<PAGE>
Filed pursuant to Rule 424(b)(4)
SEC File No. 333-2375
PROSPECTUS
JUNE 11, 1996
OFFER TO EXCHANGE
10 1/2% SERIES B SENIOR SUBORDINATED NOTES DUE 2006
FOR ALL OUTSTANDING 10 1/2% SERIES A SENIOR SUBORDINATED NOTES DUE 2006
OF
[CODA ENERGY, INC. LOGO]
--------------
THE EXCHANGE OFFER WILL EXPIRE AT 5:00 P.M, NEW YORK CITY TIME ON JULY 12,
1996 UNLESS EXTENDED.
Coda Energy, Inc., a Delaware corporation ("Coda;" and, together with the
guarantor subsidiaries, Diamond Energy Operating Company, Taurus Energy Corp.
and Electra Resources, Inc., the "Company"), is hereby offering (the "Exchange
Offer"), upon the terms and subject to the conditions set forth in this
Prospectus and the accompanying Letter of Transmittal (the "Letter of
Transmittal"), to exchange $1,000 principal amount of its 10 1/2% Series B
Senior Subordinated Notes due 2006 (the "Exchange Notes"), which exchange has
been registered under the Securities Act of 1933, as amended (the "Securities
Act"), pursuant to a registration statement of which this Prospectus is a part
(the "Registration Statement"), for each $1,000 principal amount of its
outstanding 10 1/2% Series A Senior Subordinated Notes due 2006 (the "Private
Notes"), of which $110,000,000 in aggregate principal amount was issued on
March 18, 1996 and is outstanding as of the date hereof. The form and terms of
the Exchange Notes are the same as the form and terms of the Private Notes
(which they replace) except that (i) the Exchange Notes will bear a Series B
designation, (ii) the Exchange Notes will have been registered under the
Securities Act, and, therefore, the Exchange Notes will not bear legends
restricting the transfer thereof and (iii) holders of the Exchange Notes will
not be entitled to certain rights of holders of the Private Notes under the
Registration Rights Agreement (as defined herein), which rights will terminate
upon the consummation of the Exchange Offer. The Exchange Notes will evidence
the same indebtedness as the Private Notes (which they replace) and will be
entitled to the benefits of an indenture dated as of March 18, 1996 governing
the Private Notes and the Exchange Notes (the "Indenture"). The Private Notes
and the Exchange Notes are referred to herein collectively as the "Notes." See
"The Exchange Offer" and "Description of Exchange Notes."
The Exchange Notes will bear interest at the same rate and on the same terms
as the Private Notes. Consequently, the Exchange Notes will bear interest at
the rate of 10 1/2% per annum and the interest thereon will be payable
semiannually in arrears on April 1 and October 1 of each year, commencing
October 1, 1996. The Exchange Notes will bear interest from and including the
date of issuance of the Private Notes (March 18, 1996). Holders whose Private
Notes are accepted for exchange will be deemed to have waived the right to
receive any interest accrued on the Private Notes.
The Exchange Notes will be general unsecured obligations of Coda and will be
subordinated in right of payment to all Senior Debt (as defined in the
Indenture) of Coda (which includes all indebtedness under the Credit Agreement
(as defined herein)) and will rank senior in right of payment to all future
subordinated indebtedness of Coda. As of March 31, 1996, Coda had $81.8
million in Senior Debt. Coda currently has no indebtedness that is junior to
the Notes. See "Description of Exchange Notes--Subordination" and "Description
of Other Indebtedness."
Coda's payment obligations under the Exchange Notes will be jointly and
severally guaranteed on a senior subordinated basis (the "Subsidiary
Guarantees") by all of Coda's current and future Restricted Subsidiaries (as
defined in the Indenture; collectively, the "Guarantors"). The Subsidiary
Guarantees will be subordinated to the guarantees of Senior Debt issued by the
Guarantors under the Credit Agreement and to other guarantees of Senior Debt
issued in the future. See "Description of Exchange Notes--Subsidiary
Guarantees."
The Exchange Notes will be redeemable at the option of Coda, in whole or in
part, at any time on or after April 1, 2001, at the redemption prices set
forth herein, together with accrued and unpaid interest thereon to the date of
redemption. Notwithstanding the foregoing, before March 12, 1999, Coda may, on
any one or more occasions, redeem up to $27.5 million in aggregate principal
amount of Notes at a redemption price of 110.5% of the principal amount
thereof plus accrued and unpaid interest thereon to the redemption date, with
the net proceeds of an offering of common equity of Coda; provided that at
least $82.5 million in aggregate principal amount of Notes must remain
outstanding immediately after the occurrence of such redemption; and provided,
further, that any such redemption shall occur within 75 days of the date of
the closing of such offering of common equity of Coda. See "Description of
Exchange Notes."
Upon the occurrence of a Change of Control (as defined herein), each holder
of Exchange Notes may require Coda to repurchase all or a portion of such
holder's Exchange Notes at a repurchase price equal to 101% of the aggregate
principal amount thereof plus accrued and unpaid interest thereon to the date
of repurchase. See "Description of Exchange Notes--Repurchase of the Option of
Holders--Change of Control."
The Company will accept for exchange any and all validly tendered Private
Notes not withdrawn prior to 5:00 p.m., New York City time, on July 12, 1996,
unless the Exchange Offer is extended by the Company in its sole discretion
(the "Expiration Date"). Tenders of Private Notes may be withdrawn at any time
prior to the Expiration Date. Private Notes may be tendered only in integral
multiples of $1,000. The Exchange Offer is subject to certain customary
conditions. See "The Exchange Offer--Conditions."
SEE "RISK FACTORS," BEGINNING ON PAGE 18, FOR A DISCUSSION OF CERTAIN
FACTORS THAT INVESTORS SHOULD CONSIDER IN CONNECTION WITH THE EXCHANGE OFFER
AND AN INVESTMENT IN THE EXCHANGE NOTES AND THE SUBSIDIARY GUARANTEES THEREOF.
--------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY
IS A CRIMINAL OFFENSE.
