information
purposes and has not been calculated entirely in accordance with SEC
guidelines.
(d) On a pro forma basis, giving effect to the Company's merger with Arch as
if it had occurred on December 31, 1997, and using SEC pricing in effect
on that date, the Company's estimated proved reserves of: (i) crude oil,
condensate and natural gas liquids would have been 64,045 MBbls; (ii)
natural gas would have been 478,373 MMcf; (iii) natural gas equivalents
would have been 862,643 MMcfe; and estimated future net revenues before
income taxes discounted at 10% would have been $528,745,000. Based on
assumed Company-wide flat prices of $12.00 per Bbl for oil and condensate
and $2.00 per Mcf for gas, the Company's reservoir engineers estimate
that the present value of future net revenues before income taxes,
discounted at 10%, of our proved reserves would have been approximately
$305,806,000 at December 31, 1997 if Arch's reserves were included as of
that date.
28
<PAGE> 29
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Company's acquisition of Arch was initially accounted for as a pooling
of interests which requires the financial results for all periods prior to the
acquisition to be combined and restated as if the Company and Arch had always
been combined. The Company then restated its consolidated financial statements
for periods prior to the merger, including the first nine months of 1997 and
the first nine months of 1998, to reflect the combined results of both the
Company and Arch. A report on Form 10-Q for the quarter ended September 30,
1998 was filed on that basis. The Company recently concluded that, as a result
of the current environment of low crude oil and natural gas prices, the Company
must maintain maximum flexibility to address its cash flow needs, including the
option of selling certain of the Company's assets. Under the current
application of accounting principles, such transactions would preclude the
pooling of interests method of accounting and require that the Company account
for the acquisition using the purchase method of accounting. Consequently, on
December 24, 1998, the Company filed an amended report on Form 10-Q for the
quarter ended September 30, 1998, primarily for the purpose of restating the
financial statements contained in such report and to make conforming changes to
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" to reflect the change from the pooling method of accounting to the
purchase method of accounting for the Arch acquisition. See "Incorporation of
Certain Documents by Reference."
NINE MONTHS ENDED SEPTEMBER 30, 1998, COMPARED WITH THE NINE MONTHS ENDED
SEPTEMBER 30, 1997
RESULTS OF OPERATIONS
Net Income (Loss)
For the first nine months of 1998, the Company reported a net loss of
$10,806,000 or $0.29 per share (on both a basic and a diluted basis) compared
to net income for the first nine months of 1997 of $29,378,000 or $0.88 per
share ($31,689,000 or $0.83 on a diluted basis). Among other items affecting
net income for the first nine months of 1998, were non-recurring expenses
totaling approximately $2,285,000 ($1,485,000 or $0.04 per share on an
after-tax basis), related to the Company's acquisition of Arch.
Earnings per share are based on the weighted average number of common
shares outstanding for the first nine months of 1998 of 37,171,000, compared to
33,374,000 for the first nine months of 1997. The increase in the weighted
average number of common shares outstanding for the 1998 period, compared to
the 1997 period, resulted primarily from the issuance of 3,882,023 shares of
its common stock upon the conversion of the Company's 5 1/2% Convertible
Subordinated Notes due 2004 (the "2004 Notes") prior to their being redeemed on
March 16, 1998, the issuance as of August 17, 1998, of approximately 2,540,000
shares of common stock to former holders of Arch capital stock and convertible
debt securities in connection with the Company's acquisition of Arch and, to a
lesser extent, the issuance of common stock upon the exercise of stock options
pursuant to the Company's stock option plans. The earnings per share
computation on a diluted basis in the 1998 period is identical to the basic
earnings per share computation because there were no securities of the Company
that were dilutive during the period. The earnings per share computation on a
diluted basis in the 1997 period primarily reflects additional shares of common
stock issuable upon the assumed conversion of the 2004 Notes and the
elimination of related interest requirements, as adjusted for applicable
federal income taxes and, to a lesser extent, the assumed exercise of options
to purchase common shares. The weighted average number of common shares
outstanding on a diluted basis for the first nine months of 1997 were
38,064,000.
Total Revenues
The Company's total revenues for the first nine months of 1998 were
$159,572,000, a decrease of approximately 26% compared to total revenues of
$215,231,000 for the first nine months of 1997. The decrease in the Company's
total revenues for the first nine months of 1998, compared to the first nine
months of 1997, resulted primarily from decreases in revenue from the Company's
oil and gas operations and, to a lesser extent, a decline in revenue from the
29
<PAGE> 30
sale of non-strategic properties, pipeline sales revenues and other
miscellaneous items. Total revenues for the first nine months of 1998 reflect
the inclusion of pipeline revenues from Saginaw Pipeline, L.C. and its
marketing subsidiary, Industrial Natural Gas, L.C., which the Company acquired
through its acquisition of Arch on August 17, 1998. Total revenues for the
first nine months of 1997 include a net gain of $1,459,000 on the sale of a
compressor by the Company during the first half of 1997.
Oil And Gas Revenues
The following table reflects an analysis of differences in the Company's
oil and gas revenues (expressed in thousands of dollars) between the first nine
months of 1998 and the same period in the preceding year.
<TABLE>
<CAPTION>
9 MONTHS 1998
COMPARED TO
9 MONTHS 1997
-------------
<S> <C>
Increase (decrease) in oil and gas revenues resulting from differences in:
NATURAL GAS --
Price...................................................................... $(13,598)
Production................................................................. (11,108)
--------
(24,706)
CRUDE OIL AND CONDENSATE --
Price...................................................................... (26,366)
Production................................................................. 866
--------
(25,500)
NGL--......................................................................... (3,597)
--------
Increase (decrease) in oil and gas revenues................................ $(53,803)
========
</TABLE>
Prices and production volumes attributable to the Company's operations in
Canada are included in the Company's domestic oil and gas prices and production
volumes. This information is not presented separately because the Company does
not believe that such information is material to an understanding of the
Company's results of operations for the period presented due to the relatively
small portion of the Company's oil and gas revenues which were attributable to
such operations during the applicable periods.
NATURAL GAS PRICES. Prices that the Company received for its natural gas
production during the first nine months of 1998 averaged $2.04 per Mcf, a
decrease of approximately 12% from an average price of $2.31 per Mcf that the
Company received for its natural gas production during the first nine months of
1997.
Domestic Prices. Prices that the Company received for its domestic natural
gas production during the first nine months of 1998 averaged $2.13 per Mcf, a
decrease of approximately 10% from an average price of $2.37 per Mcf that the
Company received for its domestic natural gas production during the first nine
months of 1997.
Thailand Prices. The Company's Tantawan Field located in the Kingdom of
Thailand commenced production of natural gas and liquid hydrocarbons in
February 1997. During the first nine months of 1998, the prices that the
Company received under its long term gas sales contract for natural gas
production from the Tantawan Field averaged approximately 74 Thai Baht per Mcf.
Based on the Thai Baht to U.S. dollar exchange rates in effect at the time that
such production was recorded on the Company's financial statements, the average
price in U.S. dollars that the Company recorded during the first nine months of
1998 for such production was approximately $1.73 per Mcf, a decrease of
approximately 14% from an average price of $2.00 per Mcf that the Company
recorded in the first nine months of 1997. The price that the Company receives
under its Gas Sales Agreement normally adjusts on a semi-annual basis. However,
the Gas Sales Agreement provides for adjustment on a more frequent basis in the
event that certain indices and factors on which the price is based fluctuate
outside a given range. Due to the volatility of the Thai Baht and the current
economic difficulties in the Kingdom of Thailand and throughout Southeast Asia,
the price that the Company received under the Gas Sales Agreement was adjusted
several times during the first nine months of 1998. See "Business and
Properties -- International Operations; Contractual Terms Governing the
Thailand Concession and Related Production." The Company cannot predict what
the Baht to dollar exchange rate may be in the future. Moreover, it is
anticipated that this exchange rate will remain volatile. See "; Foreign
Currency
30
<PAGE> 31
Transaction Gain (Loss)", "-- Liquidity and Capital Resources; Other Matters;
Southeast Asia Economic Issues" and "Business and Properties -- International
Operations; Contractual Terms Governing the Thailand Concession and Related
Production."
NATURAL GAS PRODUCTION. The Company's total natural gas production during
the first nine months of 1998 averaged 164.4 MMcf per day, a decrease of
approximately 11% from an average of 184.5 MMcf per day that the Company
produced during the first nine months of 1997.
Domestic Production. The decrease in the Company's natural gas production
during the first nine months of 1998, compared to the first nine months of
1997, was related in large measure to decreased production from the Company's
East Cameron Block 334 "E" platform, and to a lesser extent, three periods in
the third quarter of 1998 during which most of the Company's offshore
production was shut-in as a precautionary measure due to hurricanes in the Gulf
of Mexico and natural production declines, that was partially offset by
increased production from the Company's onshore properties located in South
Texas and South Louisiana. As of December 31, 1998, the Company was not a party
to any future natural gas sales contracts.
Thailand Production. The Company's share of natural gas production from the
Tantawan Field during the first nine months of 1998 averaged 38.9 MMcf per day,
an increase of approximately 21% from an average of 32.1 MMcf per day that the
Company produced during the first nine months of 1997. The increase in the
Company's average daily natural gas production from the Tantawan Field during
the first nine months of 1998, compared to the first nine months of 1997,
reflects the fact that production from the Tantawan Field did not commence
until early in February 1997 and did not achieve sustained commercial
production rates until March 15, 1997. Commencing on October 1, 1998, the
Company and its joint venture partners have been delivering less natural gas
than is being nominated by PTT under the Gas Sales Agreement. This could result
in the Company receiving only 75% of the current contract price on a portion of
its future natural gas sales to PTT. The Company is taking actions that it
currently believes will minimize the penalty that it will incur on future gas
sales to PTT by, among other things, increasing production from the Tantawan
Field.
CRUDE OIL AND CONDENSATE PRICES. Prices that the Company received for its
crude oil and condensate production during the first nine months of 1998
averaged $13.49 per Bbl, a decrease of approximately 31% from an average price
of $19.58 per Bbl that the Company received during the first nine months of
1997.
Domestic Prices. Prices that the Company received for its domestic crude
oil and condensate production during the first nine months of 1998 averaged
$13.44 per Bbl, a decrease of approximately 32% from an average price of $19.69
per Bbl that the Company received during the first nine months of 1997.
Thailand Prices. Since the inception of production from the Tantawan Field,
crude oil and condensate have been stored in a Floating Production, Storage and
Offloading System (the "FPSO") until an economic quantity is accumulated for
offloading and sale. The first such sale of crude oil and condensate from the
Tantawan Field occurred in July 1997. The price that the Company recorded for
its crude oil and condensate production stored on the FPSO for the first nine
months of 1998 was $13.72 per Bbl, a decrease of approximately 27% from the
price of $18.84 per Bbl that was recorded for the first nine months of 1997.
Prices that the Company receives for its crude oil and condensate production
from Thailand are based on world benchmark prices, which are denominated in
dollars. In addition, the Company is generally paid for its crude oil and
condensate production from Thailand in U.S. dollars.
CRUDE OIL AND CONDENSATE PRODUCTION. The Company's total crude oil and
condensate production during the first nine months of 1998 averaged 16,090 Bbls
per day, an increase of approximately 1% from an average of 15,856 Bbls per day
during the first nine months of 1997.
Domestic Production. The Company's domestic crude oil and condensate
production during the first nine months of 1998 averaged 13,317 Bbls per day, a
decrease of approximately 4% from an average of 13,927 Bbls per day during the
first nine months of 1997. The decrease in the Company's domestic crude oil and
condensate production during the first nine months of 1998, compared to the
first nine months of 1997, resulted primarily from a decrease
31
<PAGE> 32
in condensate production from the Company's East Cameron Block 334 "E"
platform, which was in part due to damage sustained in a marine accident at the
crude oil and condensate pipeline from the platform, that was only partially
offset by increased production from the Company's ongoing development drilling
and workover programs in the offshore and onshore Gulf of Mexico regions. As of
December 31, 1998, the Company was not a party to any crude oil swaps or
futures contracts.
Thailand Production. The Company's share of crude oil and condensate
production from the Tantawan Field during the first nine months of 1998
averaged 2,773 Bbls per day, an increase of approximately 44% from an average
of 1,930 Bbls per day during the first nine months of 1997. The increase in the
Company's average daily crude oil and condensate production from the Tantawan
Field during the first nine months of 1998, compared to the first nine months
of 1997, primarily reflects the fact that production from the Tantawan Field
did not commence until early in February 1997 and did not achieve sustained
commercial production rates until March 15, 1997.
NGL PRODUCTION. The Company's oil and gas revenues, and its total liquid
hydrocarbon production volumes, reflect the production and sale by the Company.
The Company's NGL revenues for the first nine months of 1998 decreased
$3,597,000, from the first nine months of 1997. The decrease in the Company's
NGL for the first nine months of 1998, compared to the first nine months of
1997, was related to both a decrease in NGL production volumes from the
Company's domestic offshore properties and a decrease in the price that the
Company received for its NGL production volumes.
TOTAL LIQUID HYDROCARBON PRODUCTION. The Company's average liquid
hydrocarbon production during the first nine months of 1998 was 18,858 Bbls per
day, a decrease of approximately 2% from an average liquid hydrocarbon
production of 19,280 Bbls per day during the first nine months of 1997.
Lease Operating Expenses
Company-wide lease operating expenses for the first nine months of 1998
were $51,196,000, an increase of approximately 13% from lease operating
expenses of $45,116,000 for the first nine months of 1997. A discussion of
lease operating expenses attributable to the Company's operations in Canada is
included in the Company's domestic lease operating expenses. The information is
not presented separately because the Company does not believe that such
information is material to an understanding of the Company's results of
operations for the periods presented due to the relatively small portion of the
Company's lease operating expenses which were attributable to such operations
during the applicable periods.
DOMESTIC LEASE OPERATING EXPENSES. The Company's domestic lease operating
expenses for the first nine months of 1998 were $35,249,000, an increase of
approximately 11% from domestic lease operating expenses of $31,802,000 for the
first nine months of 1997. The increase in domestic lease operating expenses
for the first nine months of 1998, compared to the first nine months of 1997,
were affected by a non-recurring maintenance project on the Company's East
Cameron 334 "E" platform during the first quarter of 1998 and by expenses
related to purchasing natural gas for transportation and subsequent resale on
the pipeline system acquired in the merger with Arch, operating expenses
related to the pipeline system for which no corresponding expenses were
recorded during the first nine months of 1997. In addition, lease operating
expenses for the first nine months of 1997 were reduced by a $954,000 refund in
connection with the Company's audit of a joint venture partner, for which no
corresponding refund of a similar magnitude was obtained in the first nine
months of 1998.
THAILAND LEASE OPERATING EXPENSES. The Company's lease operating expenses
in the Kingdom of Thailand for the first nine months of 1998 were $15,947,000,
an increase of approximately 20% from lease operating expenses of $13,314,000
for the first nine months of 1997. The increase in lease operating expenses in
the Kingdom of Thailand for the first nine months of 1998, compared to the
first nine months of 1997, was primarily related to the fact that prior to the
commencement of production in the Tantawan Field on February 1, 1997, no lease
operating expenses were incurred by the Company in Thailand. Consequently, the
Company does not believe that a comparison of lease operating expenses in the
Kingdom of Thailand between the first nine months of 1998 and the first nine
months of 1997 is meaningful. A substantial portion of the Company's lease
operating expenses in the Kingdom of Thailand
32
<PAGE> 33
relate to lease payments made by Tantawan Services, L.C., in connection with
its bareboat charter of the FPSO, which amounted to $8,318,000 and $7,404,000
(net to the Company's interest) for the first nine months of 1998 and 1997,
respectively. See "-- Liquidity and Capital Resources; Capital Requirements;
Other Material Long-Term Commitments."
General and Administrative Expenses
General and administrative expenses for the first nine months of 1998 were
$19,843,000, an increase of approximately 26% from general and administrative
expenses of $15,746,000 for the first nine months of 1997. The increase in
general and administrative expenses for the first nine months of 1998, compared
with the first nine months of 1997, was primarily related to a number of
non-recurring expenses arising in connection with the Company's acquisition of
Arch totaling approximately $2,285,000, that included severance payments to
former officers and employees of Arch. In addition, the increase in general and
administrative expense was attributable, in part, to an increase in the size of
the Company's work force and normal salary and concomitant benefit expense
adjustments.
Exploration Expenses
Exploration expenses consist primarily of rental payments required under
oil and gas leases to hold non-producing properties ("delay rentals") and
geological and geophysical costs which are expensed as incurred. Exploration
expenses for the first nine months of 1998 were $7,260,000, a decrease of
approximately 7% from exploration expenses of $7,823,000 for the first nine
months of 1997. The decreases in exploration expenses for the first nine months
of 1998, compared to the first nine months of 1997, resulted primarily from
decreased geophysical activity in the Gulf of Mexico and West Texas, and a
decrease in delay rental payments, that were partially offset, during the
comparable nine month periods, by increased geophysical activity by the Company
in East Texas, South Louisiana and in the Gulf of Thailand.
Dry Hole and Impairment Expenses
Dry hole and impairment expenses relate to costs of unsuccessful wells
drilled, along with impairments due to decreases in expected reserves from
producing wells. The Company's dry hole and impairment expenses for the first
nine months of 1998 were $7,906,000, an increase of approximately 14% from dry
hole and impairment expenses of $6,926,000 for the first nine months of 1997.
Depreciation, Depletion and Amortization Expenses
The Company accounts for its oil and gas activities using the successful
efforts method of accounting. Under the successful efforts method, lease
acquisition costs and all development costs are capitalized. Proved properties
are reviewed whenever events or changes in circumstances indicate that the
value of such property on the Company's books may not be recoverable. Unproved
properties are reviewed quarterly to determine if there has been impairment of
the carrying value, with any such impairment charged to expense in the period.
Exploratory drilling costs are capitalized until the results are determined. If
proved reserves are not discovered, the exploratory drilling costs are
expensed. Other exploratory costs are expensed as incurred.
The provision for depreciation, depletion and amortization ("DD&A") is
based on the capitalized costs, as determined in the preceding paragraph, plus
future costs to abandon offshore wells and platforms, and is determined on a
cost center by cost center basis using the units of production method. The
Company generally creates cost centers on a field by field basis for oil and
gas activities in the Gulf of Mexico and Gulf of Thailand. Generally, the
Company establishes cost centers on the basis of an oil or gas trend or play
for its oil and gas activities onshore in the United States. The Company's DD&A
expense for the first nine months of 1998 was $83,739,000, an increase of
approximately 10% from DD&A expense of $75,989,000 for the first nine months of
1997. The increases in DD&A expense for the first nine months of 1998, compared
to the first nine months of 1997, resulted primarily from an
33
<PAGE> 34
increase in the Company's composite DD&A rate that was only partially offset by
a decrease in production of oil and natural gas.
The composite DD&A rate for all of the Company's producing fields for the
first nine months of 1998 was $1.09 per equivalent Mcf ($6.54 per equivalent
Bbl), an increase of approximately 20% from a composite DD&A rate of $0.91 per
equivalent Mcf ($5.46 per equivalent Bbl) for the first nine months of 1997.
The increase in the composite DD&A rate for all of the Company's producing
fields for the first nine months of 1998, compared to the first nine months of
1997, resulted primarily from an increased percentage of the Company's
production coming from certain of the Company's fields that have DD&A rates
that are higher than the Company's recent historical composite rate and a
corresponding decrease in the percentage of the Company's production coming
from fields that have DD&A rates that are lower than the Company's recent
historical composite DD&A rate. The Company produced 75,781,000 equivalent Mcf
(12,630,000 equivalent Bbls) during the first nine months of 1998, a decrease
of approximately 8% from the 82,036,000 equivalent Mcf (13,673,000 equivalent
Bbls) produced by the Company during the first nine months of 1997.
Interest
INTEREST CHARGES. Interest charges incurred by the Company for the first
nine months of 1998 were $17,513,000, an increase of approximately 11% from
interest charges of $15,771,000 for the first nine months of 1997. The increase
in interest charges for the first nine months of 1998, compared to the first
nine months of 1997, resulted primarily from an increase in the average amount
of debt outstanding and, to a lesser extent, the average interest rate charged
on the Company's outstanding debt. As of December 31, 1998, the Company was not
a party to any interest rate swap agreements.
CAPITALIZED INTEREST. Capitalized interest expense for the first nine
months of 1998 was $6,540,000, an increase of approximately 89% from
capitalized interest expense of $3,463,000 for the first nine months of 1997.
The increase in capitalized interest for the first nine months of 1998,
compared to the first nine months of 1997, resulted primarily from an increase
in the amount of capital expenditures subject to interest capitalization during
the first nine months of 1998 ($122,414,000), compared to the first nine months
of 1997 ($73,086,000), and from an increase in the computed rate that the
Company uses to apply on such capital expenditures to arrive at the total
amount of capitalized interest. A substantial percentage of the Company's
capitalized interest expense during the latter half of 1997 and the first nine
months of 1998 resulted from capitalization of interest related to such capital
expenditures for the development of the Benchamas Field in the Gulf of Thailand
and, to a lesser extent, several development projects in the Gulf of Mexico.
Foreign Currency Transaction Gain (Loss)
The Company experienced a foreign currency transaction gain of $953,000
during the first nine months of 1998, compared to a foreign currency
transaction loss of $6,522,000 during the first nine months of 1997. The
foreign currency transaction gain and loss each resulted primarily from the
fluctuation against the U.S. dollar of cash and other monetary assets and
liabilities denominated in Thai Baht that were on the Company's subsidiary's
financial statements during the respective periods and, to a much lesser
extent, the fluctuation of the Canadian dollar against the U.S. dollar. In
early July 1997, the government of the Kingdom of Thailand announced that the
value of the Baht would be set against the dollar and other currencies under a
"managed float" program arrangement. This led to a substantial decline in value
of the Thai Baht compared to the U.S. dollar, resulting in the foreign currency
transaction losses during the 1997 periods presented. During the 1998 periods
presented, the value of the Thai Baht has generally strengthened against the
U.S. dollar, resulting in corresponding foreign currency transaction gains.
However, the Company cannot predict what the Thai Baht to dollar exchange rate
may be in the future. Moreover, it is anticipated that this exchange rate will
remain volatile. As of December 31, 1998, the Company was not a party to any
financial instrument that was intended to constitute a foreign currency hedging
arrangement.
34
<PAGE> 35
Income Tax Benefit (Expense)
The Company experienced an income tax benefit for the first nine months of
1998 of $9,052,000, compared to income tax expense of $15,694,000 for the first
nine months of 1997. The income tax benefit for the first nine months of 1998,
compared to the income tax expense for the first nine months of 1997, resulted
primarily from a pre-tax loss resulting from substantially lower revenues in
the United States and the tax benefit of accrued foreign losses from the
Company's operations in the Kingdom of Thailand.
YEAR ENDED DECEMBER 31, 1997, COMPARED WITH YEARS ENDED DECEMBER 31, 1996 AND
1995, RESPECTIVELY
RESULTS OF OPERATIONS
Net income
The Company reported net income for 1997 of $37,116,000 or $1.11 per share
($40,198,000 or $1.06 per share on a diluted basis) compared to net income for
1996 of $32,760,000 or $0.99 per share ($35,843,000 or $0.95 per share on a
diluted basis)and net income for 1995 of $9,230,000 or $0.28 per share (on both
a basic and a diluted basis). The Company recorded an extraordinary loss of
$821,000 during the second quarter of 1996 related to the early retirement of
the Company's 8% Convertible Subordinated Debentures, due 2005 with the
proceeds from the Company's issuance on June 18, 1996, of its 5 1/2%
Convertible Subordinated Notes, due 2006 (the "2006 Notes").
Earnings per common share are based on the weighted average number of
common and common equivalent shares outstanding for 1997 of 33,421,000
(38,064,000 on a diluted basis), compared to 33,203,000 (37,920,000 on a
diluted basis) for 1996 and 32,893,000 (33,490,000 on a diluted basis) for
1995. The yearly increases in the weighted average number of common shares
outstanding resulted primarily from the issuance of shares of Common Stock upon
the exercise of stock options pursuant to the Company's stock option plans.
Earnings per common share computations on a diluted basis primarily reflect
additional common shares issuable upon the assumed conversion of the 2004 Notes
in 1996 and 1997 (the only convertible securities of the Company that were
dilutive during the applicable periods) and the elimination of related interest
requirements, as adjusted for applicable federal income taxes. In addition, the
number of common shares outstanding in the diluted computation is adjusted, in
accordance with the Financial Accounting Standards Board's Statement of
Financial Accounting Standards No. 128 ("SFAS 128"), to include dilutive shares
that are assumed to have been issued by the Company in connection with options
exercised during the year, less treasury shares that are assumed to have been
purchased by the Company from the option proceeds. SFAS 128 was adopted by the
Company in 1997, resulting in a restatement of the earnings per share
calculations for 1996 and 1995, and all preceding years.
Total Revenues
The Company's total revenues for 1997 were $286,300,000, an increase of
approximately 40% from total revenues of $203,977,000 for 1996, and an increase
of approximately 82% from total revenues of $157,559,000 for 1995. The increase
in the Company's total revenues for 1997, compared to 1996, resulted primarily
from the substantial increase in the Company's natural gas and liquid
hydrocarbon (including crude oil, condensate and NGL) production, which was
only partially offset by a decline in the average price that the Company
received for its liquid hydrocarbon production and, to a much lesser extent,
the average price that the Company received for its natural gas production. The
increase in the Company's total revenues for 1997, compared to 1995, resulted
primarily from the substantial increases in the Company's natural gas
production, the average price that the Company received for its natural gas
production, the Company's liquid hydrocarbon production and, to a lesser
extent, the average price that the Company received for its liquid hydrocarbon
production.
Oil and Gas Revenues
The Company's oil and gas revenues for 1997 were $285,200,000, an increase
of approximately 40% from oil and gas revenues of $204,142,000 for 1996, and an
increase of approximately 81% from oil and gas revenues of
35
<PAGE> 36
$157,459,000 for 1995. The following table reflects an analysis of variances in
the Company's oil and gas revenues (expressed in thousands) between 1997 and
the previous two years:
<TABLE>
<CAPTION>
1997 COMPARED TO
----------------------
1996 1995
-------- --------
<S> <C> <C>
Increase (decrease) in oil and gas revenues resulting from variances in:
NATURAL GAS --
Price................................................ $ (394) $ 33,466
Production........................................... 64,305 53,002
-------- --------
63,911 86,468
CRUDE OIL AND CONDENSATE --
Price................................................ (12,064) 6,767
Production........................................... 27,759 29,279
-------- --------
15,695 36,046
NGL AND OTHER, NET --................................... 1,452 5,227
-------- --------
Increase in oil and gas revenues..................... $ 81,058 $127,741
======== ========
</TABLE>
NATURAL GAS PRICES. Prices per Mcf that the Company received for its
natural gas production during 1997 averaged $2.39 per Mcf. The average price
that the Company received for its natural gas production in 1997 was
approximately equal to the average price that the Company had received during
1996 of $2.40 per Mcf, but was a substantial increase (of approximately 47%)
from the average price of $1.63 that it received during 1995.
Domestic Prices. Prices that the Company received for its domestic natural
gas production during 1997 averaged $2.50 per Mcf, an increase of approximately
4% from an average price of $2.40 per Mcf that the Company received for its
domestic natural gas production during 1996, and an increase of approximately
53% from an average price of $1.63 that the Company received for its natural
gas production during 1995.
Thailand Prices. The Company's Tantawan Field located in the Kingdom of
Thailand commenced production of natural gas and liquid hydrocarbons in
February 1997. During 1997, the price that the Company received under the Gas
Sales Agreement averaged approximately 60 Thai Baht per Mcf. The price that the
Company receives under the Gas Sales Agreement would normally adjust on a
semi-annual basis. However, the Gas Sales Agreement provides for adjustment on
a more frequent basis in the event that certain indices and factors on which
the price is based fluctuate outside a given range. See "Business and
Properties -- International Operations; Contractual Terms Governing the
Thailand Concession and Related Production." Due to the volatility of the Thai
Baht and the current economic difficulties in the Kingdom of Thailand and
throughout Southeast Asia, the price that the Company receives under the Gas
Sales Agreement has been adjusted on almost a monthly basis since July 1997. As
a result of these adjustments, during December 1997 the price that the Company
received under the Gas Sales Agreement for its production from the Thailand
Concession averaged approximately 68 Thai Baht per Mcf. However, the increases
that the Company received during 1997 in the Thai Baht price for its natural
gas production from the Thailand Concession were not sufficient to completely
ameliorate, in U.S. dollar terms, the decline of the Thai Baht against the U.S.
dollar. The Company cannot predict when, if ever, the adjustments provided for
in the Gas Sales Agreement will completely recompense the Company for the
decline of the Thai Baht against the U.S. dollar. See ";Foreign Currency
Transaction Loss," "-- Liquidity and Capital Resources; Other Matters;
Southeast Asia Economic Issues" and "Business and Properties -- International
Operations; Contractual Terms Governing the Thailand Concession."
NATURAL GAS PRODUCTION. The Company's natural gas production for 1997
averaged 181.7 MMcf per day, an increase of approximately 69% from average
production of 107.7 MMcf per day during 1996, and an increase of approximately
50% from average production of 121 MMcf per day during 1995.
36
<PAGE> 37
Domestic Production. The Company's domestic natural gas production for 1997
averaged 147.2 MMcf per day, an increase of approximately 37% from average
production of 107.7 MMcf per day during 1996, and an increase of approximately
22% from average production of 121 MMcf per day during 1995. The increase in
the Company's average domestic natural gas production for 1997, compared to
1996 and 1995, was related in large measure to production from the Company's
East Cameron Block 334 "E" platform, which commenced production in April 1997,
and, to a lesser extent, the results of successful drilling in the Company's
Lopeno Field in South Texas and its Eugene Island Block 261 field, that was
only partially offset by the anticipated natural decline in deliverability from
certain of the Company's properties.
Thailand Production. The Company commenced production from its Tantawan
Field early in February 1997. Following a field startup phase which ended on
March 15, 1997, production from the Tantawan Field stabilized. During 1997, the
Company's share of natural gas production from the Tantawan Field averaged
approximately 37.7 MMcf per day.
CRUDE OIL AND CONDENSATE PRICES. Prices received by the Company for its
crude oil and condensate production averaged $19.37 per Bbl during 1997, a
decrease of approximately 12% compared to an average of $22.12 per Bbl during
1996, and an increase of approximately 9% compared to an average price of
$17.80 per Bbl that the Company received during 1995.
Domestic Prices. Prices that the Company received for its domestic crude
oil and condensate production during 1997 averaged $19.49 per Bbl, a decrease
of approximately 12% from an average price of $22.12 per Bbl that the Company
received for its domestic crude oil and condensate production during 1996, and
an increase of approximately 9% from an average price of $17.80 per Bbl that
the Company received for its crude oil and condensate production during 1995.
Thailand Prices. Since the inception of production from the Tantawan Field,
crude oil and condensate has been stored on the FPSO until an economic quantity
was accumulated for offloading and sale. The first such sale of crude oil and
condensate from the Tantawan Field occurred in July 1997. The average price
that the Company recorded for its crude oil and condensate production stored on
the FPSO during 1997 was $18.60 per Bbl. Prices that the Company receives for
such production are based on world benchmark prices, which are denominated in
U.S. dollars, and are generally paid in U.S. dollars.
CRUDE OIL AND CONDENSATE PRODUCTION. The Company's crude oil and condensate
production for 1997 averaged 15,927 Bbls per day, an increase of approximately
33% from 11,968 Bbls per day for 1996, and an increase of approximately 35%
from 11,786 Bbls per day for 1995.
Domestic Production. The Company's domestic crude oil and condensate
production for 1997 averaged 13,711 Bbls per day, an increase of approximately
15% from 11,968 Bbls per day for 1996, and an increase of approximately 16%
from 11,786 Bbls per day for 1995. The increase in the Company's crude oil and
condensate production for 1997, compared to 1996 and 1995, resulted primarily
from increased condensate production from wells located in the Gulf of Mexico
and, to a lesser extent, increased crude oil production from certain of the
Company's onshore properties, which was only partially offset by the natural
decline in deliverability from certain of the Company's more mature properties.
Thailand Production. The Company commenced production from its Tantawan
Field early in February 1997. Following a field startup phase which ended on
March 15, 1997, production from the Tantawan Field stabilized. During 1997, the
Company's share of crude oil and condensate production from the Tantawan Field
averaged approximately 2,216 Bbls per day.
NGL PRODUCTION AND "OTHER" NET REVENUE ITEMS. The Company's oil and gas
revenues, and its total liquid hydrocarbon production, reflect the production
and sale by the Company of NGL, which are liquid products that are extracted
from natural gas production. In addition, the Company's oil and gas revenues
for 1997, 1996 and 1995 also reflect adjustments for various miscellaneous
items. The Company's NGL and other, net revenues for 1997
37
<PAGE> 38
increased $1,452,000 from those reported in 1996, and $5,227,000 from those
reported in 1995. The increase in NGL and other, net revenues in 1997, compared
with 1996, primarily related to an increase in the Company's NGL production
that was partially offset by a decrease in the average price that the Company
received for such NGL production. The increase in NGL and other, net revenues
in 1997, compared with 1995, primarily related to an increase in the Company's
NGL production and, to a lesser extent, an increase in the price that the
Company received for its NGL production.
TOTAL LIQUID HYDROCARBON PRODUCTION. The Company's average liquid
hydrocarbon (including crude oil, condensate and NGL) production during 1997
was 18,851 Bbls per day, an increase of approximately 33% from an average total
liquids production of 14,141 Bbls per day for 1996, and an increase of
approximately 37% from an average total liquids production of 13,784 Bbls per
day for 1995.
Lease Operating Expenses
Lease operating expenses for 1997 were $63,501,000, an increase of
approximately 69% from lease operating expenses of $37,628,000 for 1996, and an
increase of approximately 81% from lease operating expenses of $35,071,000 for
1995.
DOMESTIC LEASE OPERATING EXPENSES. The Company's domestic lease operating
expenses for 1997 were $43,934,000, an increase of approximately 17% from
domestic lease operating expenses of $37,628,000 for 1996, and an increase of
approximately 25% from domestic lease operating expenses of $35,071,000 for
1995. The increase in domestic lease operating expenses for 1997, compared to
1996 and 1995, resulted primarily from increased costs to the Company (and the
entire offshore oil industry) because of a shortage of qualified offshore
service contractors, which permitted such contractors to increase the costs of
their services significantly during 1997, increased expenses related to the
leasing of certain equipment in the Gulf of Mexico, a year to year increase in
the level of the Company's operating activities, including increased operating
costs related to additional properties brought on production and an increased
ownership interest in certain properties as a result of the acquisition of such
interests.
THAILAND LEASE OPERATING EXPENSES. The Company's lease operating expenses
in Thailand for 1997 were $19,567,000. Prior to the commencement of production
in the Tantawan Field on February 1, 1997, there were no lease operating
expenses incurred by the Company in Thailand. A substantial portion of the
Company's lease operating expenses in the Kingdom of Thailand relate to lease
payments made by a subsidiary of the Company in connection with its bareboat
charter of the FPSO, which amounted to $10,200,000 during 1997. See " --
Liquidity and Capital Resources; Capital Requirements; Other Material Long-Term
Commitments."
General and Administrative Expenses
General and administrative expenses for 1997 were $21,412,000, an increase
of approximately 19% from general and administrative expenses of $18,028,000
for 1996, and an increase of approximately 31% from general and administrative
expenses of $16,400,000 for 1995. The increase in general and administrative
expenses for 1997, compared to 1996 and 1995, was primarily related to salary
and benefit expenses incurred in connection with the increase in the Company's
work force in its Bangkok, Thailand office as a result of the Company's
increased activities there.
Exploration Expenses
Exploration expenses for 1997 were $10,530,000, a decrease of approximately
37% from exploration expenses of $16,777,000 for 1996, and an increase of
approximately 41% from exploration expenses of $7,468,000 for 1995. The
decrease in exploration expenses for 1997, compared to 1996, resulted primarily
from the incurrence of costs associated with conducting several 3-D seismic
surveys by the Company on its leases in South Louisiana, East Texas and the
Permian Basin during 1996 for which no similar costs of their magnitude were
incurred during the comparative periods, although such costs were partially
offset in 1997 by the costs associated with conducting the
38
<PAGE> 39
Jarmjuree 3-D seismic survey in the Gulf of Thailand and by increased seismic
data acquisition in the Gulf of Mexico. The increase in exploration expenses
for 1997, compared to 1995, resulted primarily from increased geophysical
activity by the Company, including the costs of conducting and processing the
Jarmjuree 3-D seismic surveys. In addition, exploration expenses attributable
to increased delay rental expense resulting from the Company's acquisition of
additional prospective oil and gas acreage during 1997, as compared to 1996 and
1995, served to offset the decrease in exploration expenses for 1997, compared
to 1996, and to increase the exploration expenses incurred during 1997,
compared to 1995. The Company does not currently expect its exploration
expenses in 1998 to increase significantly over those incurred during 1997.
Dry Hole and Impairment Expenses
Dry hole and impairment expenses relate to costs of unsuccessful wells
drilled along with impairments due to decreases in expected reserves from
producing wells. The Company's dry hole and impairment expenses for 1997 were
$9,631,000, an increase of approximately 12% from dry hole and impairment costs
of $8,579,000 for 1996, and an increase of approximately 44% from dry hole and
impairment costs of $6,703,000 for 1995.
Depreciation, Depletion and Amortization Expenses
The Company's DD&A expense for 1997 was $103,157,000, an increase of
approximately 67% from DD&A expenses of $61,857,000 for 1996, and an increase
of approximately 51% from DD&A expenses of $68,489,000 for 1995. The increase
in the Company's DD&A expenses for 1997, compared to 1996 and 1995, resulted
primarily from an increase in the Company's natural gas and liquid hydrocarbon
production and, to a lesser extent, an increase in the Company's composite DD&A
rate.
The composite DD&A rate for all of the Company's producing fields for 1997
was $0.95 per equivalent Mcf ($5.68 per equivalent Bbl), an increase of
approximately 9% from a composite DD&A rate of $0.87 per equivalent Mcf ($5.20
per equivalent Bbl) for 1996, and an increase of approximately 3% from a
composite DD&A rate of $0.91 per equivalent Mcf ($5.47 per equivalent Bbl) for
1995. The increase in the composite DD&A rate for all of the Company's
producing fields for 1997, compared to 1996 and 1995, resulted primarily from
an increased percentage of the Company's production coming from certain of the
Company's fields that have DD&A rates that are higher than the Company's recent
historical composite rate and a corresponding decrease in the percentage of the
Company's production coming from fields that have DD&A rates that are lower
than the Company's recent historical composite DD&A rate. Management currently
anticipates that this trend will continue for the foreseeable future, resulting
in generally increasing DD&A rates. The Company produced 107,605,000 equivalent
Mcf (17,934,000 equivalent Bbls) in 1997, an increase of approximately 53% from
the 70,472,000 equivalent Mcf (11,745,000 equivalent Bbls) produced in 1996,
and an increase of approximately 45% from the 74,337,000 equivalent Mcf
(12,389,000 equivalent Bbls) produced in 1995.
Interest
INTEREST CHARGES. The Company incurred interest charges for 1997 of
$21,886,000, an increase of approximately 66% from interest charges of
$13,203,000 for 1996, and an increase of approximately 96% from interest
charges of $11,167,000 for 1995. The increase in the Company's interest charges
for 1997, compared to 1996 and 1995, resulted primarily from an increase in the
average amount of the Company's outstanding debt and, to a lesser extent,
increased average interest rates on the debt outstanding (resulting primarily
from the issuance of the 8 3/4% Senior Subordinated Notes due 2007 (the "2007
Notes") on May 22, 1997, which bear interest at an 8 3/4% annual interest rate)
and increased expenses related to amortization of debt issuance expenses
resulting from the issuance of the 2006 Notes in 1996.
CAPITALIZED INTEREST EXPENSE. Capitalized interest for 1997 was $6,175,000
an increase of approximately 46% from capitalized interest of $4,244,000 for
1996, and an increase of approximately 237% from capitalized interest of
$1,834,000 for 1995. The increase in capitalized interest for 1997, compared to
1996 and 1995, resulted primarily from the requirement to capitalize interest
expense attributable to capital expenditures on non-producing properties,
39
<PAGE> 40
principally capital expenditures related to the Company's development of the
Tantawan Field and the East Cameron Block 334 "E" platform during the first
quarter of 1997 and its development of the Benchamas Field commencing in 1997,
which substantially exceeded the Company's capital expenditures on
non-producing properties (principally the Tantawan Field) during 1996 and 1995.
To a lesser extent, the increase in capitalized interest expense is also
attributable to an increase in the rate used to compute the interest that was
capitalized. The Company expects its capitalized interest costs to increase in
the future, primarily as a result of the requirement to capitalize interest
expense attributable to capital expenditures incurred in connection with its
development of the Benchamas Field in the Gulf Thailand. See "Business and
Properties -- International Operations; Significant International Operating
Areas During 1997."
Foreign Currency Transaction Loss
The Company incurred a foreign currency transaction loss of $7,604,000
during 1997. No comparable losses were incurred in 1996 or 1995. The foreign
currency transaction loss resulted from the devaluation against the U.S. dollar
of cash and other monetary assets and liabilities denominated in Thai Baht that
were on the Company's subsidiary's financial statements during 1997. In early
July 1997, the government of the Kingdom of Thailand announced that the value
of the Thai Baht would be set against the U.S. dollar and other currencies
under a "managed float" program arrangement. Since that time the value of the
Thai Baht has generally declined, although in recent weeks it has shown some
sign of stabilizing. During the last two weeks of the month of February 1998,
the Thai Baht traded in a range of approximately 43 to 48 Thai Baht to the U.S.
dollar. The Company cannot predict what the Thai Baht to U.S. dollar exchange
rate may be in the future. Moreover, it is anticipated that this exchange rate
will remain volatile.
Income Tax Expense
Income tax expense for 1997 was $18,091,000, a decrease of approximately 4%
from income tax expense of $18,800,000 for 1996, and an increase of
approximately 270% from income tax expense of $4,891,000 for 1995. The decrease
in income tax expense for 1997, compared to 1996, resulted primarily from the
foreign currency transaction loss discussed in the preceding paragraph, which
was partially offset by increased taxable income. The increase in income tax
expense for 1997, compared to 1995, resulted primarily from increased taxable
income.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
The Company's Condensed Consolidated Statement of Cash Flows for the nine
months ended September 30, 1998, reflects net cash provided by operating
activities of $70,466,000. In addition to net cash provided by operating
activities, the Company received net proceeds of $998,000 from the exercise of
stock options, $350,000 from the sale of certain non-strategic properties, and
had net borrowings of $83,354,000 under its Credit Agreement and other senior
debt facilities.
During the first nine months of 1998, the Company invested $135,964,000 of
such cash flow in capital projects, retired a production payment obligation for
$15,246,000, spent $2,961,000 to purchase proved reserves, paid $3,327,000
($0.03 per share for each of the first three quarters of 1998) in cash
dividends to holders of the Company's common stock and paid a net amount of
$621,000 in miscellaneous other expenditures. As of September 30, 1998, the
Company's cash and cash investments were $17,422,000 and its long-term debt
stood at $381,854,000.
Future Capital Requirements
The Company's capital and exploration budget for 1998, which does not
include any amounts that may be expended for the purchase of proved reserves or
any interest which may be capitalized resulting from projects in progress, was
established by the Company's Board of Directors at $230,000,000. Substantially
all of the Company's 1998 capital and exploration budget was spent or incurred
during 1998. The Company currently anticipates that its
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available cash and cash investments, cash provided by operating activities,
funds available under its Credit Agreement and an uncommitted line of credit
and amounts that the Company currently believes that it can obtain from
external sources including the issuance of new debt (including the Notes) and
convertible preferred securities, or asset sales, will be sufficient to fund
the Company's ongoing operating, interest and general and administrative
expenses, the remainder of its 1998 capital and exploration budget, any
currently anticipated costs associated with the Company's projects during 1999,
and future dividend payments at current levels. Subject to favorable market
conditions and other factors, the Company also currently intends to issue
convertible preferred equity securities during 1999 to assist in funding its
future capital and exploration plans. The declaration of future dividends on
the Company's common stock will depend upon, among other things, the Company's
future earnings and financial condition, liquidity and capital requirements,
its ability to pay dividends under certain covenants contained in its debt
instruments, the general economic and regulatory climate and other factors
deemed relevant by the Company's Board of Directors.
Other Material Long-Term Commitments
As of February 9, 1996, Tantawan Services, LLC ("TS"), a company that is
currently a wholly owned subsidiary of the Company, entered into a Bareboat
Charter Agreement (the "Charter") with Tantawan Production B.V. for the charter
of the FPSO for use in the Tantawan Field. See "Business and Properties --
International Operations." The term of the Charter is for a period ending July
31, 2008, subject to extension. In addition, TS has a purchase option on the
FPSO throughout the term of the Charter. TS has also contracted with another
company, SBM Marine Services Thailand Ltd., to operate the FPSO on a
reimbursable basis throughout the initial term of the Charter. Performance of
both the Charter and the agreement to operate the FPSO are non-recourse to TS
and the Company. However, performance is secured by a negative pledge on any
hydrocarbons stored on the FPSO and is guaranteed by each of the working
interest holders in the Tantawan Field, including Thaipo. Thaipo's guarantee is
limited to its percentage interest in the Tantawan Field (currently 46.34%).
The Charter currently provides for an estimated charter hire commitment of
$24,000,000 per year ($11,122,000 net to Thaipo).