<PAGE>
Based on an interpretation by the staff of the Securities and Exchange
Commission (the "Commission") set forth in no-action letters issued to third
parties, the Company believes that the Exchange Notes issued pursuant to the
Exchange Offer in exchange for Private Notes may be offered for resale, resold
and otherwise transferred by a holder thereof (other than (i) a broker-dealer
who purchases such Exchange Notes directly from the Company to resell pursuant
to Rule 144A or any other available exemption under the Securities Act or (ii)
a person that is an affiliate of the Company within the meaning of Rule 405
under the Securities Act), without compliance with the registration and
prospectus delivery provisions of the Securities Act; provided that the holder
is acquiring the Exchange Notes in the ordinary course of its business and is
not participating, and had no arrangement or understanding with any person to
participate, in the distribution of the Exchange Notes. Holders of Private
Notes wishing to accept the Exchange Offer must represent to the Company, as
required by the Registration Rights Agreement, that such conditions have been
met. Each broker-dealer that receives Exchange Notes for its own account in
exchange for Private Notes, where such Private Notes were acquired by such
broker-dealer as a result of market-making activities or other trading
activities, must acknowledge that it will deliver a prospectus in connection
with any resale of such Exchange Notes. The Company believes that none of the
registered holders of the Private Notes is an affiliate (as such term is
defined in Rule 405 under the Securities Act) of the Company.
Prior to the Exchange Offer, there has been no public market for the Private
Notes. The Company does not intend to list the Exchange Notes on any securities
exchange or to seek approval for quotation through any automated quotation
system. There can be no assurance that an active market for the Exchange Notes
will develop. To the extent that a market for the Notes does develop, the
market value of the Notes will depend on market conditions (such as yields on
alternative investments), general economic conditions, the Company's financial
condition and certain other factors. Such conditions might cause the Notes, to
the extent that they are traded, to trade at a significant discount from face
value. See "Risk Factors--Absence of Public Market for the Notes."
Each broker-dealer that receives Exchange Notes for its own account pursuant
to the Exchange Offer must acknowledge that it will deliver a prospectus in
connection with any resale of such Exchange Notes. The Letter of Transmittal
states that by so acknowledging and by delivering a prospectus, a broker-dealer
will not be deemed to admit that it is an "underwriter" within the meaning of
the Securities Act. This Prospectus, as it may be amended or supplemented from
time to time, may be used by a broker-dealer in connection with resales of
Exchange Notes received in exchange for Private Notes where such Private Notes
were acquired by such broker-dealer as a result of market-making activities or
other trading activities. The Company has agreed to make this Prospectus (as it
may be amended or supplemented) available to any broker-dealer for use in
connection with any such resale for a period of one year after the effective
date of the Registration Statement of which this Prospectus forms a part. See
"Plan of Distribution."
The Company will not receive any proceeds from, and has agreed to bear the
expenses of, the Exchange Offer. No underwriter is being used in connection
with this Exchange Offer. See "The Exchange Offer--Resale of the Exchange
Notes."
THE EXCHANGE OFFER IS NOT BEING MADE TO, NOR WILL THE COMPANY ACCEPT
SURRENDERS FOR EXCHANGE FROM, HOLDERS OF PRIVATE NOTES IN ANY JURISDICTION IN
WHICH THE EXCHANGE OFFER OR THE ACCEPTANCE THEREOF WOULD NOT BE IN COMPLIANCE
WITH THE SECURITIES OR BLUE SKY LAWS OF SUCH JURISDICTION.
NO PERSON IS AUTHORIZED IN CONNECTION WITH THE EXCHANGE OFFER TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN THIS PROSPECTUS OR
THE ACCOMPANYING LETTER OF TRANSMITTAL, AND, IF GIVEN OR MADE, SUCH INFORMATION
OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE
COMPANY. NEITHER THE DELIVERY OF THIS PROSPECTUS OR THE ACCOMPANYING LETTER OF
TRANSMITTAL, NOR ANY EXCHANGE MADE HEREUNDER SHALL UNDER ANY CIRCUMSTANCES
CREATE ANY IMPLICATION THAT THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF
ANY DATE SUBSEQUENT TO THE DATE HEREOF.
2
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UNTIL SEPTEMBER 9, 1996 (90 DAYS AFTER THE DATE OF THIS PROSPECTUS), ALL
DEALERS OFFERING TRANSACTIONS IN THE EXCHANGE NOTES, WHETHER OR NOT
PARTICIPATING IN THE EXCHANGE OFFER, MAY BE REQUIRED TO DELIVER A PROSPECTUS
IN CONNECTION THEREWITH. THIS IS IN ADDITION TO THE OBLIGATION OF DEALERS TO
DELIVER A PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR
UNSOLD ALLOTMENTS OR SUBSCRIPTIONS.
The Exchange Notes will be available initially only in book-entry form. The
Company expects that the Exchange Notes issued pursuant to the Exchange Offer
will be issued in the form of one permanent global certificate in definitive,
fully-registered form ("Global Note") that will be deposited with, or on
behalf of, the Depository Trust Company ("DTC" or the "Depositary") and
registered in its name or in the name of Cede & Co., as its nominee.
Beneficial interests in the Global Note representing the Exchange Notes will
be shown on, and transfers thereof will be effected only through, records
maintained by the Depositary and its participants. After the initial issuance
of such Global Note, Exchange Notes in certificated form will be issued in
exchange for the Global Note only in accordance with the terms and conditions
set forth in the Indenture. See "The Exchange Offer--Book-Entry Transfer" and
"Description of Exchange Notes--Book-Entry, Delivery and Form."
3
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SUMMARY
The following summary is qualified in its entirety by the detailed
information, financial statements and other data appearing elsewhere in this
Prospectus. The pro forma financial data presented give effect as of January 1,
1995, to (i) the Snyder Acquisition (as defined below), (ii) the Merger (as
defined below) and (iii) the offering of the Private Notes and the application
of the estimated net proceeds therefrom. Certain oil and gas terms used in this
Prospectus are defined in the "Glossary" included herein. Certain terms used in
connection with the Notes are defined under the caption "Description of
Exchange Notes--Certain Definitions."
THE COMPANY
The Company is an independent energy company that is principally engaged in
the acquisition and exploitation of producing oil and natural gas properties.
The Company also owns and operates natural gas processing and liquids
extraction facilities and natural gas gathering systems. The Company seeks to
acquire oil and natural gas properties whose predominant economic value is
attributable to proved producing reserves and to enhance that value through
control of operations, reduction of costs and property development. The
Company's producing properties are concentrated in the mid-continent region of
the United States. At December 31, 1995, the Company had proved reserves of
42.6 Mmbbls of oil and 37.1 Bcf of natural gas, aggregating 48.8 Mmboe. Company
operated properties accounted for approximately 94% of its 1995 production of
3.9 Mmboe.
As a result of the Company's successful acquisition and exploitation
activities, the Company has shown significant growth in reserves, production
and earnings before interest, income taxes, depletion, depreciation and
amortization ("EBITDA") over the last five years. From 1991 through 1995, the
Company achieved an average annual reserve replacement of 480% at an average
cost of $3.67 per Boe. To achieve these results, management estimates that the
Company evaluated, over the last five years, in excess of 1,400 acquisition
opportunities with an aggregate market value estimated by management to exceed
$15 billion. Over the same period, management estimates that the Company made
approximately 280 offers totaling more than $3 billion and successfully closed
in excess of 50 transactions having an aggregate purchase price of $172.2
million. This strategy enabled the Company to increase average net daily
production from 3,329 Boe in 1991 to 10,688 Boe in 1995, representing a
compound annual growth rate of 34%. Similarly, EBITDA increased at a 46%
compound annual growth rate from $8.2 million in 1991 to $37.3 million in 1995.
See "Business--General" and "--Acquisition and Exploitation of Principal
Properties."
4
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STRATEGY
The Company's strategy is to increase oil and natural gas reserves,
production and cash flow by selectively acquiring and exploiting oil and
natural gas properties, especially those properties with enhanced recovery and
other lower risk development potential. In order to implement its strategy, the
Company principally seeks to acquire oil and natural gas properties with the
following characteristics:
. Geographic Focus--The Company has focused its acquisition activities in
the mid-continent region of the United States. This region includes oil
and natural gas basins with geological and production characteristics
potentially responsive to the Company's exploitation and development
techniques. Management believes that it has considerable experience in,
and knowledge of, this region. The Company presently has four core
operating areas: west Texas, north Texas, west central Oklahoma and
southwestern Kansas. The geographic proximity of the Company's various
properties allows the Company to minimize the number of operations and
field production offices that it must maintain and the number of
supervisory personnel that it must employ.
. Proved Developed Reserves--The Company prefers to acquire properties
where the majority of the reserves are proved developed reserves
producing from relatively shallow horizons. Management believes these
properties generally present lower geologic and mechanical risks for
drilling, recompleting and operating activities. Substantially all of
the Company's wells are under 10,000 feet deep.
. Operated, High Working Interest Properties--The Company prefers to
operate the properties it acquires and to own the majority working
interest in those properties. This allows the Company greater control
over (i) timing and plans for future development, (ii) drilling,
completing and lifting costs and (iii) marketing of production. At
December 31, 1995, the Company operated 2,052 of the 2,190 gross
producing and active water injection wells in which it owned an
interest, and its weighted average working interest in its properties
was approximately 82%.
. Exploitation Potential--The Company seeks to increase production and
recoverable reserves through exploitation efforts on the properties it
acquires. Exploitation efforts include workovers and/or recompletions of
existing wells; the initiation of, or improvements to, secondary
recovery projects, particularly the use of waterflooding; and the
drilling of lower risk development and/or infill wells. The Company
believes that it has been able to enhance the value and to extend the
economic life of many of the properties that it has acquired by
utilizing techniques such as these.
. Cost Reduction Potential--The Company seeks to acquire properties where
significant economic value can be created by lowering operating costs.
The Company believes that it has been able to lower the lifting costs on
certain properties it has acquired in comparison to the costs incurred
by the major oil companies and larger independents that previously
operated the properties. These savings were achieved through reductions
in labor, electricity, materials and other costs.
. Price Improvement Potential--Whenever possible, the Company attempts to
negotiate more favorable marketing agreements than those in place under
prior owners. After the Company has begun its exploitation activities on
its properties, it may attempt to negotiate more favorable prices as the
volumes of oil increase. Certain of the Company's oil purchasers have
paid and are currently paying a premium over posted prices and have
eliminated certain quality and marketing deductions for a portion of the
Company's oil production due to the Company's control over a significant
volume of oil production in its core geographic areas.
5
<PAGE>
The Company believes that future acquisitions, like its past acquisitions,
will come from several categories of sellers including: (i) major oil
companies; (ii) companies that are consolidating operations to achieve cost
savings; (iii) companies and individuals owning interests in wells in which the
Company owns a substantial working interest; and (iv) companies with limited
capital resources.
The success of the Company's strategy depends upon a number of factors
outside of the Company's control, including the availability of attractive
acquisition opportunities. In recent years, major oil companies have been
divesting many of their higher cost domestic oil and natural gas properties. In
addition, the oil and natural gas industry continues to consolidate as smaller
independents exit the business. The Company believes these trends will
continue. By increasing production and lowering operating costs, the Company
believes that it can increase economic value and cash flow as well as extend
the productive lives of these properties. However, there can be no assurance
that the Company will be able to successfully implement its operating strategy.
See "Risk Factors--Acquisition Risks; Depletion of Reserves" and "Business--
Exploitation and Development Activities."
RECENT ACQUISITION OF CERTAIN PROPERTIES
On October 6, 1995, the Company acquired 63 producing oil and natural gas
properties and related assets (the "Snyder Acquisition") from Snyder Oil
Corporation ("Snyder"). The majority of these properties are located in the
Permian Basin in west Texas. The total purchase price of these properties was
$17.1 million in cash, of which $16.0 million was financed with borrowings
under the Company's then-existing credit agreement. Total proved reserves of
these properties were estimated as of October 1, 1995, to be 4.3 Mmbbls of oil
and 6.8 Bcf of natural gas. The Company believes that these properties present
exploitation opportunities, including opportunities to implement cost-cutting
strategies and initiate or improve secondary recovery operations and lower risk
development drilling activities. Additionally, the Snyder Acquisition
complements the Company's core operating areas within the mid-continent region
of the United States. See Pro Forma Condensed Financial Statements.
TAURUS
Through its Taurus Energy Corp. ("Taurus") subsidiary, the Company also owns
and operates three gas processing and liquid extraction facilities and
approximately 700 miles of gas gathering systems, primarily located in west
central Texas. Taurus was acquired by the Company in April 1994. The Company's
gas gathering and processing revenues, from Taurus and its predecessor, have
grown from $5.2 million in 1991 to $35.6 million in 1995, and EBITDA has
increased from $50,000 to $3.4 million over the same period. Taurus represented
approximately nine percent of the Company's consolidated 1995 EBITDA of
approximately $37.3 million. The Company intends to study alternatives for
maximizing the value of its investment in Taurus. These alternatives could
include a sale of Taurus, whether by merger, sale of all or substantially all
of the assets of Taurus or sale of all of the capital stock of Taurus.