As of August 24, 1998, Thaipo and its joint venture partners (collectively,
the "Charterers") entered into a Bareboat Charter Agreement (the "BCA") with
Watertight Shipping B.V. for the charter of a Floating Storage and Offloading
system named the "Benchamas Explorer" (the "FSO"). See "Business and Properties
- -- International Operations." The term of the BCA is for a period of ten years
commencing on the date that the FSO is ready to begin operations in the
Benchamas Field. In addition, the Charterers have a purchase option on the FSO
throughout the term of the BCA. The Charterers have also contracted with
another company, Tanker Pacific (Thailand) Co. Ltd, to operate the FSO on a
fixed fee basis throughout the initial term of the BCA. Performance of both the
BCA and the agreement to operate the FSO are non-recourse to the Company.
However the obligations of each joint venturer are full recourse to each joint
venturer, but the obligations are several, meaning that each joint venturer's
obligations are limited to its percentage interest in the Thailand Concession.
Collectively, the BCA and the operating agreement currently provides for an
estimated expense of chartering and operating the FSO of $11,253,000 per year
($5,215,000 net to Thaipo).
Capital Structure
CREDIT AGREEMENT AND UNCOMMITTED CREDIT LINE. Effective August 1, 1997, the
Company entered into an amended and restated Credit Agreement, which has
subsequently been amended several times, most recently on December 21, 1998.
The Credit Agreement provides for a $250,000,000 revolving/term credit facility
which will be fully revolving until July 1, 2000, after which the balance will
be due in eight quarterly term loan installments, commencing October 31, 2000.
A portion of the amount that may be borrowed under the Credit Agreement (the
"Primary Tranche") may not exceed a borrowing base which is composed of
domestic, Canadian and Thai properties. Generally, the borrowing base is
determined semi-annually by the lenders in accordance with the Credit
Agreement, based on the lenders' usual and customary criteria for oil and gas
transactions. As of December 21, 1998, the Company's total borrowing base was
set at $200,000,000, which amount cannot be reduced until after April 30, 1999.
In addition, certain lenders that are parties to the Credit Agreement have
agreed to extend an additional $50,000,000 in credit (the "Secondary Tranche")
under the Credit Agreement without reference to the
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<PAGE> 42
borrowing base limitations of the Credit Agreement. The term of the Secondary
Tranche is until the earlier of April 30, 1999 or the completion of the
Offering. The Credit Agreement is governed by various financial and other
covenants, including requirements to maintain positive working capital
(excluding current maturities of debt) and a fixed charge coverage ratio, and
limitations on indebtedness, creation of liens, the prepayment of subordinated
debt, the payment of dividends, mergers and consolidations, investments and
asset dispositions. Upon the occurrence or declaration of certain events, the
lenders would be entitled to a security interest in the Company's domestic
borrowing base properties. In addition, the Company is prohibited from pledging
borrowing base properties as security for other debt. Borrowings under the
Primary Tranche bear interest at a rate based upon the percentage of the
borrowing base that is being utilized, ranging from a base (prime) rate or
LIBOR plus 1.25% to a base rate plus 0.25% or LIBOR plus 2.0%, at the Company's
option. Borrowings under the Primary Tranche currently bear interest at a base
rate plus 0.25% or LIBOR plus 2.0%, at the Company's option. Borrowings under
the Secondary Tranche currently bear interest at a base rate plus 0.75% or
LIBOR plus 2.5%, at the Company's option. A commitment fee on the unborrowed
amount under the Primary Tranche is also charged and is based upon the
percentage of the borrowing base that is being utilized, ranging from 0.25% to
0.375%. The commitment fee is currently 0.375% per annum on the unborrowed
amount under the Primary Tranche. As of December 31, 1998, there was
$155,000,000 outstanding under the Primary Tranche and $50,000,000 outstanding
under the Secondary Tranche.
As of December 31, 1998, the Company had also entered into a separate
letter agreement with a bank under which the bank may provide a $20,000,000
uncommitted money market line of credit. The line of credit is on an as
available or offered basis and the bank has no obligation to make any advances
under its line of credit. Although loans made under that letter agreement are
for a maximum term of 30 days, they are reflected as long-term debt on the
Company's balance sheet because the Company currently has the ability and
intent to reborrow such amounts under its Credit Agreement. The letter
agreement permits either party to terminate such letter agreement at any time.
Under its Credit Agreement, the Company is currently limited to incurring a
maximum of $20,000,000 of additional senior debt, which would include debt
incurred under that line of credit and under the banker's acceptances discussed
below. Further, the 2007 Notes and the Notes offered hereby also restrict the
incurrence of additional senior indebtedness. See "; 2007 Notes" and
"Description of the Notes -- Certain Covenants; Limitation on Indebtedness."
BANKER'S ACCEPTANCES. On June 3, 1998, the Company entered into a Master
Banker's Acceptance Agreement under which one of the Company's lenders has
offered to accept up to $20,000,000 in bank drafts from the Company. The
banker's drafts are available on an uncommitted basis and the bank has no
obligation to accept the Company's request for drafts. Drafts drawn under this
agreement are for a maximum term of 182 days; however, they are reflected as
long-term debt on the Company's balance sheet because the Company currently has
the ability and intent to reborrow such amounts under the Credit Agreement.
Under its Credit Agreement, the Company is currently limited to incurring a
maximum of $20,000,000 of additional senior debt, which would include banker's
acceptances as well as debt incurred under the line of credit discussed
previously. Further, the 2007 Notes and the Notes offered hereby also restrict
the incurrence of additional senior indebtedness. See "; 2007 Notes" and
"Description of the Notes -- Certain Covenants; Limitation on Indebtedness."
The Master Banker's Acceptance Agreement permits either party to terminate the
letter agreement at any time upon five business days notice. As of September
30, 1998, bank drafts in the principal amount of $10,854,000 bearing interest
at a rate of 6.1% were outstanding under this agreement.
2007 NOTES. On May 22, 1997, the Company issued $100,000,000 principal
amount of 2007 Notes. The proceeds from the issuance of the 2007 Notes were
used to repay amounts outstanding under the Credit Agreement, and to purchase
short-term cash investments. The 2007 Notes bear interest at a rate of 8 3/4%,
payable semi-annually in arrears on May 15 and November 15 of each year,
commencing November 15, 1997. The 2007 Notes are general unsecured senior
subordinated obligations of the Company, are subordinated in right of payment
to the Company's senior indebtedness, which currently includes the Company's
obligations under the Credit Agreement, its unsecured credit line and its
banker's acceptances, are equal in right of payment to the Notes offered
hereby, but are senior in right of payment to the Company's subordinated
indebtedness, which currently includes the 2006 Notes. The Company, at its
option, may redeem the 2007 Notes in whole or in part, at any time on or after
May 15, 2002, at a redemption price of 104.375% of their principal value and
decreasing percentages thereafter. No sinking fund payments are required on the
2007 Notes. The 2007 Notes are redeemable at the option of any holder, upon the
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<PAGE> 43
occurrence of a change of control (as defined in the indenture governing the
2007 Notes), at 101% of their principal amount. The indenture governing the
2007 Notes also imposes certain covenants on the Company that are substantially
identical to the covenants contained in the indenture governing the Notes,
including covenants limiting: incurrence of indebtedness including senior
indebtedness; restricted payments; the issuance and sales of restricted
subsidiary capital stock; transactions with affiliates; liens; disposition of
proceeds of assets sales; non-guarantor restricted subsidiaries; dividends and
other payment restrictions affecting restricted subsidiaries; and mergers,
consolidations and the sale of assets.
2004 NOTES. The Company's 2004 Notes were called for redemption on March
13, 1998, at a price equal to 103.30% of their principal amount. Prior thereto,
holders of all but $95,000 principal amount of the 2004 Notes chose to convert
their 2004 Notes into Common Stock at a conversion price of $22.188 per common
share, rather than receive cash for their 2004 Notes resulting in the issuance
of 3,879,726 shares of Common Stock.
2006 NOTES. The outstanding principal amount of 2006 Notes was $115,000,000
as of September 30, 1998. The 2006 Notes are convertible into Common Stock at
$42.185 per share, subject to adjustment upon the occurrence of certain events.
The 2006 Notes will be redeemable at the option of the Company, in whole or in
part, at any time on or after June 15, 1999, at a redemption price of 103.85%
of their principal amount and decreasing percentages thereafter. No sinking
fund payments are required on the 2006 Notes. The 2006 Notes are redeemable at
the option of any holder, upon the occurrence of a repurchase event (a change
of control and other circumstances as defined in the indenture governing the
2006 Notes), at 100% of the principal amount.
Other Matters
INFLATION. Publicly held companies are asked to comment on the effects of
inflation on their business. Currently annual inflation in terms of the
decrease in the general purchasing power of the U.S. dollar is running much
below the general annual inflation rates experienced in the past. While the
Company, like other companies, continues to be affected by fluctuations in the
purchasing power of the U.S. dollar due to inflation, such effect is not
currently considered significant.
SOUTHEAST ASIA ECONOMIC ISSUES. A substantial portion of the Company's oil
and gas operations are conducted in Southeast Asia, and a substantial portion
of its natural gas and liquid hydrocarbon production are sold there. In recent
months, Southeast Asia in general, and the Kingdom of Thailand in particular,
have experienced severe economic difficulties which have been characterized by
sharply reduced economic activity, illiquidity, highly volatile foreign
currency exchange rates and unstable stock markets. The government of the
Kingdom of Thailand and other governments in the region are currently acting to
address these issues. However, the economic difficulties currently being
experienced in Thailand, together with the volatility of the Thai Baht against
the U.S. dollar, will continue to have a material impact on the Company's
operations in the Kingdom of Thailand, together with the prices that the
company receives for its oil and natural gas production there. See "-- Results
of Operations; Oil and Gas Revenues" and "-- Results of Operations; Foreign
Currency Transaction Gain (Loss)" for both the nine month and yearly
comparative periods.
All of the Company's current natural gas production from the Thailand
Concession is committed under a long term Gas Sales Agreement to PTT at a price
denominated in Thai Baht which is determined in accordance with a formula that
is intended to ameliorate, at least in part, any decline in the purchasing
power of the Thai Baht against the U.S. dollar. See "Business and Properties --
International Operations; Contractual Terms Governing the Thailand Concession"
and "Business and Properties -- Miscellaneous; Sales." Although the Company
currently believes that PTT will honor its commitments under the Gas Sales
Agreement, a failure by PTT to honor such commitments could have a material
adverse effect on the Company.
The Company's crude oil and condensate production from the Thailand
Concession is sold on a tanker load by tanker load basis. Prices that the
Company receives for such production are based on world benchmark prices, which
are denominated in U.S. dollars, and are typically paid in U.S. dollars. See
"Business and Properties -- International Operations; Contractual Terms
Governing the Thailand Concession and Related Production" and "Business and
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Properties -- Miscellaneous; Sales." The Company believes that the current
economic difficulties in Southeast Asia have resulted in a decreased demand for
petroleum products in the region, which has contributed to the recent general
decline in crude oil and condensate prices throughout the world. This price
decline has had an adverse effect on all oil and gas companies that sell their
production on the world spot markets, including the Company, without regard to
where their respective production is located.
YEAR 2000 READINESS DISCLOSURE. Many computer software systems, as well as
certain hardware and equipment using date-sensitive data, were structured to
use a two-digit date field meaning that they may not be able to properly
recognize dates in the year 2000. The Company is addressing this issue through
a process that entails evaluation of the Company's critical software and, to
the extent possible, its hardware and equipment to identify and assess Year
2000 issues and to remediate, replace or establish alternative procedures
addressing non-Year 2000 compliant systems, hardware and equipment.
The Company has substantially completed an inventory of its systems and
equipment including computer systems and business applications. Based upon this
review, the Company currently believes that all of its critical software and
computer hardware systems are either Year 2000 compliant or will be within the
next six months. The Company continues to inventory its equipment and
facilities to determine if they contain embedded date-sensitive technology. If
problems are discovered, remediation, replacement or alternative procedures for
non-compliant equipment and facilities will be undertaken on a business
priority basis. This process will continue and, depending upon the equipment
and facilities, is scheduled for completion during the first three quarters of
1999. As of September 30, 1998, the Company had incurred approximately $50,000
in expenses related to its Year 2000 compliance efforts. These costs are
currently being expensed as they are incurred. However, in certain instances
the Company may determine that replacing existing equipment may be more
efficient, particularly where additional functionality is available. These
replacements may be capitalized and therefore would reduce the estimated 1998
and 1999 expenses associated with the Year 2000 issue. The Company currently
expects total out-of-pocket costs to become Year 2000 compliant to be less than
$1,000,000. The Company currently expects that such costs will not have a
material adverse effect on the Company's financial condition, operations or
liquidity.
The foregoing timetable and assessment of costs to become Year 2000
compliant reflect management's current best estimates. These estimates are
based on many assumptions, including assumptions about the cost, availability
and ability of resources to locate, remediate and modify affected systems,
equipment and facilities. Based upon its activities to date, the Company does
not currently believe that these factors will cause results to differ
significantly from those estimated. However, the Company cannot reasonably
estimate the potential impact on its financial condition and operations if key
third parties including, among others, suppliers, contractors, joint venture
partners, financial institutions, customers and governments do not become Year
2000 compliant on a timely basis. The Company is contacting many of these third
parties to determine whether they will be able to resolve in a timely fashion
their Year 2000 issues as they may affect the Company.
In the event that the Company is unable to complete the remediation or
replacement of its critical systems, facilities and equipment, establish
alternative procedures in a timely manner, or if those with whom the Company
conducts business are unsuccessful in implementing timely solutions, Year 2000
issues could have a material adverse effect on the Company's liquidity and
results of operations. At this time, the potential effect in the event the
Company and/or third parties are unable to timely resolve their Year 2000
problems is not determinable; however, the Company currently believes that it
will be able to resolve its own Year 2000 issues in a timely manner.
The disclosure set forth in this section is provided pursuant to Securities
Act Release No. 33-7558. As such it is protected as a forward-looking statement
under the Private Securities Litigation Reform Act of 1995. See "Forward-
Looking Statements." This disclosure is also subject to protection under the
Year 2000 Information and Readiness Disclosure Act of 1998, Public Law 105-271,
as a "Year 2000 Statement" and "Year 2000 Readiness Disclosure" as defined
therein.
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BUSINESS AND PROPERTIES
The Company was incorporated in 1970 and is engaged in oil and gas
exploration, development and production activities on its properties located
offshore in the Gulf of Mexico, onshore in selected areas in New Mexico, Texas
and Louisiana, and internationally, primarily in the Gulf of Thailand. As of
December 31, 1998, the Company had interests in 105 lease blocks offshore
Louisiana and Texas, approximately 378,000 gross acres onshore in the United
States, approximately 734,000 gross acres offshore in the Kingdom of Thailand,
150,000 gross acres in Canada and 113,000 gross acres in the British North Sea.
On August 17, 1998, a wholly owned subsidiary of the Company merged with and
into Arch in a tax free, stock for stock transaction through which Arch became
a wholly owned subsidiary of the Company. The Company issued approximately
2,540,000 of its common shares in connection with the merger, or approximately
6% of its common stock outstanding at the time of the merger. For a description
of the Arch and its subsidiaries' businesses, properties and operations, please
see "-- Arch and its Subsidiaries." Quantitative information in this "Business
and Properties" section which precedes "-- Arch and its Subsidiaries" does not
include any such information relating to Arch and its subsidiaries.
Quantitative and geological information in the "-- Arch and its Subsidiaries"
subsection includes only information relating to Arch and its subsidiaries.
Unless otherwise specifically identified, the information set forth in this
offering memorandum, including production rates and the number of wells,
platforms and blocks, is presented on a gross basis, rather than net to the
Company or Arch, as applicable. Unless otherwise stated, quantitative data set
forth in this "Business and Properties" section was current as of March 13,
1998. The Company has not attempted to update this information but it believes
that any changes in this quantitative information are not material to an
understanding of the Company and its subsidiaries.
In recent years, the Company has concentrated its efforts in selected areas
where it believes that its expertise, competitive acreage position, or ability
to quickly take advantage of new opportunities offer the possibility of
superior rates of return. As of December 31, 1997, six significant operating
areas, of which three are located in the Gulf of Mexico and one each in South
Texas, New Mexico and Thailand, accounted for approximately 82% of the
Company's estimated proved natural gas reserves, approximately 90% of the
Company's estimated proved oil, condensate and natural gas liquids reserves,
approximately 80% of the Company's natural gas production and 89% of the
Company's oil, condensate and natural gas liquids production for 1997.
Reserves, as estimated by Ryder Scott, and production data, as estimated by the
Company, for the six significant operating areas are shown in the following
table. No other producing area accounted for more than 3% of the Company's
estimated proved reserves as of December 31, 1997.
SIGNIFICANT OPERATING AREAS
<TABLE>
<CAPTION>
1997 AVERAGE NET
NET PROVED RESERVES(A) DAILY PRODUCTION
---------------------------------------- --------------------------------------- TOTAL NET
NATURAL GAS LIQUIDS(B) NATURAL GAS LIQUIDS(B) PROVED
----------------- ----------------- ----------------- ----------------
RESERVES(a)
MMCF % MBBLS % MCF % BBLS % %
------- ---- ------ ---- ------ ---- ----- ---- ----
DOMESTIC OFFSHORE
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Eugene Island........ 27,182 6.8 7,607 13.1 23,334 13.5 4,673 24.5 10.7
Main Pass............ 14,570 3.6 3,830 6.6 7,104 4.1 2,777 14.6 5.0
East Cameron......... 30,199 7.5 1,006 1.7 53,893 31.2 3,242 17.0 4.8
DOMESTIC ONSHORE
New Mexico........... 20,578 5.1 11,287 19.4 9,151 5.3 4,008 21.0 11.8
South Texas.......... 52,724 13.1 1 0.0 11,484 6.6 0 0.0 7.0
INTERNATIONAL
Kingdom of Thailand.. 184,768 46.0 28,783 49.5 37,733 19.0 2,421 14.0 47.6
</TABLE>
- -------------
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(a) Net proved reserves and total net proved reserves are each as of December
31, 1997.
(b) "Liquids," includes oil, condensate and NGL.
DOMESTIC OFFSHORE OPERATIONS
Historically, the Company's interests have been concentrated in the Gulf of
Mexico, where approximately 59% of the Company's domestic proved reserves and
31% of its total proved reserves were located as of December 31, 1997. During
1997, approximately 65% of the Company's natural gas production and
approximately 59% of its oil and condensate production was from its domestic
offshore properties, contributing approximately 62% of the Company's
consolidated oil and gas revenues. Three offshore producing areas, Eugene
Island, Main Pass and East Cameron, accounted for approximately 18% of the
Company's net proved natural gas reserves and approximately 21% of the
Company's proved crude oil, condensate and natural gas liquids reserves as of
December 31, 1997. See "-- Significant Domestic Offshore Operating Areas During
1997."
Lease Acquisitions
The Company has participated, either on its own or with other companies, in
bidding on and acquiring interests in federal and state leases offshore in the
Gulf of Mexico since December 1970. As a result of such sales and subsequent
activities, as of December 31, 1997, the Company owned interests in 93 federal
leases and 8 state leases offshore Louisiana and Texas. Federal leases
generally have primary terms of five, eight or ten years, depending on water
depth, and state leases generally have terms of three or five years, depending
on location, in each case subject to extension by development and production
operations.
As part of its strategy, the Company intends to continue an active lease
evaluation program in the Gulf of Mexico in order to identify exploration and
exploitation opportunities. During 1997, the Company was successful in
acquiring interests in 19 lease blocks through federal Outer Continental Shelf
oil and gas lease sales and 1 lease block by assignment from a third party. As
in the case of prior sales, the extent to which the Company participates in
future bidding on federal or state offshore lease sales will depend on the
availability of funds and its estimates of hydrocarbon deposits, operating
expenses and future revenues which reasonably may be expected from available
lease blocks. Such estimates typically take into account, among other things,
estimates of future hydrocarbon prices, federal regulations, and taxation
policies applicable to the petroleum industry. It is also the Company's
objective to acquire certain producing leasehold properties in areas where
additional low-risk drilling or improved production methods by the Company can
provide attractive rates of return.
Exploration and Development
The scope of exploration and development programs relating to the Company's
offshore interests is affected by prices for oil and gas, and by federal, state
and local legislation, regulations and ordinances applicable to the petroleum
industry. The Company's domestic offshore capital and exploration expenditures
for 1997 were approximately $86,300,000, or 9% lower than the Company's
domestic offshore capital and exploration expenditures of approximately
$94,400,000 (excluding approximately $2,000,000 of net property acquisitions)
for 1996 and 128% higher than the Company's domestic offshore capital and
exploration expenditures of approximately $37,800,000 for 1995 (excluding
approximately $650,000 of net property acquisitions) for 1995. The decrease in
the Company's domestic offshore capital and exploration expenditures for 1997,
compared with 1996, resulted primarily from a decrease in drilling activity and
in construction and installation of offshore platforms, pipelines and other
facilities, which was partially offset by the increased costs to the Company
(and the entire oil and gas industry generally) because of price increases by
the oil and gas services, construction and supply industries due to the
shortage of skilled workers and the comparative scarcity of certain equipment,
such as drilling rigs, and critical materials, such as certain types of steel
pipe. The increase in the Company's domestic offshore capital and exploration
expenditures for 1997, compared to 1995, resulted primarily from increased
drilling activity and increased costs associated with
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<PAGE> 47
the construction and installation of offshore platforms, pipelines and other
facilities and the increase in prices discussed above. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
Leases acquired by the Company and other participants in its bidding groups
are customarily committed, on a block-by-block basis, to separate operating
agreements under which the appointed operator supervises exploration and
development operations for the account and at the expense of the group. These
agreements usually contain terms and conditions which have become relatively
standardized in the industry. Major decisions regarding development and
operations typically require the consent of at least a majority (in working
interest) of the participants. Because the Company generally has a meaningful
working interest position, the Company believes it can significantly influence
(but not always control) decisions regarding development and operations on most
of the leases in which it has a working interest even though it may not be the
operator of a particular lease. The Company was the operator on all or a
portion of 30 of the 101 offshore leases in which it had an interest on
December 31, 1997.
Platforms and related facilities are installed on an offshore lease block
when, in the judgment of the lease interest owners, the necessary capital
expenditures are justified. A decision to install a platform generally is made
after the drilling of one or more exploratory wells with contracted drilling
equipment. Platforms are used to accommodate both development drilling and
additional exploratory drilling. Over the three years ended December 31, 1997,
the gross cost of production platforms and related facilities to the joint
ventures in which the Company has varying net interests has ranged from
approximately $3,000,000 to approximately $16,500,000. Platform costs vary and
more expensive platforms could be required in the future depending on, among
other factors, the number of slots, water depth, currents, and sea floor
conditions. For example, during 1997, the Company and its joint venture
partners approved construction of a platform located on Viosca Knoll Block 823
which will be located in approximately 1,200 feet of water. This platform,
together with its related pipelines and other facilities, is estimated to have
a gross cost of approximately $140,000,000 (approximately $15,100,000 net to
the Company's current working interest).
Significant Domestic Offshore Operating Areas During 1997
EUGENE ISLAND. A significant portion of the Company's reserves and a
substantial part of its production are located in the Eugene Island area off
the Louisiana coast in the Gulf of Mexico. The Eugene Island area has been an
important part of the Company's operations since the first lease in that area
was purchased in 1970 and production began in 1973. As of December 31, 1997,
the Company held interests in 10 blocks in the Eugene Island area. These blocks
comprise eight fields containing 64 oil and gas wells producing from multiple
reservoirs and horizons. During 1997, the Company participated in the drilling
of eight wells in the Eugene Island operating area.
The Eugene Island Block 330 field is one of the Company's most significant
producing assets. This field, located in 245 feet of water, contains three
drilling and production platforms in which the Company holds a 35% working
interest, as well as an additional platform in which the Company holds a 30%
working interest. As of December 31, 1997, there were 12 wells producing
primarily natural gas and 34 wells producing primarily oil on the block. The
Company and its joint venture partners drilled six new wells which added
significant new reserves in this field during 1997.
MAIN PASS. The Company's 12 lease blocks in the Main Pass area, including
two acquired in 1997, are located near the mouth of the Mississippi River in
the Gulf of Mexico and include leases in which the Company has held an interest
since 1974. The majority of the Company's production from the Main Pass area
comes from a field that includes Main Pass Blocks 72, 73 and 72/74 which was
unitized in 1982. The Company's working interest in this field is 35%. As of
December 31, 1997, this field contained 20 producing oil wells and nine
producing natural gas wells from three platforms operated by the Company's
joint venture partner and is located in 125 feet of water. The Company
participated in the drilling of 3 exploratory wells in the Main Pass area
during 1997.
EAST CAMERON. The first leasehold interest acquired by the Company in the
East Cameron area off the Texas/Louisiana border in the Gulf of Mexico
commenced production in February 1973. Presently, the Company has interests in
five offshore blocks in this area which contain two fields and 19 producing gas
wells. Two of the
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five blocks were awarded to the Company and its joint venture partners during
1997 and have yet to be fully evaluated.
During 1997, the Company and its partners were active in the East Cameron
Block 334/335 field. In February 1997, the Company and one of its joint venture
partners completed construction of the East Cameron "E" platform and commenced
production from two wells. Following mechanical problems in one of these wells
which caused it to be shut in, production was restored in the first week of
January 1998. The Company and its joint venture partners completed construction
of a sixth platform during 1997, known as the "F" platform. Production from the
well served by this platform, in which the Company holds a 42% interest,
commenced in December 1997.
DOMESTIC ONSHORE OPERATIONS
The Company has onshore division staffs in Houston and Midland, Texas. Its
onshore activities are concentrated in known oil and gas provinces, principally
the Permian Basin area of southeastern New Mexico, West Texas and Northwest
Texas, and in the onshore Gulf Coast areas of South Texas, East Texas and South
Louisiana. See "-- Significant Domestic Onshore Operating Areas During 1997."
Lease Acquisitions
Commencing in 1995 and continuing into 1997, the Company increased its
activities in the onshore Gulf Coast areas of East Texas and South Louisiana
through its participation in several large proprietary 3-D seismic surveys, in
connection with which the Company typically purchases an option to acquire an
interest in the acreage covered by the 3-D seismic survey. As it has in recent
years, in 1997 the Company also successfully participated in various onshore
federal and state lease sales and acquired interests in prospective acreage
from private individuals. As of December 31, 1997, the Company held interests
in approximately 237,000 gross (113,000 net) acres onshore in the United
States, an increase of approximately 12% from year end 1996.
Exploration and Development
The Company's primary drilling objective in the Permian Basin is the Brushy
Canyon (Delaware) formation which generally produces oil from depths of 6,000
to 9,000 feet. Since the Company began exploring in the Brushy Canyon
(Delaware) formation in October 1989, it has participated in drilling 357 wells
in the Permian Basin, West and Northwest Texas areas through December 31, 1997,
including 58 wells in 1997.
The Company's primary drilling activity in East Texas has been in the
Cotton Valley formation reef play. In South Louisiana, the Company participated
in drilling 11 wells in 1997 to test various Hackberry formation and Yegua
formation prospects, all of which were identified on proprietary 3-D seismic
surveys that the Company and its industry partners have acquired since 1995.
The Company also actively explores for oil and gas onshore in South Texas. In
total, the Company participated in the drilling of 25 wells in the onshore Gulf
Coast areas of South Texas, East Texas and South Louisiana, including 14
exploratory wells (principally in East Texas and South Louisiana) and 11
developmental wells (principally in the Lopeno Field in South Texas). See "--
Significant Domestic Onshore Operating Areas During 1997; South Texas."
Domestic onshore reserves as of December 31, 1997, accounted for approximately
41% of the Company's domestic proved reserves and approximately 21% of its
total proved reserves. During 1997, approximately 16% of the Company's natural
gas production and 27% of its oil and condensate production was from its
domestic onshore properties, contributing approximately 20% of the Company's
consolidated oil and gas revenues.
The Company generally conducts its onshore activities through joint
ventures and other interest-sharing arrangements with major and independent oil
companies. The Company operates many of its own onshore properties using
independent contractors.
The Company's domestic onshore capital and exploration expenditures were
approximately $60,000,000 (excluding approximately $1,700,000 of net property
acquisitions) for 1997, or 28% higher than the Company's
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<PAGE> 49
domestic onshore capital and exploration expenditures of approximately
$47,000,000 (excluding approximately $3,800,000 of net property acquisitions)
for 1996 and 82% higher than the Company's domestic onshore capital and
exploration expenditures of approximately $33,000,000 (excluding approximately
$7,800,000 of net property acquisitions) for 1995. The increase in the
Company's domestic onshore capital and exploration expenditures for 1997,
compared to 1996 and 1995, resulted primarily from increased drilling activity
in South Texas, East Texas and South Louisiana and, to a lesser extent, by the
increased costs to the Company (and the entire oil and gas industry generally)
because of price increases by the oil and gas services, construction and supply
industries due to the shortage of skilled workers and the comparative scarcity
of certain equipment, such as drilling rigs and critical materials, such as
certain types of steel pipe.
Significant Domestic Onshore Operating Areas During 1997
NEW MEXICO. The Company believes that during the past five years it has
been one of the most active companies drilling for oil and natural gas in the
southeastern New Mexico (Lea and Eddy Counties) portion of the Permian Basin
where the Company has interests in over 79,000 gross acres. The Company's
primary drilling objective is the Brushy Canyon (Delaware) formation. Fields in
the Brushy Canyon (Delaware) formation in the southeastern New Mexico portion
of the Permian Basin are generally characterized by production from relatively
shallow depths (6,000 to 9,000 feet), multiple producing zones in most wells
and relatively high initial rates of production (frequently equaling the top
field allowables which typically range from 142 Bbls to 230 Bbls per day,
depending on the depth of production from the field). The Company has achieved
rapid cost recovery with respect to its New Mexico wells drilled to date
because of relatively low capital costs and high initial rates of production.
Since the Company began exploring in the Brushy Canyon (Delaware) formation
in the southeastern New Mexico portion of the Permian Basin in October 1989, it
has participated through December 31, 1997, in the drilling of, among others,
94 wells in the Sand Dunes field where the Company's working interest ranges
from 4% to 100%, 27 wells in the East Loving field where the Company's working
interest ranges from 33% to 98%, 60 wells in the Livingston Ridge field where
the Company's working interest ranges from 25% to 100%, 61 wells in the Red
Tank field where the Company's working interest ranges from 89% to 100%, 31
wells in the Cedar Canyon field where the Company's working interest ranges
from 38% to 100% (including 15 during 1997), 15 wells in the Lost Tank field
where the Company's working interest ranges from 50% to 100% (including 12
during 1997), and 3 wells in the Poker Lake Field where the Company's working
interest ranges from 60% to 100%.
SOUTH TEXAS. The Company has increased its activity in South Texas in
recent years, where, as of December 31, 1997, it was active in two fields, both
of which primarily produce natural gas. The most significant of these two
fields is the Lopeno Field, which is located within 40 miles of the border with
Mexico. The Company acquired its initial interest in the Lopeno Field in 1983.
As of December 31, 1997, the Company had interests in over 7,800 gross acres in
South Texas containing 29 producing wells, with working interests generally
averaging approximately 50%. The Lopeno Field produces from over 20 upper
Wilcox sandstone reservoirs ranging in depth up to 12,500 feet. Based in part
on a 3-D seismic survey acquired over the field in 1994, the Company and its
joint venture partners commenced an active development drilling program in the
fourth quarter of 1995. In 1997, the Company drilled seven successful wells in
the Lopeno Field and drilled additional wells in this field during 1998.
INTERNATIONAL OPERATIONS
The Company has conducted international exploration activities since the
late 1970's in numerous oil and gas areas throughout the world. Currently, the
Company maintains an office in Bangkok, Thailand from which it directs field
operations in the Gulf of Thailand on its Thailand Concession through its
wholly owned subsidiary Thaipo. As a result of its acquisition in 1995 and
March 1997 of portions of the original interest of Maersk Oil (Thailand) Ltd.,
a former joint venture partner that owned a 31.67% interest in the Thailand
Concession, the Company has increased its ownership interest in the Thailand
Concession so that it currently owns, directly or indirectly, a 46.34% working
interest in the entire Thailand Concession. The remainder of the working
interest is owned, directly or indirectly by Thai Romo Ltd. (46.34%), a
subsidiary of RMOC, and Palang Sophon Limited ("Palang") (7.32%). Thaipo is
currently the operator of the Thailand Concession, pursuant to the joint
operating agreement and as designated by the
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<PAGE> 50
government of Thailand. On December 23, 1998, RMOC, the parent company of Thai
Romo, Ltd., announced that it had agreed to be acquired by Chevron. Their
agreement is subject to conditions, several of which are outside of RMOC's
control. One of these conditions is that Chevron reach agreement with the
Company on a new joint operating agreement that would include the transfer of
operatorship on the Thailand Concession from Thaipo to a subsidiary of Chevron.
The merger is also conditioned upon Chevron reaching agreement with Palang, the
third partner in the Thailand Concession, to acquire at least a 5 percent
interest in the Concession from Palang and upon all parties waiving any
preferential rights that may arise in connection with the acquisition. The
Company cannot predict whether Chevron will reach agreement with the Company
and Palang or whether the other conditions to Chevron's acquisition of RMOC
will be satisfied or waived. RMOC has also stated that its financial resources
will be exhausted in February 1999, and that its banks have currently refused
to lend it any additional funds. Chevron has agreed to lend additional funds to
RMOC if most of the conditions to the acquisition have been satisfied,
including Chevron's reaching agreement with us on a new joint operating
agreement. Thai Romo's failure to pay its share of the expenses of our projects
in the Gulf of Thailand could have a material adverse effect on the Company,
due to the increased capital requirements that funding Thai Romo's share of the
project development costs could have on the Company. As of December 31, 1997,
the Company's proved reserves located in the Kingdom of Thailand accounted for
approximately 48% of the Company's total proved reserves. During 1997,
approximately 19% of the Company's natural gas production and 14% of its oil
and condensate production came from its operations on the Thailand Concession,
contributing approximately 14% of the Company's consolidated oil and gas
revenues.
Exploration and Development
The Company's international capital and exploration expenditures were
approximately $88,300,000 (excluding approximately $28,600,000 of net property
acquisitions) for 1997, or 37% higher than the Company's international capital
and exploration expenditures of approximately $64,400,000 for 1996 and 152%
higher than the Company's international capital and exploration expenditures of
approximately $35,000,000 (excluding approximately $4,200,000 of net property
acquisitions) for 1995. The increase in the Company's international capital and
exploration expenditures for 1997, compared to 1996 and 1995, resulted
primarily from increased platform and facilities construction costs related to
initial development of the Benchamas Field, increased drilling activity and, to
a lesser extent, by the increased costs to the Company (and the entire oil and
gas industry generally) because of price increases by the oil and gas services,
construction and supply industries due to the shortage of skilled workers and
the comparative scarcity of certain equipment, such as drilling rigs, and
certain critical materials, such as certain types of steel pipe. Substantially
all of the Company's international capital and exploration expenditures for
1997 were related to the Company's license in the Kingdom of Thailand. In
addition, the Company continues to evaluate other international opportunities
that are consistent with the Company's international exploration strategy.
Platforms are installed on the Thailand Concession in fields where, in the
judgment of Thaipo and its joint venture partners, the necessary capital
expenditures are justified. A decision to install a platform generally is made
after the drilling of one or more exploratory wells with contracted drilling
equipment and the area where the platform would be located has been designated
a production area by the Thai government. See "-- Contractual Terms Governing
the Thailand Concession and Related Production." Platforms are used to
accommodate both development drilling and additional exploratory drilling. Over
the three years ended December 31, 1997, the gross cost of the first four
production platforms and related facilities in the Tantawan Field has averaged
approximately $20,000,000. Platform costs vary and more (or less) expensive
platforms could be required in the future depending on, among other factors,
the number of slots, water depth, currents, and sea floor conditions. See "--
Significant International Operating Areas During 1997; Tantawan Field."
Significant International Operating Areas During 1997
TANTAWAN FIELD. In August 1995, at the request of Thaipo and its joint
venture partners, the government of Thailand designated a portion of the
Thailand Concession comprising approximately 68,000 acres as the Tantawan
production area. The Tantawan production area has been named the Tantawan
Field. Through March 13, 1998, 19 exploration and 29 development wells have
been drilled in the Tantawan Field. Initial production from the Tantawan Field
commenced on February 1, 1997, from wells located on two platforms. Currently,
there are wells producing
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from four platforms. The Company is currently planning to install a fifth
platform in the Tantawan Field from which production is currently expected to
commence in the second half of 1999.
Oil and gas production from the Tantawan Field is gathered through
pipelines from the platforms into the FPSO named the "Tantawan Explorer." The
FPSO is a converted oil tanker with a capacity of slightly less than 1,000,000
Bbls, that is moored in the Tantawan Field, on which hydrocarbon processing,
separation, dehydration, compression, metering and other production related
equipment is installed. Following processing on board the FPSO, natural gas
produced from the field is delivered to PTT through an export pipeline. Oil and
condensate produced from the field is stored on board the FPSO and transferred
to shore by oil tanker. The FPSO and its processing equipment is leased from a
third party under a bareboat charter by Tantawan Services, LLC, an affiliate of
Thaipo. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity and Capital Resources." Thaipo and its joint
venture partners pay a processing fee to Tantawan Services, LLC to process the
production from the Tantawan Field through the FPSO.
BENCHAMAS FIELD AND THE MALIWAN PRODUCTION AREA. In July 1997, the
government of Thailand designated another portion of the Thailand Concession
comprising approximately 102,000 acres of the Benchamas and Pakakrong
production area as the Benchamas Field. This area includes at least two
discrete geologic structures which were previously designated as the Benchamas
and Pakakrong areas, respectively. In September 1997, the government of
Thailand designated an additional 91,000 acres of the Thailand Concession as
the Maliwan production area. Through March 13, 1998, 14 exploration wells have
been drilled in the Benchamas Field and four exploration wells have been
drilled in the Maliwan production area. Current development plans call for the
staged development of these fields, with the Benchamas Field to be brought on
production first. The Benchamas Field development plan contemplates the initial
installation of three production platforms, with natural gas and oil from these
platforms delivered by undersea pipeline to a central processing and
compression platform where the oil, condensate and natural gas will be
processed and separated. The natural gas will then be sold to PTT and delivered
into export pipelines for transportation to shore, while the oil and condensate
produced from the field will be stored on board the FSO for sale and ultimate
transfer to shore by oil tanker. The FSO will be moored in the Benchamas Field.
Its capacity will be approximately 1,400,000 Bbls of oil, or slightly more than
the FPSO. The field's current development plan calls for initial production to
commence in the third quarter of 1999.
OTHER AREAS. In addition to the above mentioned fields, Thaipo and its
joint venture partners have identified other potentially promising areas on the
Thailand Concession. Since acquiring their interest in the Thailand Concession,
Thaipo and its joint venture partners have acquired 3-D seismic surveys
covering approximately 673,650 acres of the Thailand Concession, including
221,650 acres during the fourth quarter of 1997 over what is known as the
Jarmjuree area. Interpretation of the Jarmjuree 3-D seismic survey commenced in
the first quarter of 1998 and is ongoing.
Contractual Terms Governing the Thailand Concession and Related Production
The Thailand Concession was granted in August 1991. The original
exploratory term of the concession agreement governing those portions of the
Thailand Concession not designated as a production area expired on July 31,
1997. However, on application from Thaipo and its joint venture partners, the
government of Thailand agreed in a supplemental concession agreement to extend
the exploratory term for those portions of the Thailand Concession that have
not yet been designated a production area (comprising approximately 474,000
acres) until July 31, 2000. In exchange, the Company and its joint venture
partners committed to, among other things, an additional work program which
includes the drilling of two wells and the acquisition of 148,000 acres of 3-D
seismic data during the remainder of the exploratory term. (This work
commitment was satisfied during the ordinary course of the Company's operations
on the Thailand Concession during 1998.) For those portions of the Thailand
Concession that have been designated as production areas the initial production
period term is 20 years, which is also subject to extension, generally for a
term of ten years. See also "-- Miscellaneous; Sales." Currently, the Tantawan,
Maliwan, and Benchamas and Pakakrong areas have been designated as production
areas. Subject to governmental approval, other portions of the Thailand
Concession may be designated production areas in the future.
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Production resulting from the Thailand Concession is subject to a royalty
ranging from 5% to 15% of oil and gas sales, plus certain fixed U.S. dollar
amounts payable at specified cumulative production levels. Revenue from
production in Thailand is also subject to income taxes and other similar
governmental charges including a Special Remuneratory Benefit tax ("SRB").
On November 7, 1995, Thaipo and its joint venture partners announced the
signing of a thirty-year Gas Sales Agreement with PTT, initially governing gas
production from the Tantawan Field. On November 12, 1997, Thaipo and its joint
venture partners entered into an amendment to the gas sales agreement to
include the reserves and anticipated gas production from the Benchamas Field.
The terms of the Gas Sales Agreement currently include a minimum daily contract
quantity ("DCQ") of 85 MMcf per day, which the Company currently anticipates
will continue until the Benchamas Field commences production, at which time the
DCQ will, subject to certain exceptions, be based on a percentage of the
remaining proved reserves, but in any event, will not be less than 125 MMcf per
day. The DCQ is the minimum daily volume that PTT has agreed to take, or pay
for if not taken under the agreement. Likewise, Thaipo and its joint venture
partners are subject to certain penalties if they are unable to meet the DCQ,
principal among which is a decrease in sales price of up to 25% of the then
current sales price. As a result of declining production from existing wells in
the Tantawan Field, the need to shut-in existing wells while drilling
additional wells from the same platform, and the decision to emphasize oil and
condensate production from the Tantawan Field, commencing on October 1, 1998,
the Company and its joint venture partners are currently delivering less
natural gas than is being nominated by PTT under the Gas Sales Agreement. This
could result in the Company receiving only 75% of the current contract price on
a portion of its future natural gas sales to PTT. The Company is taking actions
that it currently believes will minimize the penalty that it will incur on
future gas sales to PTT by, among other things, increasing production from the
Tantawan Field. The contract sales price is subject to automatic semi-annual
adjustments based upon a formula which takes into account, among other things,
changes in: Singapore fuel oil prices; the U.S. Bureau of Labor Statistics
Oilfield Machinery and Tool Index; the Thai wholesale producer price index; and
the U.S./Thai currency exchange rate. However, the Gas Sales Agreement provides
for adjustment on a more frequent basis in the event that certain indices and
factors on which the price is based fluctuate outside a given range. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Results of Operations; Foreign Currency Transaction Gain (Loss)"
and "-- Liquidity and Capital Resources; Other Matters; Southeast Asia Economic
Issues."
MISCELLANEOUS
Other Assets
The Company and a subsidiary, Pogo Offshore Pipeline Co., own interests in
eight pipelines (excluding field gathering pipelines) through which offshore
hydrocarbon production is transported. In addition, the Company owns
approximately 19% interest in a cryogenic gas processing plant near Erath,
Louisiana, which entitles it to process up to 186 MMcf of natural gas and 5,478
Bbls of natural gas liquids per day. The plant is not currently operating at
full capacity. See also "-- Arch and its Subsidiaries."
In 1989, the Company entered into a limited partnership agreement as
general partner of Pogo Gulf Coast, Ltd., a Texas limited partnership ("Pogo
Gulf Coast"). As of December 31, 1997, Pogo Gulf Coast had interests in 5
federal offshore leases. The Company owned 40% of any interest in properties
acquired by the limited partnership. Unless otherwise noted, the statistical
data reported in this offering memorandum reflect only the Company's share of
Pogo Gulf Coast's holdings as of March 13, 1998. Effective September 1, 1998,
the Company acquired all of the limited partnership interest of Pogo Gulf
Coast.
Sales
The marketing of offshore oil and gas production is subject to the
availability of pipelines and other transportation, processing and refining
facilities, as well as the existence of adequate markets. As a result, even if
hydrocarbons are discovered in commercial quantities, a substantial period of
time may elapse before commercial production commences. If pipeline facilities
in an area are insufficient, the Company may have to await the construction or
expansion of pipeline capacity before production from that area can be
marketed. The Company's
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domestic offshore properties are generally located in areas where a pipeline
infrastructure is well developed and there is adequate availability in such
pipelines to handle the Company's current and projected future production.
The Company's Thailand Concession is traversed by two major (34 inches and
36 inches in diameter, respectively) natural gas pipelines that are owned and
operated by PTT and which come within approximately 25 miles of the Tantawan
Field (and are slightly closer to the Benchamas Field). Thaipo and its joint
venture partners in the Tantawan Field signed a long term gas sales contract
with PTT in November 1995 which has since been amended to include production
from the Benchamas Field. All oil and condensate production from the Tantawan
field is initially stored aboard the FPSO and is then sold to various third
parties, including PTT, on a tanker load by tanker load basis at prices based
on then current world oil prices, typically with reference to the Malaysian
Tapis crude oil benchmark price. The buyer is responsible for sending a tanker
to off load the oil and condensate it has purchased. It is currently
anticipated that crude oil and condensate production from the Benchamas Field,
when it commences production, will be initially stored aboard the FSO and sold
in the same manner. See "-- International Operations; Contractual Terms
Governing the Thailand Concession and Related Production."
The marketing of domestic onshore oil and gas production is also subject to
the availability of pipelines, crude oil hauling and other transportation,
processing and refining facilities as well as the existence of adequate
markets. Generally, the Company's onshore domestic oil and gas production is
located in areas where commercial production of economic discoveries can be
rapidly effectuated.
Most of the Company's domestic natural gas sales are currently made in the
"spot market" for no more than one month at a time at then currently available
prices. Prices on the spot market fluctuate with demand. Crude oil and
condensate production is also generally sold one month at a time at the price
that is then currently available. Other than any futures contracts which may
exist from time to time, and which are referred to in "-- Miscellaneous;
Competition and Market Conditions," and the Gas Sales Agreement with PTT for
production from the Tantawan and Benchamas Fields (see "-- International
Operations; Contractual Terms Governing the Thailand Concession and Related
Production"), the Company has no existing contracts that require the delivery
of fixed quantities of oil or natural gas other than on a best efforts basis.
Enron Corp. and its affiliates and PTT, who purchased $57,965,000 (20% of the
Company's consolidated gross revenues) and $30,108,000 (11% of the Company's
consolidated gross revenues) of the Company's oil and gas production during
1997, respectively, were the Company's only customers to which sales exceeded
10% of its 1997 revenues. The oil and gas sold to Enron Corp. and its
affiliates was sold under a number of short term, generally month to month,
contracts.
Competition and Market Conditions
The Company experiences competition from other oil and gas companies in all
phases of its operations, as well as competition from other energy related
industries. The Company's profitability and cash flow are highly dependent upon
the prices of oil and natural gas, which historically have been seasonal,
cyclical and volatile. In general, prices of oil and gas are dependent upon
numerous factors beyond the control of the Company, including various weather,
economic, political and regulatory conditions. In the past, when natural gas
prices in the United States were low, the Company at times elected to curtail
certain quantities of its production. In the future, the Company may again
elect to curtail certain quantities of its natural gas production. Current oil
prices which, on an inflation adjusted basis are at historic lows, continue to
have a material adverse effect on the Company's cash flows and, if sustained
for a significant length, could have a material adverse effect on the Company's
operations and financial condition and may result in a further reduction in
funds available under the Company's Credit Agreement.
Because it is impossible to predict future oil and gas price movements with
any certainty, the Company from time to time enters into contracts on a portion
of its production to hedge against the volatility in oil and gas prices. Such
hedging transactions, historically, have never exceeded 50% of the Company's
total oil and gas production on an energy equivalent basis for any given
period. While intended to limit the negative effect of price declines, such
transactions could effectively limit the Company's participation in price
increases for the covered period, which increases could be significant. As of
December 31, 1998, the Company was not a party to any natural gas futures
contracts, crude oil swap agreements or other commodity hedging arrangements.
When the Company does engage in
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such hedging activities, it may satisfy its obligations with its own production
or by the purchase (or sale) of third party production. The Company may also
cancel all delivery obligations by offsetting such obligations with equivalent
agreements, thereby effecting a purely cash transaction.
Operating and Uninsured Risks
The Company's operations are subject to risks inherent in the exploration
for and production of oil and natural gas, such as blowouts, cratering,
explosions, uncontrollable flows of oil, natural gas or well fluids, fires,
pollution and other environmental risks. Offshore oil and gas operations are
subject to the additional hazards of marine and helicopter operations, such as
capsizing, collision and adverse weather and sea conditions. These hazards
could result in substantial losses to the Company due to injury or loss of
life, severe damage to and destruction of property and equipment, pollution and
other environmental damage and suspension of operations. The Company carries
insurance which it believes is in accordance with customary industry practices,
but is not fully insured against all risks incident to its business.
Drilling activities are subject to numerous risks, including the risk that
no commercially productive hydrocarbon reserves will be encountered. The cost
of drilling, completing and operating wells and of installing production
facilities and pipelines is often uncertain. The Company's drilling operations
may be curtailed, delayed or canceled as a result of numerous factors,
including title problems, weather conditions, compliance with governmental
requirements and shortages or delays in the delivery or availability of
material, equipment and fabrication yards. The availability of a ready market
for the Company's natural gas production depends on a number of factors,
including the demand for and supply of natural gas, the proximity of natural
gas reserves to pipelines, the capacity of such pipelines and government
regulations.
Risks of Foreign Operations
Ownership of property interests and production operations in Thailand, and
in any other areas outside the United States in which the Company may choose to
do business, are subject to the various risks inherent in foreign operations.
These risks may include, among other things, currency restrictions and exchange
rate fluctuations, loss of revenue, property and equipment as a result of
hazards such as expropriation, nationalization, war, insurrection and other
political risks, risks of increases in taxes and governmental royalties,
renegotiation of contracts with governmental entities, changes in laws and
policies governing operations of foreign-based companies and other
uncertainties arising out of foreign government sovereignty over the Company's
international operations. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Results of Operations; Foreign
Currency Transaction Gain (Loss)," and "-- Liquidity and Capital Resources;
Other Matters; Southeast Asia Economic Issues." The Company's international
operations may also be adversely affected by laws and policies of the United
States affecting foreign trade, taxation and investment. In addition, in the
event of a dispute arising from 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 courts of the United
States. The Company seeks to manage these risks by concentrating its
international exploration efforts in areas where the Company believes that the
existing government is stable and favorably disposed towards United States
exploration and production companies.
EXPLORATION AND PRODUCTION DATA
In the following data "gross" refers to the total acres or wells in which
the Company has an interest and "net" refers to gross acres or wells multiplied
by the percentage working interest owned by the Company.
Acreage
The following table shows the Company's interest in developed and
undeveloped oil and gas acreage as of December 31, 1997:
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<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
ACREAGE(a) ACREAGE(b)
------------------- ---------------------
Gross Net Gross Net
----- --- ----- ---
<S> <C> <C> <C> <C>
DOMESTIC ONSHORE
Louisiana.............................. 2,475 598 36,074 10,895
New Mexico............................. 21,021 12,591 58,410 42,932
Texas.................................. 12,084 4,346 103,100 40,769
Other.................................. 3,200 333 238 55
------ ------ ------ ------
Total Domestic Onshore......... 38,780 17,868 197,822 94,651
------ ------ ------- ------
DOMESTIC OFFSHORE
Louisiana (State)...................... 7,942 3,255 1,508 753
Louisiana (Federal)(c)................. 186,422 61,378 152,879 56,061
Texas (Federal)........................ 40,320 10,251 56,905 16,530
------ ------ ------ ------
Total Domestic Offshore........ 234,684 74,854 211,292 73,344
------- ------ ------- ------
Total Domestic................. 273,464 92,722 409,114 167,995
------- ------ ------- -------
INTERNATIONAL
Kingdom of Thailand.................... 260,407 120,682 473,733 219,530
------- ------- ------- -------
Total Company.................. 533,871 213,404 882,847 387,525
======= ======= ======= =======
</TABLE>
- -----------------
(a) "Developed acreage" consists of lease acres spaced or assignable to
production (including acreage held by production) on which wells have
been drilled or completed to a point that would permit production of
commercial quantities of oil or natural gas. "Developed acreage" in
Thailand includes all acreage designated as production area by the Thai
government, which currently includes the Tantawan, Maliwan, Benchamas and
Pakakrong production areas.
(b) "Undeveloped acreage" includes acreage under lease or subject to lease or
purchase options that the Company currently expects to exercise. Less
than 1% of the Company's total domestic offshore net undeveloped acreage
is under leases that have terms expiring in 1998 (unless otherwise
extended) and another approximately 1% of total domestic offshore net
undeveloped acreage will expire in 1999 (unless otherwise extended).
Approximately 7% of the Company's total domestic onshore net undeveloped
acreage is under leases that have terms expiring in 1998 (unless
otherwise extended) and another approximately 15% of total domestic
onshore net undeveloped acreage will expire in 1999 (unless otherwise
extended). The Company's total international net undeveloped acreage must
be relinquished to the Thai government on July 31, 2000, unless
designated as a production area or unless the exploration term is
extended. See "--International Operations; Contractual Terms Governing
the Thailand Concession and Related Production."
(c) The Company also owns overriding royalty interests in one federal lease
offshore Louisiana totaling 5,000 gross acres (1,250 net acres).
Productive Wells and Drilling Activity
The following table shows the Company's interest in productive oil and
natural gas wells as of December 31, 1997. For purposes of this table
"productive wells" are defined as wells producing hydrocarbons and wells
"capable of production" (e.g., natural gas wells waiting for pipeline
connections or necessary governmental certification to commence deliveries and
oil wells waiting to be connected to currently installed production
facilities). This table does not include exploratory or developmental wells
which have located commercial quantities of oil or natural gas but which are
not capable of commercial production without the installation of material
production facilities or which, for a variety of reasons, the Company does not
currently believe will be placed on production.
55
<PAGE> 56
<TABLE>
<CAPTION>
NATURAL GAS
OIL WELLS(a) WELLS(a)
------------------ ----------------
GROSS NET GROSS NET
----- --- ----- ---
<S> <C> <C> <C> <C>
Offshore United States......................... 129 33.3 113 33.8
Onshore United States.......................... 339 214.4 91 33.1
Kingdom of Thailand............................ -- -- 34 15.8
--- ----- --- ----
Total................................ 468 247.7 238 82.7
=== ===== === ====
</TABLE>
- -------------------
(a) One or more completions in the same bore hole are counted as one well.
The data in the above table includes five gross (.6 net) oil wells and 45
gross (20.4 net) natural gas wells with multiple completions.
The following table shows the number of successful gross and net
exploratory and development wells in which the Company has participated and the
number of gross and net wells abandoned as dry holes during the periods
indicated. An onshore well is considered successful upon the installation of
permanent equipment for the production of hydrocarbons or when electric logs
run to evaluate such wells indicate the presence of commercial hydrocarbons and
the Company currently intends to complete such wells. Successful offshore wells
consist of exploratory or development wells that have been completed or are
"suspended" pending completion (which has been determined to be feasible and
economic) and exploratory test wells that were not intended to be completed and
that encountered commercially producible hydrocarbons. A well is considered a
dry hole upon reporting of permanent abandonment to the appropriate agency.
<TABLE>
<CAPTION>
1997 1996 1995
------------------ ---------------- -----------------
SUCCESSFUL DRY SUCCESSFUL DRY SUCCESSFUL DRY
---------- --- ---------- --- ---------- ---
<S> <C> <C> <C> <C> <C> <C>
Gross Wells:
Offshore United States
Exploratory....................... 4.0 1.0 4.0 2.0 7.0 4.0
Development....................... 12.0 3.0 17.0 3.0 3.0 1.0
Onshore United States
Exploratory....................... 18.0 12.0 12.0 4.0 8.0 1.0
Development....................... 50.0 3.0 39.0 1.0 47.0 1.0
Offshore Kingdom of Thailand
Exploratory....................... 18.0 1.0 7.0 -- 3.0 --
Development....................... 12.0 -- 16.0 -- 7.0 --
----- ----- ---- ---- ---- ----
Total........................ 114.0 20.0 95.0 10.0 75.0 7.0
===== ===== ==== ==== ==== ====
NET WELLS:
Offshore United States
Exploratory....................... 1.21 .25 1.7 1.5 3.0 1.6
Development....................... 4.15 1.05 4.9 1.5 1.0 0.4
Onshore United States
Exploratory....................... 11.27 7.40 6.5 0.9 4.6 1.0
Development....................... 30.18 1.41 24.4 0.7 31.3 0.1
Onshore Kingdom of Thailand
Exploratory....................... 8.34 .46 2.4 -- 1.1 --
Development....................... 5.11 -- 7.4 -- 3.2 --
----- ----- --- ---- ---- ---
Total........................ 60.26 10.57 47.3 4.6 44.2 3.1
===== ===== ==== ==== ==== ===
</TABLE>
As of December 31, 1997, the Company was participating in the drilling of 3
gross (1.1 net) offshore domestic wells, 6 gross (4.2 net) onshore wells and 1
gross (0.5 net) wells offshore the Kingdom of Thailand.
56
<PAGE> 57
Production and Sales
The following table summarizes the Company's average daily production, net
of all royalties, overriding royalties and other outstanding interests, for the
periods indicated. Natural gas production refers only to marketable production
of natural gas on an "as sold" basis.
<TABLE>
<CAPTION>
1997 1996 1995
------- ------- -------
<S> <C> <C> <C>
Located in the United States
Natural Gas (Mcf per day)................................... 147,200 107,700 121,000
======= ======= =======
Liquid Hydrocarbons (Bbls per day)
Crude Oil and Condensate................................. 13,712 11,968 11,786
Natural Gas Liquids(a)................................... 2,923 2,173 1,998
------- ------- -------
Total Domestic Liquid Hydrocarbons.................. 16,635 14,141 13,784
======= ======= =======
Located in the Kingdom of Thailand
Natural Gas (Mcf per day)................................... 37,700 -- --
======= ======= =======
Liquid Hydrocarbons (Bbls per day)
Crude Oil and Condensate................................. 2,421 -- --
======= ======= =======
</TABLE>
- -------------------
(a) NGL production sales includes sales attributable to both the Company's
leasehold and plant ownership.
The following table shows the average sales prices received by the Company
for its production and the average production (lifting) costs per unit of
production during the periods indicated. See "-- Miscellaneous; Competition"
and "-- Miscellaneous; Market Conditions and Sales."
<TABLE>
<CAPTION>
1997 1996 1995
------- -------- --------
<S> <C> <C> <C>
SALES PRICES:
Located in the United States
Natural Gas (per Mcf).................................. $ 2.50 $ 2.40 $ 1.63
Crude Oil and Condensate (per Bbl)..................... $ 19.49 $ 22.12 $ 17.80
Natural Gas Liquids (per Bbl).......................... $ 12.89 $ 14.92 $ 11.10
Located in the Kingdom of Thailand
Natural Gas (per Mcf).................................. $ 1.93 -- --
Crude Oil and Condensate (per Bbl).......................... $ 18.60 -- --
PRODUCTION (LIFTING) COSTS(a):
Located in the United States
Natural Gas, Crude Oil, Condensate and Natural
Gas Liquids (per Mcf equivalent)...................... $ .49 $ .53 $ .47
Located in the Kingdom of Thailand
Natural Gas, Crude Oil and Condensate (per Mcf
equivalent)(b)........................................ $ 1.12 -- --
</TABLE>
- --------------------
(a) Production costs were converted to common units of measure on the basis
of relative energy content. Such production costs exclude all depletion
and amortization associated with property and equipment.
(b) The major contributing factor to lifting costs are lease operating
expenses. A substantial portion of the Company's lease operating expenses
in the Kingdom of Thailand relate to lease payments made by a subsidiary
of the Company in connection with its bareboat charter of the FPSO, which
amounted to $10,200,000 during 1997. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity
and Capital Resources; Future Capital Requirements; Other Material
Long-Term Commitments."
57
<PAGE> 58
Reserves
The following table sets forth information as to the Company's net proved
and proved developed reserves as of December 31, 1997, 1996, and 1995, and the
present value as of such dates (based on an annual discount rate of 10%) of the
estimated future net revenues from the production and sale of those reserves,
as estimated by Ryder Scott in accordance with criteria prescribed by the SEC.
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-----------------------------------
1997 1996 1995
-------- -------- -------
<S> <C> <C> <C>
TOTAL PROVED RESERVES(a):
Oil, condensate, and natural gas liquids (MBbls)
Located in the United States............................ 29,382 28,270 26,185
Located in the Kingdom of Thailand...................... 28,783 21,332 18,997
-------- -------- --------
Total Company...................................... 58,165 49,602 45,182
======== ======== ========
Natural Gas (MMcf)
Located in the United States............................ 216,720 215,946 196,454
Located in the Kingdom of Thailand...................... 184,768 144,998 131,607
-------- -------- --------
Total Company...................................... 401,488 360,944 328,061
======== ======== ========
Present value of estimated future net revenues, before
income taxes (in thousands)(b)
Located in the United States............................ $406,161 $773,127 $400,845
Located in the Kingdom of Thailand...................... 56,620 181,418 131,630
-------- -------- --------
Total Company...................................... $462,781 $954,545 $532,745
======== ======== ========
TOTAL DEVELOPED RESERVES(a):
Oil, condensate, and natural gas liquids (MBbls)
Located in the United States............................ 26,168 25,898 22,488
Located in the Kingdom of Thailand...................... 6,982 5,192 --
-------- -------- --------
Total Company...................................... 33,150 31,090 22,488
======== ======== ========
Natural Gas (MMcf)
Located in the United States............................ 179,972 192,034 164,679
Located in the Kingdom of Thailand...................... 59,760 45,998 --
-------- -------- --------
Total Company...................................... 239,732 238,032 164,679
======== ======== ========
Present value of estimated future net revenues, before
income taxes (in thousands)(b)
Located in the United States............................ $377,530 $710,871 $359,984
Located in the Kingdom of Thailand...................... 36,692 69,062 --
-------- -------- --------
Total Company...................................... $414,222 $779,933 $359,984
======== ======== ========
</TABLE>
- ------------------------
(a) Gives no effect to the Company's acquisition of Arch in August 1998. See
"-- Arch and its Subsidiaries; Oil and Gas Reserves."
(b) The Company believes, for the reasons set forth in succeeding paragraphs,
that the present value of estimated future net revenues set forth in the
Annual Report and calculated in accordance with SEC guidelines are not
necessarily indicative of the true present value of the Company's
reserves and, due to the fact that essentially all of the Company's
domestic natural gas production is currently sold on the spot market,
whereas all of the Company's Thai natural gas production is sold pursuant
to a long term gas sales contract, such estimates of future net revenues
from the Company's domestic and Thai reserves are, accordingly, not
useful for comparative purposes. See the discussion on the following
pages for the prices used in making these calculations.
Natural gas liquids comprised approximately 7% of the Company's total
proved liquids reserves and approximately 11% of the Company's proved developed
liquids reserves as of December 31, 1997. All hydrocarbon liquid reserves are
expressed in standard 42 gallon Bbls. All gas volumes and gas sales are
expressed in MMcf at the pressure and temperature bases of the area where the
gas reserves are located.
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from
known reservoirs under existing conditions. Reservoirs are considered proved if
economic producibility is supported by
58
<PAGE> 59
actual production or formation tests. In certain instances, proved reserves are
assigned on the basis of a combination of core analysis and electrical and
other type logs which indicate the reservoirs are analogous to reservoirs in
the same field which are producing or have demonstrated the ability to produce
on a formation test. The area of a reservoir considered proved includes (i)
that portion delineated by drilling and defined by fluid contacts, if any, and
(ii) the adjoining portions not yet drilled that can be reasonably judged as
economically productive on the basis of available geological and engineering
data. In the absence of data on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of the reservoir.
Proved reserves are estimates of hydrocarbons to be recovered from a given date
forward. They may be revised as hydrocarbons are produced and additional data
becomes available. Proved natural gas reserves are comprised of non-associated,
associated and dissolved gas. An appropriate reduction in gas reserves has been
made for the expected removal of liquids, for lease and plant fuel and the
exclusion of non-hydrocarbon gases if they occur in significant quantities and
are removed prior to sale. Reserves that can be produced economically through
the application of established improved recovery techniques are included in the
proved classification when these qualifications are met: (i) 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, and (ii) it is reasonably certain the project will proceed. Improved
recovery includes all methods for supplementing natural reservoir forces and
energy, or otherwise increasing ultimate recovery from a reservoir, including,
(i) pressure maintenance, (ii) cycling, and (iii) secondary recovery in its
original sense. Improved recovery also includes the enhanced recovery methods
of thermal, chemical flooding, and the use of miscible and immiscible
displacement fluids. Estimates of proved reserves do not include crude oil,
condensate, natural gas, or natural gas liquids being held in underground
storage. Depending on the status of development, these proved reserves are
further subdivided into:
(i) "developed reserves" which are those proved reserves reasonably
expected to be recovered through existing wells with existing
equipment and operating methods, including (a) "developed producing
reserves" which are those proved developed reserves reasonably
expected to be produced from existing completion intervals now open
for production in existing wells, and (b) "developed non-producing
reserves" which are those proved developed reserves which exist
behind casing of existing wells which are reasonably expected to be
produced through these wells in the predictable future where the cost
of making such hydrocarbons available for production should be
relatively small compared to the cost of new wells; and
(ii) "undeveloped reserves" which are those proved reserves
reasonably expected to be recovered from new wells on undrilled
acreage, from existing wells where a relatively large expenditure is
required and from acreage for which an application of fluid injection
or other improved recovery technique is contemplated where the
technique has been proved effective by actual tests in the area in
the same reservoir. Reserves from undrilled acreage are limited to
those drilling units offsetting productive units that are reasonably
certain of production when drilled. Proved reserves for other
undrilled units are included only where it can be demonstrated with
reasonable certainty that there is continuity of production from the
existing productive formation.
In computing future revenues from gas reserves attributable to the
Company's domestic interests, prices in effect at December 31, 1997 were used,
including current market prices, contract prices and fixed and determinable
price escalations where applicable. In accordance with SEC guidelines, the gas
prices that were used make no allowances for seasonal variations in gas prices
which are likely to cause future yearly average gas prices to be somewhat lower
than December gas prices. For domestic gas sold under contract, the contract
gas price including fixed and determinable escalations, exclusive of inflation
adjustments, was used until the contract expires and then was adjusted to the
current market price for the area and held at this adjusted price to depletion
of the reserves. In computing future revenues from liquids attributable to the
Company's domestic interests, prices in effect at December 31, 1997 were used
and these prices were held constant to depletion of the properties. The future
revenues are adjusted to reflect the Company's net revenue interest in these
reserves as well as any ad valorem and other severance taxes but do not
include, unless otherwise noted, any provisions for corporate income taxes.
59
<PAGE> 60
In computing future revenues from the Company's gas reserves
attributable to the Company's interests in the Kingdom of Thailand, the current
contract price under the Gas Sales Agreement was used, without giving effect to
any of the adjustments provided for in the Gas Sales Agreement, due to their
indeterminate nature as of December 31, 1997, in accordance with SEC
guidelines. In computing future revenues from liquids attributable to the
Company's interests in the Kingdom of Thailand, a price was used which the
Company believes approximates the price that the Company would have received
for its production from the Thailand Concession based upon the world market
price for Tapis benchmark crude on December 31, 1997, and this price was held
constant until depletion of the Company's reserves in the Kingdom of Thailand.
The future revenues are adjusted to reflect the Company's net revenue interest
in these reserves and the Company's obligations under the Thailand Concession,
including the payment of SRB and applicable production bonuses, but does not
include, unless otherwise noted, any provisions for U.S. or Thai corporate
income or other taxes.
In accordance with SEC guidelines, the prices used by the Company to
calculate the present value of estimated future revenues are determined on a
well or field by field basis, as applicable, as described above and were held
constant over the productive life of the reserves. The initial weighted average
prices used by Ryder Scott were as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------------------
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
INITIAL WEIGHTED AVERAGE PRICE (in U.S. dollars):
Oil, condensate, and natural gas liquids (per Bbl)
Located in the United States............................ $16.60 $24.06 $19.10
Located in the Kingdom of Thailand...................... $16.00 $24.56 $18.71
Natural Gas (per Mcf)
Located in the United States............................ $ 2.30 $ 3.93 $ 2.08
Located in the Kingdom of Thailand...................... $ 1.83 $ 2.09 $ 2.02
</TABLE>
The estimates of future net revenue from the Company's domestic and
Thailand properties are based on existing law where the properties are located
and are calculated in accordance with SEC guidelines. Operating costs for the
leases and wells include only those costs directly applicable to the leases or
wells. When applicable, the operating costs include a portion of general and
administrative costs allocated directly to the leases and wells under terms of
operating agreements. Development costs are based on authorization for
expenditure for the proposed work or actual costs for similar projects. The
current operating and development costs were held constant throughout the life
of the properties. For properties located onshore, the estimates of future net
revenues and the present value thereof do not consider the salvage value of the
lease equipment or the abandonment cost of the lease since both are relatively
insignificant and tend to offset each other. The estimated net cost of
abandonment after salvage was considered for offshore properties where such
costs net of salvage are significant.
No deduction was made for indirect costs such as general and
administrative and overhead expenses, loan repayments, interest expenses, and
exploration and development prepayments. Accumulated gas production imbalances,
if any, have been taken into account.
Production data used to arrive at the estimates set forth above
includes estimated production for the last few months of 1997. The future
production rates from reservoirs now on production may be more or less than
estimated because of, among other reasons, mechanical breakdowns and changes in
market demand or allocable set by regulatory bodies. Properties which are not
currently producing may start producing earlier or later than anticipated in
the estimates of future production rates.
The future prices received by the Company for the sales of its
production may be higher or lower than the prices used in calculating the
estimates of future net revenues and the present value thereof as set forth
herein, and the operating costs and other costs relating to such production may
also increase or decrease from existing levels; however, such possible changes
in prices and costs were, in accordance with rules adopted by the SEC, omitted
from consideration in arriving at such estimates. See "Risk Factors --
Volatility of oil and gas markets affects us" and "-- Miscellaneous;
Competition and Market Conditions."
60
<PAGE> 61
There are numerous uncertainties in estimating the quantity of proved
reserves and in projecting the future rates of production and timing of
development expenditures. Oil and gas reserve engineering must be recognized as
a subjective process of estimating underground accumulations of oil and gas
that cannot be measured in an exact way, and estimates of other engineers might
differ materially from those of Ryder Scott, the Company's reserve engineers.
The accuracy of any reserve estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. Results of
drilling, testing and production subsequent to the date of the estimate may
justify revision of such estimate, which revisions may be material.
Accordingly, reserve estimates are often different from the quantities of oil
and gas that are ultimately recovered.
The Company is periodically required to file estimates of its oil and
gas reserve data with various U.S. governmental regulatory authorities and
agencies, including the Federal Energy Regulatory Commission ("FERC") and the
Federal Trade Commission; with respect to reserves located in Canada, with the
Alberta Energy Utilities Board and, with respect to reserves located in
Thailand, the Kingdom of Thailand's Department of Mineral Resources and PTT,
which the Company considers a quasi-governmental authority. In addition,
estimates are from time to time furnished to governmental agencies in
connection with specific matters pending before such agencies. The basis for
reporting reserves to these agencies, in some cases, is not comparable to that
furnished by Ryder Scott in accordance with SEC guidelines because of the
nature of the various reports required. The major differences generally include
differences in the time as of which such estimates are made, differences in the
definition of reserves, requirements to report in some instances on a gross,
net or total operator basis and requirements to report in terms of smaller
geographical units. During 1997, no estimates by the Company of its total
proved net oil and gas reserves were filed with or included in reports to any
governmental authority or agency other than the SEC and, with respect to
reserves relating to the Company's properties located in Thailand, the Kingdom
of Thailand's Department of Mineral Resources and PTT.
GOVERNMENT REGULATION
The Company's operations are affected from time to time in varying
degrees by political developments and governmental laws and regulations. Rates
of production of oil and gas have for many years been subject to governmental
conservation laws and regulations, and the petroleum industry has been subject
to federal and state tax laws dealing specifically with it.
Federal Income Tax
The Company's operations are significantly affected by certain
provisions of the federal income tax laws applicable to the petroleum industry.
The principal provisions affecting the Company are those that permit the
Company, subject to certain limitations, to deduct as incurred, rather than to
capitalize and amortize, its domestic "intangible drilling and development
costs" and to claim depletion on a portion of its domestic oil and gas
properties based on 15% of its oil and gas gross income from such properties
(up to an aggregate of 1,000 Bbls per day of domestic crude oil and/or
equivalent units of domestic natural gas) even though the Company has little or
no basis in such properties. Under certain circumstances, however, a portion of
such intangible drilling and development costs and the percentage depletion
allowed in excess of basis will be tax preference items that will be taken into
account in computing the Company's alternative minimum tax.
Environmental Matters
Domestic oil and gas operations are subject to extensive federal
regulation and, with respect to federal leases, to interruption or termination
by governmental authorities on account of environmental and other
considerations including the Comprehensive Environmental Response, Compensation
and Liability Act ("CERCLA") also known as the "Superfund Law." The recent
trend towards stricter standards in environmental legislation and regulation
may continue, and this could increase costs to the Company and others in the
industry. Oil and gas lessees are subject to liability for the costs of
clean-up of pollution resulting from a lessee's operations, and may also be
subject to liability for pollution damages. The Company maintains insurance
against costs of clean-up operations, but is not fully insured against all such
risks. A serious incident of pollution may, as it has in the past,
61
<PAGE> 62
also result in the Department of the Interior requiring lessees under federal
leases to suspend or cease operation in the affected area.
The operators of the Company's properties have numerous applications
pending before the Environmental Protection Agency (the "EPA") for National
Pollution Discharge Elimination System water discharge permits with respect to
offshore drilling and production operations. The issue generally involved is
whether effluent discharges from each facility or installation comply with the
applicable federal regulations.
The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder
impose a variety of regulations on "responsible parties" related to the
prevention of oil spills and liability for 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 an
offshore facility is located. The OPA assigns liability to each responsible
party for oil removal costs and a variety of public and private damages. While
liability limits apply in some circumstances, a party cannot take advantage of
liability limits if the spill was caused by gross negligence or willful
misconduct or resulted from violation of a federal safety, construction or
operating regulation. If the party fails to report a spill or cooperate fully
in the cleanup, liability limits likewise do not apply. Few defenses exist to
the liability imposed by the OPA.
The OPA also imposes ongoing requirements on responsible parties,
including proof of financial responsibility to cover at least some costs in a
potential spill. For tank vessels, including mobile offshore drilling rigs, the
OPA imposes on owners, operators and charterers of the vessels, an obligation
to maintain evidence of financial responsibility of up to $10,000,000 depending
on gross tonnage. With respect to offshore facilities, proof of greater levels
of financial responsibility may be applicable. For offshore facilities that
have a worst case oil spill potential of more than 1,000 Bbls (which includes
many of the Company's offshore producing facilities), certain amendments to the
OPA that were enacted in 1996 provide that the amount of financial
responsibility that must be demonstrated for most facilities ranges from
$10,000,000 to $35,000,000, depending upon location, with higher amounts, up to
$150,000,000 in certain limited circumstances. The Company believes that it
currently has established adequate proof of financial responsibility for its
offshore facilities at no significant increase in expense over recent prior
years. However, the Company cannot predict whether these financial
responsibility requirements under the OPA amendments will result in the
imposition of substantial additional annual costs to the Company in the future
or otherwise materially adversely effect the Company. The impact, however,
should not be any more adverse to the Company than it will be to other
similarly situated or less capitalized owners or operators in the Gulf of
Mexico.
The Company's onshore operations are subject to numerous United
States federal, state, and local laws and regulations controlling the discharge
of materials into the environment or otherwise relating to the protection of
the environment including CERCLA. Such laws and regulations, among other
things, impose absolute liability on the lessee under a lease for the cost of
clean-up of pollution resulting from a lessee's operations, subject the lessee
to liability for pollution damages, may require suspension or cessation of
operations in affected areas, and impose restrictions on the injection of
liquids into subsurface aquifers that may contaminate groundwater. Such laws
could have a significant impact on the operating costs of the Company, as well
as the oil and gas industry in general. Federal, state and local initiatives to
further regulate the disposal of oil and gas wastes are also pending in certain
states, and these initiatives could have a similar impact on the Company.
The Company is asked to comment on the costs it incurred during the
prior year on capital expenditures for environmental control facilities and the
amount it anticipates incurring during the coming year. The Company believes
that, in the course of conducting its oil and gas operations, many of the costs
attributable to environmental control facilities would have been incurred
absent environmental regulations as prudent, safe oilfield practice. During
1997, the Company incurred capital expenditures of approximately $610,000 for
environmental control facilities, primarily relating to the installation of
certain environmental control facilities on two platforms installed in the Gulf
of Thailand. The Company budgeted approximately $1,630,000 for expenditures
involving environmental control facilities during 1998, including, among other
things, two salt water disposal facilities in New Mexico and
62
<PAGE> 63
environmental control equipment for three platforms in the Gulf of Thailand and
two platforms in the Gulf of Mexico.
Other Laws and Regulations
Various laws and regulations often require permits for drilling wells
and also cover spacing of wells, the prevention of waste of oil and gas
including maintenance of certain gas/oil ratios, rates of production and other
matters. The effect of these laws and regulations, as well as other regulations
that could be promulgated by the jurisdictions in which the Company has
production, could be to limit the number of wells that could be drilled on the
Company's properties and to limit the allowable production from the successful
wells completed on the Company's properties, thereby limiting the Company's
revenues.
The Minerals Management Service of the Department of the Interior
(the "MMS") administers the oil and gas leases held by the Company on federal
onshore lands and offshore tracts in the Outer Continental Shelf. The MMS holds
a royalty interest in these federal leases on behalf of the federal government.
While the royalty interest percentage is fixed at the time that the lease is
entered into, from time to time the MMS changes or reinterprets the applicable
regulations governing its royalty interests, and such action can indirectly
affect the actual royalty obligation that the Company is required to pay. In a
letter dated May 3, 1993, the MMS announced a reinterpretation of its right to
collect royalty payments from producers on certain settlements in which such
producers and pipeline companies were involved a number of years ago. The MMS
reinterpretation has been challenged in court by various producers and trade
groups representing them. On August 27, 1996, in Independent Petroleum
Association of America, et al. v. Babbit et al., Nos. 95-5210 etc., the United
States Court of Appeals for the District of Columbia Circuit held that the May
3, 1993, reinterpretation was invalid and unenforceable. Unless and until this
or other similar cases are resolved in favor of the MMS' reinterpretation of
its regulations, it is unlikely that the Company or other producers will be
legally required to pay royalties on such settlement agreements. The Company
was involved in several settlement agreements with pipelines that could be
subject to the MMS' new reinterpretation. The MMS has reviewed the Company's
and other producers' settlement agreements, to determine whether it believes
any additional royalty payments may be due and has asserted that additional
royalties may be due in connection with two of the Company's settlement
agreements. Based upon existing case law, the Company has asserted through the
administrative appeals process, and continues to believe, that it does not owe
any additional royalties beyond what it has previously paid. However, in the
event that the MMS is able to successfully assert that additional royalty is
due from the Company in connection with settlement agreements to which the
Company is a party, the Company does not currently believe that such additional
assessment will have a material adverse impact on the financial position or
results of operations of the Company.
Recently the MMS and various state and municipal authorities have
attempted to collect alleged underpayment of royalties from various integrated
oil companies in connection with sale transactions between exploration and
production affiliates and pipeline affiliates of the same company. The Company
has not been named in any of these collection efforts, a fact that the Company
believes is primarily due to its never having sold any oil or gas production
from one of its affiliates to another. The Company does not believe that it has
any material liability for underpayment of royalty in connection with affiliate
transactions, including those described above.
The FERC has recently embarked on regulatory initiatives relating to
its jurisdiction over rates for natural gas gathering services provided by
interstate pipelines and to the availability of market-based and other
alternative rate mechanisms to such pipelines for transmission and storage
services. Among the FERC initiatives is the creation of a pilot program to
determine the effect on rates of lifting price caps on the rates for
interruptible transportation, short-term firm transportation, and for
transportation using capacity released by the firm transportation customers of
interstate pipelines. In addition, the FERC has announced and implemented a
policy allowing pipelines and transportation customers to negotiate rates above
the otherwise applicable maximum lawful cost-based rates on the condition that
the pipelines alternatively offer so-called recourse rates equal to the maximum
lawful cost-based rates. This negotiated/recourse rate policy has been
challenged in the United States Court of Appeals for the District of Columbia,
and the appeal remains pending. With respect to gathering services, the FERC
has issued orders declaring that certain facilities owned by interstate
pipelines primarily perform a gathering function, and may be transferred to
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<PAGE> 64
affiliated and non-affiliated entities that are not subject to the FERC's rate
jurisdiction. These orders have been generally upheld on appeal to the courts.
The Company cannot predict the ultimate outcome of these developments, nor the
effect of these developments on transportation rates. Inasmuch as the rates for
these pipeline services can affect the gas prices received by the Company for
the sale of its production, the FERC's actions may have an impact on the
Company. However, the impact should not be substantially different on the
Company than it will on other similarly situated gas producers and sellers.
EMPLOYEES
As of December 31, 1998, the Company and its subsidiaries had 185
full-time employees, including 24 in its Bangkok, Thailand office and seven in
its Calgary, Canada office. None of the Company's employees are presently
represented by a union for collective bargaining purposes. The Company
considers its relations with its employees to be excellent.
ARCH AND ITS SUBSIDIARIES
Overview
Arch and its subsidiaries primarily engage in oil and natural gas
exploration, development, production, transportation and marketing in the
Southwestern United States and Western Canada. Arch and its subsidiaries are
also active in the acquisition of interests in both producing and non-producing
oil and gas leases. Arch was acquired by the Company in a stock-for-stock
tax-free merger accounted for as a purchase. In connection with the merger, the
Company paid off $36,500,000 of Arch's existing bank debt and a $15,246,000
production payment obligation (the "VPP") utilizing funds under its Credit
Agreement. The Company also exchanged $5,000,000 of Arch's existing convertible
subordinated notes, 777,273 shares of Arch preferred stock (having a
liquidation preference of $20,000,000) and 17,321,804 shares of Arch common
stock for approximately 2,540,000 shares of Common Stock.
As of January 1, 1999, Pogo Canada Ltd. (formerly known as Arch
Petroleum Ltd. ("APL")), Saginaw Pipeline Company, L.C. ("Saginaw") and its
subsidiary Industrial Natural Gas, L.C. ("ING") were the only subsidiaries of
Arch. All of the Company's and Arch's operations in Canada are conducted by
Pogo Canada Ltd. Saginaw owns a six inch pipeline that extends approximately
100 miles from Wichita Falls, Texas to Saginaw, Texas. ING, a subsidiary of
Saginaw, markets the sale and transmission of natural gas through the Saginaw
pipeline.
Oil and Gas Reserves
The following table sets forth a summary of Arch's oil and gas
reserve quantities and present value of future net cash flows associated
therewith at the dates indicated. All domestic oil and gas reserves were
estimated by Ryder Scott, independent petroleum engineers, and are detailed in
a report prepared for the exclusive use of Arch. Oil and gas reserves for APL
were estimated by Ryder Scott and Sproule Associates Limited, both independent
petroleum engineers in Canada in 1997 and 1996, respectively. All such
estimations were made in accordance with regulations promulgated by the SEC.
Such reserve reports are available for examination at Arch's corporate
headquarters in Houston, Texas.
<TABLE>
<CAPTION>
UNITED STATES CANADA TOTAL
-------------- ------------ -------------
<S> <C> <C> <C>
Present value of discounted future net cash flows
before income taxes:
December 31, 1997............................... $ 60,289,500 $ 8,422,300 $ 68,711,800
December 31, 1996............................... 101,701,100 11,775,700 113,476,800
December 31, 1995............................... 64,296,200 -- 64,296,200
Proved developed and undeveloped reserves:
Oil (Bbls)
December 31, 1997............................... 5,060,500 812,900 5,873,400
December 31, 1996............................... 3,861,000 856,900 4,717,900
</TABLE>
64
<PAGE> 65
<TABLE>
<CAPTION>
<S> <C> <C> <C>
December 31, 1995............................... 4,030,200 -- 4,030,200
Gas (Mcf)
December 31, 1997............................... 68,430,700 6,575,000 75,005,700
December 31, 1996............................... 59,120,900 1,136,000 60,256,900
December 31, 1995............................... 61,286,300 -- 61,286,300
Proved developed reserves:
Oil (Bbls)
December 31, 1997............................... 4,475,600 693,800 5,169,400
December 31, 1996............................... 3,128,400 809,900 3,938,300
December 31, 1995............................... 2,993,600 -- 2,993,600
Gas (Mcf)
December 31, 1997............................... 65,324,800 6,489,000 71,813,800
December 31, 1996............................... 54,981,200 504,000 55,485,200
December 31, 1995............................... 55,628,500 -- 55,628,500
</TABLE>
The United States figures above exclude 1.9 Bcf, 8.7 Bcf and 11.9 Bcf
of proved gas reserves and $436,400, $2,960,600 and $11,672,700 of discounted
future net cash flows (after operating expenses and severance taxes) at
December 31, 1997, 1996 and 1995, respectively, which were sold to Enron Corp.
in the VPP. See "-- Exploration and Production Data; Reserves" for key factors
and additional information related to Arch's reserve estimates.
Leases and Wells Owned
At December 31, 1997, Arch owned interests in the following acreage.
<TABLE>
<CAPTION>
UNITED STATES CANADA TOTAL
------------- ------- -------
<S> <C> <C> <C>
Developed acres:
Gross........................................... 67,017 35,223 102,240
Net............................................. 16,950 3,810 20,760
Undeveloped acres:
Gross........................................... 74,435 106,705 181,140
Net............................................. 23,452 51,777 75,229
</TABLE>
As of December 31, 1997, Arch's interests in wells owned were as
follows:
<TABLE>
<CAPTION>
TOTAL UNITED STATES CANADA
----------------- ----------------- -----------------
Gross Net Gross Net Gross Net
TYPE Wells Wells Wells Wells Wells Wells
- ------ ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Oil ...... 1,209 363.7 1,076 344.8 133 18.9
Gas ...... 134 62.8 131 62.2 3 0.6
----- ----- ----- ----- --- ----
1,343 426.5 1,207 407.0 136 19.5
===== ===== ===== ===== === ====
</TABLE>
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<PAGE> 66
MANAGEMENT AND BOARD OF DIRECTORS
EXECUTIVE OFFICERS
Executive officers of the Company are appointed annually to serve for
the ensuing year or until their successors have been elected or appointed. The
executive officers of the Company, their age as of December 31, 1998, and the
year each was elected to his present position are as follows:
<TABLE>
<CAPTION>
YEAR
EXECUTIVE OFFICER EXECUTIVE OFFICE AGE ELECTED
- ------------------------ ----------------------------------------------- --- -------
<S> <C> <C> <C>
Paul G. Van Wagenen Chairman of the Board, President and Chief 52 1991
Executive Officer
Stuart P. Burbach Executive Vice President-- Exploration 46 1998
Kenneth R. Good Executive Vice President 61 1998
Jerry A. Cooper Senior Vice President and Western Division 50 1998
Manager
R. Phillip Laney Senior Vice President and Manager of Worldwide 58 1998
New Ventures
John O. McCoy, Jr. Senior Vice President and Chief Administrative 47 1998
Officer
J. D. McGregor Senior Vice President-- Sales 54 1998
Bruce E. Archinal Vice President and Onshore Division Manager 46 1997
David R. Beathard Vice President-- Engineering 40 1997
Stephen R. Brunner Vice President-- Operations 40 1997
Frank Davis III Vice President-- Land 52 1997
John W. Elsenhans Vice President and Chief Financial Officer 46 1998
Thomas E. Hart Vice President and Controller 56 1988
Ronald B. Manning Vice President and General Counsel 45 1995
Gerald A. Morton Vice President-- Law and Corporate 40 1997
Secretary
</TABLE>
Prior to assuming their present positions with the Company, the
business experience of each executive officer for more than the last five years
was as follows: Mr. Van Wagenen, who joined the Company in 1979, served as
President and Chief Operating Officer of the Company since 1990; Mr. Burbach
served as Vice President and Offshore Division Manager since rejoining the
Company in 1991; Mr. Good, who joined the Company in 1977, served as Corporate
Senior Vice President of the Company since 1996 and prior thereto served as the
Company's Senior Vice President -- Land and Budgets since 1991; Mr. Cooper, who
joined the Company in 1979, served as Vice President and Western Division
Manager for the Company since 1991; Mr. Laney, who joined the Company in 1977,
served as Vice President and International Exploration Manager for the Company
since 1991; Mr. McCoy, who joined the Company in 1978, served as Vice President
and Chief Administrative Officer of the Company since 1989; Mr. McGregor, who
joined the Company in 1981, served as Vice President -- Sales since 1988; Mr.
Archinal, who joined the Company in 1982, served as the Company's Onshore
Division Manager since 1994 and prior thereto served as Offshore Division
Exploration Manager for the Company since 1991; Mr. Beathard, who joined the
Company in 1982, served as Manager of Petroleum Engineering for the Company
since 1991; Mr. Brunner served as Resident Manager of the Company's Thailand
operations since 1995, prior to which he was an Operations Manager for the
Company since joining in 1994 and prior thereto held various positions in the
energy industry, the most recent of which was as Operations Manager for Zilkha
Energy since 1991; Mr. Davis, who joined the Company in 1978, served as Land
Manager for the Company since 1991; Mr. Elsenhans, who joined the Company in
1991, served as Vice President -- Finance and Treasurer for the Company since
1995, and prior thereto was Director, Corporate Finance for the Company since
1991; Mr. Hart was Controller for the Company since joining the Company in
1977; Mr. Manning, who joined the Company in 1987, was Corporate Secretary and
an Associate General Counsel for the Company since 1990; and Mr. Morton was an
Associate General Counsel for the Company since 1993.
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<PAGE> 67
BOARD OF DIRECTORS
The following is a list of the members of the Company's Board of
Directors and their principal occupations.
<TABLE>
<CAPTION>
NAME PRINCIPAL OCCUPATION
- ---- --------------------
<S> <C>
Paul G. Van Wagenen.............................. Chairman of the Board, President and
Chief Executive Officer of the
Company
Jerry M. Armstrong*.............................. Rancher
Tobin Armstrong*................................. Rancher
Jack S. Blanton.................................. President, Eddy Refining Company;
Chairman, Houston Endowment, Inc.
W. M. Brumley, Jr................................ Personal Investments
John B. Carter, Jr............................... Director, Sterling Bancshares
William L. Fisher................................ Barrow Chair and Geological Sciences
Professor University of Texas at
Austin
Gerrit W. Gong................................... Freeman Chair and Director of Asian
Studies, Center for Strategic and
International Studies
J. Stuart Hunt................................... Personal Investments
Frederick A. Klingenstein........................ Chairman of the Board, Klingenstein,
Fields & Co., L.P.