6
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THE MERGER
On February 16, 1996, pursuant to an Agreement and Plan of Merger dated as of
October 30, 1995 (as amended, the "Merger Agreement"), by and among Coda, Joint
Energy Development Investments Limited Partnership ("JEDI"), which is an
affiliate of Enron Capital & Trade Resources Corp. ("ECT"), and Coda
Acquisition, Inc. ("CAI"), which was a subsidiary of JEDI, JEDI acquired Coda
through a merger (the "Merger") at a price of $7.75 per share in cash (for an
aggregate purchase price of approximately $176.2 million). Concurrently with
the execution of the Merger Agreement, JEDI and CAI entered into certain
agreements with members of the Company's management (the "Management Group").
Following consummation of the Merger, the Management Group owns approximately
5% of Coda's common stock on a fully-diluted basis. JEDI owns the remaining
95%. JEDI was formed as a limited partnership between California Public
Employees' Retirement System ("CalPERS") and an affiliate of ECT, with the ECT
affiliate designated as the general partner. The purpose of the partnership is
to invest in a diversified portfolio of energy related assets. See "The
Merger."
The sources and uses of funds related to financing the Merger were as
follows:
SOURCES OF FUNDS
(in millions)
<TABLE>
<S> <C>
Credit Agreement.................................................. $ 95.0
JEDI Debt(1)...................................................... 100.0
Redeemable Preferred Stock issued to JEDI......................... 20.0
Common Stock issued to JEDI....................................... 90.0
------
Total......................................................... $305.0
======
</TABLE>
USES OF FUNDS
(in millions)
<TABLE>
<S> <C>
Payments to Coda stockholders, warrantholders and
optionholders.................................................. $176.2
Repayment of former credit facility and other indebtedness...... 122.7
Merger costs and other expenses................................. 6.1
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Total....................................................... $305.0
======
</TABLE>
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(1) Represents indebtedness incurred by CAI and assumed by Coda to fund
a portion of the consideration paid in the Merger. See "Use of
Proceeds."
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The Company was incorporated in Delaware in 1981. The Company's executive
offices are located at 5735 Pineland Drive, Suite 300, Dallas, Texas 75231, and
its telephone number is (214) 692-1800.
7
<PAGE>
THE EXCHANGE OFFER
THE EXCHANGE OFFER.............. The Company is hereby offering to exchange
$1,000 principal amount of Exchange Notes for
each $1,000 principal amount of Private Notes
that are properly tendered and accepted. The
Private Notes were sold in transactions ex-
empt from registration under the Securities
Act on March 18, 1996. This Registration
Statement is intended to satisfy certain of
the Company's obligations under the Registra-
tion Rights Agreement and Purchase Agreement
(as defined below) entered into in connection
with the private placement. The Company will
issue Exchange Notes on or promptly after the
Expiration Date. As of the date hereof, there
is $110,000,000 aggregate principal amount of
Private Notes outstanding. See "The Exchange
Offer--Purpose of the Exchange Offer."
Based on an interpretation by the staff of
the Commission set forth in no-action letters
issued to third parties, the Company believes
that the Exchange Notes issued pursuant to
the Exchange Offer in exchange for Private
Notes may be offered for resale, resold and
otherwise transferred by a holder thereof
(other than (i) a broker-dealer who purchases
such Exchange Notes directly from the Company
to resell pursuant to Rule 144A or any other
available exemption under the Securities Act
or (ii) a person that is an affiliate of the
Company within the meaning of Rule 405 under
the Securities Act), without compliance with
the registration and prospectus delivery pro-
visions of the Securities Act; provided that
the holder is acquiring Exchange Notes in the
ordinary course of its business and is not
participating, and had no arrangement or un-
derstanding with any person to participate,
in the distribution of the Exchange Notes.
Each broker-dealer that receives Exchange
Notes for its own account in exchange for
Private Notes, where such Private Notes were
acquired by such broker-dealer as a result of
market-making activities or other trading ac-
tivities, must acknowledge that it will de-
liver a prospectus in connection with any re-
sale of such Exchange Notes. See "The Ex-
change Offer--Resale of the Exchange Notes."
REGISTRATION RIGHTS AGREEMENT... The Private Notes were sold by the Company on
March 18, 1996 to Goldman, Sachs & Co., Chem-
ical Securities Inc., ECT Securities Corp.
and NationsBanc Capital Markets, Inc. (col-
lectively, the "Initial Purchasers") pursuant
to a Purchase Agreement, dated March 12,
1996, by and among the Company, the Guaran-
tors and the Initial Purchasers (the "Pur-
chase Agreement"). Pursuant to the Purchase
Agreement, the Company, the Guarantors and
8
<PAGE>
the Initial Purchasers entered into a Regis-
tration Rights Agreement, dated as of March
18, 1996 (the "Registration Rights Agree-
ment"), which grants the holders of the Pri-
vate Notes certain exchange and registration
rights. The Exchange Offer is intended to
satisfy such rights, which will terminate
upon the consummation of the Exchange Offer.
The holders of the Exchange Notes will not be
entitled to any exchange or registration
rights with respect to the Exchange Notes.
See "The Exchange Offer--Termination of Cer-
tain Rights."
EXPIRATION DATE................. The Exchange Offer will expire at 5:00 p.m.,
New York City time, on July 12, 1996, unless
the Exchange Offer is extended by the Company
in its sole discretion, in which case the
term "Expiration Date" shall mean the latest
date and time to which the Exchange Offer is
extended. See "The Exchange Offer--Expiration
Date; Extensions; Amendments."
ACCRUED INTEREST ON THE
EXCHANGE NOTES AND THE PRIVATE
NOTES.......................... The Exchange Notes will bear interest from
and including the date of issuance of the
Private Notes (March 18, 1996). Holders whose
Private Notes are accepted for exchange will
be deemed to have waived the right to receive
any interest accrued on the Private Notes.
See "The Exchange Offer--Interest on the Ex-
change Notes."
CONDITIONS TO THE EXCHANGE
OFFER.......................... The Exchange Offer is subject to certain cus-
tomary conditions that may be waived by the
Company. The Exchange Offer is not condi-
tioned upon any minimum aggregate principal
amount of Private Notes being tendered for
exchange. See "The Exchange Offer--
Conditions."