Jack A. Vickers.................................. Chairman of the Board, The Vickers
Companies
</TABLE>
- ----------
* Jerry M. Armstrong and Tobin Armstrong are not related to each other.
67
<PAGE> 68
THE EXCHANGE OFFER
PURPOSE AND EFFECT OF THE EXCHANGE OFFER
The Company entered into a Registration Rights Agreement with the
initial purchasers of the outstanding notes in which the Company agreed to file
a registration statement relating to an offer to exchange the outstanding notes
for new notes. The Company also agreed to use its reasonable best efforts to
complete that offer within 180 days after January 15, 1999. The Company is
offering the new notes under this prospectus to satisfy those obligations under
the Registration Rights Agreement.
Under limited circumstances, the Company will use its reasonable best
efforts to cause the SEC to declare effective a shelf registration statement
with respect to the resale of the outstanding notes and keep the shelf
registration statement effective for up to two years after the effective date
of the shelf registration statement. These circumstances include:
o if any changes in law or applicable interpretations by the staff
of the SEC do not permit the Company to effect the exchange
offer as contemplated by the Registration Rights Agreement
o if the exchange offer is not consummated within 180 days after
January 15, 1999
o if any initial purchaser of the outstanding notes so requests,
in certain circumstances
If the Company fails to comply with deadlines for registering the
issuance of the new notes and completion of the exchange offer, it will be
required to pay additional interest to holders of the outstanding notes. Please
read the section captioned "Outstanding Notes Registration Rights Agreement"
for more details regarding the Registration Rights Agreement.
To exchange an outstanding note for transferable new notes in the
exchange offer, the holder of that outstanding note will be required to make
the following representations:
o any new note the holder receives will be acquired in the
ordinary course of its business
o the holder has no arrangement with any person to participate in
the distribution of the new notes
o if the holder is not a broker-dealer, that holder is not engaged
in and does not intend to engage in the distribution of the new
notes
o if the holder is a broker-dealer that will receive new notes for
its own account in exchange for outstanding notes that were
acquired as a result of market-making activities, that holder
will deliver a prospectus, as required by law, in connection
with any resale of such new notes
o the holder is not the Company's "affiliate," as defined in Rule
405 of the Securities Act, nor a broker-dealer tendering
outstanding notes acquired directly from the Company for its own
account
RESALE OF NEW NOTES
Based on interpretations of the SEC staff in no action letters issued
to third parties, the Company believes that each new note issued under the
exchange offer may be offered for resale, resold and otherwise transferred by
the holder of that new note without compliance with the registration and
prospectus delivery provisions of the Securities Act if:
o the holder is not the Company's "affiliate" within the meaning
of Rule 405 under the Securities Act
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<PAGE> 69
o such new note is acquired in the ordinary course of the holder's
business
o the holder does not intend to participate in the distribution of
new notes
If a holder of outstanding notes tenders in the exchange offer with
the intention of participating in any manner in a distribution of the new
notes, that holder
o cannot rely on such interpretations by the SEC staff
o must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with a
secondary resale transaction
Unless an exemption from registration is otherwise available, any
security holder intending to distribute new notes should be covered by an
effective registration statement under the Securities Act containing the
selling securityholder's information required by Item 507 of Regulation S-K
under the Securities Act. This prospectus may be used for an offer to resell,
resale or other retransfer of new notes only as specifically described in this
prospectus. Only broker-dealers that acquired the outstanding notes as a result
of market-making activities or other trading activities may participate in the
exchange offer. Please read the section captioned "Plan of Distribution" for
more details regarding the transfer of new notes.
TERMS OF THE EXCHANGE OFFER
Upon the terms and subject to the conditions described in this
prospectus and in the letter of transmittal, the Company will accept for
exchange any outstanding notes properly tendered and not withdrawn prior to the
expiration date. The Company will issue $1,000 principal amount of new notes in
exchange for each $1,000 principal amount of outstanding notes surrendered
under the exchange offer. Outstanding notes may be tendered only in integral
multiples of $1,000.
The exchange offer is not conditioned upon any minimum aggregate
principal amount of outstanding notes being tendered for exchange.
As of the date of this prospectus, $150 million aggregate principal
amount of the outstanding notes are outstanding. This prospectus and the letter
of transmittal are being sent to all registered holders of outstanding notes.
There will be no fixed record date for determining registered holders of
outstanding notes entitled to participate in the exchange offer.
The Company intends to conduct the exchange offer in accordance with
the provisions of the registration rights agreement, the applicable
requirements of the Securities Act and the Securities Exchange Act of 1934 and
the rules and regulations of the SEC. Outstanding notes that are not tendered
for exchange in the exchange offer will remain outstanding and continue to
accrue interest and will be entitled to the rights and benefits such holders
have under the indenture relating to the notes and the Registration Rights
Agreement.
The Company will be deemed to have accepted for exchange properly
tendered outstanding notes when it has given oral or written notice of the
acceptance to the exchange agent and complied with the applicable provisions of
the Registration Rights Agreement. The exchange agent will act as agent for the
tendering holders for the purposes of receiving the new notes from the Company.
Holders tendering outstanding 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 with respect to the exchange of
outstanding notes. The Company will pay all charges and expenses, other than
certain applicable taxes described below, in connection with the exchange
offer. It is important for noteholders to read the section labeled "--Fees and
Expenses" for more details regarding fees and expenses incurred in the exchange
offer.
69
<PAGE> 70
The Company will return any outstanding notes that it does not accept
for exchange for any reason without expense to the tendering holder as promptly
as practicable after the expiration or termination of the exchange offer.
EXPIRATION DATE
The exchange offer will expire at 5:00 p.m., New York City time on
April 5, 1999, unless in the Company's sole discretion, the Company extends it.
EXTENSIONS, DELAY IN ACCEPTANCE, TERMINATION OR AMENDMENT
The Company expressly reserves the right, at any time or at various
times, to extend the period of time during which the exchange offer is open.
During any such extensions, all outstanding notes previously tendered will
remain subject to the exchange offer, and the Company may accept them for
exchange.
In order to extend the exchange offer, the Company will notify the
exchange agent orally or in writing of any extension. The Company will also
make a public announcement of the extension no later than 9:00 a.m., New York
City time, on the next business day after the previously scheduled expiration
date.
If any of the conditions described below under "--Conditions to the
Exchange Offer" have not been satisfied, the Company reserves the right, in its
sole discretion to delay accepting for exchange any outstanding notes or to
extend the exchange offer or to terminate the exchange offer by giving oral or
written notice of such delay, extension or termination to the exchange agent.
Subject to the terms of the Registration Rights Agreement, the Company also
reserves the right to amend the terms of the exchange offer in any manner.
Any such delay in acceptance, extension, termination or amendment will
be followed as promptly as practicable by oral or written notice thereof to the
registered holders of outstanding notes. If the Company amends the exchange
offer in a manner that it determines to constitute a material change, it will
promptly disclose such amendment by means of a prospectus supplement. The
supplement will be distributed to the registered holders of the outstanding
notes. Depending upon the significance of the amendment and the manner of
disclosure to the registered holders, the Company will extend the exchange
offer if the exchange offer would otherwise expire during such period.
Without limiting the manner in which the Company may choose to make
public announcements of any delay in acceptance, extension, termination or
amendment of the exchange offer, the Company will have no obligation to
publish, advertise, or otherwise communicate any such public announcement,
other than by making a timely release to the Dow Jones News Service.
CONDITIONS TO THE EXCHANGE OFFER
Despite any other term of the exchange offer, the Company will not be
required to accept for exchange, or exchange any new notes for, any outstanding
notes, and the Company may terminate the exchange offer as provided in this
prospectus before accepting any outstanding notes for exchange, if in the
Company's reasonable judgment the exchange offer, or the making of any exchange
by a holder of outstanding notes, would violate applicable law or any
applicable interpretation of the staff of the SEC.
In addition, the Company will not be obligated to accept for exchange
the outstanding notes of any holder that has not made to us (1) the
representations described under "--Purpose and Effect of the Exchange Offer,"
"--Procedures for Tendering" and "Plan of Distribution" and (2) such other
representations as may be reasonably necessary under applicable SEC rules,
regulations or interpretations to make available to the Company an appropriate
form for registration of the new notes under the Securities Act.
The Company expressly reserves the right to amend or terminate the
exchange offer, and to reject for exchange any outstanding notes not previously
accepted for exchange, upon the occurrence of any of the conditions
70
<PAGE> 71
to the exchange offer specified above. The Company will give oral or written
notice of any extension, amendment, non-acceptance or termination to the
holders of the outstanding notes as promptly as practicable.
These conditions are for the Company's sole benefit and the Company
may assert them or waive them in whole or in part at any time or at various
times in our sole discretion. If the Company fails at any time to exercise any
of these rights, this failure will not mean that the Company has waived its
rights. Each such right will be deemed an ongoing right that the Company may
assert at any time or at various times.
In addition, the Company will not accept for exchange any outstanding
notes tendered, and will not issue new notes in exchange for any such
outstanding notes, if at such time any stop order has been threatened or is in
effect with respect to the registration statement of which this prospectus
constitutes a part or the qualification of the indenture relating to the notes
under the Trust Indenture Act of 1939.
PROCEDURES FOR TENDERING
How to Tender Generally
Only a holder of outstanding notes may tender such outstanding notes
in the exchange offer. To tender in the exchange offer, a holder must:
o complete, sign and date the letter of transmittal, or a
facsimile of the letter of transmittal; have the signature on
the letter of transmittal guaranteed if the letter of
transmittal so requires; and mail or deliver such letter of
transmittal or facsimile to the exchange agent prior to the
expiration date
o comply with the automated tender offer program procedures of The
Depository Trust Company, or DTC, described below
In addition, either:
o the exchange agent must receive outstanding notes along with the
letter of transmittal
o the exchange agent must receive, prior to the expiration date, a
timely confirmation of book-entry transfer of such outstanding
notes into the exchange agent's account at DTC according to the
procedure for book-entry transfer described below or a properly
transmitted agent's message, or
o the holder must comply with the guaranteed delivery procedures
described below
To be tendered effectively, the exchange agent must receive any
physical delivery of the letter of transmittal and other required documents at
its address provided above under "Prospectus Summary--The Exchange Agent" prior
to the expiration date.
The tender by a holder that is not withdrawn prior to the expiration
date will constitute an agreement between the holder and the Company in
accordance with the terms and subject to the conditions described in this
prospectus and in the letter of transmittal.
THE METHOD OF DELIVERY OF OUTSTANDING NOTES, THE LETTER OF TRANSMITTAL
AND ALL OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT THE HOLDER'S
ELECTION AND RISK. RATHER THAN MAIL THESE ITEMS, THE COMPANY RECOMMENDS THAT
HOLDERS USE AN OVERNIGHT OR HAND DELIVERY SERVICE. IN ALL CASES, HOLDERS SHOULD
ALLOW SUFFICIENT TIME TO ASSURE DELIVERY TO THE EXCHANGE AGENT BEFORE THE
EXPIRATION DATE. HOLDERS SHOULD NOT SEND THE LETTER OF TRANSMITTAL OR
OUTSTANDING NOTES TO THE COMPANY. HOLDERS MAY REQUEST THEIR BROKERS, DEALERS,
COMMERCIAL BANKS, TRUST COMPANIES OR OTHER NOMINEES TO EFFECT THE ABOVE
TRANSACTIONS FOR YOU.
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<PAGE> 72
How to Tender--Beneficial Owners
Beneficial owners of outstanding notes that are registered in the name
of a broker, dealer, commercial bank, trust company or other nominee wishing to
tender those notes should contact the registered holder promptly and instruct
it to tender on the beneficial owner's behalf. Beneficial owners who wish to
tender on their own behalf must, prior to completing and executing the letter
of transmittal and delivering their outstanding notes, either:
o make appropriate arrangements to register ownership of the
outstanding notes in their name, or
o obtain a properly completed bond power from the registered
holder of outstanding notes
The transfer of registered ownership may take considerable time and
may not be completed prior to the expiration date.
Signatures and Signature Guarantees
Holders of outstanding notes must have signatures on a letter of
transmittal or a notice of withdrawal described below guaranteed by a member
firm of a registered national securities exchange or of the National
Association of Securities Dealers, Inc., a commercial bank or trust company
having an office or correspondent in the United States, or an "eligible
guarantor institution" within the meaning of Rule 17Ad-15 under the Securities
Exchange Act of 1934, that is a member of one of the recognized signature
guarantee programs identified in the letter of transmittal, unless the
outstanding notes are tendered:
o by a registered holder who has not completed the box entitled
"Special Issuance Instructions" or "Special Delivery
Instructions" on the letter of transmittal and the new notes are
being issued directly to the registered holder of the
outstanding notes tendered in the exchange for those new notes
o for the account of a member firm of a registered national
securities exchange or of the National Association of Securities
Dealers, Inc., a commercial bank or trust company having an
office or correspondent in the United States, or an eligible
guarantor institution
When Endorsements or Bond Powers are Needed
If the letter of transmittal is signed by a person other than the
registered holder of any outstanding notes, the outstanding notes must be
endorsed or accompanied by a properly completed bond power. The bond power must
be signed by the registered holder as the registered holder's name appears on
the outstanding notes and a member firm of a registered national securities
exchange or of the National Association of Securities Dealers, Inc., a
commercial bank or trust company having an office or correspondent in the
United States, or an eligible guarantor institution must guarantee the
signature on the bond power.
If the letter of transmittal or any outstanding notes or bond powers
are signed by trustees, executors, administrators, guardians,
attorneys-in-fact, officers of corporations or other acting in a fiduciary or
representative capacity, those persons should so indicate when signing. Unless
waived by the Company, they should also submit evidence satisfactory to the
Company of their authority to deliver the letter of transmittal.
Tendering Through DTC's Automated Tender Offer Program
The exchange agent and DTC have confirmed that any financial
institution that is a participant in DTC's system may use DTC's automated
tender offer program to tender. Participants in the program may, instead of
physically completing and signing the letter of transmittal and delivering it
to the exchange agent, transmit their acceptance of the exchange offer
electronically. They may do so by causing DTC to transfer the outstanding notes
to
72
<PAGE> 73
the exchange agent in accordance with its procedures for transfer. DTC will
then send an agent's message to the exchange agent.
The term "agent's message" means a message transmitted by DTC,
received by the exchange agent and forming part of the book-entry confirmation,
to the effect that:
o DTC has received an express acknowledgment from a participant in
its automated tender offer program that is tendering outstanding
notes that are the subject of such book-entry confirmation
o such participant has received and agrees to be bound by the
terms of the letter of transmittal or, in the case of an agent's
message relating to guaranteed delivery, that such participant
has received and agrees to be bound by the applicable notice of
guaranteed delivery
o the agreement may be enforced against such participant
Determinations Under the Exchange Offer
The Company will determine in its sole discretion all questions as to
the validity, form, eligibility, time of receipt, acceptance of tendered
outstanding notes and withdrawal of tendered outstanding notes. The Company's
determination will be final and binding. The Company reserves the absolute
right to reject any outstanding notes not properly tendered or any outstanding
notes the Company's acceptance of which would, in the opinion of its counsel,
be unlawful. The Company also reserves the right to waive any defects,
irregularities or conditions of tender as to particular outstanding notes. The
Company's 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 outstanding notes must be cured within such time as
the Company shall determine. Neither the Company, the exchange agent nor any
other person will be under any duty to give notification of defects or
irregularities with respect to tenders of outstanding notes, and they will
incur no liability for failure to give such notification. Tenders of
outstanding notes will not be deemed made until such defects or irregularities
have been cured or waived. Any outstanding notes received by the exchange agent
that are not properly tendered and as to which the defects or irregularities
have not been cured or waived will be returned to the tendering holder, unless
otherwise provided in the letter of transmittal, as soon as practicable
following the expiration date.
When the Company Will Issue New Notes
In all cases, the Company will issue new notes for outstanding notes
that it has accepted for exchange under the exchange offer only after the
exchange agent timely receives:
o outstanding notes or a timely book-entry confirmation of such
outstanding notes into the exchange agent's account at DTC
o a properly completed and duly executed letter of transmittal and
all other required documents or a properly transmitted agent's
message
Return of Outstanding Notes Not Accepted or Exchanged
If the Company does not accept any tendered outstanding notes for
exchange for any reason described in the terms and conditions of the exchange
offer or if outstanding notes are submitted for a greater principal amount than
the holder desires to exchange, the unaccepted or non-exchanged outstanding
notes will be returned without expense to their tendering holder. In the case
of outstanding notes tendered by book-entry transfer into the exchange agent's
account at DTC according to the procedures described below, such non-exchanged
outstanding notes will be credited to an account maintained with DTC. These
actions will occur as promptly as practicable after the expiration or
termination of the exchange offer.
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Representations to the Company
Each holder, by signing or agreeing to be bound by the letter of
transmittal, will represent to the Company that, among other things:
o any new notes that the holder receives will be acquired in the
ordinary course of its business
o that holder has no arrangement or understanding with any person
or entity to participate in the distribution of the new notes
o if the holder is not a broker-dealer, that the holder is not
engaged in and does not intend to engage in the distribution of
the new notes
o if the holder is a broker-dealer that will receive new notes for
its own account in exchange for outstanding notes that were
acquired as a result of market-making activities, that the
holder will deliver a prospectus, as required by law, in
connection with any resale of such new notes
o that holder is not the Company's "affiliate," as defined in Rule
405 of the Securities Act, or, if the holder is an affiliate of
the Company, that holder will comply with any applicable
registration and prospectus delivery requirements of the
Securities Act
BOOK-ENTRY TRANSFER
The exchange agent will make a request to establish an account with
respect to the outstanding notes at DTC for purposes of the exchange offer
promptly after the date of this prospectus. Any financial institution
participating in DTC's system may make book-entry delivery of outstanding notes
by causing DTC to transfer such outstanding notes into the exchange agent's
account at DTC in accordance with DTC's procedures for transfer. Holders of
outstanding notes who are unable to deliver confirmation of the book-entry
tender of their outstanding notes into the exchange agent's account at DTC or
all other documents required by the letter of transmittal to the exchange agent
on or prior to the expiration date must tender their outstanding notes
according to the guaranteed delivery procedures described below.
GUARANTEED DELIVERY PROCEDURES
Any holder wishing to tender its outstanding notes but whose
outstanding notes are not immediately available or who cannot deliver its
outstanding notes, the letter of transmittal or any other required documents to
the exchange agent or comply with the applicable procedures under DTC's
automated tender offer program prior to the expiration date may tender if:
o the tender is made through a member firm of a registered
national securities exchange or of the National Association of
Securities Dealers, Inc., a commercial bank or trust company
having an office or correspondent in the United States, or an
eligible guarantor institution
o prior to the expiration date, the exchange agent receives from
such member firm of a registered national securities exchange or
of the National Association of Securities Dealers, Inc.,
commercial bank or trust company having an office or
correspondent in the United States, or eligible guarantor
institution either a properly completed and duly executed notice
of guaranteed delivery by facsimile transmission, mail or hand
delivery or a properly transmitted agent's message and notice of
guaranteed delivery:
o setting forth the holder's name and address, the
registered number(s) of the holder's outstanding notes
and the principal amount of outstanding notes tendered
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<PAGE> 75
o stating that the tender is being made thereby
o guaranteeing that, within five business days after the
expiration date, the letter of transmittal or
facsimile thereof, together with the outstanding notes
or a book-entry confirmation, and any other documents
required by the letter of transmittal will be
deposited by the eligible guarantor institution with
the exchange agent
o the exchange agent receives such properly completed and executed
letter of transmittal or facsimile thereof, as well as all
tendered outstanding notes in proper form for transfer or a
book-entry confirmation, and all other documents required by the
letter of transmittal, within five business days after the
expiration date
Upon request to the exchange agent, a notice of guaranteed delivery
will be sent to a holder if it wishes to tender its outstanding notes according
to the guaranteed delivery procedures described above.
WITHDRAWAL OF TENDERS
Except as otherwise provided in this prospectus, any holder may
withdraw its tender at any time prior to 5:00 p.m., New York City time, on the
expiration date (unless previously accepted for exchange).
For a withdrawal to be effective:
o the exchange agent must receive a written notice of withdrawal
at one of the addresses listed above under "Prospectus
Summary--The Exchange Agent" or
o the withdrawing holder must comply with the appropriate
procedures of DTC's automated tender offer program system
Any notice of withdrawal must:
o specify the name of the person who tendered the outstanding
notes to be withdrawn (the "Depositor")
o identify the outstanding notes to be withdrawn, including the
registration number or numbers and the principal amount of such
outstanding notes
o be signed by the Depositor in the same manner as the original
signature on the letter of transmittal used to deposit those
outstanding notes (or be accompanied by documents of transfer
sufficient to permit the trustee for the outstanding notes to
register the transfer into the name of the Depositor withdrawing
the tender)
o specify the name in which such outstanding notes are to be
registered, if different from that of the Depositor
If outstanding notes have been tendered under the procedure for
book-entry transfer described above, any notice of withdrawal must specify the
name and number of the account at DTC to be credited with the withdrawn
outstanding notes and otherwise comply with the procedures of DTC.
The Company will determine all questions as to the validity, form,
eligibility and time of receipt of notice of withdrawal, and the Company's
determination shall be final and binding on all parties. The Company will deem
any outstanding notes so withdrawn not to have been validly tendered for
exchange for purposes of the exchange offer.
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<PAGE> 76
Any outstanding notes that have been tendered for exchange but that
are not exchanged for any reason will be returned to their holder without cost
to the holder or, in the case of outstanding notes tendered by book-entry
transfer into the exchange agent's account at DTC according to the procedures
described above, such outstanding notes will be credited to an account
maintained with DTC for the outstanding notes. This return or crediting will
take place as soon as practicable after withdrawal, rejection of tender or
termination of the exchange offer. Holders may retender properly withdrawn
outstanding notes by following one of the procedures described under
"--Procedures for Tendering" above at any time on or prior to the expiration
date.
FEES AND EXPENSES
The Company will bear the expenses of soliciting tenders. The
principal solicitation is being made by mail; however, the Company may make
additional solicitation by telegraph, telephone or in person by our officers
and regular employees and those of our affiliates.
The Company has not retained any dealer-manager in connection with the
exchange offer and will not make any payments to broker-dealers or others
soliciting acceptances of the exchange offer. The Company will, however, pay
the exchange agent reasonable and customary fees for its services and reimburse
it for its related reasonable out-of-pocket expenses. The Company 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 outstanding notes and in handling or forwarding tenders for
exchange.
The Company will pay the cash expenses to be incurred in connection
with the exchange offer. They include:
o SEC registration fees
o fees and expenses of the exchange agent and trustee
o accounting and legal fees and printing costs
o related fees and expenses
The Company will pay all transfer taxes, if any, applicable to the
exchange of outstanding notes under the exchange offer. The tendering holder,
however, will be required to pay any transfer taxes, whether imposed on the
registered holder or any other person, if:
o certificates representing outstanding notes for principal
amounts not tendered or accepted for exchange are to be
delivered to, or are to be issued in the name of, any person
other than the registered holder of outstanding notes tendered
o tendered outstanding notes are registered in the name of any
person other than the person signing the letter of transmittal
o a transfer tax is imposed for any reason other than the exchange
of outstanding notes under the exchange offer
If satisfactory evidence of payment of any transfer taxes payable by a note
holder is not submitted with the letter of transmittal, the amount of such
transfer taxes will be billed directly to that tendering holder.
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<PAGE> 77
TRANSFER TAXES
If a holder tenders its outstanding notes for exchange, it will not be
required to pay any transfer taxes. However, if a holder instructs the Company
to register new notes in the name of, or request that outstanding notes not
tendered or not accepted in the exchange offer be returned to, a person other
than that holder, in that holder's capacity as the registered tendering holder,
that holder will be required to pay any applicable transfer tax.
CONSEQUENCES OF FAILURE TO EXCHANGE
Holders who do not exchange their outstanding notes for new notes
under the exchange offer will remain subject to the existing restrictions on
transfer of the outstanding notes.
In general, such a holder may not offer or sell the outstanding notes
unless they are registered under the Securities Act, or if the offer or sale is
exempt from registration under the Securities Act and applicable state
securities laws. Except as required by the Registration Rights Agreement, the
Company does not intend to register resales of the outstanding notes under the
Securities Act. Based on interpretations of the SEC staff, holders may offer
for resale, resell or otherwise transfer new notes issued in the exchange offer
without compliance with the registration and prospectus delivery provisions of
the Securities Act, if (1) they are not the Company's "affiliate" within the
meaning of Rule 405 under the Securities Act, (2) they acquired the new notes
in the ordinary course of their business and (3) they have no arrangement or
understanding with respect to the distribution of the new notes to be acquired
in the exchange offer. If a holder tenders in the exchange offer for the
purpose of participating in a distribution of the new notes, it:
o cannot rely on the applicable interpretations of the SEC
o must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with a
secondary resale transaction
ACCOUNTING TREATMENT
No gain or loss for accounting purposes will be recognized by the
Company upon the consummation of the exchange offer. The expenses of the
exchange offer will be amortized by the Company over the term of the new notes
under generally accepted accounting principles.
OTHER
Participation in the exchange offer is voluntary, and holders of
outstanding notes should carefully consider whether to accept. Those holders
are urged to consult their financial and tax advisors in making their own
decision on what action to take.
The Company may in the future seek to acquire untendered outstanding
notes in open market or privately negotiated transactions, through subsequent
exchange offers or otherwise. The Company has no present plans to acquire any
outstanding notes that are not tendered in the exchange offer or to file a
registration statement to permit resales of any untendered outstanding notes.
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<PAGE> 78
DESCRIPTION OF THE NOTES
The new notes will be issued, and the outstanding notes were issued,
pursuant to an indenture (the "Indenture") between the Company, as issuer, and
State Street Bank and Trust Company, as trustee (the "Trustee"). The terms of
the notes include those stated in the Indenture and those made part of the
Indenture by the Trust Indenture Act of 1939, as amended (the "Trust Indenture
Act"). The definitions of certain capitalized terms used in the following
summary are set forth below under "-- Certain Definitions."
The following description is a summary of the material provisions of
the Indenture. It does not restate that agreement in its entirety. The Company
urges Holders to read the Indenture because it, and not this description,
defines the rights of Holders of these notes. The Company has filed the
Indenture as an exhibit to the registration statement which includes this
Prospectus.
If the exchange offer contemplated by this prospectus (the "Exchange
Offer") is consummated, Holders of outstanding notes who do not exchange those
notes for new notes in the Exchange Offer will vote together with Holders of
new notes for all relevant purposes under the Indenture. In that regard, the
Indenture requires that certain actions by the Holders thereunder, including
acceleration following an Event of Default, must be taken, and certain rights
must be exercised, by specified minimum percentages of the aggregate principal
amount of the outstanding securities issued under the Indenture. In determining
whether Holders of the requisite percentage in principal amount have given any
notice, consent or waiver or taken any other action permitted under the
Indenture, any outstanding notes that remain outstanding after the Exchange
Offer will be aggregated with the new notes, and the Holders of such
outstanding notes and the new notes will vote together as a single series for
all such purposes. Accordingly, all references herein to specified percentages
in aggregate principal amount of the notes outstanding shall be deemed to mean,
at any time after the Exchange Offer is consummated, such percentages in
aggregate principal amount of the outstanding notes and the new notes then
outstanding.
BRIEF DESCRIPTION OF THE NOTES
The notes:
o are unsecured obligations of the Company;
o are limited to $150,000,000 aggregate principal amount;
o are subordinated in right of payment to all existing and future
Senior Indebtedness of the Company;
o are senior in right of payment to all existing and future
Subordinated Indebtedness of the Company; and
o rank equally with all Pari Passu Indebtedness.
The new notes will be issued, and the outstanding notes were issued,
only in registered form, without coupons, in denominations of $1,000 and
integral multiples thereof. Principal of, premium, if any, on and interest on
the notes is payable, and the notes are transferable, at the office or agency
of the Company in the City of New York maintained for such purposes, which
initially will be the corporate trust office or agency of the Trustee
maintained at New York, New York. In addition, interest may be paid, at the
option of the Company, by check mailed to the registered Holders of the notes
at their respective addresses as shown on the Note Register or, upon
application to the Trustee by any Holder of an aggregate principal amount of
notes in excess of $500,000 not later than the applicable Regular Record Date,
by transfer to an account (such transfer to be made only to a Holder of an
aggregate principal amount of notes in excess of $500,000) maintained by such
Holder with a bank in New York City. No transfer will be made to any such
account unless the Trustee has received written wire instructions not less than
15 days prior to the relevant payment date. No service charge will be made for
any transfer, exchange or
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redemption of notes, but the Company or the Trustee may require payment of a
sum sufficient to cover any tax or other governmental charge that may be
payable in connection therewith. For a discussion of the circumstances in which
the interest rate on the outstanding notes may be temporarily increased, see
"Outstanding Notes Registration Rights Agreement."
Any outstanding notes that remain outstanding after the completion of
the Exchange Offer, together with the new notes issued in connection with the
Exchange Offer, will be treated as a single class of securities under the
Indenture.
MATURITY, INTEREST AND PRINCIPAL PAYMENTS
The notes will mature on February 15, 2009. Interest on the notes will
accrue at the rate of 10 3/8% per annum and will be payable semiannually on
February 15 and August 15 of each year (each an "Interest Payment Date"),
commencing August 15, 1999, to the Person in whose name the note is registered
in the Note Register at the close of business on the February 1, or August 1
next preceding such interest payment date. Interest will be computed on the
basis of a 360-day year comprised of twelve 30-day months.
REDEMPTION
Optional Redemption.
The notes will be redeemable at the option of the Company, in whole or
in part, at any time on or after February 15, 2004, at the redemption prices
(expressed as percentages of principal amount) set forth below, plus accrued
and unpaid interest, if any, to the redemption date, subject to the right of
Holders of record on the relevant record date to receive interest due on an
interest payment date that is on or prior to the redemption date, if redeemed
during the 12-month period beginning on February 15 of the years indicated
below:
<TABLE>
<CAPTION>
REDEMPTION
YEAR PRICE
- ---- ------------
<S> <C>
2004................................................................................. 105.188%
2005................................................................................. 103.458%
2006................................................................................. 101.729%
2007 and thereafter.................................................................. 100.000%
</TABLE>
Selection and Notice
In the event that less than all of the notes are to be redeemed at any
time, selection of such notes, or any portion thereof that is an integral
multiple of $1,000, for redemption will be made by the Trustee from the notes
outstanding not previously called for redemption, or otherwise purchased by the
Company, on a pro rata basis, by lot or by such method as the Trustee shall
deem fair and appropriate; provided, however, that no note with a principal
amount of $1,000 or less shall be redeemed in part. Notice of redemption shall
be mailed by first-class mail at least 30 but not more than 60 days before the
redemption date to each Holder of notes to be redeemed at its registered
address. If any note is to be redeemed in part only, the notice of redemption
that relates to such note shall state the portion of the principal amount
thereof to be redeemed. Another note in a principal amount equal to the
unredeemed portion thereof will be issued in the name of the Holder thereof
upon cancellation of the original note. On and after the redemption date,
interest will cease to accrue on the notes or portions thereof called for
redemption and accepted for payment.
Offers to Purchase
As described below:
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<PAGE> 80
(1) upon the occurrence of a Change of Control, the Company is obligated
to make an offer to purchase all of the notes then outstanding at a
purchase price equal to 101% of the principal amount thereof, together
with accrued and unpaid interest, if any, to the date of purchase and
(2) upon the occurrence of an Asset Sale, the Company may be obligated to
make offers to purchase notes with a portion of the Net Cash Proceeds
of such Asset Sale at a purchase price equal to 100% of the principal
amount thereof, together with accrued and unpaid interest, if any, to
the date of purchase.
See "-- Certain Covenants; Change of Control" and "-- Limitation on
Disposition of Proceeds of Asset Sales."
SUBORDINATION
Payments of and distributions on or with respect to the Note
Obligations are subordinated, to the extent set forth in the Indenture, in right
of payment to the prior payment in full in cash or Cash Equivalents of all
existing and future Senior Indebtedness, which includes, without limitation, all
Credit Agreement Obligations of the Company. The notes rank prior in right of
payment only to other Indebtedness of the Company which is, by its terms,
subordinated in right of payment to the notes. In addition, the Note Obligations
are effectively subordinated to all creditors of the Company's Subsidiaries,
including trade creditors. See "Risk Factors -- The right to receive payments on
the notes is junior to our senior debt; The notes are structurally subordinated
to obligations of our subsidiaries."
In the event of:
(1) any insolvency or bankruptcy case or proceeding, or any receivership,
liquidation, reorganization or other similar case or proceeding in
connection therewith, relating to the Company (or its creditors, as
such) or its properties and assets, or
(2) any liquidation, dissolution or other winding-up of the Company,
whether voluntary or involuntary, or
(3) any assignment for the benefit of creditors or other marshaling of
assets or liabilities of the Company
all Senior Indebtedness of the Company must be paid in full in cash or Cash
Equivalents before any direct or indirect payment or distribution, whether in
cash, property or securities (excluding certain permitted equity and
subordinated debt securities referred to in the Indenture as "Permitted Junior
Securities"), is made on account of the Note Obligations. In the event that,
notwithstanding the foregoing, the Trustee or the Holder of any note receives
any payment or distribution of properties or assets of the Company of any kind
or character, whether in cash, property or securities, by set-off or otherwise,
in respect of Note Obligations before all Senior Indebtedness is paid or
provided for in full in cash or Cash Equivalents, then the Trustee or the
Holders of notes receiving any such payment or distribution, other than a
payment or distribution in the form of Permitted Junior Securities, will be
required to pay or deliver such payment or distribution forthwith to the
trustee in bankruptcy, receiver, liquidating trustee, custodian, assignee,
agent or other person making payment or distribution of assets of the Company
for application to the payment of all Senior Indebtedness remaining unpaid, to
the extent necessary to pay all Senior Indebtedness in full.
During the continuance of any default in the payment when due, whether
at Stated Maturity, upon scheduled repayment, upon acceleration or otherwise,
of principal of or premium, if any, or interest on, or of unreimbursed amounts
under drawn letters of credit or fees relating to letters of credit
constituting, any Designated Senior Indebtedness (a "Payment Default"), no
direct or indirect payment or distribution by or on behalf of the Company of
any kind or character shall be made on account of the Note Obligations or any
obligation under any Subsidiary Guarantee unless and until such default has
been cured or waived or has ceased to exist or such Designated Senior
Indebtedness shall have been discharged or paid in full in cash or Cash
Equivalents.
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In addition, during the continuance of any default other than a
Payment Default with respect to any Designated Senior Indebtedness pursuant to
which the maturity thereof may then be accelerated (a "Non-payment Default"),
after receipt by the Trustee from the holders, or their representative, of such
Designated Senior Indebtedness of a written notice of such Non-payment Default,
no payment or distribution of any kind or character may be made by the Company
on account of the Note Obligations for the period specified below (the "Payment
Blockage Period").
The Payment Blockage Period shall commence upon the receipt of notice
of a Non-payment Default by the Trustee from the holders (or their
representative) of Designated Senior Indebtedness stating that such notice is a
payment blockage notice pursuant to the Indenture and shall end on the earliest
to occur of the following events:
(1) 179 days shall have elapsed since the receipt by the Trustee of such
notice;
(2) the date, as set forth in a written notice to the Company or the
Trustee from the holders, or their representative, of the Designated
Senior Indebtedness initiating such Payment Blockage Period, on which
such default is cured or waived or ceases to exist (provided, that no
other Payment Default or Non-payment Default has occurred or is then
continuing after giving effect to such cure or waiver);
(3) the date on which such Designated Senior Indebtedness is discharged or
paid in full in cash or Cash Equivalents; and
(4) the date, as set forth in a written notice to the Company or the
Trustee from the holders, or their representative, of the Designated
Senior Indebtedness initiating such Payment Blockage Period, on which
such Payment Blockage Period shall have been terminated by written
notice to the Company or the Trustee from the holders, or their
representative, of Designated Senior Indebtedness initiating such
Payment Blockage Period, after which the Company, subject to the
subordination provisions set forth above and the existence of another
Payment Default, shall promptly resume making any and all required
payments in respect of the notes, including any missed payments.
Only one Payment Blockage Period with respect to the notes may be
commenced within any 360 consecutive day period. No Non-payment Default with
respect to Designated Senior Indebtedness that existed or was continuing on the
date of the commencement of any Payment Blockage Period with respect to the
Designated Senior Indebtedness initiating such Payment Blockage Period will be,
or can be, made the basis for the commencement of a second Payment Blockage
Period, whether or not within a period of 360 consecutive days, unless such
default has been cured or waived for a period of not less than 90 consecutive
days (it being acknowledged that any subsequent action, or any breach of any
financial covenant for a period commencing after the date of commencement of
such Payment Blockage Period, that, in either case, would give rise to a
Non-payment Default pursuant to any provision under which a Non-payment Default
previously existed or was continuing shall constitute a new Non-payment Default
for this purpose; provided, however, that, in the case of a breach of a
particular financial covenant, the Company shall have been in compliance for at
least one full 90 consecutive day period commencing after the date of
commencement of such Payment Blockage Period). In no event will a Payment
Blockage Period extend beyond 179 days from the date of the receipt by the
Trustee of the notice, and there must be a 181 consecutive day period in any
360-day period during which no Payment Blockage Period is in effect. In the
event that, notwithstanding the foregoing, the Company makes any payment or
distribution to the Trustee or the Holder of any note prohibited by the
subordination provision of the Indenture, then such payment or distribution
will be required to be paid over and delivered forthwith to the holders, or
their representative, of Designated Senior Indebtedness.
If the Company fails to make any payment on the notes when due or
within any applicable grace period, whether or not on account of the payment
blockage provisions referred to above, such failure will constitute an Event of
Default under the Indenture and will enable the Holders of the notes to
accelerate the maturity thereof. See "-- Events of Default."
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<PAGE> 82
By reason of such subordination, in the event of liquidation,
receivership, reorganization or insolvency, creditors of the Company who are
holders of Senior Indebtedness may recover more, ratably, than the Holders of
the notes, and funds which would be otherwise payable to the Holders of the
notes will be paid to the holders of the Senior Indebtedness to the extent
necessary to pay the Senior Indebtedness in full, and the Company may be unable
to meet its obligations in full with respect to the notes.
As of September 30, 1998, after giving effect pro forma to the sale of
the outstanding notes and the application of the net proceeds therefrom as if
that sale had occurred on that date, the aggregate amount of outstanding Senior
Indebtedness would have been approximately $23,179,000. See "Use of Proceeds,"
"Capitalization" and "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."
Although the Indenture contains limitations on the amount of additional
Indebtedness that the Company and the Restricted Subsidiaries may incur, the
amounts of such Indebtedness could be substantial and, in any case, such
Indebtedness may be Senior Indebtedness or Indebtedness of Subsidiaries to
which the notes are subordinated. The Indenture prohibits the incurrence by the
Company of Indebtedness that is contractually subordinated in right of payment
to any Senior Indebtedness of the Company and senior in right of payment to the
notes. Currently, the aggregate amount of outstanding Indebtedness of the
Company that is:
(1) contractually subordinated in right of payment to the notes is
$115,000,000 and
(2) pari passu in right of payment with the notes is $100,000,000.
POSSIBLE SUBSIDIARY GUARANTEES OF THE NOTES
If the Company's existing or future Restricted Subsidiaries guarantee
any other Indebtedness of the Company, they will be required by the terms of
the Indenture to jointly and severally guarantee the notes on a senior
subordinated basis. See "-- Certain Covenants; Limitations on Non-Guarantor
Restricted Subsidiaries." At the date hereof, no Subsidiary of the Company has
an outstanding guarantee of any Indebtedness of the Company, and the Company
does not intend to cause any Subsidiary to guarantee any such Indebtedness in
the future, thus requiring it to issue a Subsidiary Guarantee.
Any Subsidiary that issues a Subsidiary Guarantee is herein called a
Subsidiary Guarantor. Each Subsidiary Guarantor will guarantee, jointly and
severally, to each Holder of Notes and the Trustee, the full and prompt
performance of the Company's obligations under the Indenture and the notes,
including the payment of principal of (or premium, if any, on) and interest on
the notes pursuant to its Subsidiary Guarantee. The Subsidiary Guarantees will
be subordinated to Guarantor Senior Indebtedness of the Subsidiary Guarantors
to the same extent and in the same manner as the notes are subordinated to
Senior Indebtedness.
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, including, but not limited to, Guarantor Senior Indebtedness, of
such Subsidiary Guarantor and after giving effect to any collections from or
payments made by or on behalf of any other Subsidiary Guarantor in respect of
the obligations of such 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 the 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 a 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 (as defined in the Indenture) of each Subsidiary Guarantor.
Each Subsidiary Guarantor may consolidate with or merge into or sell,
assign, convey, transfer, lease or otherwise dispose of its properties and
assets substantially as an entirety (or any portion thereof) to the Company or
another Subsidiary Guarantor without limitation, except to the extent any such
transaction is subject to the covenants described below under the caption "--
Merger, Consolidation and Sale of Assets." Each Subsidiary Guarantor may
consolidate with or merge into or sell, assign, convey, transfer, lease or
otherwise dispose of its properties and assets
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substantially as an entirety in one transaction or series of related
transactions to a Person other than the Company or another Subsidiary
Guarantor, whether or not affiliated with the Subsidiary Guarantor; provided,
that:
(1) in the case of a merger or consolidation, if the surviving Person is
not the Subsidiary Guarantor, such surviving Person or, in the case of
a sale, assignment, conveyance, transfer, lease or other disposition,
the transferee Person agrees to assume such Subsidiary Guarantor's
Subsidiary Guarantee and all its obligations pursuant to the
Indenture, except to the extent that the following paragraph would
result in the release of such Subsidiary Guarantee and
(2) such transaction does not:
(a) violate any of the covenants described below under the caption
"-- Certain Covenants" or in the Indenture or
(b) result in a Default or Event of Default immediately thereafter.
The Subsidiary Guarantee of any Restricted Subsidiary may be released
upon the terms and subject to the conditions described under paragraph (2) of
the caption "-- Certain Covenants -- Limitation on Non-Guarantor Restricted
Subsidiaries." Each Subsidiary Guarantor that is designated as an Unrestricted
Subsidiary in accordance with the Indenture shall be released from its
Subsidiary Guarantee and related obligations set forth in the Indenture for so
long as it remains an Unrestricted Subsidiary.
CERTAIN COVENANTS
The Indenture contains, among others, the covenants described below:
Limitation on Indebtedness.
Neither the Company nor any Restricted Subsidiary will create, incur,
issue, assume, guarantee or in any manner become directly or indirectly liable
for the payment of (collectively "incur") any Indebtedness, including any
Acquired Indebtedness, other than Permitted Indebtedness and Permitted
Subsidiary Indebtedness, as the case may be; provided, however, that the
Company and its Restricted Subsidiaries that are Subsidiary Guarantors may
incur additional Indebtedness if:
(1) the Company's Consolidated Fixed Charge Coverage Ratio for the four
full fiscal quarters immediately preceding the incurrence of such
Indebtedness (and for which financial statements are available), taken
as one period (at the time of such incurrence, after giving pro forma
effect to: (a) the incurrence of such Indebtedness and, if applicable,
the application of the net proceeds therefrom as if such Indebtedness
had been incurred and the application of such proceeds had occurred at
the beginning of such four-quarter period; (b) the incurrence,
repayment or retirement of any other Indebtedness, including Permitted
Indebtedness and Permitted Subsidiary Indebtedness, by the Company or
its Restricted Subsidiaries since the first day of such four-quarter
period (including any other Indebtedness to be incurred concurrent
with the incurrence of such Indebtedness) as if such Indebtedness had
been incurred, repaid or retired at the beginning of such four-quarter
period; and (c) notwithstanding clause (4) of the definition of
Consolidated Net Income, the acquisition (whether by purchase, merger
or otherwise) or disposition (whether by sale, merger or otherwise) of
any Person acquired or disposed of by the Company or its Restricted
Subsidiaries, as the case may be, since the first day of such
four-quarter period, as if such acquisition or disposition had
occurred at the beginning of such four-quarter period), would have
been equal to at least 2.5 to 1.0 and
(2) no Default or Event of Default would occur or be continuing.
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Limitation on Restricted Payments.
(1) The Company will not, and will not permit any Restricted
Subsidiary to, directly or indirectly, take any of the following actions
(unless such action constitutes a Permitted Investment):
(a) declare or pay any dividend on, or make any distribution to
holders of, any shares of the Company's Capital Stock (other than
dividends or distributions payable solely in shares of Qualified
Capital Stock of the Company, options, warrants or other rights to
purchase Qualified Capital Stock of the Company);
(b) purchase, redeem or otherwise acquire or retire for value any
Capital Stock of the Company or any Affiliate thereof (other than any
Wholly Owned Restricted Subsidiary of the Company) or any options,
warrants or other rights to acquire such Capital Stock; provided,
however, that the Company may make any payment of the applicable
redemption price in connection with a Qualified Redemption
Transaction;
(c) make any principal payment on or repurchase, redeem, defease
or otherwise acquire or retire for value, prior to any scheduled
principal payment, scheduled sinking fund payment or maturity, any
Pari Passu Indebtedness or Subordinated Indebtedness, except in any
case out of a Pari Passu Offer or a Net Proceeds Deficiency (each as
defined in "-- Limitation on Disposition of Proceeds of Asset Sales")
pursuant to the provisions of the Indenture described under the
caption "-- Limitation on Disposition of Proceeds of Asset Sales" and
except upon a Change of Control or similar event required by the
indenture or other agreement or instrument pursuant to which such Pari
Passu Indebtedness or Subordinated Indebtedness was issued, provided
the Company is then obligated to make a Change of Control Offer in
compliance with the covenant described below under "-- Change of
Control;" provided, however, that the Company may make any payment of
the applicable redemption price in connection with a Qualified
Redemption Transaction;
(d) declare or pay any dividend on, or make any distribution to
the holders of, any shares of Capital Stock of any Restricted
Subsidiary of the Company (other than to the Company or any of its
Wholly Owned Restricted Subsidiaries) or purchase, redeem or otherwise
acquire or retire for value any Capital Stock of any Restricted
Subsidiary (other than a Wholly Owned Restricted Subsidiary) or any
options, warrants or other rights to acquire any such Capital Stock
(other than with respect to any such Capital Stock held by the Company
or any Wholly Owned Restricted Subsidiary of the Company);
(e) make any Investment; or
(f) in connection with the acquisition of any property or asset by
the Company or its Restricted Subsidiaries after the date of the
Indenture, which property or asset would secure or be subject to any
Production Payment obligations of the Company or its Restricted
Subsidiaries, make any investment (of cash, property or other assets)
in such property or asset so acquired in addition to the amount of
Indebtedness, including Production Payment obligations, incurred by
the Company or its Restricted Subsidiaries in connection with such
acquisition;
(such payments or other actions described in, but not excluded from, clauses
(a) through (f) are collectively referred to as "Restricted Payments"), unless
at the time of and after giving effect to the proposed Restricted Payment (with
the amount of any such Restricted Payment, if other than cash, being the amount
determined by the Board of Directors, whose determination shall be conclusive
and evidenced by a resolution), (i) no Default or Event of Default shall have
occurred and be continuing, (ii) the Company could incur $1.00 of additional
Indebtedness (other than Permitted Indebtedness) in accordance with the
covenant described above under the caption "-- Limitation on Indebtedness" and
(iii) the aggregate amount of all Restricted Payments declared or made after
the date of the Indenture shall not exceed the sum (without duplication) of the
following:
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(A) 50% of the aggregate Consolidated Net Income of the Company
accrued on a cumulative basis during the period beginning on the first
day of the first month after the date of the Indenture and ending on
the last day of the Company's last fiscal quarter ending prior to the
date of such proposed Restricted Payment (or, if such aggregate
cumulative Consolidated Net Income shall be a loss, minus 100% of such
loss), plus
(B) the aggregate net cash proceeds received after the date of the
Indenture by the Company as capital contributions to the Company
(other than from any Restricted Subsidiary), plus
(C) the aggregate net cash proceeds received after the date of the
Indenture by the Company from the issuance or sale (other than to any
of its Restricted Subsidiaries) of shares of Qualified Capital Stock
of the Company or any options, warrants or rights to purchase such
shares of Qualified Capital Stock of the Company, plus
(D) the aggregate net cash proceeds received after the date of the
Indenture by the Company (other than from any of its Restricted
Subsidiaries) upon the exercise of any options, warrants or rights to
purchase shares of Qualified Capital Stock of the Company, plus
(E) the aggregate net cash proceeds received after the date of the
Indenture by the Company from the issuance or sale (other than to any
of its Restricted Subsidiaries) of debt securities or shares of
Redeemable Capital Stock that have been converted into or exchanged
for Qualified Capital Stock of the Company to the extent such debt
securities were originally sold for cash, together with the aggregate
cash received by the Company at the time of such conversion or
exchange, plus
(F) to the extent not otherwise included in the Company's
Consolidated Net Income, the net reduction in Investments in
Affiliates and Unrestricted Subsidiaries resulting from the payments
of interest on Indebtedness, dividends, repayments of loans or
advances, or other transfers of assets, in each case to the Company or
a Restricted Subsidiary after the date of the Indenture from any
Affiliate or Unrestricted Subsidiary or from the redesignation of an
Unrestricted Subsidiary as a Restricted Subsidiary (valued in each
case as provided in the definition of "Investment"), not to exceed in
the case of any Affiliate or Unrestricted Subsidiary the total amount
of Investments (other than Permitted Investments) in such Affiliate or
Unrestricted Subsidiary made by the Company and its Restricted
Subsidiaries in such Affiliate or Unrestricted Subsidiary after the
date of the Indenture, plus
(G) $15,000,000.
(2) Notwithstanding paragraph (1) above, the Company and its
Restricted Subsidiaries may take the following actions so long as (in the case
of clauses (b), (c) and (d) below) no Default or Event of Default shall have
occurred and be continuing:
(a) the payment of any dividend within 60 days after the date of
declaration thereof, if at such declaration date such declaration
complied with the provisions of paragraph (1) above (and such payment
shall be deemed to have been paid on such date of declaration for
purposes of any calculation required by the provisions of paragraph
(1) above);
(b) the repurchase, redemption or other acquisition or retirement
of any shares of any class of Capital Stock of the Company or any
Restricted Subsidiary, in exchange for, or out of the aggregate net
cash proceeds of, a substantially concurrent issue and sale (other
than to a Restricted Subsidiary) of shares of Qualified Capital Stock
of the Company;
(c) the purchase, redemption, repayment, defeasance or other
acquisition or retirement for value of any Subordinated Indebtedness
(other than Redeemable Capital Stock) in exchange for or out of
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the aggregate net cash proceeds of a substantially concurrent issue
and sale (other than to a Restricted Subsidiary) of shares of
Qualified Capital Stock of the Company;
(d) the purchase, redemption, repayment, defeasance or other
acquisition or retirement for value of Subordinated Indebtedness
(other than Redeemable Capital Stock) 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
of the Company so long as (i) 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 Subordinated Indebtedness being so purchased,
redeemed, repaid, defeased, acquired or retired, plus the amount of
any premium required to be paid in connection with such refinancing
pursuant to the terms of the Subordinated Indebtedness refinanced or
the amount of any premium reasonably determined by the Company as
necessary to accomplish such refinancing, plus the amount of fees and
expenses of the Company incurred in connection with such refinancing,
(ii) such new Subordinated Indebtedness is subordinated to the notes
at least to the same extent as such Subordinated Indebtedness so
purchased, redeemed, repaid, defeased, acquired or retired, (iii) such
new Subordinated Indebtedness has an Average Life to Stated Maturity
that is longer than the Average Life to Stated Maturity of the notes
and such new Subordinated 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
notes; and
(e) repurchases, acquisitions or retirements of shares of
Qualified Capital Stock of the Company deemed to occur upon the
exercise of stock options or similar rights issued under employee
benefit plans of the Company if such shares represent all or a portion
of the exercise price or are surrendered in connection with satisfying
any Federal income tax obligation.
The actions described in clauses (a), (b) and (c) of this paragraph (2)
shall be Restricted Payments that shall be permitted to be taken in accordance
with this paragraph (2) but shall reduce the amount that would otherwise be
available for Restricted Payments under clause (c) of paragraph (1) (provided,
that any dividend paid pursuant to clause (a) of this paragraph (2) shall reduce
the amount that would otherwise be available under clause (c) of paragraph (1)
when declared, but not also when subsequently paid pursuant to such clause (a)),
and the actions described in clauses (d) and (e) of this paragraph (2) shall be
Restricted Payments that shall be permitted to be taken in accordance with this
paragraph and shall not reduce the amount that would otherwise be available for
Restricted Payments under clause (c) of paragraph (1).
(3) In computing Consolidated Net Income of the Company under
paragraph (1) above:
(a) the Company shall use audited financial statements for the
portions of the relevant period for which audited financial statements
are available on the date of determination and unaudited financial
statements and other current financial data based on the books and
records of the Company for the remaining portion of such period and
(b) the Company shall be permitted to rely in good faith on the
financial statements and other financial data derived from the books
and records of the Company that are available on the date of
determination.
If the Company makes a Restricted Payment which, at the time of the making of
such Restricted Payment, would in the good faith determination of the Company
be permitted under the requirements of the Indenture, such Restricted Payment
shall be deemed to have been made in compliance with the Indenture
notwithstanding any subsequent adjustments made in good faith to the Company's
financial statements affecting Consolidated Net Income of the Company for any
period.
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Limitation on Issuances and Sales of Restricted Subsidiary Capital Stock.
The Company:
(1) will not permit any Restricted Subsidiary to issue any Preferred Stock
(other than to the Company or a Wholly Owned Restricted Subsidiary)
and
(2) will not permit any Person (other than the Company and/or one or more
Wholly Owned Restricted Subsidiaries) to own any Capital Stock of any
Restricted Subsidiary;
provided, however, that this covenant shall not prohibit:
(1) the issuance and sale of all, but not less than all, of the issued and
outstanding Capital Stock of any Restricted Subsidiary owned by the
Company or any of its Restricted Subsidiaries in compliance with the
other provisions of the Indenture,
(2) the ownership by directors of directors' qualifying shares,
(3) the ownership by any Person of Capital Stock of a Restricted
Subsidiary that was owned by a Person at the time such Restricted
Subsidiary became a Restricted Subsidiary or acquired by a Person in
connection with the formation of the Restricted Subsidiary (including,
in each case, any Capital Stock issued as a result of a stock split, a
dividend of shares of Capital Stock to holders of such Capital Stock,
a recapitalization affecting such Capital Stock or similar event) and
(4) the ownership by any Person of Capital Stock of any Foreign Subsidiary
so long as none of the Capital Stock of that Subsidiary has been
issued in a public offering.
Limitation on Transactions with Affiliates.
The Company will not, and will not permit any Restricted Subsidiary
to, directly or indirectly, enter into any transaction or series of related
transactions (including, without limitation, the sale, purchase, exchange or
lease of assets, property or the rendering of any services) with, or for the
benefit of, any Affiliate of the Company other than a Restricted Subsidiary
(each, other than a Restricted Subsidiary, being an "Interested Person"),
unless:
(1) such transaction or series of transactions is on terms that are no
less favorable to the Company or such Restricted Subsidiary, as the
case may be, than those that would be available in a comparable arm's
length transaction with unrelated third parties who are not Interested
Persons, or, in the event no comparable transaction with an unrelated
third party who is not an Interested Person is available, on terms
that are fair from a financial point of view to the Company or such
Restricted Subsidiary, as the case may be,
(2) with respect to any one transaction or series of related transactions
involving aggregate payments in excess of $10,000,000, the Company
delivers an Officers' Certificate to the Trustee certifying that such
transaction or series of transactions complies with clause (1) above
and such transaction or series of transactions has been approved by
the Board of Directors and
(3) with respect to any one transaction or series of related transactions
involving aggregate payments in excess of $20,000,000, the Officers'
Certificate referred to in clause (2) above also includes a
certification that such transaction or series of transactions has been
approved by a majority of the Disinterested Directors (either of the
full Board of Directors or, in the case of action by a committee
thereof, of such committee) or, in the event there are no such
Disinterested Directors, that the Company has obtained a written
opinion from an independent nationally recognized investment banking
firm or appraisal firm, in either case specializing or having a
specialty in the type and subject matter of the transaction or series
of related transactions at issue, which opinion shall be to the effect
set forth in clause (1) above;
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provided, however, that this covenant will not restrict the Company from:
(1) paying reasonable and customary regular compensation and fees to
directors of the Company who are not employees of the Company or any
Restricted Subsidiary,
(2) paying dividends on, or making distributions with respect to, shares
of Capital Stock of the Company on a pro rata basis to the extent
permitted by the covenant described above under the caption "--
Limitation on Restricted Payments,"
(3) making Restricted Payments that are permitted by the provisions of the
Indenture described above under the caption "-- Limitation on
Restricted Payments,"
(4) making loans or advances to officers, directors and employees of the
Company or any Restricted Subsidiary in the ordinary course of
business and consistent with customary practices in the Oil and Gas
Business in an aggregate amount not to exceed $1,000,000 outstanding
at any one time,
(5) making any indemnification or similar payment to any director or
officer (a) in accordance with the corporate charter or bylaws of the
Company or any Restricted Subsidiary, (b) under any agreement or (c)
under applicable law and
(6) fulfilling obligations of the Company or any Restricted Subsidiary
under employee compensation and other benefit arrangements entered
into or provided for in the ordinary course of business.
Limitation on Liens.
The Company will not, and will not permit any Restricted Subsidiary
to, directly or indirectly, create, incur, assume, affirm or suffer to exist or
become effective any Lien of any kind, except for Permitted Liens, on or with
respect to any of its property or assets (including any intercompany notes),
whether owned at the date of the Indenture or thereafter acquired, or any
income, profits or proceeds therefrom, or assign or otherwise convey any right
to receive income thereon, unless:
(1) in the case of any Lien securing Subordinated Indebtedness, the notes
are secured by a Lien on such property, assets or proceeds that is
senior in priority to such Lien and
(2) in the case of any other Lien, the notes are directly secured equally
and ratably with the obligation or liability secured by such Lien.
The incurrence of additional secured Indebtedness by the Company or any
Restricted Subsidiary is subject to further limitations on the incurrence of
Indebtedness as described above under the caption "-- Limitation on
Indebtedness."
Change of Control.
Upon the occurrence of a Change of Control, the Company shall be
obligated to make an offer to purchase all of the notes then outstanding (a
"Change of Control Offer"), and shall purchase, on a business day (the "Change
of Control Purchase Date") not more than 75 nor less than 30 days following the
Change of Control, all of the notes then outstanding that are validly tendered
pursuant to such Change of Control Offer at a purchase price (the "Change of
Control Purchase Price") equal to 101% of the principal amount thereof, plus
accrued and unpaid interest, if any, to the Change of Control Purchase Date.
The Change of Control Offer is required to remain open for at least 20 Business
Days and until the close of business on the Change of Control Purchase Date.
In order to effect such Change of Control Offer, the Company shall,
not later than the 30th day after the Change of Control, mail to each Holder of
a note a notice of the Change of Control Offer, which notice shall govern
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the terms of the Change of Control Offer and shall state, among other things,
the procedures that Holders of the notes must follow to accept the Change of
Control Offer.
If a Change of Control Offer is made, there can be no assurance that
the Company will have available funds sufficient to pay the Change of Control
Purchase Price for all of the notes delivered by Holders of the notes seeking
to accept the Change of Control Offer. If on a Change of Control Purchase Date
the Company does not have available funds sufficient to pay the Change of
Control Purchase Price or is prohibited from purchasing the notes, an Event of
Default will occur under the Indenture.
Moreover, the definition of Change of Control includes a phrase
relating to the sale or other disposition of the Company's properties and
assets "substantially as an entirety." Although there is a developing body of
case law interpreting phrases such as "substantially as an entirety," there is
no precise established definition of such phrases under applicable law.
Accordingly, the ability of a Holder of the notes to require the Company to
repurchase such notes as a result of a sale or other disposition of less than
all of the properties and assets of the Company on a consolidated basis to
another Person or related group of Persons may be uncertain.
The Company will not be required to make a Change of Control Offer
upon a Change of Control if a third party makes the Change of Control Offer at
the same purchase price, at the same times and otherwise in substantial
compliance with the requirements applicable to a Change of Control Offer made
by the Company and purchases all notes validly tendered and not withdrawn under
such Change of Control Offer.
The Company intends to comply with Rule 14e-1 under the Exchange Act
and any other securities laws and regulations thereunder, if applicable, in the
event that a Change of Control occurs and the Company is required to purchase
notes as described above. The existence of a Holder's right to require, subject
to certain conditions, the Company to repurchase its notes upon a Change of
Control may deter a third party from acquiring the Company in a transaction
that constitutes, or results in, a Change of Control.
Limitation on Disposition of Proceeds of Asset Sales.
(1) The Company will not, and will not permit any Restricted
Subsidiary to, engage in any Asset Sale unless (a) the Company or such
Restricted Subsidiary, as the case may be, receives consideration at the time
of such Asset Sale at least equal to the fair market value of the assets and
properties sold or otherwise disposed of pursuant to the Asset Sale (as
determined by the Board of Directors, whose determination shall be conclusive
and evidenced by a resolution) and (b) at least 75% of the consideration
received by the Company or the Restricted Subsidiary, as the case may be, in
respect of such Asset Sale consists of cash, Cash Equivalents and/or the
assumption by the purchaser of liabilities of the Company (other than
liabilities of the Company that are by their terms subordinated to the notes)
or any Restricted Subsidiary as a result of which the Company and its remaining
Restricted Subsidiaries are no longer liable.
(2) If the Company or any Restricted Subsidiary engages in an Asset
Sale, the Company may either: (a) apply the Net Cash Proceeds thereof to reduce
Senior Indebtedness, to reduce Guarantor Senior Indebtedness or to reduce
Indebtedness of any Restricted Subsidiary incurred pursuant to clause (13) of
the definition of Permitted Subsidiary Indebtedness, provided, if any such
Senior Indebtedness, Guarantor Senior Indebtedness or Permitted Subsidiary
Indebtedness has been incurred under any revolving credit facility, that the
related commitment to lend or the amount available to be reborrowed under such
facility is also reduced, or (b) invest all or any part of the Net Cash
Proceeds thereof, within 365 days after such Asset Sale, in properties and
assets which replace the properties and assets that were the subject of the
Asset Sale or in properties and assets that will be used in the business of the
Company or its Restricted Subsidiaries, as the case may be ("Replacement
Assets"). The amount of such Net Cash Proceeds not applied or invested as
provided in this paragraph constitutes "Excess Proceeds."
(3) When the aggregate amount of Excess Proceeds equals or exceeds
$15,000,000, the Company shall make an offer to purchase, from all Holders of
the notes and any then outstanding Pari Passu Indebtedness
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required to be repurchased or repaid on a permanent basis in connection with an
Asset Sale, an aggregate principal amount of notes and any then outstanding
Pari Passu Indebtedness equal to such Excess Proceeds as follows:
(a) (i) the Company shall make an offer to purchase (a "Net
Proceeds Offer") from all Holders of the notes in accordance with the
procedures set forth in the Indenture the maximum principal amount
(expressed as a multiple of $1,000) of notes that may be purchased out
of an amount (the "Payment Amount") equal to the product of such
Excess Proceeds, multiplied by a fraction, the numerator of which is
the outstanding principal amount of the notes and the denominator of
which is the sum of the outstanding principal amount of the notes and
such Pari Passu Indebtedness, if any (subject to proration in the
event such amount is less than the aggregate Offered Price (as defined
below) of all notes tendered), and (ii) to the extent required by such
Pari Passu Indebtedness and provided there is a permanent reduction in
the principal amount of such Pari Passu Indebtedness, the Company
shall make an offer to purchase Pari Passu Indebtedness (a "Pari Passu
Offer") in an amount (the "Pari Passu Indebtedness Amount") equal to
the excess of the Excess Proceeds over the Payment Amount.
(b) The offer price for the notes shall be payable in cash in an
amount equal to 100% of the principal amount of the notes tendered
pursuant to a Net Proceeds Offer, plus accrued and unpaid interest, if
any, to the date such Net Proceeds Offer is consummated (the "Offered
Price"), in accordance with the procedures set forth in the Indenture.
To the extent that the aggregate Offered Price of the notes tendered
pursuant to a Net Proceeds Offer is less than the Payment Amount
relating thereto or the aggregate amount of the Pari Passu
Indebtedness that is purchased or repaid pursuant to the Pari Passu
Offer is less than the Pari Passu Indebtedness Amount (such shortfall
constituting a "Net Proceeds Deficiency"), the Company may use such
Net Proceeds Deficiency for general corporate purposes, subject to the
limitations described above under the caption "-- Limitation on
Restricted Payments."
(c) If the aggregate Offered Price of notes validly tendered and
not withdrawn by Holders thereof exceeds the Payment Amount, notes to
be purchased will be selected on a pro rata basis. Upon completion of
such Net Proceeds Offer and Pari Passu Offer, the amount of Excess
Proceeds shall be reset to zero.
The Company intends to comply with Rule 14e-1 under the Exchange Act, and any
other securities laws and regulations thereunder, if applicable, in the event
that an Asset Sale occurs and the Company is required to purchase notes as
described above.
The Credit Agreement may prohibit the Company from purchasing any
notes from Excess Proceeds. Any future credit agreements or other agreements
relating to Senior Indebtedness to which the Company becomes a party may
contain similar restrictions. In the event a Net Proceeds Offer occurs at a
time when the Company is prohibited by the terms of any Senior Indebtedness
from purchasing the notes, the Company could seek the consent of the holders of
such Senior Indebtedness to the purchase or could attempt to refinance such
Senior Indebtedness. If the Company does not obtain such a consent or repay
such Senior Indebtedness, the Company may remain prohibited from purchasing the
notes. In such case, the Company's failure to purchase tendered notes would
constitute an Event of Default under the Indenture which would, in turn,
constitute a default under the Credit Agreement and possibly a default under
other agreements relating to Senior Indebtedness. In such circumstances, the
subordination provisions in the Indenture would likely restrict payments to the
Holders of the notes.
Limitation on Non-Guarantor Restricted Subsidiaries.
(1) The Company will not permit any Restricted Subsidiary that is not
a Subsidiary Guarantor to guarantee the payment of any Indebtedness of the
Company unless (a)(i) such Restricted Subsidiary simultaneously executes and
delivers a supplemental indenture to the Indenture providing for a Subsidiary
Guarantee of the notes by such Restricted Subsidiary which Subsidiary Guarantee
will be subordinated to Guarantor Senior Indebtedness (but no other
Indebtedness) to the same extent that the notes are subordinated to Senior
Indebtedness and (ii), with respect to any guarantee of Subordinated
Indebtedness by a Restricted Subsidiary, any such guarantee shall be
subordinated
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to such Restricted Subsidiary's Subsidiary Guarantee at least to the same
extent as such Subordinated Indebtedness is subordinated to the notes; (b) such
Restricted Subsidiary waives, and agrees not in any manner whatsoever to claim
or take the benefit or advantage of, any rights of reimbursement, indemnity or
subrogation or any other rights against the Company or any other Restricted
Subsidiary as a result of any payment by such Restricted Subsidiary under its
Subsidiary Guarantee until such time as the obligations guaranteed thereby are
paid in full; and (c) such Restricted Subsidiary shall deliver to the Trustee
an Opinion of Counsel to the effect that such Subsidiary Guarantee has been
duly executed and authorized and constitutes a valid, binding and enforceable
obligation of such Restricted Subsidiary, except insofar as enforcement thereof
(i) may be limited by bankruptcy, insolvency or similar laws (including,
without limitation, all laws relating to fraudulent transfers and fraudulent
conveyances), (ii) is subject to general principles of equity and (iii) any
implied covenant of good faith or fair dealing.
(2) Notwithstanding the foregoing and the other provisions of the
Indenture, each Subsidiary Guarantee shall provide by its terms that it shall
be automatically and unconditionally released and discharged upon (a) (i) any
sale, exchange or transfer of all the Capital Stock in the applicable
Subsidiary Guarantor owned by the Company and any Restricted Subsidiary or (ii)
any sale, assignment, conveyance, transfer, lease or other disposition of the
properties and assets of such Subsidiary Guarantor substantially as an
entirety, in each case, in a single transaction or series of related
transactions to any Person that is not a Restricted Subsidiary (provided, that
such transaction or series of transactions is not prohibited by the Indenture),
(b) the merger or consolidation of such Subsidiary Guarantor with or into the
Company or a Restricted Subsidiary (provided, that, in the case of a merger
into or consolidation with a Restricted Subsidiary that is not then a
Subsidiary Guarantor, the surviving Restricted Subsidiary assumes the
Subsidiary Guarantee and that transaction or series of transactions is not
prohibited by the Indenture) or (c) the release or discharge of all guarantees
by such Subsidiary Guarantor of Indebtedness other than the Note Obligations,
except a discharge or release by or as a result of the payment of such
Indebtedness by such Subsidiary Guarantor pursuant to its Subsidiary Guarantee.
Limitation on Dividends and Other Payment Restrictions Affecting Restricted
Subsidiaries.
The Company will not, and will 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:
(1) pay dividends, in cash or otherwise, or make any other distributions
on or in respect of its Capital Stock to the Company or any Restricted
Subsidiary,
(2) pay any Indebtedness owed to the Company or any Restricted Subsidiary,
(3) make an Investment in the Company or any Restricted Subsidiary or
(4) transfer any of its properties or assets to the Company or any
Restricted Subsidiary;
except for such encumbrances or restrictions:
(a) pursuant to any agreement in effect or entered into on the date of the
Indenture,
(b) pursuant to any agreement or other instrument of a Person acquired by
the Company or any Restricted Subsidiary in existence at the time of
such acquisition (but not created in contemplation thereof), 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,
(c) by reason of customary non-assignment provisions in leases and
licenses entered into in the ordinary course of business,
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(d) pursuant to capital leases and purchase money obligations for property
leased or acquired in the ordinary course of business that impose
restrictions of the nature described in clause (4) above on the
property so leased or acquired,
(e) pursuant to any merger agreements, stock purchase agreements, asset
sale agreements and similar agreements limiting the transfer of
properties and assets pending consummation of the subject transaction,
(f) pursuant to Permitted Liens which are customary limitations on the
transfer of collateral,
(g) pursuant to applicable law,
(h) pursuant to agreements among holders of Capital Stock of any
Restricted Subsidiary of the Company requiring distributions in
respect of such Capital Stock to be made pro rata based on the
percentage of ownership in and/or contribution to such Restricted
Subsidiary or
(i) existing under any agreement that extends, renews, refinances or
replaces the agreements containing the restrictions in the preceding
clauses (a) and (b), provided, that the terms and conditions of any
such restrictions are not materially less favorable to the Holders of
the notes than those under or pursuant to the agreement evidencing the
Indebtedness so extended, renewed, refinanced or replaced.
Limitation on Other Senior Subordinated Indebtedness.
The Company will not incur, directly or indirectly, any Indebtedness
which is expressly subordinate or junior in right of payment in any respect to
Senior Indebtedness unless such Indebtedness ranks pari passu in right of
payment with the notes, or is expressly subordinated in right of payment to the
notes.
Reports.
The Company (and the Subsidiary Guarantors, if applicable) must file
on a timely basis with the SEC, to the extent such filings are accepted by the
SEC and whether or not the Company has a class of securities registered under
the Exchange Act, the annual reports, quarterly reports and other documents
that the Company would be required to file if it were subject to Section 13 or
15(d) of the Exchange Act. The Company is (and any future Subsidiary Guarantors
will be) also required:
(1) to file with the Trustee, and provide to each Holder of notes, without
cost to such Holder, copies of such reports and documents within 15
days after the date on which the Company files such reports and
documents with the SEC or the date on which the Company (and the
Subsidiary Guarantors, if applicable) would be required to file such
reports and documents if the Company (and the Subsidiary Guarantors,
if applicable) were so required and
(2) if filing such reports and documents with the SEC is not accepted by
the SEC or is prohibited under the Exchange Act, to furnish at the
Company's cost copies of such reports and documents to any Holder of
notes promptly upon written request.
The Company is obligated to make available, upon request, to any Holder of
notes or prospective purchaser the information required by Rule 144A(d)(4)
under the Securities Act, during any period in which the Company is not subject
to Section 13 or 15(d) of the Exchange Act and for so long as the transfer of
any note is restricted under the Securities Act.
Future Designation of Restricted and Unrestricted Subsidiaries.
The preceding covenants, including calculation of financial ratios and
the determination of limitations on the incurrence of Indebtedness and Liens,
may be affected by the designation by the Company of any existing or
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future Subsidiary of the Company as an Unrestricted Subsidiary. Generally, a
Restricted Subsidiary includes any Subsidiary of the Company, whether existing
on or after the date of the Indenture, unless the Subsidiary of the Company is
designated as an Unrestricted Subsidiary pursuant to the terms of the
Indenture. The definition of "Unrestricted Subsidiary" set forth below under
the caption "-- Certain Definitions" describes the circumstances under which a
Subsidiary of the Company may be designated as an Unrestricted Subsidiary by
the Board of Directors.
CONSOLIDATION, MERGER, ETC.
The Company will 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 the properties and
assets of the Company and its Restricted Subsidiaries substantially as an
entirety on a consolidated basis to any Person, and the Company will not permit
any Restricted Subsidiary to enter into any transaction or series of related
transactions if such transaction or series of transactions would result in a
sale, assignment, conveyance, transfer, lease or other disposition of the
properties and assets of the Company and its Restricted Subsidiaries
substantially as an entirety on a consolidated basis to any Person, unless at
the time and after giving effect thereto:
(1) either (a) if the transaction or series of related transactions is a
merger or consolidation, the Company shall be the surviving Person of
such merger or consolidation, or (b) the Person, if other than the
Company, formed by such consolidation or into which the Company or
such Restricted Subsidiary is merged or to which the properties and
assets of the Company or such Restricted Subsidiary, as the case may
be, are sold, assigned, conveyed, transferred, leased or otherwise
disposed of (any such surviving Person or transferee Person being the
"Surviving Entity") shall be a corporation organized and existing
under the laws of the United States of America, any state thereof or
the District of Columbia and shall, in either case, expressly assume
by a supplemental indenture to the Indenture executed and delivered to
the Trustee, in form satisfactory to the Trustee, all the obligations
of the Company under the notes and the Indenture, and, in each case,
the Indenture shall remain in full force and effect;
(2) immediately before and immediately after giving effect to such
transaction or series of transactions on a pro forma basis (and
treating any Indebtedness not previously an obligation of Company or
any of its Restricted Subsidiaries in connection with or as a result
of such transaction or series of transactions as having been incurred
at the time of such transaction or series of transactions), no Default
or Event of Default shall have occurred and be continuing;
(3) except in the case of the consolidation or merger of any Restricted
Subsidiary with or into the Company, immediately after giving effect
to such transaction or series of transactions on a pro forma basis,
the Consolidated Net Worth of the Company (or the Surviving Entity if
the Company is not the continuing obligor under the Indenture) is at
least equal to the Consolidated Net Worth of the Company immediately
before such transaction or series of transactions;
(4) except in the case of the consolidation or merger of (a) any
Restricted Subsidiary with or into the Company or any Wholly Owned
Restricted Subsidiary or (b) the Company with or into any Person that
has no Indebtedness outstanding, immediately before and immediately
after giving effect to such transaction or series of transactions on a
pro forma basis (on the assumption that the transaction or series of
transactions occurred on the first day of the period of four fiscal
quarters ending immediately prior to the consummation of such
transaction or series of transactions, with the appropriate
adjustments with respect to such transaction or series transactions
being included in such pro forma calculation), the Company, or the
Surviving Entity if the Company is not the continuing obligor under
the Indenture, could incur $1.00 of additional Indebtedness, other
than Permitted Indebtedness, pursuant to the covenant described above
under the caption "--Limitation on Indebtedness;"
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(5) each Subsidiary Guarantor, unless it is the other party to the
transactions or series of transactions described above, shall have by
supplemental indenture to the Indenture confirmed that its Subsidiary
Guarantee shall apply to such Person's obligations under the Indenture
and the notes; and
(6) if any of the properties or assets of the Company or any Restricted
Subsidiary would upon such transaction or series of transactions
become subject to any Lien, other than a Permitted Lien, the creation
and imposition of such Lien shall have been in compliance with the
covenant described above under the caption "-- Limitation on Liens."
In connection with any consolidation, merger, transfer, lease or other
disposition contemplated hereby, the Company shall deliver, or cause to be
delivered, to the Trustee, in form and substance reasonably satisfactory to the
Trustee, an Officers' Certificate stating that such consolidation, merger,
transfer, lease or other disposition and the supplemental indenture in respect
thereto comply with the requirements under the Indenture and an Opinion of
Counsel stating that the requirements of clause (1) of the preceding paragraph
have been complied with. Upon any such consolidation or merger or any such
sale, assignment, transfer, lease or other disposition substantially as an
entirety on a consolidated basis of the properties and assets of the Company in
accordance with the foregoing in which the Company is not the continuing
Person, the Surviving Entity shall succeed to, and be substituted for, and may
exercise every right and power of, the Company under the Indenture with the
same effect as if the Surviving Entity had been named as the Company therein,
and thereafter the Company, except in the case of a lease, will be discharged
from all obligations and covenants under the Indenture and the notes.
EVENTS OF DEFAULT
The following are "Events of Default" under the Indenture:
(1) default in the payment of the principal of or premium, if any, on
any of the notes, whether such payment is due at maturity, upon redemption,
upon repurchase pursuant to a Change of Control Offer or a Net Proceeds Offer,
upon acceleration or otherwise; or
(2) default in the payment of any installment of interest on any of
the notes, when it becomes due and payable, and the continuance of such default
for a period of 30 days; or
(3) default in the performance or breach of the provisions of the
"Consolidation, Merger, Etc." section of the Indenture, the failure to make or
consummate a Change of Control Offer in accordance with the provisions of the
Indenture described under the caption "-- Change of Control" or the failure to
make or consummate a Net Proceeds Offer in accordance with the provisions of
the Indenture described under the caption "-- Limitation on Disposition of
Proceeds of Asset Sales;" or
(4) the Company or any Subsidiary Guarantor shall fail to perform or
observe any other term, covenant or agreement contained in the notes, any
Subsidiary Guarantee or the Indenture (other than a default specified in (1),
(2) or (3) above) for a period of 45 days after written notice of such failure
requiring the Company to remedy the same shall have been given (a) to the
Company by the Trustee or (b) to the Company and the Trustee by the holders of
at least 25% in aggregate principal amount of the notes then outstanding; or
(5) the occurrence and continuation beyond any applicable grace period
of any default in the payment of the principal of (or premium, if any, on) or
interest on any Indebtedness of the Company (other than the notes or any
Non-Recourse Indebtedness) or any Restricted Subsidiary for money borrowed when
due, or any other default causing acceleration of any Indebtedness (other than
Non-Recourse Indebtedness) of the Company or any Restricted Subsidiary for
money borrowed, provided that the aggregate principal amount of such
Indebtedness shall exceed $12,000,000; 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
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consequential acceleration of the notes shall be automatically rescinded, so
long as such rescission does not conflict with any judgment or decree; or
(6) the commencement of proceedings, or the taking of any enforcement
action, including by way of set-off, by any holder of at least $12,000,000 in
aggregate principal amount of Indebtedness, other than Non- Recourse
Indebtedness, of the Company or any Restricted Subsidiary, after a default
under such Indebtedness, to retain in satisfaction of such Indebtedness or to
collect or seize, dispose of or apply in satisfaction of such Indebtedness,
property or assets of the Company or any Restricted Subsidiary having a fair
market value (as determined by the Board of Directors) in excess of $12,000,000
individually or in the aggregate, provided, that if any such proceedings or
actions are terminated or rescinded, or such Indebtedness is repaid, such Event
of Default under the Indenture and any consequential acceleration of the notes
shall be automatically rescinded, so long as (a) such rescission does not
conflict with any judgment or decree and (b) the holder of such Indebtedness
shall not have applied any such property or assets in satisfaction of such
Indebtedness; or
(7) any Subsidiary Guarantee shall for any reason cease to be, or be
asserted by the Company or any Subsidiary Guarantor, as applicable, not to be,
in full force and effect, enforceable in accordance with its terms (except
pursuant to the release of any such Subsidiary Guarantee in accordance with the
Indenture); or
(8) certain events giving rise to ERISA liability; or
(9) final judgments or orders rendered against the Company 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
$12,000,000 over the coverage under applicable insurance policies and either
(a) 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 (b) 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;
or
(10) the entry of a decree or order by a court having jurisdiction in
the premises (a) for relief in respect of the Company or any Material
Restricted Subsidiary in an involuntary case or proceeding under any applicable
federal or state bankruptcy, insolvency, reorganization or other similar law or
(b) adjudging the Company or any Material Restricted Subsidiary bankrupt or
insolvent, or approving a petition seeking reorganization, arrangement,
adjustment or composition of the Company or a Material Restricted 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 the Company or any Material Restricted Subsidiary or of a
substantial part of their consolidated assets, or ordering the winding up or
liquidation of their 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
(11) the commencement by the Company or any Material Restricted
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
the Company or any Material Restricted Subsidiary to the entry of a decree or
order for relief in respect thereof 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 it, or the filing by the Company or any Material Restricted
Subsidiary of a petition or consent seeking reorganization or relief under any
applicable federal or state law, or the consent by it 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 or sequestrator (or other
similar official) of any of the Company or any Material Restricted Subsidiary
or of any substantial part of their consolidated assets, or the making by it of
an assignment for the benefit of creditors under any such law.
If an Event of Default (other than as specified in clause (10) or (11)
above) shall occur and be continuing, the Trustee, by written notice to the
Company, or the holders of at least 25% in aggregate principal amount of the
notes then outstanding, by notice to the Trustee and the Company, may declare
the principal of, premium, if any, and accrued interest on all of the notes
then outstanding due and payable immediately, upon which declaration all
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amounts payable in respect of the notes shall be immediately due and payable.
If an Event of Default specified in clause (10) or (11) above occurs and is
continuing, then the principal of, premium, if any, and accrued interest on all
of the notes then outstanding shall ipso facto become and be immediately due
and payable without any declaration, notice or other act on the part of the
Trustee or any Holder of 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 notes
then outstanding, by written notice to the Company and the Trustee, may rescind
such declaration if:
(1) the Company or any Subsidiary Guarantor has paid or deposited with the
Trustee a sum sufficient to pay:
(a) 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,
(b) all overdue interest on all notes then outstanding,
(c) the unpaid principal of and premium, if any, on any notes which
have become due otherwise than by such declaration of
acceleration, including any securities required to have been
purchased pursuant to a Change of Control Offer or a Net Proceeds
Offer, as applicable, and interest thereon at the rate borne by
the notes, and
(d) to the extent that payment of such interest is lawful, interest
upon overdue interest and overdue principal at the rate borne by
the notes which has become due otherwise than by such declaration
of acceleration;
(2) the rescission would not conflict with any judgment or decree of a
court of competent jurisdiction; and
(3) all Events of Default, other than the nonpayment of principal of,
premium, if any, and interest on the notes that has become due solely
by such declaration of acceleration, have been cured or waived.
The Holders of not less than a majority in aggregate principal amount
of the notes then outstanding may on behalf of the Holders of all the notes
waive any past defaults under the Indenture, except a default in the payment of
the principal of (or premium, if any, on) or interest on any note or a default
in respect of a covenant or provision which under the Indenture cannot be
modified or amended without the consent of the Holder of each note then
outstanding affected thereby.
No Holder of any of the notes has any right to institute any
proceeding with respect to the Indenture or any remedy thereunder, unless such
Holder has previously given written notice to the Trustee of a continuing Event
of Default, the Holders of at least 25% in aggregate principal amount of the
notes then outstanding have made written request, and offered reasonable
indemnity, to the Trustee to institute such proceeding as Trustee under the
notes and the Indenture, the Trustee has failed to institute such proceeding
within 60 days after receipt of such notice and offer of indemnity and 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 notes then outstanding. Such limitations do not apply, however,
to a suit instituted by a Holder of a note for the enforcement of the payment
of the principal of, premium, if any, or interest on such note on or after the
respective due dates expressed in such note.
During the existence of an Event of Default, the Trustee is required
to exercise such of the rights and powers vested in it under the Indenture, and
use the same degree of care and skill in its exercise, as a prudent person
would exercise or use 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, the Trustee under the Indenture is not under any obligation to
exercise any of its rights or powers under the Indenture at the request or
direction of any Holders of the notes unless such Holders shall have offered to
the Trustee reasonable security or indemnity. Subject to certain provisions in
the Indenture relating to the rights of the Trustee, the Holders of a majority
in aggregate principal amount of the notes
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then outstanding 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.
If a Default or an Event of Default occurs and is known to the
Trustee, the Trustee shall mail to each Holder of notes notice of the Default
or Event of Default within 60 days after the occurrence thereof in the manner
and to the extent provided in Section 313(c) of the Trust Indenture Act. Except
in the case of a Default or an Event of Default in payment of principal of,
premium, if any, or interest on any notes, the Trustee may withhold the notice
to the Holders of such notes if and so long as the board of directors, the
executive committee, or a trust committee of directors and/or responsible
officers of the Trustee in good faith determine that the withholding of such
notice is in the interest of the Holders of the notes.
The Company is required to furnish to the Trustee annual and quarterly
statements as to the performance by the Company of its obligations under the
Indenture and as to any default in such performance. The Company is also
required to notify the Trustee within ten days after any Default.
LEGAL DEFEASANCE OR COVENANT DEFEASANCE OF INDENTURE
The Company may, at its option and at any time, terminate the
obligations of the Company and the Subsidiary Guarantors with respect to the
notes then outstanding ("legal defeasance"). Such legal defeasance means that
the Company and the Subsidiary Guarantors shall be deemed to have paid and
discharged the entire Indebtedness represented by the notes then outstanding,
except for:
(1) the rights of Holders of notes then outstanding to receive payment in
respect of the principal of, premium, if any, on and interest on such
notes when such payments are due,
(2) the Company's obligations to issue temporary notes, register the
transfer or exchange of any notes, replace mutilated, destroyed, lost
or stolen notes and maintain an office or agency for payments in
respect of the notes,
(3) the rights, powers, trusts, duties and immunities of the Trustee, and
(4) the defeasance provisions of the Indenture.
In addition, the Company may, at its option and at any time, elect to terminate
the obligations of the Company and any Subsidiary Guarantor with respect to
certain covenants that are set forth in the Indenture, some of which are
described above under the caption "-- Certain Covenants," and any omission to
comply with such obligations shall not constitute a Default or an Event of
Default with respect to the notes ("covenant defeasance").
In order to exercise either legal defeasance or covenant defeasance:
(1) the Company or any Subsidiary Guarantor must irrevocably deposit, with
the Trustee, in trust, for the benefit of the holders of the notes,
cash in United States dollars, U.S. Government Obligations (as defined
in the Indenture), or a combination thereof, in such amounts as will
be sufficient, in the opinion of a nationally recognized firm of
independent public accountants, to pay the principal of, premium, if
any, on and interest on the notes then outstanding to redemption or
maturity;
(2) the Company shall have delivered to the Trustee an Opinion of Counsel
to the effect that the Holders of the notes then outstanding will not
recognize income, gain or loss for federal income tax purposes as a
result of such legal defeasance or covenant defeasance and will be
subject to federal income tax on the same amounts, in the same manner
and at the same times as would have been the case if such legal
defeasance or covenant defeasance had not occurred (in the case of
legal defeasance, such opinion must refer to and be based upon a
published ruling of the Internal Revenue Service or a change in
applicable federal income tax laws);
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(3) no Default or Event of Default shall have occurred and be continuing
on the date of such deposit;
(4) such legal defeasance or covenant defeasance shall not cause the
Trustee to have a conflicting interest under the Indenture or the
Trust Indenture Act with respect to any securities of the Company or
any Subsidiary Guarantor;
(5) such legal defeasance or covenant defeasance shall not result in a
breach or violation of, or constitute a default under, any material
agreement or instrument to which the Company or any Subsidiary
Guarantor is a party or by which it is bound; and
(6) the Company shall have delivered to the Trustee an Officers'
Certificate and an Opinion of Counsel satisfactory to the Trustee,
which, taken together, state that all conditions precedent under the
Indenture to either legal defeasance or covenant defeasance, as the
case may be, have been complied with and that no violations under
agreements governing any other outstanding Indebtedness would result
therefrom.
SATISFACTION AND DISCHARGE
The Indenture will be discharged and will cease to be of further
effect (except as to surviving rights or registration of transfer or exchange
of the notes, as expressly provided for in the Indenture) as to all notes then
outstanding when:
(1) either (a) all the notes theretofore authenticated and delivered
(except lost, stolen or destroyed notes which have been replaced or
paid and notes for whose payment money has theretofore been deposited
in trust or segregated and held in trust by the Company and thereafter
repaid to the Company or discharged from such trust) have been
delivered to the Trustee for cancellation or (b) all notes not
theretofore delivered to the Trustee for cancellation have become due
and payable or will become due and payable at their Stated Maturity
within one year, or are to be called for redemption within one year
under arrangements satisfactory to the Trustee for the serving of
notice of redemption by the Trustee in the name, and at the expense,
of the Company, and the Company has irrevocably deposited or caused to
be deposited with the Trustee funds in an amount sufficient to pay and
discharge the entire indebtedness on the notes not theretofore
delivered to the Trustee for cancellation, for principal of (and
premium, if any, on) and interest on the notes to the date of deposit
(in the case of notes which have become due and payable) or to the
Stated Maturity or Redemption Date, as the case may be, together with
instructions from the Company irrevocably directing the Trustee to
apply such funds to the payment thereof at maturity or redemption, as
the case may be;
(2) the Company has paid all other sums payable under the Indenture by the
Company; and
(3) the Company has delivered to the Trustee an Officers' Certificate and
an Opinion of Counsel satisfactory to the Trustee, which, taken
together, state that all conditions precedent under the Indenture
relating to the satisfaction and discharge of the Indenture have been
complied with and that no violations under agreements governing any
other outstanding Indebtedness would result therefrom.
AMENDMENTS
From time to time, the Company and the Trustee may, without the
consent of the Holders of the notes, modify, amend or supplement the Indenture
or the notes for certain specified purposes, including, among other things,
curing ambiguities, defects or inconsistencies, qualifying, or maintaining the
qualification of, the Indenture under the Trust Indenture Act, provided that
such change does not adversely affect the rights of any Holder of the notes.