PROCEDURES FOR TENDERING
PRIVATE NOTES.................. Each holder of Private Notes wishing to ac-
cept the Exchange Offer must complete, sign
and date the Letter of Transmittal, or a fac-
simile thereof, in accordance with the in-
structions contained herein and therein, and
mail or otherwise deliver such Letter of
Transmittal, or such facsimile, together with
such Private Notes and any other required
documentation to Texas Commerce Bank National
Association, as exchange agent (the "Exchange
Agent"), at the address set forth herein. By
executing the Letter of Transmittal, the
holder will represent to and agree with the
Company that, among other things, (i) the Ex-
change Notes to be acquired by such holder of
Private Notes in connection with the Exchange
Offer are being acquired by such holder in
the ordinary course of its business, (ii) if
such holder is not a broker-dealer,
9
<PAGE>
such holder is not currently participating
in, does not intend to participate in, and
has no arrangement or understanding with any
person to participate in a distribution of
the Exchange Notes, (iii) if such holder is a
broker-dealer registered under the Exchange
Act or is participating in the Exchange Offer
for the purposes of distributing the Exchange
Notes, such holder will comply with the reg-
istration and prospectus delivery require-
ments of the Securities Act in connection
with a secondary resale transaction of the
Exchange Notes acquired by such person and
cannot rely on the position of the staff of
the Commission set forth in no-action letters
(see "The Exchange Offer--Resale of Exchange
Notes"), (iv) such holder understands that a
secondary resale transaction described in
clause (iii) above and any resales of Ex-
change Notes obtained by such holder in ex-
change for Private Notes acquired by such
holder directly from the Company should be
covered by an effective registration state-
ment containing the selling securityholder
information required by Item 507 or Item 508,
as applicable, of Regulation S-K of the Com-
mission and (v) such holder is not an "affil-
iate," as defined in Rule 405 under the Secu-
rities Act, of the Company. If the holder is
a broker-dealer that will receive Exchange
Notes for its own account in exchange for
Private Notes that were acquired as a result
of market-making activities or other trading
activities, such holder will be required to
acknowledge in the Letter of Transmittal that
such holder will deliver a prospectus in con-
nection with any resale of such Exchange
Notes; however, by so acknowledging and by
delivering a prospectus, such holder will not
be deemed to admit that it is an "underwrit-
er" within the meaning of the Securities Act.
See "The Exchange Offer--Procedures for
Tendering."
SPECIAL PROCEDURES FOR
BENEFICIAL OWNERS.............. Any beneficial owner whose Private Notes are
registered in the name of a broker, dealer,
commercial bank, trust company or other nomi-
nee and who wishes to tender such Private
Notes in the Exchange Offer should contact
such registered holder promptly and instruct
such registered holder to tender on such ben-
eficial owner's behalf. If such beneficial
owner wishes to tender on such owner's own
behalf, such owner must, prior to completing
and executing the Letter of Transmittal and
delivering such owner's Private Notes, either
make appropriate arrangements to register
ownership of the Private Notes in such own-
er's name or obtain a properly completed bond
power from the registered holder. The trans-
fer of registered ownership may take consid-
erable time and may
10
<PAGE>
not be able to be completed prior to the Ex-
piration Date. See "The Exchange Offer--Pro-
cedures for Tendering."
GUARANTEED DELIVERY
PROCEDURES..................... Holders of Private Notes who wish to tender
their Private Notes and whose Private Notes
are not immediately available or who cannot
deliver their Private Notes, the Letter of
Transmittal or any other documentation re-
quired by the Letter of Transmittal to the
Exchange Agent prior to the Expiration Date
must tender their Private Notes according to
the guaranteed delivery procedures set forth
under "The Exchange Offer--Guaranteed Deliv-
ery Procedures."
ACCEPTANCE OF THE PRIVATE NOTES
AND DELIVERY OF THE EXCHANGE
NOTES.......................... Subject to the satisfaction or waiver of the
conditions to the Exchange Offer, the Company
will accept for exchange any and all Private
Notes that are properly tendered in the Ex-
change Offer prior to the Expiration Date.
The Exchange Notes issued pursuant to the Ex-
change Offer will be delivered on the earli-
est practicable date following the Expiration
Date. See "The Exchange Offer--Terms of the
Exchange Offer."
CONSEQUENCES OF NOT EXCHANGING
PRIVATE NOTES..................
Private Notes that are not exchanged for Ex-
change Notes pursuant to the Exchange Offer
will continue to be deemed restricted securi-
ties under the Securities Act and subject to
the restrictions on transfer of such Private
Notes as set forth in the legend thereon. Ac-
cordingly, the Private Notes may not be of-
fered or sold, unless registered under the
Securities Act or sold pursuant to an exemp-
tion from, or in a transaction not subject
to, the Securities Act and applicable state
securities laws. Furthermore, any and all
registration rights under the Registration
Rights Agreement held by holders of Private
Notes eligible to participate in the Exchange
Offer will be extinguished as a result of the
completion of the Exchange Offer. See "Risk
Factors--Consequences of Not Exchanging Pri-
vate Notes" and "The Exchange Offer--Conse-
quences of Not Exchanging Private Notes."
WITHDRAWAL RIGHTS............... Tenders of Private Notes may be withdrawn at
any time prior to the Expiration Date. See
"The Exchange Offer--Withdrawal of Tenders."
CERTAIN FEDERAL INCOME TAX
CONSIDERATIONS................. For a discussion of certain material federal
income tax considerations relating to the ex-
change of the Exchange Notes for the Private
Notes, see "Certain Federal Income Tax Con-
siderations."
11
<PAGE>
EXCHANGE AGENT.................. Texas Commerce Bank National Association is
serving as the Exchange Agent in connection
with the Exchange Offer.
THE EXCHANGE NOTES
The Exchange Offer applies to $110,000,000 aggregate principal amount of the
Private Notes. The form and terms of the Exchange Notes are the same as the
form and terms of the Private Notes except that (i) the Exchange Notes will
bear the Series B designation, (ii) the Exchange Notes will have been
registered under the Securities Act and, therefore, the Exchange Notes will not
bear legends restricting the transfer thereof and (iii) holders of the Exchange
Notes will not be entitled to certain rights of holders of the Private Notes
under the Registration Rights Agreement, which rights will terminate upon
consummation of the Exchange Offer. The Exchange Notes will evidence the same
indebtedness as the Private Notes (which they replace) and will be issued
under, and be entitled to the benefits of, the Indenture. For further
information and for definitions of certain capitalized terms used below, see
"Description of Exchange Notes."