Other modifications and amendments of the Indenture or the notes may be made by
the Company, the Subsidiary Guarantors and the Trustee with the consent of the
Holders of not less than a majority of the aggregate principal amount of the
notes then outstanding; provided, however, that no such modification or
amendment may, without the consent of the Holder of each note then outstanding
affected thereby:
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(1) change the Stated Maturity of the principal of, or any installment of
interest on any note,
(2) reduce the principal amount of (or the premium, if any, on) or
interest on any note,
(3) change the place, coin or currency of payment of principal of (or the
premium, if any, on) or interest on, any note,
(4) impair the right to institute suit for the enforcement of any payment
on or with respect to any note,
(5) reduce the above-stated percentage of aggregate principal amount of
notes then outstanding necessary to modify or amend the Indenture,
(6) reduce the percentage of aggregate principal amount of notes then
outstanding necessary for waiver of compliance with certain provisions
of the Indenture or for waiver of certain defaults under the
Indenture,
(7) modify or amend any provisions of the Indenture relating to the
modification and amendment of the Indenture or relating to the waiver
of past defaults or covenants, except as otherwise specified,
(8) modify or amend any provision of the Indenture relating to Subsidiary
Guarantees in a manner adverse to the Holders or
(9) modify or amend the obligation of the Company to make and consummate a
Change of Control Offer in the event of a Change of Control or to make
and consummate the Net Proceeds Offer with respect to any Asset Sale
or modify any of the provisions or definitions with respect thereto.
THE TRUSTEE
Prior to a Default, the Trustee shall not be liable except for the
performance of such duties as are specifically set out in the Indenture. If an
Event of Default has occurred and is continuing, the Trustee will exercise such
rights and powers vested in it under the Indenture, and use the same degree of
care and skill in its exercise, as a prudent person would exercise or use under
the circumstances in the conduct of such person's own affairs.
The Indenture and the Trust Indenture Act contain limitations on the
rights of the Trustee thereunder, should it become a creditor of the Company,
to obtain payment of claims in certain cases or to realize on certain property
received by it in respect of any such claims, as security or otherwise. The
Trustee is permitted to engage in other transactions; provided, however, that
if it acquires any conflicting interest (as defined in the Trust Indenture Act)
it must eliminate such conflict or resign.
State Street Bank and Trust Company is also trustee under indentures
for the 2007 Notes and the 2006 Notes. Pursuant to the Trust Indenture Act,
should a default occur with respect to either the notes or the 2006 Notes,
State Street Bank and Trust Company would be required to resign as trustee
under either the Indenture and the indenture for the 2007 Notes or the
indenture for the 2006 Notes within 90 days of such default unless such default
were cured, duly waived or otherwise eliminated.
GOVERNING LAW
The Indenture, the notes and the Subsidiary Guarantees provide that
they will be governed by the laws of the State of New York.
CERTAIN DEFINITIONS
"Acquired Indebtedness" means Indebtedness of a Person:
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(1) assumed in connection with an Asset Acquisition from such Person,
(2) outstanding at the time such Person becomes a Subsidiary of any other
Person (other than any Indebtedness incurred in connection with, or in
contemplation of, such Asset Acquisition or such Person becoming such
a Subsidiary) or
(3) any renewals, extensions, substitutions, refinancings or replacements
(each, for purposes of this clause, a "refinancing") by the Company of
any Indebtedness described in clause (1) or (2) of this definition,
including any successive refinancings, so long as
(a) 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 the Company as necessary to
accomplish such refinancing, plus the amount of expenses of the
Company incurred in connection with such refinancing,
(b) in the case of any refinancing of Subordinated Indebtedness, such
new Indebtedness is made subordinate to the notes at least to the
same extent as the Indebtedness being refinanced and
(c) such new Indebtedness has an Average Life longer than the Average
Life of the notes and a final Stated Maturity later than the
final Stated Maturity of the notes.
"Adjusted Consolidated Net Tangible Assets" means, without
duplication, as of the date of determination:
(1) the sum of:
(a) discounted future net revenues from proved oil and gas reserves
of the Company and its Restricted Subsidiaries calculated in
accordance with SEC guidelines 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 the Company's most recently completed fiscal year,
as increased by, as of the date of determination, the estimated
discounted future net revenues from (i) estimated proved oil and
gas reserves acquired since the date of such year-end reserve
report, and (ii) estimated oil and gas reserves attributable to
upward revisions of estimates of proved oil and gas reserves
since the date of such year-end reserve report due to
exploration, development or exploitation activities, in each case
calculated in accordance with SEC guidelines (using the prices
utilized in such year-end reserve report), and decreased by, as
of the date of determination, the estimated discounted future net
revenues from (iii) estimated proved oil and gas reserves
produced or disposed of since the date of such year-end reserve
report and (iv) 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 changes in
geological conditions or other factors which would, in accordance
with standard industry practice, cause such revisions, in each
case calculated in accordance with SEC guidelines (using the
prices utilized in such year-end reserve report); provided, that
in the case of each of the determinations made pursuant to
clauses (i) through (iv), such increases and decreases shall be
as estimated by the Company's 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 revenues used for purposes of this clause (1) (a)
shall be confirmed in writing by a nationally recognized firm of
independent petroleum engineers,
(b) the capitalized costs that are attributable to oil and gas
properties of the Company and its Restricted Subsidiaries to
which no proved oil and gas reserves are attributable, based on
the Company's
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books and records as of a date no earlier than the date of the
Company's latest annual or quarterly financial statements,
(c) the Net Working Capital on a date no earlier than the date of the
Company's latest annual or quarterly financial statements and
(d) the greater of (i) the net book value on a date no earlier than
the date of the Company's latest annual or quarterly financial
statements or (ii) the appraised value, as estimated by
independent appraisers, of other tangible assets (including,
without duplication, Investments in unconsolidated Restricted
Subsidiaries) of the Company and its Restricted Subsidiaries, as
of the date no earlier than the date of the Company's latest
audited financial statements,
(2) minus the sum of
(a) minority interests (other than a minority interest in a
Subsidiary that is a business trust or similar entity formed for
the primary purpose of issuing preferred securities the proceeds
of which are loaned to the Company or a Restricted Subsidiary),
(b) any net gas balancing liabilities of the Company and its
Restricted Subsidiaries reflected in the Company's latest audited
financial statements,
(c) to the extent included in (1) (a) above, the discounted future
net revenues, calculated in accordance with SEC guidelines (using
the prices utilized in the Company's year-end reserve report),
attributable to reserves which are required to be delivered to
third parties to fully satisfy the obligations of the Company and
its Restricted Subsidiaries with respect to Volumetric Production
Payments on the schedules specified with respect thereto and
(d) the discounted future net revenues, calculated in accordance with
SEC guidelines, attributable to reserves subject to
Dollar-Denominated Production Payments which, based on the
estimates of production and price assumptions included in
determining the discounted future net revenues specified in (1)
(a) above, would be necessary to fully satisfy the payment
obligations of the Company and its Restricted Subsidiaries with
respect to Dollar-Denominated Production Payments on the
schedules specified with respect thereto.
If the Company changes its method of accounting from the successful efforts
method to the full cost method or a similar method of accounting, "Adjusted
Consolidated Net Tangible Assets" will continue to be calculated as if the
Company were still using the successful efforts method of accounting.
"Affiliate" means, with respect to any specified Person, any other
Person directly or indirectly controlling or controlled by or under direct or
indirect common control with such specified Person. For the purposes of this
definition, "control," when used with respect to any Person, means the power to
direct the management and policies of such Person, directly or indirectly,
whether through the ownership of voting securities, by contract or otherwise;
and the terms "controlling" and "controlled" have meanings correlative to the
foregoing. For purposes of this definition, beneficial ownership of 10% or more
of the voting common equity (on a fully diluted basis) or options or warrants
to purchase such equity (but only if exercisable at the date of determination
or within 60 days thereof) of a Person shall be deemed to constitute control of
such Person. No Person shall be deemed an Affiliate of an oil and gas royalty
trust solely by virtue of ownership of units of beneficial interest in such
trust.
"Asset Acquisition" means:
(1) an Investment by the Company or any Restricted Subsidiary in any other
Person pursuant to which such Person shall become a Restricted
Subsidiary or any Restricted Subsidiary shall be merged with or into
the Company or any Restricted Subsidiary or
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(2) the acquisition by the Company or any Restricted Subsidiary of the
properties and assets of any Person which constitute all or
substantially all of the properties and assets of such Person or any
division or line of business of such Person.
"Asset Sale" means any sale, issuance, conveyance, transfer, lease or
other disposition to any Person other than the Company or any of its Restricted
Subsidiaries (including by means of a Sale/Leaseback Transaction or by way of
merger or consolidation) (collectively, for purposes of this definition, a
"transfer"), directly or indirectly, in one or a series of related
transactions, of:
(1) any Capital Stock of any Restricted Subsidiary held by the Company or
any Restricted Subsidiary;
(2) the properties and assets of any division or line of business of the
Company or any of its Restricted Subsidiaries substantially as an
entirety; or
(3) any other properties or assets of the Company or any of its Restricted
Subsidiaries other than a disposition of hydrocarbons or other mineral
products in the ordinary course of business.
For the purposes of this definition, the term "Asset Sale" shall not include:
(1) any transfer of properties or assets that is governed by, and made in
accordance with, the provisions described under the caption "--
Consolidation, Merger, etc."
(2) any transfer of properties or assets to any Person, if permitted under
the provisions described under the caption "-- Limitation on
Restricted Payments;"
(3) any trade or exchange of properties and assets used in the Oil and Gas
Business of the Company or any Restricted Subsidiary or shares of
Capital Stock in any Person in the Oil and Gas Business owned by the
Company or any Restricted Subsidiary for properties and assets used in
the Oil and Gas Business of any Person or shares of Capital Stock in
any Person owned or held by another Person, provided, that:
(a) the fair market value of the properties, assets and shares traded
or exchanged by the Company or such Restricted Subsidiary
(including any cash or Cash Equivalents, not to exceed 15% of
such fair market value, to be delivered by the Company or such
Restricted Subsidiary) is reasonably equivalent to the fair
market value of the properties, assets and shares of Capital
Stock (together with any cash or Cash Equivalents, not to exceed
15% of such fair market value) to be received by the Company or
such Restricted Subsidiary as determined in good faith by (i) any
officer of the Company if such fair market value is less than
$5,000,000 and (ii) the Board of Directors of the Company as
certified by a certified resolution delivered to the Trustee if
such fair market value is equal to or in excess of $5,000,000;
provided, that if such fair market value is equal to or in excess
of $10,000,000 the Company shall deliver a written appraisal by a
nationally recognized investment banking firm or appraisal firm,
in each case specializing or having a speciality in oil and gas
properties, and
(b) such exchange is approved by a majority of the Disinterested
Directors; or
(4) any transfer of properties or assets in a single transaction or series
of related transactions having a fair market value of less than
$5,000,000.
"Attributable Indebtedness" means, with respect to any particular
lease under which any Person is at the time liable and at any date as of which
the amount thereof is to be determined, the present value of the total net
amount of rent required to be paid by such Person under the lease during the
primary term thereof, without giving effect to any renewals at the option of
the lessee, discounted from the respective due dates thereof to such date of
determination at the rate of interest per annum implicit in the terms of the
lease. As used in the preceding sentence,
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the "net amount of rent" under any lease for any such period shall mean the sum
of rental and other payments required to be paid with respect to such period by
the lessee thereunder, excluding any amounts required to be paid by such lessee
on account of maintenance and repairs, insurance, taxes, assessments, water
rates or similar charges. In the case of any lease which is terminable by the
lessee upon payment of a penalty, such net amount of rent shall also include
the amount of such penalty, but no rent shall be considered as required to be
paid under such lease subsequent to the first date upon which it may be so
terminated.
"Average Life" means, with respect to any Indebtedness, as at any date
of determination, the quotient obtained by dividing:
(1) the sum of the products of (a) 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 (b) the amount of each such principal
payment by
(2) the sum of all such principal payments.
"Board of Directors" means:
(1) with respect to the Company, either the board of directors of the
Company or any properly constituted committee thereof that is (a)
authorized to take the action in question and (b) comprised of
members, a majority of whom are not officers or employees of the
Company or any Subsidiary of the Company, and
(2) with respect to any Restricted Subsidiary, the board of directors of
that Restricted Subsidiary or any properly constituted committee
thereof that is authorized to take the action in question.
"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.
"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:
(1) any evidence of Indebtedness with a maturity of 365 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),
(2) demand and time deposits and certificates of deposit or acceptances
with a maturity of 365 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 $100,000,000 or any
commercial bank organized under the laws of any country other than the
United States of America that is a member of the Organization for
Economic Cooperation and Development ("OECD") and has total assets in
excess of $100,000,000,
(3) commercial paper with a maturity of 365 days or less issued by a
Person that is not an Affiliate of the Company and is organized under
the laws of any state of the United States of America or the District
of Columbia and rated at least A-1 by S&P or at least P-1 by Moody's
(or, if at any time neither S&P nor
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Moody's shall be rating such obligations, then from such other rating
service as may be acceptable to the Trustee),
(4) repurchase obligations with a term of not more than seven days for
underlying securities of the types described in clause (1) above
entered into with any commercial bank meeting the specifications of
clause (2) above,
(5) overnight bank deposits and bankers' acceptances at any commercial
bank meeting the qualifications specified in clause (2) above, and
(6) investments in money market mutual or similar funds which have assets
in excess of $500,000,000.
"Change of Control" means the occurrence of any of the following
events:
(1) the Company's properties and assets are sold or otherwise disposed of
substantially as an entirety on a consolidated basis to any Person or
related group of Persons in any one transaction or a series of related
transactions;
(2) there shall be consummated any consolidation or merger of the Company
(a) in which the Company is not the continuing or surviving Person
(other than a consolidation or merger with a wholly owned Subsidiary
of the Company in which all shares of Common Stock outstanding
immediately prior to the effectiveness thereof are changed into or
exchanged for the same number of shares of Common Stock of such
Subsidiary) or (b) pursuant to which the Common Stock would be
converted into cash, securities or other property, in each case, other
than a consolidation or merger of the Company in which the holders of
the Common Stock immediately prior to the consolidation or merger
have, directly or indirectly, at least a majority of the Common Stock
of the continuing or surviving Person immediately after such
consolidation or merger; or
(3) any Person or any Persons acting together which would constitute a
"group" for purposes of Section 13(d) of the Exchange Act (other than
the Company, any Subsidiary of the Company, any employee stock
purchase plan, stock option plan or other stock incentive plan or
program, retirement plan or automatic dividend reinvestment plan or
any substantially similar plan of the Company or any Subsidiary of the
Company or any Person holding securities of the Company for or
pursuant to the terms of any such employee benefit plan), together
with any Affiliates thereof, shall acquire beneficial ownership (as
defined in Rule 13d-3 under the Exchange Act) of at least 50% of the
Voting Stock of the Company.
"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 Fixed Charge Coverage Ratio" means, for any period, the
ratio of:
(1) the sum of Consolidated Net Income, Consolidated Interest Expense,
Consolidated Income Tax Expense and Consolidated Non-cash Charges
deducted in computing Consolidated Net Income, in each case, for such
period, of the Company and its Restricted Subsidiaries on a
consolidated basis, all determined in accordance with GAAP, decreased
(to the extent included in determining Consolidated Net Income) by the
sum of
(a) the amount of deferred revenues that are amortized during such
period and are attributable to reserves that are subject to
Volumetric Production Payments and
(b) amounts recorded in accordance with GAAP as repayments of
principal and interest pursuant to Dollar-Denominated Production
Payments, to
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(2) the sum of such Consolidated Interest Expense for such period;
provided, that:
(a) 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 clause (1) of
the covenant described under the caption "-- Limitation on
Indebtedness" and 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,
(b) 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 clause (1) of the covenant described under the
caption "--Limitation on 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,
(c) notwithstanding clauses (a) and (b) 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 and
(d) in making such calculation, Consolidated Interest Expense shall
exclude interest attributable to Dollar-Denominated Production
Payments.
"Consolidated Income Tax Expense" means, for any period, the provision
for federal, state, local and foreign income taxes of the Company and its
Restricted Subsidiaries 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:
(1) the interest expense of the Company and its Restricted Subsidiaries
for such period as determined on a consolidated basis in accordance
with GAAP, including, without limitation:
(a) any amortization of debt discount,
(b) the net cost under Interest Rate Protection Obligations
(including any amortization of discounts),
(c) the interest portion of any deferred payment obligation,
(d) all commissions, discounts and other fees and charges owed with
respect to letters of credit and bankers' acceptance financing
and
(e) all accrued interest, in each case to the extent attributable to
such period,
(2) to the extent any Indebtedness of any Person (other than the Company
or a Restricted Subsidiary) is guaranteed by the Company or any
Restricted Subsidiary, the aggregate amount of interest paid or
accrued by such other Person during such period attributable to any
such Indebtedness, in each case to the extent attributable to that
period,
(3) the aggregate amount of the interest component of Capitalized Lease
Obligations paid, accrued and/or scheduled to be paid or accrued by
the Company and its Restricted Subsidiaries during such period as
determined on a consolidated basis in accordance with GAAP and
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(4) the aggregate amount of dividends paid or accrued on Redeemable
Capital Stock or Preferred Stock of the Company and its Restricted
Subsidiaries, to the extent such Redeemable Capital Stock or Preferred
Stock is owned by Persons other than Restricted Subsidiaries.
"Consolidated Net Income" means, for any period, the consolidated net
income (or loss) of the Company and its Restricted Subsidiaries for such period
as determined in accordance with GAAP, adjusted by excluding:
(1) net after-tax extraordinary gains or losses (less all fees and
expenses relating thereto),
(2) net after-tax gains or losses (less all fees and expenses relating
thereto) attributable to Asset Sales,
(3) the net income (or net loss) of any Person (other than the Company or
any of its Restricted Subsidiaries), in which the Company or any of
its Restricted Subsidiaries has an ownership interest, except to the
extent of the amount of dividends, interest on indebtedness or other
distributions actually paid to the Company or its Restricted
Subsidiaries in cash by such other Person during such period
(regardless of whether such cash dividends, interest on indebtedness
or other distributions is attributable to net income (or net loss) of
such Person during such period or during any prior period),
(4) net income (or net loss) of any Person combined with the Company or
any of its Restricted Subsidiaries on a "pooling of interests" basis
attributable to any period prior to the date of combination,
(5) 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,
(6) income resulting from transfers of assets received by the Company or
any Restricted Subsidiary from an Unrestricted Subsidiary and
(7) any write-downs of non-current assets; provided, however, that any
ceiling limitation write-downs under SEC guidelines shall be treated
as capitalized costs, as if such write-downs had not occurred.
"Consolidated Net Worth" means, at any date, the consolidated
stockholders' equity of the Company less the amount of such stockholders'
equity attributable to Redeemable Capital Stock or treasury stock of the
Company and its Restricted Subsidiaries, as determined in accordance with GAAP.
"Consolidated Non-cash Charges" means, for any period, the aggregate
depreciation, depletion, amortization, impairment and other non-cash expenses
of the Company and its Restricted Subsidiaries reducing Consolidated Net Income
for such period, determined on a consolidated basis in accordance with GAAP
(excluding any such non-cash charge which requires an accrual of or reserve for
cash charges for any future period).
"Credit Agreement" means the Amended and Restated Credit Agreement
dated August 1, 1997, among the Company and Bank of Montreal and Banque
Paribas, as co-agents, and the other banks specified therein, including any
notes and guarantees executed in connection therewith, as such agreement has
been and may be amended, modified, supplemented, extended, restated, replaced
(including replacement after the termination of such agreement), restructured,
increased, renewed or refinanced from time to time in one or more credit
agreements, loan agreements, instruments or similar agreements, whether or not
with the same lenders or agents, as such may be further amended, modified,
supplemented, extended, restated, replaced (including replacement after the
termination of such agreement), restructured, increased, renewed or refinanced
from time to time.
"Credit Agreement Obligations" means all monetary obligations of every
nature of the Company or a Restricted Subsidiary, including without limitation,
obligations to pay principal and interest, reimbursement
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obligations under letters of credit, fees, expenses and indemnities, from time
to time owed to the lenders or any agent under or in respect of the Credit
Agreement.
"Default" means any event, act or condition that is, or after notice
or passage of time or both would be, an Event of Default.
"Designated Senior Indebtedness" means:
(1) all Senior Indebtedness constituting Credit Agreement Obligations and
(2) any other Senior Indebtedness which (a) at the time of incurrence
equals or exceeds $10,000,000 in aggregate principal amount and (b) is
specifically designated by the Company in the instrument evidencing
such Senior Indebtedness as "Designated Senior Indebtedness" for
purpose of the Indenture.
"Disinterested Director" means, with respect to any transaction or
series of transactions in respect of which the Board of Directors is required
to deliver its resolution under the Indenture, a member of the 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 Capital
Stock of the Company) 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.
"Event of Default" has the meaning set forth above under the caption
"Events of Default."
"Foreign Subsidiary" means:
(1) any Restricted Subsidiary engaged in the Oil and Gas Business having
the majority of its operations outside the United States of America,
irrespective of its jurisdiction of organization, and
(2) any other Restricted Subsidiary whose assets (excluding any cash and
Cash Equivalents) consist exclusively of Capital Stock or Indebtedness
of one or more Restricted Subsidiaries described in clause (1) of this
definition.
"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 are applicable as of the date of the Indenture.
"guarantee" means, as applied to any obligation:
(1) a guarantee (other than by endorsement of negotiable instruments for
collection in the ordinary course of business), direct or indirect, in
any manner, of any part or all of such obligation and
(2) 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 nonperformance) of
all or any part of such obligation, including, without limiting the
foregoing, the payment of amounts drawn down by letters of credit.
When used as a verb, "guarantee" shall have a corresponding meaning.
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"Guarantor Senior Indebtedness" means all Indebtedness of a Subsidiary
Guarantor created, incurred, assumed or guaranteed by such Subsidiary Guarantor
(and all renewals, substitutions, refinancings or replacements thereof)
(including the principal of, interest on and fees, premiums, expenses
(including costs of collection), indemnities and other amounts payable in
connection with such Indebtedness) (and including, in the case of the Credit
Agreement, interest accruing after the filing of a petition by or against such
Subsidiary Guarantor under any bankruptcy law, in accordance with and at the
rate, including any default rate, specified with respect to such Indebtedness,
whether or not a claim for such interest is allowed as a claim after such
filing in any proceeding under such bankruptcy law), unless the instrument
governing such Indebtedness expressly provides that such Indebtedness is not
senior in right of payment to its Subsidiary Guarantee. Notwithstanding the
foregoing, Guarantor Senior Indebtedness of a Subsidiary Guarantor will not
include:
(1) Indebtedness of such Subsidiary Guarantor evidenced by its Subsidiary
Guarantee,
(2) Indebtedness of such Subsidiary Guarantor that is expressly
subordinated or junior in right of payment to any Guarantor Senior
Indebtedness of such Subsidiary Guarantor or its Subsidiary Guarantee,
(3) Indebtedness which, when incurred and without respect to any election
under Section 1111(b) of Title 11 United States Code, is by its terms
without recourse to such Subsidiary Guarantor or Non-Recourse
Indebtedness,
(4) any repurchase, redemption or other obligation in respect of
Redeemable Capital Stock of such Subsidiary Guarantor,
(5) to the extent it might constitute Indebtedness, any liability for
federal, state, local or other taxes owed or owing by such Subsidiary
Guarantor,
(6) Indebtedness of such Subsidiary Guarantor to the Company or any of the
Company's other Subsidiaries or any other Affiliate of the Company or
any of such Affiliate's Subsidiaries and
(7) that portion of any Indebtedness of such Subsidiary Guarantor which at
the time of issuance is issued in violation of the Indenture (but, as
to any such Indebtedness, no such violation shall be deemed to exist
for purposes of this clause (7) if the holder(s) of such Indebtedness
or their representative or such Subsidiary Guarantor shall have
furnished to the Trustee an Opinion of Counsel, addressed to the
Trustee (which counsel may, as to matters of fact, rely upon a
certificate of such Subsidiary Guarantor) to the effect that the
incurrence of such Indebtedness does not violate the provisions of
such Indenture);
provided, that the foregoing exclusions shall not affect the priorities of any
Indebtedness arising solely by operation of law in any case or proceeding or
similar event described in clause (1), (2) or (3) of the second paragraph under
the caption "-- Subordination."
"Hedging Obligations" means obligations of any Person arising out of
hedging transactions entered into in the ordinary course of business,
including, without limitation, swaps, options, forward sales and futures
contracts entered into in connection with interest rates, currencies and
energy-related commodities.
"Holder" means a Person in whose name a note is registered in the Note
Register.
"Indebtedness" means, with respect to any Person, without duplication:
(1) 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, but including, without limitation, all
obligations, contingent or otherwise, of such Person in connection
with any letters of credit, bankers' acceptance or other similar
credit transaction and in connection with any agreement to purchase,
redeem, exchange, convert or otherwise acquire for value any
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Capital Stock of such Person, or any warrants, rights or options to
acquire such Capital Stock, now or hereafter outstanding, 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,
(2) 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,
(3) 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,
(4) all Capitalized Lease Obligations of such Person,
(5) the Attributable Indebtedness (in excess of any related Capitalized
Lease Obligations) related to any Sale/Leaseback Transaction of such
Person,
(6) 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,
contingent or otherwise, 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),
(7) all guarantees by such Person of Indebtedness referred to in this
definition (including, with respect to any Production Payment, any
warranties or guarantees of production or payment by such Person with
respect to such Production Payment but excluding other contractual
obligations of such Person with respect to such Production Payment),
(8) all Redeemable Capital Stock of such Person valued at the greater of
its voluntary or involuntary maximum fixed repurchase price plus
accrued dividends,
(9) all obligations of such Person under or in respect of currency
exchange contracts and Interest Rate Protection Obligations and
(10) any amendment, supplement, modification, deferral, renewal, extension
or refunding of any liability of such Person of the types referred to
in clauses (1) through (9) above.
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. Subject to clause (7)
of the first sentence of this definition, neither Dollar-Denominated
Production Payments nor Volumetric Production Payments shall be deemed to be
Indebtedness.
"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
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notional amount and includes, 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 to (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 the Company in such
Unrestricted Subsidiary at such time. "Investments" shall exclude:
(1) extensions of trade credit on commercially reasonable terms in
accordance with normal trade practices and
(2) Interest Rate Protection Obligations entered into in the ordinary
course of business or as required by any Permitted Indebtedness,
Permitted Subsidiary Indebtedness or any Indebtedness incurred in
compliance with the covenant described above under the caption "--
Limitation on Indebtedness," but only to the extent that the notional
principal amount of such Interest Rate Protection Obligations does not
exceed 105% of the principal amount of such Indebtedness to which such
Interest Rate Protection Obligations relate and
(3) bonds, notes, debentures or other securities received in compliance
with the covenant described under the caption "-- Limitation on
Disposition of Proceeds of Asset Sales."
"Lien" means any mortgage, charge, pledge, lien (statutory or other),
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; provided,
however, "Lien" shall not include rights created in a third Person in
connection with the creation by the Company or a Subsidiary of a Production
Payment. 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.
"Material Change" means an increase or decrease (excluding changes
that result solely from changes in prices) of more than 50% during a fiscal
quarter in the estimated discounted future net cash flows from proved oil and
gas reserves of the Company and its Restricted Subsidiaries, calculated in
accordance with clause (1) (a) of the definition of Adjusted Consolidated Net
Tangible Assets; provided, however, that the following will be excluded from
the calculation of Material Change:
(1) 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
(2) 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 "-- Limitation on Disposition of Proceeds of Asset Sales."
"Material Restricted Subsidiary" means, at any particular time:
(1) any Subsidiary Guarantor and
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(2) any other Restricted Subsidiary that, together with its Subsidiaries:
(a) accounted for more than 5% of the consolidated revenues of the
Company and its Restricted Subsidiaries for the most recently
completed fiscal year of the Company or
(b) was the owner of more than 5% of the consolidated assets of the
Company and its Restricted Subsidiaries at the end of such fiscal
year, all as shown in the case of (a) and (b) on the consolidated
financial statements of the Company and its Restricted
Subsidiaries for such fiscal year.
"Maturity" means, with respect to any note, the date on which any
principal of such 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 received by the Company or any Restricted Subsidiary in the
form of 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 the Company or any Restricted Subsidiary)), net of:
(1) brokerage commissions and other fees and expenses (including fees and
expenses of engineers, legal counsel, accountants and investment
banks) related to such Asset Sale,
(2) provisions for all taxes payable as a result of such Asset Sale,
(3) amounts required to be paid (a) to any minority interest holder or
other Person (other than the Company or any Restricted Subsidiary)
owning a beneficial interest in the assets subject to the Asset Sale
or (b) in respect of any Indebtedness (other than Indebtedness under
the Credit Agreement) secured by a Lien on any of the properties or
assets that were the subject of such Asset Sale and
(4) appropriate amounts to be provided by the Company 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 the Company 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:
(1) all current assets of the Company and its Restricted Subsidiaries,
minus
(2) all current liabilities of the Company and its Restricted
Subsidiaries, except current liabilities included in Indebtedness, in
each case as set forth in financial statements of the Company prepared
in accordance with GAAP.
"Non-Recourse Indebtedness" means Indebtedness or that portion of
Indebtedness of the Company or a Restricted Subsidiary incurred in connection
with the acquisition by the Company or a Restricted Subsidiary of any property
or assets and as to which:
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(1) the holders of such Indebtedness agree that they will look solely to
the property or assets so acquired and securing such Indebtedness for
payment on or in respect of such Indebtedness and
(2) no default with respect to such Indebtedness would permit (after
notice or passage of time or both), according to the terms of any
other Indebtedness of the Company or a Restricted Subsidiary, any
holder of such other Indebtedness to declare a default under such
other Indebtedness or cause the payment of such other Indebtedness to
be accelerated or payable prior to its stated maturity.
"Note Obligations" means any principal of, premium, if any, and
interest on, and any other amounts (including, without limitation, any payment
obligations with respect to the notes as a result of any Asset Sale, Change of
Control or redemption) owing in respect of, the notes payable pursuant to the
terms of the notes or the Indenture or upon acceleration of the notes.
"Note Register" means the register maintained by or for the Company in
which the Company shall provide for the registration of the notes and of
transfer of the notes.
"Officers' Certificate" means a certificate delivered to the Trustee
signed by the Chairman, the President, a Vice President or the Chief Financial
Officer, and by the Treasurer, an Assistant Treasurer, the Secretary or an
Assistant Secretary of the Company.
"Oil and Gas Business" means:
(1) the acquisition, exploration, exploitation, development, operation and
disposition of interests in oil, gas and other hydrocarbon properties,
(2) the gathering, marketing, treating, processing, storage, refining,
selling and transporting of any production from such interests or
properties,
(3) any business relating to or arising from exploration for or
exploitation, development, production, treatment, processing, storage,
refining, transportation or marketing of oil, gas and other minerals
and products produced in association therewith,
(4) any power generation and electrical transmission business in a
jurisdiction outside North America where fuel required by such
business is supplied, directly or indirectly, from hydrocarbons
produced substantially from properties in which the Company or its
Restricted Subsidiaries, directly or indirectly, participates and
(5) any activity necessary, appropriate or incidental to the activities
described in the preceding clauses (1) through (4) of this definition.
"Opinion of Counsel" means a written opinion of legal counsel for the
Company (or any Subsidiary Guarantor, if applicable) including an employee of
the Company (or any Subsidiary Guarantor, if applicable), who is reasonably
acceptable to the Trustee.
"Pari Passu Indebtedness" means:
(1) the Company's 8 3/4% Senior Subordinated Notes due 2007 issued under
the Indenture dated as of May 15, 1997 between the Company and Fleet
National Bank (now State Street Bank and Trust Company), as Trustee,
and
(2) any other Indebtedness of the Company that is pari passu in right of
payment to the notes.
"Permitted Indebtedness" means any of the following:
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(1) Indebtedness of the Company under one or more bank credit or
revolving credit facilities in an aggregate principal amount at any one time
outstanding not to exceed:
(a) the greater of: (i) $270,000,000 and (ii) an amount equal to
the sum of (A) $170,000,000 and (B) 10% of Adjusted Consolidated Net
Tangible Assets determined as of the date of the most recent quarterly
consolidated financial statements of the Company and its Restricted
Subsidiaries, less
(b) the amount of Net Cash Proceeds applied to reduce Indebtedness
pursuant to the covenant of the Indenture described under the caption
"-- Limitation on Disposition of Proceeds of Asset Sales" (together
with interest and fees under such facilities, the "Maximum Credit
Amount," with the Maximum Credit Amount being an aggregate maximum
amount for the Company and all Guarantor Subsidiaries, pursuant to
clause (1) of the definition of "Permitted Subsidiary Indebtedness"),
and any renewals, amendments, extensions, supplements, modifications,
deferrals, refinancings or replacements (each, for purposes of this
clause, a "refinancing") thereof by the Company, including any
successive refinancings thereof by the Company, so long as the
aggregate principal amount of any such new Indebtedness, together with
the aggregate principal amount of all other Indebtedness outstanding
pursuant to this clause (1) (and clause (1) of the definition of
"Permitted Subsidiary Indebtedness"), shall not at any one time exceed
the Maximum Credit Amount;
(2) Indebtedness of the Company under the notes;
(3) Indebtedness of the Company outstanding on the date of the
Indenture (and not repaid or defeased with the proceeds of the Company's sale
of the outstanding notes);
(4) obligations of the Company pursuant to Interest Rate Protection
Obligations, but only to the extent 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 Obligations;
(5) Indebtedness of the Company to any Restricted Subsidiaries;
(6) in-kind obligations relating to net gas balancing positions arising
in the ordinary course of business and consistent with past practice;
(7) Indebtedness in respect of bid, performance or surety bonds issued
or other reimbursement obligations for the account of the Company in the
ordinary course of business, including guarantees and letters of credit
supporting such bid, performance, surety bonds or other reimbursement
obligations (in each case other than for an obligation for money borrowed);
(8) Non-Recourse Indebtedness;
(9) Indebtedness incurred in respect of any letters of credit in the
ordinary course of business of the Company or reimbursement obligations in
respect thereof;
(10) any renewals, extensions, substitutions, refinancings or
replacements (each, for purposes of this clause, a "refinancing") by the
Company of any Indebtedness of the Company described in clauses (2) or (3)
above, including any successive refinancings by the Company, so long as (a) 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 the Company as
necessary to accomplish such refinancing, plus the amount of expenses of the
Company incurred in connection with such refinancing, and (b) in the case of
any refinancing of
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Subordinated Indebtedness, such new Indebtedness is made subordinate to the
notes at least to the same extent as the Indebtedness being refinanced and (c)
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;
(11) other Indebtedness of the Company in an aggregate principal
amount not in excess of $25,000,000 at any one time outstanding.
"Permitted Investments" means any of the following:
(1) Investments in Cash Equivalents;
(2) Investments in the Company or any of its Restricted Subsidiaries;
(3) Investments by the Company or any of its Restricted Subsidiaries
in another Person, if as a result of such Investment (a) such other Person
becomes a Restricted Subsidiary of the Company or (b) such other Person is
merged or consolidated with or into, or transfers or conveys all or
substantially all of its properties and assets to, the Company or a Restricted
Subsidiary;
(4) entry into operating agreements, joint ventures, partnership
agreements, working interests, royalty interests, mineral leases, processing
agreements, farm-out agreements, contracts for the sale, transportation or
exchange of oil and natural gas, unitization agreements, pooling arrangements,
area of mutual interest agreements, development agreements, joint ownership
arrangements and other similar or customary agreements, transactions,
properties, interests and arrangements, whether or not any such Investment
involves or results in the creation of a legal entity, and Investments and
expenditures in connection therewith or pursuant thereto, in each case made or
entered into in the ordinary course of the Company or its Restricted
Subsidiaries' Oil and Gas Business;
(5) entry into any arrangement pursuant to which the Company or any of
its Restricted Subsidiaries may incur Hedging Obligations; and
(6) other Investments having an aggregate fair market value (measured
on the date each such Investment was made without giving effect to subsequent
changes in value), when taken together with all other Investments made pursuant
to this clause (6) that are at the time outstanding (net of repayments,
dividends and distributions received with respect to such Investments), not to
exceed $25,000,000 at any one time outstanding.
"Permitted Liens" means the following types of Liens:
(1) Liens existing as of the date the notes are first issued;
(2) Liens securing the notes;
(3) Liens in favor of the Company or a Subsidiary Guarantor;
(4) Liens securing Senior Indebtedness or Guarantor Senior
Indebtedness;
(5) Liens for taxes, assessments and governmental charges or claims
either (a) not delinquent or (b) contested in good faith by appropriate
proceedings and as to which the Company or its Restricted Subsidiaries shall
have set aside on its books such reserves as may be required pursuant to GAAP;
(6) statutory Liens of landlords and Liens of carriers, warehousemen,
mechanics, suppliers, materialmen, repairmen and other Liens imposed by law
incurred in the ordinary course of business for sums not delinquent or being
contested in good faith, if such reserve or other appropriate provision, if
any, as shall be required by GAAP shall have been made in respect thereof;
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(7) Liens incurred and deposits made in the ordinary course of
business in connection with workers' compensation, unemployment insurance and
other types of social security, and Liens incurred and deposits made to secure
the payment or performance of tenders, statutory or regulatory obligations,
surety and appeal bonds, bids, leases, government contracts and leases, trade
contracts (other than to secure an obligation for borrowed money), performance
and return of money bonds and other similar obligations (exclusive of
obligations for the payment of borrowed money but including lessee and operator
obligations under statutes, governmental regulations or instruments related to
the ownership, exploration and production of oil, gas and minerals on state,
federal or foreign lands or waters);
(8) pre-judgment Liens and judgment Liens not giving rise to an Event
of Default so long as any appropriate legal proceedings which may have been
duly initiated for the review of such judgment shall not have been finally
terminated or the period within which such proceeding may be initiated shall
not have expired;
(9) any interest or title of a lessor under any Capitalized Lease
Obligation or operating lease;
(10) Liens resulting from the deposit of funds or evidences of
Indebtedness in trust for the purpose of defeasing Indebtedness of the Company
or any of the Subsidiaries; customary Liens for the fees, costs and expenses of
trustees and escrow agents pursuant to the indenture, escrow agreement or other
similar agreement establishing such trust or escrow arrangement; and Liens
pursuant to merger agreements, stock purchase agreements, asset sale agreements
and similar agreements (a) limiting the transfer of properties and assets
pending consummation of the subject transaction or (b) in respect of earnest
money deposits, good faith deposits, purchase price adjustment escrows or
similar deposits or escrow arrangements made or established thereunder;
(11) Liens securing any Hedging Obligations of the Company or any
Restricted Subsidiary;
(12) Liens upon specific items of inventory or other goods and
proceeds of any Person securing such Person's obligations in respect of
bankers' acceptances issued or created for the account of such Person to
facilitate the purchase, shipment or storage of such inventory or other goods;
(13) Liens securing reimbursement obligations with respect to
commercial letters of credit which encumber documents and other property
relating to such letters of credit and products and proceeds thereof;
(14) Liens encumbering property or assets under construction arising
from progress or partial payments by a customer of the Company or its
Restricted Subsidiaries relating to such property or assets and Liens to secure
Indebtedness used to finance all or a part of the construction of property or
assets used by the Company or any of its Restricted Subsidiaries in the Oil and
Gas Business, provided, that such Liens do not extend to any other property or
assets owned by the Company or its Restricted Subsidiaries;
(15) Liens encumbering deposits made to secure obligations arising
from statutory, regulatory, contractual or warranty requirements of the Company
or any of its Restricted Subsidiaries, including rights of offset and set-off;
(16) Liens securing Interest Rate Protection Obligations which
Interest Rate Protection Obligations relate to Indebtedness that is secured by
Liens otherwise permitted under this Indenture;
(17) Liens on, or related to, properties or assets to secure all or
part of the costs incurred in the ordinary course of business for the
exploration, drilling, development or operation thereof;
(18) Liens on pipeline or pipeline facilities which arise out of
operation of law;
(19) Liens arising under operating agreements, joint venture
agreements, partnership agreements, oil and gas leases, farm-out agreements,
division orders, contracts for the sale, purchase, transportation, processing
or exchange of oil, gas or other hydrocarbons, unitization and pooling
declarations and agreements, area of mutual
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interest agreements, development agreements, joint ownership arrangements and
other agreements which are customary in the Oil and Gas Business;
(20) Liens reserved in oil and gas mineral leases for bonus or rental
payments and for compliance with the terms of such leases;
(21) Liens constituting survey exceptions, encumbrances, easements, or
reservations of, or rights to others for, rights-of-way, zoning restrictions
and other similar charges and encumbrances as to the use of real properties,
and minor defects of title which, in the case of any of the foregoing, were not
incurred or created to secure the payment of borrowed money or the deferred
purchase price of property, assets or services, and in the aggregate do not
interfere in any material respect with the ordinary conduct of the business of
the Company or its Restricted Subsidiaries;
(22) rights reserved to or vested in any municipality or governmental,
statutory or public authority by the terms of any right, power, franchise,
grant, license or permit, or by any provision of law, to terminate such right,
power, franchise, grant, license or permit or to purchase, condemn, expropriate
or recapture or to designate a purchaser of any of the property of such Person;
rights reserved to or vested in any municipality or governmental, statutory or
public authority to control or regulate any property of such Person, or to use
such property in a manner which does not materially impair the use of such
property for the purposes for which it is held by such Person; any obligation
or duties affecting the property of such Person to any municipality or
governmental, statutory or public authority with respect to any franchise,
grant, license or permit;
(23) Liens securing Non-Recourse Indebtedness; provided, however, that
the related Non-Recourse Indebtedness shall not be secured by any property or
assets of the Company or any Restricted Subsidiary other than the property and
assets acquired by the Company with the proceeds of such Non-Recourse
Indebtedness; and
(24) Liens securing Acquired Indebtedness; provided, however, that any
such lien extends only to the properties or assets that were subject to such
Lien prior to the related acquisition by the Company or such Restricted
Subsidiary and was not created, incurred or assumed in contemplation of such
transaction.
Notwithstanding anything in clauses (1) through (24) of this definition, the
term "Permitted Liens" does not include any Liens resulting from the creation,
incurrence, issuance, assumption or guarantee of any Production Payments other
than Production Payments that are created, incurred, issued, assumed or
guaranteed in connection with the financing of, and within 30 days after, the
acquisition of the properties or assets that are subject thereto.
"Permitted Subsidiary Indebtedness" means any of the following:
(1) Indebtedness of any Guarantor Subsidiary under one or more bank
credit or revolving credit facilities (and "refinancings" thereof) in an amount
at any one time outstanding not to exceed the Maximum Credit Amount (in the
aggregate for all Guarantor Subsidiaries and the Company, pursuant to clause
(1) of the definition of "Permitted Indebtedness");
(2) Indebtedness of any Restricted Subsidiary outstanding on the date
of the Indenture;
(3) obligations of any Restricted Subsidiary pursuant to Interest Rate
Protection Obligations, but only to the extent such obligations do not exceed
105% of the aggregate principal amount of the Indebtedness covered by such
Interest Rate Protection Obligations; and Hedging Obligations of any Restricted
Subsidiary;
(4) the Subsidiary Guarantees (and any assumption of the obligations
guaranteed thereby);
(5) Indebtedness of any Restricted Subsidiary relating to guarantees
by such Restricted Subsidiary of Permitted Indebtedness;
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(6) in-kind obligations relating to net gas balancing positions
arising in the ordinary course of business and consistent with past practice;
(7) Indebtedness in respect of bid, performance or surety bonds or
other reimbursement obligations issued for the account of any Restricted
Subsidiary in the ordinary course of business, including guarantees and letters
of credit supporting such bid, performance, surety bonds or other reimbursement
obligations (in each case other than for an obligation for money borrowed);
(8) Indebtedness of any Restricted Subsidiary to any other Restricted
Subsidiary or to the Company;
(9) Indebtedness relating to guarantees by any Restricted Subsidiary
permitted to be incurred pursuant to paragraph (a) of the provisions of the
Indenture described under the caption "-- Limitation on Non-Guarantor
Restricted Subsidiaries";
(10) Indebtedness incurred in respect of letters of credit in the
ordinary course of business of any Restricted Subsidiary or reimbursement
obligation in respect thereof;
(11) Non-Recourse Indebtedness;
(12) any renewals, extensions, substitutions, refinancings or
replacements (each, for purposes of this clause, a "refinancing") by any
Restricted Subsidiary of any Indebtedness of such Restricted Subsidiary
including any successive refinancings by such Restricted Subsidiary, so long as
(a) 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 such
Restricted Subsidiary as necessary to accomplish such refinancing, plus the
amount of expenses of such Subsidiary incurred in connection with such
refinancing and (b) 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; and
(13) other Indebtedness incurred by one or more Restricted
Subsidiaries that are not Guarantor Subsidiaries in an aggregate principal
amount not to exceed $20,000,000 at any time outstanding.
"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 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.
"Public Market" exists at any time with respect to the Qualified
Capital Stock of the Company if such Qualified Capital Stock of the Company is
then:
(1) registered with the SEC pursuant to Section 12(b) or 12(g) of the
Exchange Act and
(2) traded either on a national securities exchange or on the NASDAQ Stock
Market.
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"Qualified Capital Stock" of any Person means any and all Capital
Stock of such Person other than Redeemable Capital Stock.
"Qualified Redemption Transaction" means a call for redemption of any
Capital Stock or Subordinated Indebtedness (including any Subordinated
Indebtedness accounted for as a minority interest of the Company that is held
by a Subsidiary that is a business trust or similar entity formed for the
primary purpose of issuing preferred securities the proceeds of which are
loaned to the Company or a Restricted Subsidiary) that by its terms is
convertible into Common Stock of the Company if on the date of notice of such
call for redemption:
(1) a Public Market exists in the shares of Common Stock of the Company
and
(2) the average closing price on the Public Market for shares of Common
Stock of the Company for the twenty trading days immediately preceding
the date of such notice exceeds 120% of the conversion price per share
(determined by reference to the redemption price) of Common Stock of
the Company issuable upon conversion of the Capital Stock or
Subordinated Indebtedness called for redemption.
"Redeemable Capital Stock" means any class or series of 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 91 days after the final Stated Maturity of the notes or is redeemable
at the option of the holder thereof at any time prior to 91 days after such
final Stated Maturity, or is convertible into or exchangeable for debt
securities at any time prior to 91 days after such final Stated Maturity.
"Regular Record Date" for the interest payable on any Interest Payment
Date means February 1 or August 1 (whether or not a business day, as the case
may be) next preceding each such Interest Payment Date.
"Restricted Subsidiary" means any Subsidiary of the Company, whether
existing on or after the date of the Indenture, unless such Subsidiary of the
Company 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.
"Sale/Leaseback Transaction" means, with respect to any Person, any
direct or indirect arrangement pursuant to which properties or assets are sold
or transferred by such Person or a Subsidiary of such Person and are thereafter
leased back from the purchaser or transferee thereof by such Person or one of
its Subsidiaries; provided, however, Sale/Leaseback Transactions shall not
include transactions whereby property or assets are sold or transferred by the
Company or any of its Restricted Subsidiaries to any Affiliate of the Company
or pursuant to any Permitted Investment constituting a joint ownership
arrangement, which property or assets are leased back, directly or indirectly,
to the Company, any Affiliate of the Company or to the constituent parties to
any such joint venture arrangement.
"Senior Indebtedness" means the principal of, premium, if any, and
interest on any Indebtedness of the Company (including, in the case of the
Credit Agreement, interest accruing after the filing of a petition by or
against the Company under any bankruptcy law, in accordance with and at the
rate, including any default rate, specified with respect to such indebtedness,
whether or not a claim for such interest is allowed as a claim after such
filing in any proceeding under such bankruptcy law), 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 shall not be senior in right of payment to the notes.
Notwithstanding the foregoing, "Senior Indebtedness" shall not include:
(1) Indebtedness evidenced by the notes,
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(2) Indebtedness that is expressly subordinate or junior in right of
payment to any Senior Indebtedness of the Company,
(3) Indebtedness which, when incurred and without respect to any election
under Section 1111(b) of Title 11 United States Code, is by its terms
without recourse to the Company or which is Non-Recourse Indebtedness,
(4) any repurchase, redemption or other obligation in respect of
Redeemable Capital Stock of the Company,
(5) to the extent it might constitute Indebtedness, any liability for
federal, state, local or other taxes owed or owing by the Company,
(6) Indebtedness of the Company to a Subsidiary of the Company or any
other Affiliate of the Company or any of such Affiliate's Subsidiaries
and
(7) that portion of any Indebtedness of the Company which at the time of
issuance is issued in violation of the Indenture (but, as to any such
Indebtedness, no such violation shall be deemed to exist for purposes
of this clause (7) if the holder(s) of such Indebtedness or their
representative or the Company shall have furnished to the Trustee an
Opinion of Counsel addressed to the Trustee (which counsel may, as to
matters of fact, rely upon a certificate of the Company) to the effect
that the incurrence of such Indebtedness does not violate the
provisions of such Indenture);
provided, that the preceding exclusions shall not affect the priorities of any
Indebtedness arising solely by operation of law in any case or proceeding or
similar event described in clause (1), (2) or (3) of the second paragraph under
the caption "-- Subordination."
"Stated Maturity" means, when used with respect to any note or any
installment of interest thereon, the date specified in such note as the fixed
date on which the principal of such 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:
(1) the Company's 5 1/2% Convertible Subordinated Notes due 2006 issued
under the Indenture dated as of June 15, 1996, between the Company and
Fleet National Bank (now State Street Bank and Trust Company), as
Trustee and
(2) other Indebtedness of the Company which, by its terms, is subordinated
in right of payment to the notes.
"Subsidiary" means, with respect to any Person, a corporation,
partnership, limited liability company, association or other business entity 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. For purposes of the foregoing definition, an
arrangement by which a Person who owns an interest in an oil and gas property
is subject to a joint operating agreement, processing agreement, net profits,
interest, overriding royalty interest, farmout agreement, development
agreement, area of mutual interest agreement, joint bidding agreement,
unitization agreement, pooling arrangement or other similar agreement or
arrangement shall not, in and of itself, be considered a Subsidiary.
"Subsidiary Guarantee" means any guarantee of the notes by any
Restricted Subsidiary in accordance with the provisions set forth in the
covenant described under the caption "-- Limitation on Non-Guarantor Restricted
Subsidiaries."
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"Subsidiary Guarantor" means each of the Company's Restricted
Subsidiaries that becomes a guarantor of the notes in compliance with the
provisions described under the caption "-- Limitation on Non-Guarantor
Restricted Subsidiaries" or otherwise executes a supplemental indenture in
which such Subsidiary agrees to be bound by the terms of the Indenture and to
guarantee the payment of the notes pursuant to the provisions described under
the caption "-- Possible Subsidiary Guarantees of the Notes."
"Unrestricted Subsidiary" means:
(1) any Subsidiary of the Company that at the time of determination will
be designated an Unrestricted Subsidiary by the Board of Directors of
the Company as provided below and
(2) any Subsidiary of an Unrestricted Subsidiary. The Board of Directors
of the Company may designate any Subsidiary of the Company as an
Unrestricted Subsidiary so long as:
(a) neither the Company nor any Restricted Subsidiary is directly or
indirectly liable pursuant to the terms of any Indebtedness of
such Subsidiary;
(b) no default with respect to any Indebtedness of such Subsidiary
would permit (upon notice, lapse of time or otherwise) any holder
of any other Indebtedness of the Company or any Restricted
Subsidiary to declare a default on such other Indebtedness or
cause the payment thereof to be accelerated or payable prior to
its stated maturity;
(c) neither the Company nor any Restricted Subsidiary has made an
Investment in such Subsidiary unless such Investment was made
pursuant to, and in accordance with, the covenant described under
the caption "-- Limitation on Restricted Payments" (other than
Investments of the type described in clause (4) of the definition
of "Permitted Investments"); and
(d) such designation shall not result in the creation or imposition
of any Lien on any of the Properties of the Company or any
Restricted Subsidiary (other than any Permitted Lien or any Lien
the creation or imposition of which shall have been in compliance
with the covenant described under the caption "-- Limitation on
Liens");
provided, however, that with respect to clause (a) of this sentence, the
Company or a Restricted Subsidiary may be liable for Indebtedness of an
Unrestricted Subsidiary if:
(i) such liability constituted a Permitted Investment or a Restricted
Payment permitted by the provisions of the Indenture described under
the caption "-- Limitation on Restricted Payments," in each case at
the time of incurrence, or
(ii) the liability would be a Permitted Investment at the time of
designation of such Subsidiary as an Unrestricted Subsidiary.
Any such designation by the Board of Directors shall be evidenced to the
Trustee by filing a resolution with the Trustee giving effect to such
designation.
The Board of Directors may designate any Unrestricted Subsidiary as a
Restricted Subsidiary if, immediately after giving effect to such designation:
(1) no Default or Event of Default shall have occurred and be continuing,
(2) the Company could incur $1.00 of additional Indebtedness (other than
Permitted Indebtedness) under the first paragraph of the covenant
described above under the caption "-- Limitation on Indebtedness" and
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<PAGE> 121
(3) if any of the Properties of the Company or any of its Restricted
Subsidiaries 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 covenant described under the
caption "-- Limitations on Liens."
"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 vote in the election of the directors, managers or trustees of
any Person (irrespective of whether or not, at the time, Capital Stock of any
other class or classes shall have, or might have, voting power by reason of the
happening of any contingency).
"Wholly Owned Restricted Subsidiary" means any Restricted Subsidiary
to the extent:
(1) all of the Capital Stock in such Restricted Subsidiary, other than any
directors qualifying shares mandated by applicable law, is owned
directly or indirectly by the Company or
(2) 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 the Company,
directly or indirectly, owns the remaining Capital Stock or ownership
interest in such Restricted Subsidiary and, by contract or otherwise,
controls the management and business of such Restricted Subsidiary and
derives the economic benefits of ownership of such Restricted
Subsidiary to substantially the same extent as if such Restricted
Subsidiary were a wholly owned Subsidiary.
OUTSTANDING NOTES REGISTRATION RIGHTS AGREEMENT
In connection with the sale of the outstanding notes, the Company
entered into a Registration Rights Agreement. Under that agreement, the Company
agreed to use its reasonable best efforts to:
o file a registration statement with the SEC with respect to an
offer to exchange the outstanding notes for new notes having
substantially identical terms as the outstanding notes (except
that the new notes will not contain terms with respect to
transfer restrictions or interest rate increases)
o cause that registration statement to be declared effective under
the Securities Act within 135 days of the date of original
issuance of the outstanding notes
o keep that registration statement effective until the closing of
the exchange offer
o cause the exchange offer to be consummated within 180 days
following the original issuance of the outstanding notes
Promptly after the exchange offer registration statement has been
declared effective, the Company will offer the outstanding notes in exchange
for surrender of the new notes.
Under the following circumstances, the Company will file with the SEC
a shelf registration statement to cover resales of the outstanding notes by
those holders who provide required information in connection with the shelf
registration statement:
o if any changes in law or the applicable interpretations of the
staff of the SEC do not permit the Company to effect the
exchange offer as contemplated by the Registration Rights
Agreement
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o if for any reason the exchange offer registration statement is
not declared effective within 135 days after the date of
original issuance of the outstanding notes
o if the exchange offer is not consummated within 180 days after
the date of original issuance of the outstanding notes
o if the initial purchasers of outstanding notes request in
certain circumstances
A "Registration Default" will occur if, among other things:
o the exchange offer registration statement is not declared
effective on or prior to the 135th day following the date of
original issuance of the outstanding notes
o the exchange offer is not consummated or a shelf registration
statement with respect to the notes is not declared effective on
or prior to the 180th day following the date of original
issuance of the outstanding notes
o the Company files the exchange offer registration statement or
shelf registration statement and the SEC declares it effective,
but afterward the Company withdraws it, or it becomes subject to
an effective stop order suspending the effectiveness of such
registration statement (except as specifically permitted in the
Registration Rights Agreement) without being succeeded
immediately by an additional registration statement filed and
declared effective
o the Company effects a suspension of offers and sales under the
shelf registration statement for more than 60 days, whether or
not consecutive, within any period of 12 consecutive months
If any Registration Default occurs, the Company will be obligated to
pay additional interest to each holder of outstanding notes at a rate equal to
0.50% per annum. This rate will continue until all registration defaults have
been cured (and, if applicable, the suspension of offers and sales of notes
under the shelf registration statement ceases).
Holders who desire to tender their outstanding notes will be required
to make to the Company the representations described under "The Exchange Offer
- -- Purpose and Effect of the Exchange Offer" and "-- Procedures for Tendering"
in order to participate in the exchange offer. In addition, the Company may
require holders to deliver information to be used in connection with the shelf
registration statement in order to have their notes included in the shelf
registration statement and benefit from the provisions regarding additional
interest described in the preceding paragraphs. A holder who sells outstanding
notes under the shelf registration statement generally will be required to be
named as a selling securityholder in the related prospectus and to deliver a
prospectus to purchasers. Such a holder will also be subject to the civil
liability provisions under the Securities Act in connection with such sales and
will be bound by the provisions of the Registration Rights Agreement that are
applicable to such holder, including indemnification obligations.
The description of the Registration Rights Agreement contained in
this section is a summary only. For more information, you may review the
provisions of the Registration Rights Agreement that the Company filed with the
SEC as an exhibit to the registration statement of which this prospectus is a
part.
BOOK ENTRY; DELIVERY AND FORM
The new notes will initially be represented by one or more permanent
global notes in definitive, fully registered book-entry form (the "Global
Securities") that will be registered in the name of Cede & Co., as nominee of
DTC. The Global Securities will be deposited on behalf of the acquirors of the
new notes represented thereby with a custodian for DTC for credit to the
respective accounts of the acquirors or to such other accounts as they may
direct at DTC. See "The Exchange Offer -- Book-Entry Transfer."
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<PAGE> 123
THE GLOBAL SECURITIES
The Company expects that under procedures established by DTC
o upon deposit of the Global Securities with DTC or its custodian,
DTC will credit on its internal system portions of the Global
Securities that shall be comprised of the corresponding
respective amounts of the Global Securities to the respective
accounts of persons who have accounts with such depositary
o ownership of the notes will be shown on, and the transfer of
ownership thereof will be effected only through, records
maintained by DTC or its nominee, with respect to interests of
persons who have accounts with DTC ("participants"), and the
records of participants, with respect to interests of persons
other than participants.
So long as DTC or its nominee is the registered owner or holder of
any of the notes, DTC or such nominee will be considered the sole owner or
holder of such notes represented by the Global Securities for all purposes
under the Indenture and under the notes represented thereby. No beneficial
owner of an interest in the Global Securities will be able to transfer such
interest except in accordance with the applicable procedures of DTC in addition
to those provided for under the indenture.
Payments on the notes represented by the Global Securities will be
made to DTC or its nominee, as the case may be, as the registered owner
thereof. None of the Company, the trustee or any paying agent under the
Indenture will have any responsibility or liability for any aspect of the
records relating to or payments made on account of beneficial ownership
interests in the Global Securities or for maintaining, supervising or reviewing
any records relating to such beneficial ownership interest.
The Company expects that DTC or its nominee, upon receipt of any
payment on the notes represented by the Global Securities, will credit
participants' accounts with payments in amounts proportionate to their
respective beneficial interests in the Global Securities as shown in the
records of DTC or its nominee. The Company also expects that payments by
participants to owners of beneficial interests in the Global Securities held
through such participants will be governed by standing instructions and
customary practice as is now the case with securities held for the accounts of
customers registered in the names of nominees for such customers. Such payment
will be the responsibility of such participants.
Transfers between participants in DTC will be effected in accordance
with DTC rules and will be settled in immediately available funds. If a holder
requires physical delivery of a certificated security for any reason, including
to sell notes to persons in states that require physical delivery of such
security or to pledge such securities, such holder must transfer its interest
in the Global Securities in accordance with the normal procedures of DTC and
the procedures in the indenture.
DTC has advised the Company that DTC will take any action permitted
to be taken by a holder of notes, including the presentation of notes for
exchange as described below, only at the direction of one or more participants
to whose account the DTC interests in the Global Securities are credited and
only in respect of the aggregate principal amount as to which such participant
or participants has or have given such direction. However, if there is an event
of default under the Indenture, DTC will exchange the Global Securities for
certificated securities that it will distribute to its participants.
DTC has advised the Company as follows:
o DTC is a limited-purpose company organized under the New York
Banking Law, a "banking organization" within the meaning of the
New York Banking Law, a member of the Federal Reserve System, a
"clearing corporation" within the meaning of the New York
Uniform Commercial Code
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and a "clearing agency" registered under the provisions of
Section 17A of the Securities Exchange Act of 1934
o DTC holds securities that its participants deposit with DTC and
facilitates the settlement among participants of securities
transactions, such as transfers and pledges, in deposited
securities through electronic computerized book-entry changes in
participants' accounts, thereby eliminating the need for
physical movement of securities certificates
o Direct participants include securities brokers and dealers,
banks, trust companies, clearing corporations and other
organizations
o DTC is owned by a number of its participants and by the New York
Stock Exchange, Inc., the American Stock Exchange, Inc. and the
National Association of Securities Dealers, Inc.
o Access to the DTC system is also available to others such as
securities brokers and dealers, banks and trust companies that
clear through or maintain a custodial relationship with a direct
participant, either directly or indirectly
o The rules applicable to DTC and its participants are on file
with the SEC
Although DTC is expected to follow these procedures in order to
facilitate transfers of interests in the Global Securities among participants
of DTC, it is under no obligation to perform such procedures, and such
procedures may be discontinued at any time. Neither the Company nor the trustee
will have any responsibility for the performance by DTC or its direct or
indirect participants on their respective obligations under the rules and
procedures governing their operations.
CERTIFICATED SECURITIES
Interests in the Global Securities will be exchanged for certificated
securities if:
o DTC or any successor depositary (the "'Depositary") notifies the
Company that it is unwilling or unable to continue as depositary
for the Global Securities, or DTC ceases to be a "clearing
agency" registered under the Securities Exchange Act of 1934,
and a successor depositary is not appointed by the Company
within 90 days
o the Company determines not to have the notes represented by
Global Securities
Upon the occurrence of either of the events described in the preceding
sentence, the Company will cause the appropriate certificated securities to be
delivered.
Neither the Company nor the trustee will be liable for any delay by
the Depositary or its nominee in identifying the beneficial owners of the
related notes. Each such person may conclusively rely on, and will be protected
in relying on, instructions from such Depositary or nominee for all purposes,
including the registration and delivery, and the respective principal amounts,
of the notes to be issued.
CERTAIN FEDERAL INCOME TAX CONSEQUENCES
The following discussion is based on the current provisions of the
Internal Revenue Code of 1986, as amended (the "Code"), applicable Treasury
regulations, judicial authority and administrative rulings and practice. There
can be no assurance that the Internal Revenue Service (the "Service") will not
take a contrary view, and no ruling from the Service has been or will be
sought. Legislative, judicial or administrative changes or interpretations may
be forthcoming that could alter or modify the statements and conditions set
forth herein. Any such changes or interpretations may or may not be retroactive
and could affect the tax consequences to holders. Certain holders
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<PAGE> 125
(including insurance companies, tax-exempt organizations, financial
institutions, broker-dealers, foreign corporations and persons who are not
citizens or residents of the United States) may be subject to special rules not
discussed below. The Company recommends that each holder consult such holder's
own tax advisor as to the particular tax consequences of exchanging such
holder's outstanding notes for new notes, including the applicability and
effect of any state, local or foreign tax laws.
The Company believes that the exchange of outstanding notes for new
notes pursuant to the exchange offer will not be treated as an "exchange" for
federal income tax purposes because the new notes will not be considered to
differ materially in kind or extent from the outstanding notes. Rather, the new
notes received by a holder will be treated as a continuation of the outstanding
notes in the hands of such holder. As a result, there will be no federal income
tax consequences to holders exchanging outstanding notes for new notes pursuant
to the exchange offer.
PLAN OF DISTRIBUTION
Based on interpretations by the staff of the SEC in no action letters
issued to third parties, the Company believes that any holder may transfer new
notes issued under the exchange offer in exchange for the outstanding notes if:
o the holder acquires the new notes in the ordinary course of its
business
o the holder is not engaged in, and does not intend to engage in,
and has no arrangement or understanding with any person to
participate in, a distribution of such new notes
Broker-dealers receiving new notes in the exchange offer will be
subject to a prospectus delivery requirement with respect to resales of the new
notes.
The Company believes that a holder may not transfer new notes issued
under the exchange offer in exchange for the outstanding notes if that holder
is:
o an "affiliate" of the Company within the meaning of Rule 405
under the Securities Act
o a broker-dealer that acquired outstanding notes directly from
the Company
o a broker-dealer that acquired outstanding notes as a result of
market-making or other trading activities without compliance
with the registration and prospectus delivery provisions of the
Securities Act
To date, the staff of the SEC has taken the position that
participating broker-dealers may fulfill their prospectus deliver requirements
with respect to transactions involving an exchange of securities such as this
exchange offer, other than a resale of an unsold allotment from the original
sale of the outstanding notes, with the prospectus contained in the exchange
offer registration statement. In the Registration Rights Agreement, the Company
has agreed to permit participating broker-dealers to use this prospectus in
connection with the resale of new notes. The Company has agreed that, for a
period of up to 180 days after the expiration of the exchange offer, the
Company will make this prospectus, and any amendment or supplement to this
prospectus, available to any broker-dealer that requests such documents in the
letter of transmittal.
If a holder wishes to exchange its outstanding notes for new notes in
the exchange offer, the holder will be required to make representations to us
as described in "The Exchange Offer -- Purpose and Effect of the Exchange
Offer" and "-- Procedures for Tendering -- Representations to the Company" of
this prospectus and in the letter of transmittal. In addition, if a
broker-dealer receives new notes for its own account in exchange for
outstanding notes that were acquired by it as a result of market-making
activities or other trading activities, it will be required to acknowledge that
it will deliver a prospectus in connection with any resale by it of such new
notes.
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<PAGE> 126
The Company will not receive any proceeds from any sale of new notes
by broker-dealers. Broker-dealers who receive new notes for their own account
in the exchange offer may sell them from time to time in one or more
transactions in the over-the-counter market:
o in negotiated transactions
o through the writing of options on the new notes or a combination
of such methods of resale
o at market prices prevailing at the time of resale
o at prices related to such prevailing market prices or 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 new notes. Any broker-dealer
that resells new notes it received for its own account in the exchange offer
and any broker or dealer that participates in a distribution of such new notes
may be deemed to be an "underwriter" within the meaning of the Securities Act.
Any profit on any resale of new notes and any commissions or concessions
received by any such persons may be deemed to be underwriting compensation
under the Securities Act. The letter of transmittal states that by
acknowledging that it will deliver and by delivering a prospectus, a
broker-dealer will not be deemed to admit that it is an "underwriter" within
the meaning of the Securities Act.
The Company has agreed to pay all expenses incidental to the exchange
offer other than commissions and concessions of any brokers or dealers. The
Company will indemnify holders of the outstanding notes, including any
broker-dealers, against certain liabilities, including liabilities under the
Securities Act, as provided in the Registration Rights Agreement.
TRANSFER RESTRICTIONS ON OUTSTANDING NOTES
The outstanding notes were not registered under the Securities Act.
Those outstanding notes may not be offered or sold in the United States or to,
or for the account or benefit of, U.S. persons except in accordance with an
exemption from the Securities Act registration requirements. Accordingly, the
outstanding notes were offered and sold only in the United States to "qualified
institutional buyers" under Rule 144A under the Securities Act in a private
sale exempt from the registration requirements of the Securities Act.
LEGAL MATTERS
The validity of the issuance of the new notes is being passed upon
for the Company by Gerald A. Morton, Vice President-Law and Corporate Secretary
of the Company. Mr. Morton owns approximately 3,961 shares of the Company's
Common Stock directly and through the Company's tax advantaged savings plan and
options to purchase an aggregate of 29,000 shares of the Company's common
stock, which are or become exercisable in periodic installments through August
1, 2001.
EXPERTS
The consolidated financial statements of Pogo Producing Company as of
December 31, 1997 and 1996, and for the three years in the period ended
December 31, 1997, incorporated by reference in this prospectus have been
audited by Arthur Andersen LLP, independent public accountants, as indicated in
their report with respect thereto, and are incorporated by reference herein in
reliance upon the authority of that firm as experts in accounting and auditing
in giving that report.
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The estimates of oil and gas reserves set forth herein and in the
Annual Report, and the related estimates set forth herein and therein of
discounted present values of estimated future net revenues therefrom, are
extracted from the report of Ryder Scott attached as an exhibit to the Annual
Report. Such information is incorporated by reference herein in reliance on the
authority of that firm as experts with respect to matters contained in that
report.
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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
Consolidated Financial Statements of Pogo Producing Company ----
<S> <C>
Report of Independent Public Accountants................................................................ F-2
Consolidated Statements of Income for the Years Ended December 31, 1997, 1996, and
1995................................................................................................. F-3
Consolidated Balance Sheets as of December 31, 1997 and 1996............................................ F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 1997, 1996
and 1995............................................................................................. F-5
Consolidated Statements of Shareholders' Equity for the Years Ended December 31,
1997, 1996, and 1995................................................................................. F-6
Notes to Consolidated Financial Statements.............................................................. F-7
</TABLE>
F-1
<PAGE> 129
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Pogo Producing Company:
We have audited the accompanying consolidated balance sheets of Pogo
Producing Company (a Delaware corporation) and subsidiaries as of December 31,
1997 and 1996, and the related consolidated statements of income, shareholders'
equity and cash flows for each of the three years in the period ended December
31, 1997. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Pogo Producing Company and
subsidiaries as of December 31, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
February 13, 1998
F-2
<PAGE> 130
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1997 1996 1995
---------- ---------- ----------
(EXPRESSED IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C>
Revenues:
Oil and gas..................... $ 285,200 $ 204,142 $ 157,459
Gains (losses) on sales......... 1,100 (165) 100
---------- ---------- ----------
Total...................... 286,300 203,977 157,559
---------- ---------- ----------
Operating Costs and Expenses:
Lease operating................. 63,501 37,628 35,071
General and administrative...... 21,412 18,028 16,400
Exploration..................... 10,530 16,777 7,468
Dry hole and impairment......... 9,631 8,579 6,703
Depreciation, depletion and
amortization.................. 103,157 61,857 68,489
---------- ---------- ----------
Total...................... 208,231 142,869 134,131
---------- ---------- ----------
Operating Income..................... 78,069 61,108 23,428
Interest:
Charges......................... (21,886) (13,203) (11,167)
Income.......................... 453 232 26
Capitalized..................... 6,175 4,244 1,834
Foreign Currency Transaction Loss.... (7,604) -- --
---------- ---------- ----------
Income Before Taxes and Extraordinary
Item............................... 55,207 52,381 14,121
---------- ---------- ----------
Income Tax Expense................... (18,091) (18,800) (4,891)
---------- ---------- ----------
Income Before Extraordinary Item..... 37,116 33,581 9,230
Extraordinary Loss on Early
Extinguishment of Debt, net of
taxes.............................. -- (821) --
---------- ---------- ----------
Net Income........................... $ 37,116 $ 32,760 $ 9,230
========== ========== ==========
Earnings per Share (restated for 1996
and 1995):
Basic
Before extraordinary
item.................... $ 1.11 $ 1.01 $ 0.28
Extraordinary item......... -- (0.02) --
---------- ---------- ----------
Net income................. $ 1.11 $ 0.99 $ 0.28
========== ========== ==========
Diluted
Before extraordinary
item.................... $ 1.06 $ 0.97 $ 0.28
Extraordinary item......... -- (0.02) --
---------- ---------- ----------
Net income................. $ 1.06 $ 0.95 $ 0.28
========== ========== ==========
Dividends per Common Share........... $ 0.12 $ 0.12 $ 0.12
========== ========== ==========
</TABLE>
The accompanying notes to consolidated financial
statements are an integral part hereof.
F-3
<PAGE> 131
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1997 1996
----------- -----------
(EXPRESSED IN THOUSANDS)
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash investments ......... $ 19,646 $ 3,054
Accounts receivable ............... 39,540 30,031
Other receivables ................. 46,951 35,027
Inventory -- product .............. 713 --
Inventories -- tubulars ........... 8,334 6,165
Other ............................. 4,087 641
----------- -----------
Total current assets ......... 119,271 74,918
----------- -----------
Property and Equipment:
Oil and gas, on the basis of
successful efforts accounting
Proved properties being
amortized ................ 1,321,817 1,079,523
Unevaluated properties and
properties under
development, not being
amortized ................ 110,231 111,192
Other, at cost .................... 12,619 8,773
----------- -----------
1,444,667 1,199,488
Less -- accumulated
depreciation, depletion, and
amortization, including $6,004
and $4,822 respectively,
applicable to other property ..... 917,363 814,623
----------- -----------
527,304 384,865
----------- -----------
Other .................................. 30,042 19,459
----------- -----------
$ 676,617 $ 479,242
=========== ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable -- operating
activities ....................... $ 13,639 $ 7,676
Accounts payable -- investing
activities ....................... 90,833 56,961
Accrued interest payable .......... 3,130 1,957
Accrued payroll and related
benefits ......................... 1,938 1,490
Other ............................. 632 163
----------- -----------
Total current
liabilities .............. 110,172 68,247
Long-Term Debt ......................... 348,179 246,230
Deferred Federal Income Tax ............ 57,502 46,321
Deferred Credits ....................... 14,658 11,162
----------- -----------
Total liabilities ............ 530,511 371,960
----------- -----------
Shareholders' Equity:
Preferred stock, $1 par;
2,000,000 shares authorized ...... -- --
Common stock, $1 par;
100,000,000 shares authorized,
and 33,552,702 and 33,321,381
shares issued, respectively ...... 33,553 33,321
Additional capital ................ 144,848 139,337
Retained earnings (deficit) ....... (31,971) (65,075)
Treasury stock and other, at
cost ............................. (324) (301)
----------- -----------
Total shareholders'
equity ................... 146,106 107,282
----------- -----------
$ 676,617 $ 479,242
=========== ===========
</TABLE>
The accompanying notes to consolidated financial
statements are an integral part hereof.
F-4
<PAGE> 132
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------
1997 1996 1995
--------- --------- ---------
(EXPRESSED IN THOUSANDS)
<S> <C> <C> <C>
Cash flows from operating activities:
Cash received from customers ......................................................... $ 272,004 $ 195,931 $ 164,065
Federal income taxes received ........................................................ 7,037 -- 6,000
Operating, exploration, and general and administrative expenses paid ................. (86,445) (74,512) (56,997)
Interest paid ........................................................................ (20,713) (12,960) (11,036)
Federal income taxes paid ............................................................ (19,500) 12,500) (6,000)
Other ................................................................................ (1,651) (3,061) 301
--------- --------- ---------
Net cash provided by operating activities ....................................... 150,732 92,898 96,333
--------- --------- ---------
Cash flows from investing activities:
Capital expenditures ................................................................. (197,326) (172,032) (96,403)
Purchase of proved reserves .......................................................... (31,234) -- (11,921)
Proceeds from the sale of property and tubular stock ................................. 387 100 100
--------- --------- ---------
Net cash used in investing activities ........................................... (228,173) (171,932) (108,224)
--------- --------- ---------
Cash flows from financing activities:
Proceeds from issuance of new debt ................................................... 100,000 115,000 --
Borrowings under senior debt agreements .............................................. 502,000 208,000 199,000
Payments under senior debt agreements ................................................ (500,000) (201,000) (182,000)
Proceeds from exercise of stock options .............................................. 3,874 3,378 1,717
Payment of cash dividends on common stock ............................................ (4,012) (3,979) (3,946)
Debt issue expenses paid ............................................................. (3,165) (3,116) --
Purchase of 8% debentures due 2005 ................................................... -- (40,699) (450)
Principal payments of other long-term debt obligations ............................... -- -- (871)
--------- --------- ---------
Net cash provided by financing activities ....................................... 98,697 77,584 13,450
--------- --------- ---------
Effect of exchange rate changes on cash .................................................. (4,664) 23 --
--------- --------- ---------
Net increase (decrease) in cash and cash investments ..................................... 16,592 (1,427) 1,559
Cash and cash investments at the beginning of the year ................................... 3,054 4,481 2,922
--------- --------- ---------
Cash and cash investments at the end of the year ......................................... $ 19,646 $ 3,054 $ 4,481
========= ========= =========
Reconciliation of net income to net cash provided by operating activities:
Net income ........................................................................... $ 37,116 $ 32,760 $ 9,230
Adjustments to reconcile net income to net cash provided by operating activities
Extraordinary losses on early extinguishments of debt, net of taxes ............. -- 821 --
Foreign currency transaction loss ............................................... 7,604 -- --
(Gains) losses on sales ......................................................... (1,100) 165 (100)
Depreciation, depletion and amortization ........................................ 103,157 61,857 68,489
Dry hole and impairment ......................................................... 9,631 8,579 6,703
Interest capitalized ............................................................ (6,175) (4,244) (1,834)
Increase in deferred income tax ................................................. 12,999 7,175 5,592
Change in assets and liabilities:
(Increase) decrease in accounts receivable .................................. (12,483) (8,211) 7,095
Increase in inventory -- product ............................................ (713) -- --
(Increase) decrease in other current assets ................................. (6,470) 81 23
Increase in other assets .................................................... (7,418) (5,228) (1,187)
Increase (decrease) in accounts payable ..................................... 8,998 (2,079) 1,942
Increase in accrued interest payable ........................................ 1,173 243 131
Increase in accrued payroll and related benefits ............................ 448 251 2
Increase in other current liability ......................................... 469 60 63
Increase in deferred credits ................................................ 3,496 668 184
--------- --------- ---------
Net cash provided by operating activities ................................................ $ 150,732 $ 92,898 $ 96,333
========= ========= =========
</TABLE>
The accompanying notes to consolidated financial
statements are an integral part hereof.
F-5
<PAGE> 133
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
TREASURY
RETAINED STOCK SHARE-
SHARES COMMON ADDITIONAL EARNINGS AND HOLDERS'
OUTSTANDING STOCK CAPITAL (DEFICIT) OTHER EQUITY
---------- ---------- ---------- ---------- ---------- ----------
(DOLLARS EXPRESSED IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
BALANCE AT DECEMBER 31, 1994 ........... 32,810,261 $ 32,826 $ 130,675 $ (99,140) $ (324) $ 64,037
Net income ............................. -- -- -- 9,230 -- 9,230
Exercise of stock options .............. 181,136 181 2,206 -- -- 2,387
Dividends ($0.12 per common share) ..... -- -- -- (3,946) -- (3,946)
---------- ---------- ---------- ---------- ---------- ----------
BALANCE AT DECEMBER 31, 1995 ........... 32,991,397 33,007 132,881 (93,856) (324) 71,708
Net income ............................. -- -- -- 32,760 -- 32,760
Foreign currency translation gain ...... -- -- -- -- 23 23
Exercise of stock options .............. 274,714 274 4,924 -- -- 5,198
Shares issued in connection with the
Long-Term Incentive Plan ............. 5,896 6 246 -- -- 252
Shares issued in connection with the
conversion of --
8% Debentures ..................... 32,898 33 1,267 -- -- 1,300
2004 Notes ........................ 901 1 19 -- -- 20
Dividends ($0.12 per common share) ..... -- -- -- (3,979) -- (3,979)
---------- ---------- ---------- ---------- ---------- ----------
BALANCE AT DECEMBER 31, 1996 ........... 33,305,806 33,321 139,337 (65,075) (301) 107,282
Net income ............................. -- -- -- 37,116 -- 37,116
Foreign currency translation loss ...... -- -- -- -- (23) (23)
Exercise of stock options .............. 229,024 230 5,461 -- -- 5,691
Shares issued in connection with the
conversion of 2004 Notes ............. 2,297 2 50 -- -- 52
Dividends ($0.12 per common share) ..... -- -- -- (4,012) -- (4,012)
---------- ---------- ---------- ---------- ---------- ----------
BALANCE AT DECEMBER 31, 1997 ........... 33,537,127 $ 33,553 $ 144,848 $ (31,971) $ (324) $ 146,106
========== ========== ========== ========== ========== ==========
</TABLE>
The accompanying notes to consolidated financial
statements are an integral part hereof.
F-6
<PAGE> 134
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations --
Pogo Producing Company was incorporated in 1970. Pogo Producing Company and
its subsidiaries (the "Company") are engaged in oil and gas exploration,
development and production activities on its properties located offshore in the
Gulf of Mexico and onshore in the United States and internationally in the Gulf
of Thailand. The Company has interests in 101 lease blocks offshore Louisiana
and Texas, approximately 237,000 gross acres onshore in the United States and
approximately 734,000 gross acres offshore in the Kingdom of Thailand.
Use of Estimates --
The preparation of these financial statements require the use of certain
estimates by management in determining the Company's assets, liabilities,
revenues and expenses. Depreciation, depletion and amortization of oil and gas
properties and the impairment of oil and gas properties are determined using
estimates of proved oil and gas reserves. There are numerous uncertainties in
estimating the quantity of proved reserves and in projecting the future rates of
production and timing of development expenditures. Oil and gas reserve
engineering must be recognized as a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact way. Proved
reserves of crude oil, condensate, natural gas and natural gas liquids are
estimated quantities that geological and engineering data demonstrate with
reasonable certainty to be recoverable in the future from known reservoirs under
existing conditions.
Principles of Consolidation --
The consolidated financial statements include the accounts of Pogo
Producing Company and its subsidiary and affiliated companies, after elimination
of all significant intercompany transactions. Majority owned subsidiaries are
fully consolidated. Minority owned subsidiaries or affiliates are pro rata
consolidated in the same manner as the Company, and the oil and gas industry
generally, accounts for its operating or working interest in oil and gas joint
ventures.
Prior-Year Reclassifications --
Certain prior-year amounts have been reclassified to conform with the
current year presentation.
Foreign Currency --
The U. S. Dollar is the functional currency for all areas of operations of
the Company. Accordingly, monetary assets and liabilities and items of income
and expense denominated in a foreign currency are remeasured to U. S. dollars at
the rate of exchange in effect at the end of each month and the resulting gains
or losses on foreign currency transactions are included in the consolidated
statements of income for the period.
Inventory -- Product
Crude oil and condensate from the Company's Tantawan field located in the
Kingdom of Thailand is produced into a floating production, storage and off
loading ("FPSO") system and sold periodically as an economic barge quantity is
accumulated. The product inventory at December 31, 1997 consists of
approximately 43,000 barrels of crude oil and condensate, net to the Company's
interest, and is carried at its estimated net realizable value of $16.67 per
barrel.
Inventory -- Tubulars
Tubular Inventories consist primarily of goods used in the Company's
operations and are stated at the lower of average cost or market value.
F-7
<PAGE> 135
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Interest Capitalized --
Interest costs related to financing major oil and gas projects in progress
are capitalized until the projects are evaluated or until production commences
if the projects are evaluated as successful.
Earnings per Share --
In 1997, the Company adopted the Financial Accounting Standards Board's
Statement of Financial Accounting Standards No. 128, Earnings Per Share ("SFAS
128"). Prior years have been restated in conformity with the provisions of SFAS
128. Earnings per common share (basic earnings per share) are based on the
weighted average number of shares of common stock outstanding during the
periods. Earnings per common share and potential common share (diluted earnings
per share) consider the effect of dilutive securities as set out below in
thousands, except per share amounts.
<TABLE>
<CAPTION>
FOR THE YEAR ENDED
DECEMBER 31, 1997
-----------------------------
INCOME SHARES PER SHARE
------- ------- -------
<S> <C> <C> <C>
BASIC EARNINGS PER SHARE ........................................ $37,116 33,421 $ 1.11
Effect of potential dilutive
securities:
Shares assumed issued from the exercise of options to
purchase common shares, net of treasury shares
assumed purchased from the proceeds, at the average
market price for the period .............................. -- 758 --
Interest expense avoided, net of taxes, and shares issued
from the assumed conversion at $22.188 per share of
the 2004 Notes ........................................... 3,082 3,885
------- ------- -------
DILUTED EARNINGS PER SHARE ...................................... $40,198 38,064 $ 1.06
======= ======= =======
Antidilutive securities:
Shares assumed not issued from options to purchase
common shares as the exercise prices are above the
average market price for the period ...................... -- 471 $ 40.82
Interest expense incurred, net of taxes, and shares not
issued related to the assumed non-conversion at
$42.185 per share of the 2006 Notes ...................... $ 4,111 2,726 $ 1.51
</TABLE>
F-8
<PAGE> 136
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
FOR THE YEAR ENDED
DECEMBER 31, 1996
-----------------------------
INCOME(a) SHARES PER SHARE
------- ------- -------
<S> <C> <C> <C>
BASIC EARNINGS PER SHARE ........................................ $33,581 33,203 $ 1.01
Effect of potential dilutive securities:
Shares issued from the assumed exercise of options to
purchase common shares, net of treasury shares
assumed purchased from the proceeds, at the average
market price for the period .............................. -- 831 --
Interest expense avoided, net of taxes, and shares issued
from the assumed conversion at $22.188 per share of
the 2004 Notes ........................................... 3,083 3,886
------- ------- -------
DILUTED EARNINGS PER SHARE ...................................... $36,664 37,920 $ 0.97
======= ======= =======
(a) Computed on income before extraordinary item
Antidilutive securities:
Shares assumed not issued from options to purchase
common shares as the exercise prices are above the
average market price for the period ...................... -- 20 $ 40.94
Interest expense incurred, net of taxes, and shares not
issued related to the assumed non-conversion at $39.50
per share of the 8% Debentures, retired on
June 28, 1996 ............................................ $ 1,179 521 $ 2.26
Interest expense incurred, net of taxes, and shares not issued
related to the assumed non-conversion at $42.185 per share
of the 2006 Notes ............................................. $ 2,238 1,472 $ 1.52
</TABLE>
<TABLE>
<CAPTION>
FOR THE YEAR ENDED
DECEMBER 31, 1995
--------------------------
INCOME SHARES PER SHARE
------ ------ ------
<S> <C> <C> <C>
BASIC EARNINGS PER SHARE ........................................ $9,230 32,893 $ 0.28
Effect of potential dilutive
securities:
Shares issued from the assumed exercise of options to
purchase common shares, net of treasury shares
assumed purchased from the proceeds, at the average
market price for the period .............................. -- 597 --
------ ------ ------
DILUTED EARNINGS PER SHARE ...................................... $9,230 33,490 $ 0.28
====== ====== ======
Antidilutive securities:
Shares assumed not issued from options to purchase
common shares as the exercise prices are above the
average market price for the period ...................... -- 598 $22.13
Interest expense incurred, net of taxes, and shares not
issued related to the assumed non-conversion at $39.50
per share of the 8% Debentures ........................... $2,229 1,085 $ 2.05
Interest expense incurred, net of taxes, and shares not
issued related to the assumed non-conversion at $22.188
per share of the 2004 Notes .............................. $3,083 3,887 $ 0.79
</TABLE>
F-9
<PAGE> 137
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Production Imbalances --
Owners of an oil and gas property often take more or less production from a
property than entitled to based on their ownership percentages in the property.
This results in a condition known in the industry as a production imbalance. The
Company follows the "take" (cash) method of accounting for production
imbalances. Under this method, the Company recognizes revenues on production as
it is taken and delivered to its purchasers. The Company's crude oil imbalances
are not significant. At December 31, 1997, the Company had taken approximately
3,751 MMcf of natural gas less than it was entitled to based on its interest in
those properties, and approximately 1,757 MMcf more than its entitlement on
other properties placing the Company at year end in a net under-delivered
position of approximately 1,994 MMcf of natural gas based on its working
interest ownership in the properties.
Oil and Gas Activities and Depreciation, Depletion and Amortization --
The Company follows the successful efforts method of accounting for its oil
and gas activities. Under the successful efforts method, lease acquisition costs
and all development costs are capitalized. Proved properties are reviewed
whenever events or changes in circumstances indicate that the value of such
property on the Company's books may not be recoverable. Unproved properties are
reviewed quarterly to determine if there has been impairment of the carrying
value, with any such impairment charged to expense in the period. Exploratory
drilling costs are capitalized until the results are determined. If proved
reserves are not discovered, the exploratory drilling costs are expensed. Other
exploratory costs are expensed as incurred. The provision for depreciation,
depletion and amortization is based on the capitalized costs as determined
above, plus future costs to abandon offshore wells and platforms, and is on a
cost center by cost center basis using the units of production method. The
Company generally creates cost centers on a field by field basis for oil and gas
activities in the Gulf of Mexico and the Gulf of Thailand. Generally, the
Company establishes cost centers on the basis of an oil or gas trend or play for
its oil and gas activities onshore in the United States.
Other properties are depreciated using a straight-line method in amounts
which in the opinion of management are adequate to allocate the cost of the
properties over their estimated useful lives.
Consolidated Statements of Cash Flows --
For the purpose of cash flows, the Company considers all highly liquid
investments with a maturity date of three months or less to be cash equivalents.
Significant transactions may occur which do not directly affect cash balances
and as such will not be disclosed in the Consolidated Statements of Cash Flows.
Certain such noncash transactions are disclosed in the Consolidated Statements
of Shareholders' Equity relating to shares issued in connection with the
Long-Term Incentive Plan and the conversion of debentures into Common Stock in
1996 and 1997.
Commitments and Contingencies --
The Company has commitments for operating leases for office space in
Houston, Midland and Bangkok and commitments for an operating lease and
operating expenses related to a floating production, storage and off-loading
vessel (FPSO) in the Gulf of Thailand. Rental expense for office space was
$1,440,000 in 1997, $1,054,000 in 1996, and $861,000 in 1995. Expenses for the
FPSO lease and related
F-10
<PAGE> 138
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
operating costs were $14,809,000 in 1997. Future minimum office and FPSO lease
expenses and related FPSO operating expense payments (in thousands of dollars)
at December 31, 1997 are as follows:
<TABLE>
<CAPTION>
<S> <C>
1998................................. $ 17,826
1999................................. 17,830
2000................................. 17,758
2001................................. 17,758
2002................................. 16,611
Thereafter........................... 91,352
</TABLE>
(2) INCOME TAXES
The components of income (loss) before income taxes for each of the three
years in the period ended December 31, 1997, are as follows (expressed in
thousands):
<TABLE>
<CAPTION>
1997 1996 1995
--------- --------- ---------
<S> <C> <C> <C>
United States........................ $ 62,953 $ 56,380 $ 16,899
Foreign.............................. (7,746) (3,999) (2,778)
--------- --------- ---------
Total........................... $ 55,207 $ 52,381 $ 14,121
========= ========= =========
</TABLE>
The components of federal income tax expense (benefit) for each of the
three years in the period ended December 31, 1997, are as follows (expressed in
thousands):
<TABLE>
<CAPTION>
1997 1996 1995
--------- --------- ---------
<S> <C> <C> <C>
United States, current............... $ 16,000 $ 12,500 $ --
United States, deferred(a)........... 5,964 7,162 5,602
Foreign, deferred.................... (3,873) (862) (711)
--------- --------- ---------
Total........................... $ 18,091 $ 18,800 $ 4,891
========= ========= =========
</TABLE>
- ------------
(a) Excludes $443,000 of deferred tax benefit on extraordinary loss of
$1,264,000 in 1996.