ISSUER.......................... Coda Energy, Inc.
SECURITIES OFFERED.............. $110 million principal amount of 10 1/2% Se-
ries B Senior Subordinated Notes due 2006.
MATURITY DATE................... April 1, 2006.
INTEREST PAYMENT DATES.......... The Exchange Notes will bear interest at an
annual rate of 10 1/2% and will be payable in
cash semiannually in arrears on April 1 and
October 1 of each year, commencing October 1,
1996. See "The Exchange Offer--Interest on
the Exchange Notes."
RANKING......................... The Exchange Notes will be general, unsecured
obligations of Coda, will be subordinated in
right of payment to all Senior Debt of Coda,
and will be senior in right of payment to all
future subordinated debt of Coda. The claims
of the holders of the Exchange Notes will be
subordinated to Senior Debt, which, as of
March 31, 1996, was $81.8 million. On May 1,
1996, the Company redeemed all its outstand-
ing 12% Senior Subordinated Debentures due
2000, which resulted in a reduction in Senior
Debt of approximately $1.2 million. See "Cap-
italization."
GUARANTEES...................... Coda's payment obligations under the Exchange
Notes will be jointly and severally guaran-
teed on a senior subordinated basis by all of
Coda's current subsidiaries and future Re-
stricted Subsidiaries. The Subsidiary Guaran-
tees will be subordinated to the guarantees
of Senior Debt issued by the Guarantors under
the Credit Agreement and to other guarantees
of Senior Debt issued in the future. See "De-
scription of Exchange Notes--Subsidiary Guar-
antees" and "Description of Other
Indebtedness."
12
<PAGE>
FORM AND DENOMINATION........... The Exchange Notes will be fully registered
as to principal and interest in minimum de-
nominations of $100,000 for institutional ac-
credited investors and $1,000 for qualified
institutional buyers and, in both cases, in
integral multiples of $1,000 in excess there-
of. The Exchange Notes will be represented by
one Global Note in fully registered form, de-
posited with a custodian for and registered
in the name of a nominee of the Depositary.
Beneficial interests in the Global Note rep-
resenting the Exchange Notes will be shown
on, and transfers thereof will be effected
only through, records maintained by the De-
positary and its participants. Except as de-
scribed herein, Exchange Notes in certifi-
cated form will not be issued in exchange for
the Global Note or interests therein. See
"Description of Exchange Notes--Book-Entry,
Delivery and Form."
CERTAIN COVENANTS............... The Exchange Notes will be issued pursuant to
the Indenture, which contains certain cove-
nants that, among other things, limit the
ability of Coda and its Restricted Subsidiar-
ies to incur additional indebtedness and is-
sue Disqualified Stock, pay dividends, make
distributions, make investments, make certain
other Restricted Payments, enter into certain
transactions with affiliates, dispose of cer-
tain assets, incur liens securing pari passu
or subordinated indebtedness of Coda and en-
gage in mergers and consolidations. See "De-
scription of Exchange Notes--Certain Cove-
nants."
MANDATORY REDEMPTION............ None.
OPTIONAL REDEMPTION............. Except as described below, the Notes are not
redeemable at Coda's option prior to April 1,
2001. After April 1, 2001, the Notes will be
subject to redemption at the option of Coda,
in whole or in part, at the redemption prices
set forth herein, plus accrued and unpaid in-
terest thereon to the applicable redemption
date.
In addition, until March 12, 1999, up to
$27.5 million in aggregate principal amount
of Notes will be redeemable at the option of
Coda on any one or more occasions from the
net proceeds of an offering of common equity
of Coda, at a price of 110.5% of the aggre-
gate principal amount of the Notes, together
with accrued and unpaid interest thereon to
the date of the redemption; provided, howev-
er, that at least $82.5 million in aggregate
principal amount of Notes must remain out-
standing immediately after the occurrence of
such redemption; provided, further, that any
such redemption shall occur within 75
13
<PAGE>
days of the date of the closing of such of-
fering of common equity. See "Description of
Exchange Notes--Optional Redemption."
CHANGE OF CONTROL............... In the event of a Change of Control, holders
of the Notes will have the right to require
Coda to repurchase their Notes, in whole or
in part, at a price in cash equal to 101% of
the aggregate principal amount thereof, plus
accrued and unpaid interest thereon to the
date of repurchase. The Indenture will re-
quire that, prior to such a repurchase but in
any event within 90 days of such Change of
Control, Coda must either repay all Senior
Debt or obtain any required consent to such
repurchase. The degree to which the Company
is leveraged at the time of a Change of Con-
trol could prevent it from repaying outstand-
ing Senior Debt (or otherwise obtaining the
consent of holders of Senior Debt to make a
Change of Control Offer) which would prohibit
Coda from repurchasing Notes tendered to it
upon such Change of Control. In such case,
Coda's failure to purchase the Notes would
constitute an Event of Default under the In-
denture. In such circumstances, the subordi-
nation provisions in the Indenture would
likely restrict payments to the Holders of
Notes by either Coda or the Guarantors. Coda
is not required to make a Change of Control
Offer if a third party makes a Change of Con-
trol Offer in compliance with the Indenture
and purchases all Notes validly tendered and
not withdrawn under such Change of Control
Offer. See "Description of Exchange Notes--
Repurchase at the Option of Holders--Change
of Control."
RISK FACTORS
Prior to making an investment decision, holders of the Private Notes should
consider all of the information set forth in this Prospectus and should
evaluate the considerations set forth in "Risk Factors" beginning on page 18
hereof.