Total federal income tax expense (benefit) for each of the three years in
the period ended December 31, 1997, differs from the amounts computed by
applying the statutory federal income tax rate to income before taxes as follows
(expressed as a percent of pretax income):
<TABLE>
<CAPTION>
1997 1996 1995
--------- --------- ---------
<S> <C> <C> <C>
Federal statutory income tax rate.... 35.0% 35.0% 35.0%
Increases (reductions) resulting
from:
Statutory depletion in excess of
tax basis....................... (0.2) (0.2) (2.2)
Foreign taxes................... (2.1) 1.1 1.6
Other........................... 0.1 -- 0.2
--------- --------- ---------
32.8% 35.9% 34.6%
========= ========= =========
</TABLE>
Deferred income taxes are determined based upon the differences between the
financial statement and tax basis of the Company's assets and liabilities using
enacted tax rates in effect for the years in which the differences are expected
to reverse. Deferred tax assets are recognized if it is more likely than not
that the
F-11
<PAGE> 139
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
future tax benefit will be realized. The principal components of the Company's
deferred income tax assets and liabilities include the following at December 31,
1997 and 1996 (expressed in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------
1997 1996
--------- ---------
<S> <C> <C>
Deferred tax liabilities:
Intangible drilling costs, capitalized and amortized for
financial statement purposes and deducted for income
tax purposes ............................................... $ 204,218 $ 184,981
Charges to property and equipment, expensed for financial
statement purposes, and capitalized and amortized for
income tax purposes ........................................ 12,203 8,089
Interest charges, capitalized and amortized for financial
statement purposes and deducted for income tax purposes .... 19,762 21,046
--------- ---------
236,183 214,116
Deferred tax asset:
Differences in depletion and depreciation rates used for
tangible assets for financial and income tax purposes ...... (178,681) (167,795)
--------- ---------
Net deferred tax liability ........................................ $ 57,502 $ 46,321
========= =========
</TABLE>
(3) LONG-TERM DEBT
Long-term debt and the amount due within one year at December 31, 1997 and
1996, consists of the following (dollars expressed in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1997 1996
-------- --------
<S> <C> <C>
Senior debt --
Bank revolving credit agreement debt:
LIBO Rate based loans, borrowings at December 31, 1997
and 1996 at average interest rates of 6.52% and 6.59%,
respectively ............................................ $ 47,000 $ 22,000
Prime rate based loans, borrowing at December 31, 1996
at an interest rate of 8.25% ............................ -- 13,000
-------- --------
Total bank revolving credit agreement debt ............ 47,000 35,000
Uncommitted credit lines with banks, borrowing at
December 31, 1996 at an average interest rate of 7.0% ... -- 10,000
-------- --------
Total senior debt .................................................... 47,000 45,000
-------- --------
Subordinated debt --
8 3/4% Senior subordinated notes, due 2007 (issued
May 22, 1997) ................................................. 100,000 --
5 1/2% Convertible subordinated notes, due 2004 ................. 86,179 86,230
5 1/2% Convertible subordinated notes, due 2006 ................. 115,000 115,000
-------- --------
Total subordinated debt .............................................. 301,179 201,230
-------- --------
Total debt ........................................................... 348,179 246,230
-------- --------
Amount due within one year -- ........................................ -- --
-------- --------
Long-term debt ....................................................... $348,179 $246,230
======== ========
</TABLE>
F-12
<PAGE> 140
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Effective August 1, 1997, the Company entered into an amended and restated
credit agreement (as so amended and restated, the "Credit Agreement"). The
Credit Agreement provides for an unsecured $250,000,000 revolving/term credit
facility which will be fully revolving until July 1, 2000, after which the
balance will be due in eight quarterly term loan installments, commencing
October 31, 2000. The amount that may be borrowed under the Credit Agreement may
not exceed a borrowing base which is composed of both domestic and Thai
properties less, in certain circumstances, the present value of interest
payments on the 2007 Notes. The domestic borrowing base is determined
semiannually by the lenders in accordance with the Credit Agreement, based
primarily on the discounted present value of future net revenues from the
Company's domestic oil and gas reserves. The portion of the borrowing base which
composed of properties located in the Kingdom of Thailand is also determined
semiannually, but may, at the lenders' discretion, be redetermined once more
during each semiannual period. The value of this portion of the borrowing base
is determined by the lenders applying their usual and customary criteria for oil
and gas evaluation. As of January 1, 1998, the Company's total borrowing base,
including both domestic and Thai properties, exceeded $250,000,000. The Credit
Agreement is governed by various financial and other covenants, including
requirements to maintain positive working capital (excluding current maturities
of debt) and fixed charge coverage ratio, and limitations on indebtedness,
creation of liens, the prepayment of subordinated debt, the payment of
dividends, mergers and consolidation, investments and asset dispositions. In
addition, the Company is prohibited from pledging borrowing base properties as
security for other debt. Borrowings under the Credit Agreement currently bear
interest at a base (prime) rate or LIBOR plus 5/8%, at the Company's option. A
commitment fee on the unborrowed amount under the Credit Agreement is also
charged. The commitment fee is currently 0.25% per annum on the unborrowed
amount under the Credit Agreement that is designated as "active" and 0.10% per
annum on the unborrowed amount under the Credit Agreement that is designated as
"inactive." Of the $250,000,000 that is currently available under the Credit
Agreement (subject to borrowing base limitations), $125,000,000 is designated as
"active" and $125,000,000 is designated as "inactive".
The Company has also entered into separate letter agreements with two banks
under which one of the banks may provide a $10,000,000 uncommitted money market
line of credit and the other bank may provide a $20,000,000 uncommitted money
market line of credit. Each line of credit is on an as available or offered
basis and neither bank has an obligation to make any advances under its
respective line of credit. Although loans made under these letter agreements are
for a maximum term of 30 days, they will be reflected as long-term on the
Company's balance sheet because the Company has the ability and intent to
reborrow such amounts under its Credit Agreement. Both letter agreements permit
either party to terminate such letter agreement at any time.
On May 22, 1997, the Company issued $100,000,000 of 8 3/4% Senior
Subordinated Notes due 2007 (the "2007 Notes"). The proceeds from the issuance
of the 2007 Notes were used to repay amounts outstanding under the Company's
bank revolving credit agreement, and to purchase short-term cash investments.
The 2007 Notes bear interest at a rate of 8 3/4%, payable semiannually in
arrears on May 15 and November 15 of each year, commencing November 15, 1997.
The 2007 Notes are general unsecured senior subordinated obligations of the
Company and are subordinated in right of payment to the Company's senior
indebtedness, which currently includes the Company's obligations under its bank
revolving credit agreement and its unsecured credit lines, but are senior in
right of payment to its subordinated indebtedness, which currently includes the
2006 Notes and the 2004 Notes. The Company, at its option, may redeem the 2007
Notes in whole or in part, at any time on or after May 15, 2002, at a redemption
price of 104.375% of their principal value and decreasing percentages
thereafter. No sinking fund payments are required on the 2007 Notes. The 2007
Notes are redeemable at the option of any holder, upon the occurrence of a
change of control (as defined in the indenture governing the 2007 Notes), at
101% of their principal amount. The indenture governing the 2007 Notes also
imposes certain covenants on the Company that are customary for senior
subordinated indebtedness generally, including covenants limiting: incurrence of
indebtedness
F-13
<PAGE> 141
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
including senior indebtedness; restricted payments; the issuance and sales of
restricted subsidiary capital stock; transactions with affiliates; liens;
disposition of proceeds of asset sales; non-guarantor restricted subsidiaries;
dividends and other payment restrictions affecting restricted subsidiaries; and
mergers, consolidations and the sale of assets. As of December 31, 1997,
$28,657,000 was available for dividends under this limitation, which is
currently the Company's most restrictive such covenant.
The 5 1/2% Convertible Subordinated Notes, due 2004 (the "2004 Notes")
are convertible into Common Stock at $22.188 per share subject to adjustment
upon the occurrence of certain events. The 2004 Notes will be redeemable at the
option of the Company, in whole or in part, at any time on or after March 15,
1998, at a redemption price of 103.3% and decreasing percentages thereafter. No
sinking fund is provided. The 2004 Notes are redeemable at the option of the
holder, upon the occurrence of a repurchase event (a change in control and other
circumstances, as defined), at 100% of the principal amount. On February 12,
1998, the Company announced its intent to redeem the 2004 Notes on March 16,
1998 at an amount equal to 103.3% of their principal amount plus accrued
interest. Holders may elect to convert the principal or any integral multiple of
a 2004 Note into common stock at $22.188 per share until close of business on
March 13, 1998.
The 5 1/2% Convertible Subordinated Notes, due 2006 (the "2006 Notes")
are convertible into Common Stock at $42.185 per share subject to adjustment
upon the occurrence of certain events. The 2006 Notes will be redeemable at the
option of the Company, in whole or in part, at any time on or after June 15,
1999, at a redemption price of 103.85% and decreasing percentages thereafter. No
sinking fund is provided. The 2006 Notes are redeemable at the option of the
holder, upon the occurrence of a repurchase event (a change in control and other
circumstances, as defined), at 100% of the principal amount.
Current maturities and sinking fund requirements during the next five years
in connection with the above long-term debt are none in 1998 and 1999,
$7,050,000 in 2000, $25,850,000 in 2001 and $14,100,000 in 2002. All of the
current maturities reflected above are related to the retirement of the
Company's bank debt. The Company has established a history of refinancing its
bank debt before scheduled maturity payments commence and expects to do so again
before the amortization of bank debt commences in 2000.
F-14
<PAGE> 142
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(4) GEOGRAPHIC SEGMENT REPORTING
During 1997, the Company adopted the Financial and Accounting Standard's
Board's Statement of Financial Accounting Standards No. 131, Disclosures about
Segments of an Enterprise and Related Information ("SFAS 131"). Information
concerning the Company's revenues and long-lived assets as required by SFAS 131
is as follows (in thousands of dollars):
<TABLE>
<CAPTION>
LONG-LIVED
REVENUES ASSETS
-------- --------
<S> <C> <C>
AS OF AND FOR THE YEAR ENDED DECEMBER 31, 1997
United States ............................... $245,458 $366,638
Kingdom of Thailand ......................... 39,393 160,666
-------- --------
$284,851 $527,304
======== ========
AS OF AND FOR THE YEAR ENDED DECEMBER 31, 1996
United States ............................... $203,364 $295,108
Kingdom of Thailand ......................... -- 89,757
-------- --------
$203,364 $384,865
======== ========
AS OF AND FOR THE YEAR ENDED DECEMBER 31, 1995
United States ............................... $156,729 $232,527
Kingdom of Thailand ......................... -- 29,306
-------- --------
$156,729 $261,833
======== ========
</TABLE>
(5) SALES TO MAJOR CUSTOMERS
The Company is an oil and gas exploration and production company that
generally sells its oil and gas to numerous customers on a month-to-month basis.
Sales to the following customers exceeded 10% of revenues during any one of the
three years indicated (expressed in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
------- ------- -------
<S> <C> <C> <C>
Enron Corp. and affiliates ....................... $57,965 $58,101 $42,895
Petroleum Authority of Thailand (PTT) ............ $30,108 $ -- $ --
Coastal Gas Marketing Company .................... $ -- $18,376 $18,117
</TABLE>
(6) CREDIT RISK
Substantially all of the Company's accounts receivable at December 31, 1997
and 1996, result from oil and gas sales and joint interest billings to other
companies in the oil and gas industry. This concentration of customers and joint
interest owners may impact the Company's overall credit risk, either positively
or negatively, in that these entities may be similarly affected by industry-wide
changes in economic or other conditions. Such receivables are generally not
collateralized. Historically, credit losses incurred by the Company on
receivables generally have not been material. No known material credit losses
were experienced during 1997 or 1996.
A substantial portion of the Company's oil and gas operations are conducted
in Southeast Asia, and a substantial portion of its natural gas and liquid
hydrocarbon production are sold there. In recent months, Southeast Asia in
general, and the Kingdom of Thailand in particular, have experienced severe
economic difficulties which have been characterized by sharply reduced economic
activity, illiquidity, highly volatile foreign currency exchange rates and
unstable stock markets. The government of the Kingdom of Thailand and other
governments in the region are currently acting to address these issues. However,
the economic difficulties currently being experienced in Thailand, together with
the volatility of the Thai Baht against the
F-15
<PAGE> 143
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
U.S. dollar, will continue to have a material impact on the Company's operations
in the Kingdom of Thailand, together with the prices that the Company receives
for its oil and natural gas production there.
All of the Company's current natural gas production from its Thailand
operations committed under a long term Gas Sales Agreement to PTT at a price
denominated in Thai Baht. The Company's crude oil and condensate production from
its Thailand operations is sold on a tanker load by tanker load basis. Prices
that the Company receives for such production are based on world benchmark
prices, which are denominated in U.S. dollars, and are currently expected on
future crude oil sales to be paid in U.S. dollars. The Company believes that the
current economic difficulties in Southeast Asia have resulted in a decreased
demand for petroleum products in the region, which has contributed to the recent
general decline in crude oil and condensate prices throughout the world.
(7) EMPLOYEE BENEFITS
As permitted by SFAS No. 123, the Company applies APB Opinion No. 25 and
related interpretations in accounting for its stock option plans. Since the
exercise price of the options granted is equal to the quoted market price of the
Company's stock at the date of grant, no compensation cost has been recognized
for its stock option plans. Had compensation costs been determined based on the
fair value at the grant dates for awards made in 1997, 1996, and 1995 consistent
with the methods of SFAS No. 123, the Company's net income and earnings per
share would have been reduced to the pro forma amounts indicated below (in
thousands, except for per share amounts):
<TABLE>
<CAPTION>
1997 1996 1995
---------- ---------- ----------
<S> <C> <C> <C>
Net income:
As reported ........................................... $ 37,116 $ 32,760 $ 9,230
Pro forma ............................................. $ 34,220 $ 31,194 $ 8,619
Earnings per share:
As reported (restated for 1996 and 1995) -- Basic ..... $ 1.11 $ 0.99 $ 0.28
As reported (restated for 1996 and 1995) -- Diluted ... $ 1.06 $ 0.95 $ 0.28
Pro forma -- Basic .................................... $ 1.04 $ 0.94 $ 0.26
Pro forma -- Diluted .................................. $ 0.99 $ 0.91 $ 0.26
</TABLE>
The fair value of grants was estimated on the date of grant using the Black
Scholes option pricing model with the following weighted-average assumptions
used in 1997, 1996, and 1995, respectively: risk-free interest rates of 6.10%,
6.25%, and 6.00%, expected volatility of 34.63%, 39.15%, and 41.78%, dividend
yields of 0.29%, 0.34%, and 0.54%, and an expected life of the options of 4
years in each of the years 1997, 1996, and 1995.
The Company has a tax-advantaged savings plan in which all salaried
employees may participate. Under such plan, a participating employee may
allocate up to 10% of his salary, up to a maximum allowed by law ($10,000 for
1998), and the Company will then match the employee's contribution on a dollar
for dollar basis up to 6% of the employee's salary. Funds contributed by the
employee and the matching funds contributed by the Company are held in trust by
a bank trustee in six separate funds. Amounts contributed by the employee and
earnings and accretions thereon may be used to purchase shares of Common Stock,
invest in a money market fund or invest in four stock, bond, or blended stock
and bond mutual funds according to instructions from the employee. Matching
funds contributed to the savings plan by the Company are invested only in Common
Stock. The Company contributed $588,000 to the savings plan in 1997, $471,000 in
1996, and $277,000 in 1995.
The Company's stock option plans authorize the granting of options to key
employees and non-employee directors at prices equivalent to the market value at
the date of grant. Options generally become exercisable in three annual
installments commencing one year after the date of grant and, if not exercised,
F-16
<PAGE> 144
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
expire 10 years from the date of grant. In 1996, the Company adopted the
Financial Accounting Standards Board's Statement of Financial Accounting
Standards No. 123, Accounting for Stock-Based Compensation ("SFAS No. 123").
As permitted by SFAS No. 123, the Company elected to continue to account for
employee stock-based compensation using the intrinsic value method prescribed by
Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to
Employees. Accordingly, the adoption of SFAS No. 123 had no effect on the
Company's results of operations in 1996 and 1997. A summary of the status of the
Company's plans as of December 31, 1997, 1996, and 1995, and changes during the
years ended on those dates is presented below:
<TABLE>
<CAPTION>
WEIGHTED
AVERAGE
NUMBER OF EXERCISE
OPTIONS PRICE
---------- ----------
<S> <C> <C>
Outstanding, December 31, 1994 ................................ 1,387,537 $ 11.72
Granted .................................................. 389,000 $ 22.34
Exercised ................................................ (181,136) $ 9.48
Forfeited or expired ..................................... (20,000) $ 14.88
----------
Outstanding, December 31, 1995 ................................ 1,575,401 $ 14.56
==========
Exercisable, December 31, 1995 ................................ 1,006,686 $ 10.87
==========
Available for grant, December 31, 1995 ........................ 1,719,893
==========
Weighted-average fair value of options granted during 1995 .... $ 8.77
Outstanding, December 31, 1995 ................................ 1,575,401 $ 14.56
Granted .................................................. 406,500 $ 34.59
Exercised ................................................ (274,714) $ 12.30
----------
Outstanding, December 31, 1996 ................................ 1,707,187 $ 19.70
==========
Exercisable, December 31, 1996 ................................ 1,077,658 $ 14.31
==========
Available for grant, December 31, 1996 ........................ 1,313,393
==========
Weighted-average fair value of options granted during 1996 .... $ 13.56
Outstanding, December 31, 1996 ................................ 1,707,187 $ 19.70
Granted .................................................. 480,400 $ 40.49
Exercised ................................................ (229,024) $ 16.83
----------
Outstanding, December 31, 1997 ................................ 1,958,563 $ 25.13
==========
Exercisable, December 31, 1997 ................................ 1,196,803 $ 18.15
==========
Available for grant, December 31, 1997 ........................ 832,993
==========
Weighted-average fair value of options granted during 1997 .... $ 14.63
</TABLE>
F-17
<PAGE> 145
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes information about stock options outstanding
at December 31, 1997:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING
---------------------------------------
WEIGHTED OPTIONS EXERCISABLE
AVERAGE -----------------------
REMAINING WEIGHTED WEIGHTED
CONTRACTUAL AVERAGE AVERAGE
RANGE OF NUMBER LIFE EXERCISE NUMBER EXERCISE
OPTION PRICES OUTSTANDING (DAYS) PRICE EXERCISABLE PRICE
- ------------------------------------- ------------ ----------- -------- ----------- --------
<S> <C> <C> <C> <C> <C>
$4.38........................... 92,750 12 $ 4.38 92,750 $ 4.38
$5.56 to $8.06.................. 349,361 1,107 $ 6.83 349,361 $ 6.83
$15.13 to $19.13................ 156,046 2,014 $16.46 156,046 $16.46
$20.31 to $23.88................ 484,838 2,620 $22.15 381,827 $22.17
$30.56 to $34.88................ 325,001 3,143 $33.91 102,319 $33.93
$35.13 to $38.94................ 82,667 3,150 $36.18 56,000 $36.03
$40.56 to $44.38................ 465,900 3,483 $40.80 58,500 $41.20
$48.75.......................... 2,000 3,306 $48.75 -- --
------------ -----------
Total........................... 1,958,563 2,493 $25.13 1,196,803 $18.15
============ ===========
</TABLE>
F-18
<PAGE> 146
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A trusteed retirement plan has been adopted by the Company for its salaried
employees. The benefits are based on years of service and the employee's average
compensation for five consecutive years within the final ten years of service
which produce the highest average compensation. The Company makes annual
contributions to the plan in the amount of retirement plan cost accrued or the
maximum amount which can be deducted for federal income tax purposes. The
following table sets forth the plan's funded status (in thousands of dollars) as
of December 31, 1997, 1996, and 1995.
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Actuarial present value (discounted at 7%, 7 1/4%, and
7 1/4%, respectively) of benefit obligations:
Accumulated benefit obligations --
Vested ................................................ $ 7,355 $ 6,408 $ 5,488
Non-vested ............................................ 1,536 1,138 1,173
-------- -------- --------
Total accumulated benefit obligations ................. 8,891 7,546 6,661
Projected salary increases (escalated at 5 1/2%, 5% and
5%, respectively) and other changes ...................... 2,329 1,804 1,734
-------- -------- --------
Projected benefit obligations for service rendered to
date ..................................................... 11,220 9,350 8,395
Plan assets at fair value, primarily listed securities with
an expected long-term rate of return of 9 1/2%, 8 1/2% and
8 1/2%, respectively .......................................... 31,312 24,181 19,089
-------- -------- --------
Plan assets in excess of projected benefit obligations .......... 20,092 14,831 10,694
Unrecognized:
Net overfunding being recognized over 15 years ............. (336) (440) (543)
Net gain arising from the difference between actual
experience and that assumed .............................. (13,134) (9,335) (5,989)
Prior service cost ......................................... (300) (343) (387)
-------- -------- --------
Accrued retirement plan asset ................................... $ 6,322 $ 4,713 $ 3,775
======== ======== ========
Retirement plan cost (benefit) for 1997, 1996, and 1995
included the following components:
Service cost, benefits accruing each year with
proration for future salary increases .................... $ 746 $ 621 $ 480
Interest cost on projected benefit obligations ........ 707 604 535
Actual return on plan assets .......................... (2,286) (1,615) (1,182)
Net amortization and deferral ......................... (775) (548) (333)
-------- -------- --------
Accrued retirement plan cost (benefit) ..................... $ (1,608) $ (938) $ (500)
======== ======== ========
</TABLE>
Although the Company has no obligation to do so, the Company currently
provides full medical benefits to its retired employees and dependents. For
current employees, the Company assumes all or a portion of post retirement
medical and term life insurance costs based on the employee's age and length of
service with the Company. The post retirement medical plan has no assets and is
currently funded by the Company on a pay-as-you-go basis.
F-19
<PAGE> 147
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following is an analysis (in thousands of dollars) of the annual
expense and activity in the deferred cost and benefits obligation accounts for
1995, 1996 and 1997. The computation assumes that future increases in medical
costs will trend down from 8.1% to 5% per year over the next 7 years for
purposes of estimating future costs. The medical cost trend rate assumption has
a significant effect on the amounts reported. Increasing the assumed medical
cost trend rate by one percent in each year would increase the aggregate of
service and interest cost components of net periodic post retirement benefit
cost for 1997 by $170,000 and the accumulated post retirement benefit obligation
as of December 31, 1997 by $1,104,000.
<TABLE>
<CAPTION>
ANNUAL DEFERRED BENEFIT
EXPENSE COSTS OBLIGATION
------- -------- ----------
<S> <C> <C> <C>
Balance at January 1, 1995 ........................................... $ 3,349 $(5,487)
Amortization of transition costs over 14 years representing the
average remaining service period of eligible employees ............. $ 304 (304) 304
Amortization of net gain from earlier periods ........................ (69) (69)
Service cost, including interest ..................................... 241
Interest cost on transition obligation ............................... 399
-------
1995 expense ......................................................... $ 875 (875)
=======
Current benefits paid ................................................ 145
Unrecognized net gain ................................................ 541
------- -------
Balance at December 31, 1995 ......................................... 3,045 (5,441)
Amortization of transition costs over 14 years ....................... $ 304 (304) 304
Amortization of net gain from earlier periods ........................ (41) (41)
Service cost, including interest ..................................... 268
Interest cost on transition obligation ............................... 387
-------
1996 expense ......................................................... $ 918 (918)
=======
Current benefits paid ................................................ 94
Unrecognized net gain ................................................ 107
------- -------
Balance at December 31, 1996 ......................................... 2,741 (5,895)
Amortization of transition costs over 14 years ....................... $ 305 (305) 305
Amortization of net gain from earlier periods ........................ (26) (26)
Service cost, including interest ..................................... 459
Interest cost on transition obligation ............................... 427
-------
1997 expense ......................................................... $ 1,165 (1,165)
=======
Current benefits paid ................................................ 99
Unrecognized net loss ................................................ (224)
-------
Balance at December 31, 1997 ......................................... $ 2,436
=======
Plan assets at fair value
-------
Funded status at December 31, 1997 (discounted at 7%) ................ $(6,906)
=======
</TABLE>
The accumulated postretirement benefit obligation (in thousands of dollars)
at December 31, 1997 is attributable to the following groups:
<TABLE>
<S> <C>
Retirees and beneficiaries.............. $1,951
Dependents of retirees.................. 978
Fully eligible active employees......... 802
Active employees, not fully eligible.... 3,175
----------
$6,906
==========
</TABLE>
F-20
<PAGE> 148
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(8) FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value.
Cash and Cash Investments
Fair value is carrying value as no cash equivalents or cash investments are
included in the balances as of December 31, 1997 and 1996.
Debt
<TABLE>
<CAPTION>
INSTRUMENT BASIS OF FAIR VALUE ESTIMATE
- -------------------------------------------------------------------------------
<S> <C>
Bank revolving credit agreement....... Fair value is carrying value as of
December 31, 1997 and 1996 based on the
market value interest rates.
Uncommitted credit lines with banks... Fair value is carrying value as of
December 31, 1997 and 1996 based on the
market value interest rates.
2007 Notes............................ Fair value is 102.5% of carrying value
as of December 31, 1997 based on a
quoted market value.
2004 Notes............................ Fair value is 140.38% and 166%, of
carrying value as of December 31, 1997
and 1996, respectively, based on quoted
market values.
2006 Notes............................ Fair value is 93.5% and 120%, of
carrying value as of December 31, 1997
and 1996, respectively, based on quoted
market values.
</TABLE>
The carrying value and estimated fair value of the Company's financial
instruments at December 31, 1997 and 1996 (in thousands of dollars) are as
follows:
<TABLE>
<CAPTION>
1997 1996
----------------------- -----------------------
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Cash and cash investments ................... $ 19,646 $ 19,646 $ 3,054 $ 3,054
Debt:
Bank revolving credit agreement ........ (47,000) (47,000) (35,000) (35,000)
Uncommitted credit lines with banks .... -- -- (10,000) (10,000)
2007 Notes ............................. (100,000) (102,500) -- --
2004 Notes ............................. (86,179) (120,978) (86,230) (143,142)
2006 Notes ............................. (115,000) (107,525) (115,000) (138,000)
</TABLE>
The Company occasionally enters into forward and futures contracts to
minimize the impact of oil and gas price fluctuations. However, the Company does
not consider its forward and futures contracts to be financial instruments since
these contracts require or permit settlement by the delivery of the underlying
commodity. Gains and losses on these activities are recognized in revenues when
the hedged production occurs. No such contracts were outstanding as of December
31, 1997 or 1996.
F-21
<PAGE> 149
UNAUDITED SUPPLEMENTARY FINANCIAL DATA
OIL AND GAS PRODUCING ACTIVITIES
The results of operations from oil and gas producing activities excludes
non-oil and gas revenues, general and administrative expenses, interest charges,
interest income and interest capitalized. United States income tax expense was
determined by applying the statutory rates to pretax operating results with
adjustments for permanent differences. Kingdom of Thailand tax expense was
determined by applying the statutory tax rate to Thailand taxable income.
<TABLE>
<CAPTION>
UNITED KINGDOM OF
TOTAL STATES THAILAND
--------- --------- ---------
(EXPRESSED IN THOUSANDS)
<S> <C> <C> <C>
1997
-------------------------------------
Revenues .............................................. $ 284,851 $ 245,458 $ 39,393
Lease operating expense ............................... (63,501) (43,934) (19,567)
Exploration expense ................................... (10,530) (6,242) (4,288)
Dry hole and impairment expense ....................... (9,631) (9,631) --
Depreciation, depletion and amortization expense ...... (101,273) (84,443) (16,830)
--------- --------- ---------
Pretax operating results .............................. 99,916 101,208 (1,292)
Income tax (expense) benefit .......................... (30,353) (32,390) 2,037
--------- --------- ---------
Operating results ..................................... $ 69,563 $ 68,818 $ 745
========= ========= =========
1996
-------------------------------------
Revenues .............................................. $ 204,142 $ 204,131 $ 11
Lease operating expense ............................... (37,628) (37,628) --
Exploration expense ................................... (16,777) (14,247) (2,530)
Dry hole and impairment expense ....................... (8,579) (8,834) 255
Depreciation, depletion and amortization expense ...... (61,033) (60,932) (101)
--------- --------- ---------
Pretax operating results .............................. 80,125 82,490 (2,365)
Income tax (expense) benefit .......................... (27,905) (28,767) 862
--------- --------- ---------
Operating results ..................................... $ 52,220 $ 53,723 $ (1,503)
========= ========= =========
1995
-------------------------------------
Revenues .............................................. $ 157,459 $ 157,536 $ (77)
Lease operating expense ............................... (35,071) (35,071) --
Exploration expense ................................... (7,468) (6,111) (1,357)
Dry hole and impairment expense ....................... (6,703) (6,703) --
Depreciation, depletion and amortization expense ...... (67,831) (67,798) (33)
--------- --------- ---------
Pretax operating results .............................. 40,386 41,853 (1,467)
Income tax (expense) benefit .......................... (13,623) (14,334) 711
--------- --------- ---------
Operating results ..................................... $ 26,763 $ 27,519 $ (756)
========= ========= =========
</TABLE>
F-22
<PAGE> 150
UNAUDITED SUPPLEMENTARY FINANCIAL DATA -- (CONTINUED)
The following table sets forth the Company's capitalized costs (expressed
in thousands) incurred for oil and gas producing activities during the years
indicated.
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Capitalized costs incurred:
Property acquisition -- United States ................. $ 14,492 $ 5,927 $ 14,864
Property acquisition -- Kingdom of Thailand ........... 28,617 -- 4,171
Exploration -- United States .......................... 24,016 20,651 14,562
Exploration -- Kingdom of Thailand .................... 21,187 8,317 5,418
Development -- United States .......................... 95,768 99,464 39,461
Development -- Kingdom of Thailand .................... 60,996 53,564 23,994
Interest capitalized -- United States ................. 3,331 4,244 1,834
Interest capitalized -- Kingdom of Thailand ........... 2,748 -- --
-------- -------- --------
$251,155 $192,167 $104,304
======== ======== ========
Provision for depreciation, depletion and amortization:
United States ......................................... $ 85,104 $ 61,033 $ 67,798
Kingdom of Thailand ................................... 16,830 101 33
-------- -------- --------
$101,934 $ 61,134 $ 67,831
======== ======== ========
</TABLE>
F-23
<PAGE> 151
UNAUDITED SUPPLEMENTARY FINANCIAL DATA -- (CONTINUED)
The following information regarding estimates of the Company's proved oil
and gas reserves, which are located offshore in United States waters of the Gulf
of Mexico, onshore in the United States and offshore in the Kingdom of Thailand
is based on reports prepared by Ryder Scott Company Petroleum Engineers. The
definitions and assumptions that served as the basis for the discussions under
the caption "Item 1. Business -- Exploration and Production Data -- Reserves"
should be referred to in connection with the following information.
ESTIMATES OF PROVED RESERVES
<TABLE>
<CAPTION>
TOTAL COMPANY UNITED STATES
--------------------------- ---------------------------
OIL OIL
CONDENSATE CONDENSATE
& NATURAL NATURAL & NATURAL NATURAL
GAS LIQUIDS GAS GAS LIQUIDS GAS
(BBLS.) (MMCF) (BBLS.) (MMCF)
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Proved Reserves as of December 31, 1994 .......... 33,861,612 242,890 26,187,240 186,151
Revisions of previous estimates .............. 496,849 21,800 363,213 16,592
Extensions, discoveries and other additions .. 11,901,880 78,434 4,267,871 35,058
Purchase of properties ....................... 4,015,131 30,054 460,156 3,770
Sale of properties ........................... (15,144) (748) (15,144) (748)
Estimated 1995 production .................... (5,078,326) (44,369) (5,078,326) (44,369)
----------- ----------- ----------- -----------
Proved Reserves as of December 31, 1995 .......... 45,182,002 328,061 26,185,010 196,454
Revisions of previous estimates .............. (499,595) (30,034) 3,374,647 3,022
Extensions, discoveries and other additions .. 9,810,363 102,039 3,601,333 55,592
Purchase of properties ....................... -- -- -- --
Sale of properties ........................... -- -- -- --
Estimated 1996 production .................... (4,890,588) (39,122) (4,890,588) (39,122)
----------- ----------- ----------- -----------
Proved Reserves as of December 31, 1996 .......... 49,602,182 360,944 28,270,402 215,946
Revisions of previous estimates .............. 1,033,664 (16,860) 2,194,936 (5,582)
Extensions, discoveries and other additions .. 9,316,407 92,063 4,649,856 49,651
Purchase of properties ....................... 5,175,501 30,319 409,428 8,919
Sale of properties ........................... (6,155) (1,864) (6,155) (1,864)
Estimated 1997 production .................... (6,957,246) (63,114) (6,136,957) (50,350)
----------- ----------- ----------- -----------
Proved Reserves as of December 31, 1997 .......... 58,164,353 401,488 29,381,510 216,720
=========== =========== =========== ===========
Proved developed reserves as of:
December 31, 1994 ............................ 24,669,755 178,518 24,669,755 178,518
December 31, 1995 ............................ 22,487,608 164,679 22,487,608 164,679
December 31, 1996 ............................ 31,090,407 238,032 25,898,414 192,034
December 31, 1997 ............................ 33,149,612 239,732 26,167,519 179,972
<CAPTION>
KINGDOM OF THAILAND
---------------------------
OIL
CONDENSATE
& NATURAL NATURAL
GAS LIQUIDS GAS
(BBLS.) (MMCF)
----------- -----------
<S> <C> <C>
Proved Reserves as of December 31, 1994 .......... 7,674,372 56,739
Revisions of previous estimates .............. 133,636 5,208
Extensions, discoveries and other additions .. 7,634,009 43,376
Purchase of properties ....................... 3,554,975 26,284
Sale of properties ........................... -- --
Estimated 1995 production .................... -- --
----------- -----------
Proved Reserves as of December 31, 1995 .......... 18,996,992 131,607
Revisions of previous estimates .............. (3,874,242) (33,056)
Extensions, discoveries and other additions .. 6,209,030 46,447
Purchase of properties ....................... -- --
Sale of properties ........................... -- --
Estimated 1996 production .................... -- --
----------- -----------
Proved Reserves as of December 31, 1996 .......... 21,331,780 144,998
Revisions of previous estimates .............. (1,161,272) (11,278)
Extensions, discoveries and other additions .. 4,666,551 42,412
Purchase of properties ....................... 4,766,073 21,400
Sale of properties ........................... -- --
Estimated 1997 production .................... (820,289) (12,764)
----------- -----------
Proved Reserves as of December 31, 1997 .......... 28,782,843 184,768
=========== ===========
Proved developed reserves as of:
December 31, 1994 ............................ -- --
December 31, 1995 ............................ -- --
December 31, 1996 ............................ 5,191,993 45,998
December 31, 1997 ............................ 6,982,093 59,760
</TABLE>
F-24
<PAGE> 152
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- UNAUDITED
<TABLE>
<CAPTION>
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND
----------- ----------- -----------
(EXPRESSED IN THOUSANDS)
1997
-------------------------------------------
<S> <C> <C> <C>
Future gross revenues ...................................... $ 1,801,254 $ 1,002,609 $ 798,645
Future production costs:
Lease operating expense ............................... (604,665) (269,505) (335,160)
Future development and abandonment costs ................... (401,970) (155,179) (246,791)
----------- ----------- -----------
Future net cash flows before income taxes .................. 794,619 577,925 216,694
Discount at 10% per annum .................................. (331,838) (171,764) (160,074)
----------- ----------- -----------
Discounted future net cash flow before income taxes ........ 462,781 406,161 56,620
Future income taxes, net of discount at 10% per annum ...... (113,316) (93,386) (19,930)
----------- ----------- -----------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves .................. $ 349,465 $ 312,775 $ 36,690
=========== =========== ===========
1996
-------------------------------------------
Future gross revenues ...................................... $ 2,318,113 $ 1,491,057 $ 827,056
Future production costs:
Lease operating expense ............................... (504,899) (259,501) (245,398)
Future development and abandonment costs ................... (310,839) (126,086) (184,753)
----------- ----------- -----------
Future net cash flows before income taxes .................. 1,502,375 1,105,470 396,905
Discount at 10% per annum .................................. (547,830) (332,343) (215,487)
----------- ----------- -----------
Discounted future net cash flow before income taxes ........ 954,545 773,127 181,418
Future income taxes, net of discount at 10% per annum ...... (268,505) (212,906) (55,599)
----------- ----------- -----------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves .................. $ 686,040 $ 560,221 $ 125,819
=========== =========== ===========
1995
-------------------------------------------
Future gross revenues ...................................... $ 1,495,320 $ 873,578 $ 621,742
Future production costs:
Lease operating expense ............................... (415,829) (208,477) (207,352)
Future development and abandonment costs ................... (247,019) (119,821) (127,198)
----------- ----------- -----------
Future net cash flows before income taxes .................. 832,472 545,280 287,192
Discount at 10% per annum .................................. (299,997) (144,435) (155,562)
----------- ----------- -----------
Discounted future net cash flow before income taxes ........ 532,475 400,845 131,630
Future income taxes, net of discount at 10% per annum ...... (155,330) (104,864) (50,466)
----------- ----------- -----------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves .................. $ 377,145 $ 295,981 $ 81,164
=========== =========== ===========
</TABLE>
The standardized measure of discounted future net cash flows from the
production of proved reserves is developed as follows:
1. Estimates are made of quantities of proved reserves and the future
periods in which they are expected to be produced based on year end
economic conditions.
F-25
<PAGE> 153
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL
AND GAS RESERVES -- UNAUDITED -- (CONTINUED)
2. The estimated future gross revenues from proved reserves are
priced on the basis of year end prices, except in those instances where
fixed and determinable natural gas price escalations are covered by
contracts.
3. The future gross revenue streams are reduced by estimated future
costs to develop and to produce the proved reserves, as well as certain
abandonment costs based on year end cost estimates, and the estimated
effect of future income taxes. These cost estimates are subject to some
uncertainty, particularly those estimates relating to the Company's
properties located in the Kingdom of Thailand.
The standardized measure of discounted future net cash flows does not
purport to present the fair market value of the Company's oil and gas reserves.
An estimate of fair value would also take into account, among other things, the
recovery of reserves in excess of proved reserves, anticipated future changes in
prices and costs, a discount factor more representative of the time value of
money and the risks inherent in reserve estimates.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows. All amounts are related to changes
in reserves located in the United States and the Kingdom of Thailand, as noted.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
-------------------------------------
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND
--------- --------- ---------
(EXPRESSED IN THOUSANDS)
<S> <C> <C> <C>
Beginning balance ............................................... $ 686,040 $ 560,221 $ 125,819
Revisions to prior years' proved reserves:
Net changes in prices and production costs ................. (473,086) (344,493) (128,593)
Net changes due to revisions in quantity estimates ......... (18,624) 9,619 (28,243)
Net changes in estimates of future development costs ....... (83,170) (75,649) (7,521)
Accretion of discount ...................................... 95,455 77,313 18,142
Changes in production rate ................................. (2,907) 8,568 (11,475)
Other ...................................................... (28,225) (13,086) (15,139)
--------- --------- ---------
Total revisions ....................................... (510,557) (337,728) (172,829)
New field discoveries and extensions, net of future
production and development costs .............................. 79,258 76,687 2,571
Purchases of properties ......................................... 10,189 5,899 4,290
Sales of properties ............................................. (6,069) (6,069) --
Sales of oil and gas produced, net of production costs .......... (221,350) (201,524) (19,826)
Previously estimated development
costs incurred ................................................ 156,764 95,768 60,996
Net change in income taxes ...................................... 155,190 119,521 35,669
--------- --------- ---------
Net change in standardized measure of discounted
future net cash flows ............................... (336,575) (247,446) (89,129)
--------- --------- ---------
Ending balance .................................................. $ 349,465 $ 312,775 $ 36,690
========= ========= =========
</TABLE>
F-26
<PAGE> 154
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL
AND GAS RESERVES -- UNAUDITED -- (CONTINUED)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1996
-------------------------------------
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND
--------- --------- ---------
(EXPRESSED IN THOUSANDS)
<S> <C> <C> <C>
Beginning balance .......................................... $ 377,145 $ 295,981 $ 81,164
Revisions to prior years' proved reserves:
Net changes in prices and production costs ............... 304,233 289,182 15,051
Net changes due to revisions in quantity estimates ....... 6,717 53,708 (46,991)
Net changes in estimates of future development costs ..... (132,685) (79,791) (52,894)
Accretion of discount .................................... 53,248 40,085 13,163
Changes in production rate ............................... (59,714) (35,762) (23,952)
Other .................................................... (12,760) (2,831) (9,929)
--------- --------- ---------
Total revisions ....................................... 159,039 264,591 (105,552)
New field discoveries and extensions, net of future
production and development costs ......................... 275,738 173,962 101,776
Sales of oil and gas produced, net of production costs ..... (165,736) (165,736) --
Previously estimated development costs incurred ............ 153,028 99,464 53,564
Net change in income taxes ................................. (113,174) (108,041) (5,133)
--------- --------- ---------
Net change in standardized measure of discounted
future net cash flows ............................ 308,895 264,240 44,655
--------- --------- ---------
Ending balance ............................................. $ 686,040 $ 560,221 $ 125,819
========= ========= =========
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995
-------------------------------------
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND
--------- --------- ---------
(EXPRESSED IN THOUSANDS)
<S> <C> <C> <C>
Beginning balance .......................................... $ 290,069 $ 257,266 $ 32,803
Revisions to prior years' proved reserves:
Net changes in prices and production costs ............... 34,004 69,988 (35,984)
Net changes due to revisions in quantity estimates ....... 29,630 26,109 3,521
Net changes in estimates of future development costs ..... (8,632) (36,721) 28,089
Accretion of discount .................................... 38,298 33,087 5,211
Changes in production rate ............................... (14,754) (15,792) 1,038
Other .................................................... (4,393) (432) (3,961)
--------- --------- ---------
Total revisions ....................................... 74,153 76,239 (2,086)
New field discoveries and extensions, net of future
production and development costs ......................... 105,172 71,701 33,471
Purchases of properties .................................... 29,299 5,160 24,139
Sales of properties ........................................ (969) (969) --
Sales of oil and gas produced, net of production costs ..... (121,615) (121,615) --
Previously estimated development costs incurred ............ 63,455 39,461 23,994
Net change in income taxes ................................. (62,419) (31,262) (31,157)
--------- --------- ---------
Net change in standardized measure of discounted
future net cash flows ............................ 87,076 38,715 48,361
--------- --------- ---------
Ending balance ............................................. $ 377,145 $ 295,981 $ 81,164
========= ========= =========
</TABLE>
F-27
<PAGE> 155
QUARTERLY RESULTS -- UNAUDITED
Summaries of the Company's results of operations by quarter for the years
1997 and 1996 are as follows:
<TABLE>
<CAPTION>
QUARTER ENDED
-----------------------------------------------------
MAR. 31 JUNE 30 SEPT. 30 DEC. 31
---------- ---------- ---------- ----------
(EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
1997
Revenues ................................................... $ 61,314 $ 76,740 $ 77,177 $ 71,069
Gross profit(a) ............................................ $ 27,776 $ 23,953 $ 27,648 $ 20,104
Net income ................................................. $ 12,818 $ 9,174 $ 7,386 $ 7,738
Earnings per share(b):
Basic ................................................. $ 0.38 $ 0.27 $ 0.22 $ 0.23
Diluted ............................................... $ 0.36 $ 0.26 $ 0.21 $ 0.22
1996
1996
Revenues ................................................... $ 48,052 $ 51,543 $ 48,233 $ 56,149
Gross profit(a) ............................................ $ 17,004 $ 20,011 $ 16,845 $ 25,276
Income before extraordinary loss ........................... $ 6,265 $ 8,937 $ 6,971 $ 11,408
Extraordinary loss on early extinguishment of debt ......... -- $ (821) -- --
Net income ................................................. $ 6,265 $ 8,116 $ 6,971 $ 11,408
Earnings per share(b):
Basic --
Income before extraordinary loss ................. $ 0.19 $ 0.27 $ 0.21 $ 0.34
Extraordinary loss ............................... -- $ (0.02) -- --
Net income ....................................... $ 0.19 $ 0.25 $ 0.21 $ 0.34
Diluted --
Income before extraordinary loss ................. $ 0.19 $ 0.26 $ 0.20 $ 0.32
Extraordinary loss ............................... -- $ (0.02) -- --
Net income ....................................... $ 0.19 $ 0.24 $ 0.20 $ 0.32
</TABLE>
- ------------
(a) Represents revenues less lease operating, exploration, dry hole and
impairment, and depreciation depletion and amortization expenses.
(b) Restated for September 30, 1997, and all prior periods
F-28
<PAGE> 156
===============================================================================
YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED OR INCORPORATED BY
REFERENCE IN THIS PROSPECTUS. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH
DIFFERENT INFORMATION.
WE ARE NOT OFFERING THE EXCHANGE NOTES IN ANY JURISDICTION WHERE THE
OFFER IS NOT PERMITTED.
WE DO NOT CLAIM THE ACCURACY OF THE INFORMATION IN THIS PROSPECTUS AS
OF ANY DATE OTHER THAN THE DATE STATED ON THE COVER.
$150,000,000
POGO PRODUCING COMPANY
[LOGO]
OFFER TO EXCHANGE
10 3/8% SERIES B SENIOR SUBORDINATED NOTES DUE 2009
FOR
10 3/8% SERIES A SENIOR SUBORDINATED NOTES DUE 2009
-------------------------
PROSPECTUS
-------------------------
February 16, 1999
===============================================================================