14
<PAGE>
SUMMARY FINANCIAL INFORMATION
The following table sets forth certain historical and pro forma operating
and financial data of the Company. See "Selected Historical and Pro Forma
Financial Data" and "Management's Discussion and Analysis of Financial
Condition and Results of Operations." The historical data should be read in
conjunction with the Historical Financial Statements and the notes thereto
included elsewhere in this Prospectus. The Company acquired significant
producing oil and natural gas properties in all the periods presented which
affect the comparability of the historical financial and operating data for
the periods presented. As a result of the Merger, JEDI acquired Coda effective
February 16, 1996. The Merger has been accounted for using the purchase method
of accounting. As such, JEDI's cost of acquiring Coda has been allocated to
the assets and liabilities acquired based on estimated fair values. As a
result, the Company's financial position and operating results subsequent to
the date of the Merger reflect a new basis of accounting and are not
comparable to prior periods. The pro forma information should be read in
conjunction with the Pro Forma Condensed Financial Statements and notes
thereto included elsewhere in this Prospectus. Neither the historical results
nor the pro forma results are necessarily indicative of the Company's future
operations or financial results.
<TABLE>
<CAPTION>
HISTORICAL PRO FORMA
----------------------------------------------------------------------------- -------------------------
THREE MONTHS 47 DAYS 44 DAYS YEAR THREE MONTHS
YEAR ENDED DECEMBER 31, ENDED ENDED ENDED ENDED ENDED
----------------------------------------- MARCH 31, FEBRUARY 16, MARCH 31, DECEMBER 31, MARCH 31,
1991 1992 1993 1994 1995 1995 1996 1996 1995(1) 1996(1)
------- ------- ------- ------- ------- ------------ ------------ --------- ------------ ------------
(in thousands, except ratios)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT
DATA:
Oil and gas
sales........... $16,512 $18,631 $38,877 $50,683 $60,997 $14,948 $8,079 $8,964 $66,156 $17,043
Gas gathering
and
processing(2)... 5,246 4,709 732 20,081 35,634 7,904 5,322 4,799 35,634 10,121
Total revenues.. 22,782 23,637 40,050 71,586 97,838 23,039 13,569 13,964 102,997 27,533
Interest
expense......... 2,420 2,752 4,834 5,281 8,676 2,068 1,102 2,087 18,563 4,300
Total costs and
expenses(3)..... 21,865 24,778 36,398 65,676 88,881 20,938 15,378 97,015 110,066 27,816
Income (loss)
before income
taxes........... 917 (1,141) 3,652 5,910 8,957 2,101 (1,809) (83,051) (7,069) (283)
Net income
(loss).......... (65) (734) 2,334 3,329 5,755 1,305 (1,298) (53,136) (4,493) (279)
Ratio of
earnings to
fixed
charges(4)...... 1.4x -- 1.8x 2.1x 2.0x 2.0x -- -- -- --
CASH FLOW
DATA(5):
Net income
(loss).......... $ (65) $ (734) $ 2,334 $ 3,329 $ 5,755 $ 1,305 $(1,298) $(53,136) $ (4,493) $ (279)
Depletion,
depreciation and
amortization.... 4,823 4,813 10,808 16,419 19,715 4,870 2,583 3,498 28,509 6,897
Net cash
provided by
operating
activities...... 6,127 2,241 16,443 22,987 24,301 5,122 3,136 1,461 17,069 3,487
OTHER DATA(6):
EBITDA.......... 8,160 6,424 19,294 27,610 37,348 9,039 1,876 5,839 40,003 10,914
EBITDA/interest
expense......... 3.4x 2.3x 4.0x 5.2x 4.3x 4.4x 1.7x 2.8x 2.2x 2.5x
Debt/EBITDA..... 3.8x 9.2x 3.2x 3.8x 3.3x
CAPITAL
EXPENDITURES:
Oil and gas
property
acquisitions.... $21,650 $23,318 $42,223 $40,109 $25,363 $ 498 $ 305 $ 92
Oil and gas
development and
other........... 4,404 7,550 10,403 12,450 14,464 4,457 1,412 678
Gas plant and
gathering
systems and
other property
additions....... 687 1,365 646 7,380 8,500 7,346 114 43
</TABLE>
15
<PAGE>
SUMMARY FINANCIAL INFORMATION (CONTINUED)
<TABLE>
<CAPTION>
AT DECEMBER 31,
------------------------------------------ MARCH 31,
1991 1992 1993 1994 1995 1996
------- ------- -------- -------- -------- ---------
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Total assets............. $56,010 $82,226 $132,754 $203,102 $229,064 $304,435
Notes.................... -- -- -- -- -- 110,000
Other long-term debt,
less current maturities.. 28,794 56,563 59,651 105,063 123,907 81,719
Redeemable Preferred
Stock.................... -- -- -- -- -- 20,000
Common stockholders'
equity................... 19,502 18,949 58,231 74,741 79,188 40,487
</TABLE>
SUMMARY OPERATING DATA
<TABLE>
<CAPTION>
HISTORICAL PRO FORMA
---------------------------------------------------------------------- -------------------------
THREE MONTHS 47 DAYS 44 DAYS YEAR THREE MONTHS
YEAR ENDED DECEMBER 31, ENDED ENDED ENDED ENDED ENDED
---------------------------------- MARCH 31, FEBRUARY 16, MARCH 31, DECEMBER 31, MARCH 31,
1991 1992 1993 1994 1995 1995 1996 1996 1995(1) 1996(1)
------ ------ ------ ------ ------ ------------ ------------ --------- ------------ ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Production
Oil (Mbbls)......... 517 734 1,766 2,650 3,165 772 408 427 3,440 835
Gas (Mmcf).......... 4,188 3,255 4,703 4,982 4,416 1,186 500 512 4,895 1,012
Oil Equivalent
(Mboe)............. 1,215 1,277 2,550 3,480 3,901 970 491 512 4,256 1,003
Average sales prices
Oil (per Bbl)....... $19.14 $19.03 $16.88 $15.86 $17.08 $17.03 $17.57 $18.89 $17.01 $18.25
Gas (per Mcf)....... 1.58 1.44 1.92 1.74 1.57 1.52 1.82 1.75 1.56 1.78
Production costs per
Boe(7).............. 5.86 8.02 6.90 6.22 6.95 6.77 7.33 7.59 7.18 7.46
Depreciation,
depletion and
amortization per
Boe................. 3.89 3.64 4.15 4.27 4.33 4.33 4.40 5.94 5.94 5.94
General and
administrative per
Boe................. 2.06 1.98 1.02 0.90 0.74 .73 .65 .69 0.46 .67
Average finding cost
per Boe............. 1.96 3.57 5.27 4.21 2.97
</TABLE>
SUMMARY RESERVE DATA
<TABLE>
<CAPTION>
AT DECEMBER 31,
-------------------------------------------
1991 1992 1993 1994 1995
------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Proved reserves(8)
Oil (Mbbls)...................... 12,389 18,941 30,084 39,207 42,590
Gas (Mmcf)....................... 28,601 27,830 36,196 39,808 37,130
Total proved reserves (Mboe)..... 17,156 23,579 36,117 45,842 48,778
Proved developed reserves
(Mboe)........................... 12,496 18,222 21,326 25,633 31,126
Annual reserve replacement
ratio(9).......................... 5.7 5.6 6.9 6.0 2.3
Estimated reserve life (in
years)(10)........................ 12.9 11.6 9.9 10.3 11.7
Present value of estimated future
net revenues before income taxes
(in thousands)(11)................ $81,361 $121,494 $140,980 $217,540 $283,375
Standardized measure of discounted
future net cash flows (in
thousands)(12).................... 65,175 95,860 116,023 168,616 220,742
</TABLE>
16
<PAGE>
- --------
(1) Reflects the pro forma effect of the Snyder Acquisition, the Merger, the
sale of the Private Notes and the application of the proceeds thereof to
retire the JEDI Debt and pay down a portion of the outstanding borrowings
under the Credit Agreement. See the Company's Pro Forma Condensed
Financial Statements, included elsewhere in this Prospectus, for a
discussion of the preparation of this data. The pro forma combined results
of operations exclude a charge of approximately $53.3 million (net of
related deferred taxes of $30.0 million) representing the adjustment of
the carrying value of proved oil and gas properties pursuant to the full
cost method of accounting. Such adjustment has been included in the
historical results of operations of the Company in the period the Merger
was consummated. Pro forma net cash provided by operating activities was
obtained by adjusting the historical amount for the pro forma changes in
oil and natural gas sales, oil and natural gas production expenses,
general and administrative expenses and interest expense. The exchange of
the Exchange Notes for the Private Notes would have no effect on the pro
forma information. See also "Use of Proceeds" and "Capitalization."
(2) The Company ceased its third party natural gas marketing operations in
1992. The Company acquired Taurus in April 1994.
(3) Total costs and expenses for the periods ended February 16, 1996 and March
31, 1996 include approximately $3.2 million of stock option compensation
expense and $83.3 million for the writedown of oil and gas properties,
respectively.
(4) For purposes of computing the ratio of earnings to fixed charges, earnings
consist of income before income taxes plus fixed charges. Fixed charges
consist of interest expense. For the periods ended December 31, 1992,
February 16, 1996 and March 31, 1996, earnings were inadequate to cover
fixed charges by approximately $1.1 million, $1.8 million and $83.1
million, respectively. Pro forma earnings for the year ended December 31,
1995 and three months ended March 31, 1996, would have been inadequate to
cover fixed charges by approximately $7.1 million and $283,000,
respectively.
(5) In addition to cash flows provided by operating activities, the Company
also has significant cash flows which are provided by or used in investing
and financing activities. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Liquidity and Capital
Resources," "--Effects of the Merger, the Sale of the Private Notes and
the Exchange Offer--Credit Agreement" and the Historical Financial
Statements of the Company.
(6) EBITDA is calculated as operating income before interest, income taxes,
depletion, depreciation and amortization. EBITDA is not a measure of cash
flow as determined by generally accepted accounting principles ("GAAP").
The Company has included information concerning EBITDA because EBITDA is a
measure used by certain investors in determining the Company's historical
ability to service its indebtedness. EBITDA should not be considered as an
alternative to, or more meaningful than, net income or cash flows as
determined in accordance with GAAP as an indicator of the Company's
operating performance or liquidity. Debt/EBITDA is calculated only for the
historical annual periods. EBITDA for the period ended February 16, 1996
is net of approximately $3.2 million of stock option compensation expense
which is a non-cash charge.
(7) Production costs in 1992 were relatively high because two of the Company's
waterflood operations and the costs associated therewith commenced in 1992
but the anticipated response of increased oil production did not commence
to any material degree until 1993.
(8) In 1994, the Company acquired Diamond Energy Operating Company and a
related company which have since merged ("Diamond") in a transaction
accounted for as a pooling of interests. Reserve data was prepared by the
Company's independent consulting engineers except that such estimates
related to the reserves of Diamond as of December 31, 1991, 1992 and 1993
were prepared by Diamond's in-house engineers.
(9) The annual reserve replacement ratio is calculated by dividing total
reserve additions (purchases of reserves, extensions and revisions) on a
Boe basis for the year by actual production on a Boe basis for such year
with the acquisition of Diamond treated as a purchase instead of a
pooling.
(10) The estimated reserve life is calculated by dividing the proved reserves
on a Boe basis by the forecasted production on a Boe basis for the 12
months following the date indicated (both as estimated by the Company's
independent consulting engineers as of December 31 of each year).
(11) Discounted at an annual rate of 10%. See "Glossary" included elsewhere in
this Prospectus for the definition of "present value of estimated future
net revenues." The Company believes that the present value of estimated
future net revenues before income taxes, while not in accordance with
generally accepted accounting principles, is an important financial
measure used by investors in independent oil and natural gas producers for
evaluating the relative significance of oil and natural gas properties and
acquisitions. The present value of estimated future net revenues should
not be construed as an alternative to the Standardized Measure, as
determined in accordance with generally accepted accounting principles.
(12) Represents after tax present value of estimated future net revenues.
17
<PAGE>
RISK FACTORS
Prior to making an investment decision, prospective investors should
consider fully, together with the other information contained in this
Prospectus, the following factors. This Prospectus contains forward looking
statements of the Company. The Company wishes to caution prospective investors
that the following important factors could affect the Company's actual results
in the future.
TENDERING PRIVATE NOTES
Exchange Notes will be issued in exchange for Private Notes only after
timely receipt by the Exchange Agent of such Private Notes, a properly
completed and duly executed Letter of Transmittal and all other required
documentation. Therefore, holders of Private Notes desiring to tender such
Private Notes in exchange for Exchange Notes should allow sufficient time to
ensure timely delivery. Neither the Exchange Agent nor the Company is under
any duty to give notification of defects or irregularities with respect to
tenders of Private Notes for exchange. In addition, any holder of Private
Notes who tenders in the Exchange Offer for the purpose of participating in a
distribution of the Exchange Notes will be required to comply with the
registration and prospectus delivery requirements of the Securities Act in
connection with any resale transaction. Each broker-dealer that receives
Exchange Notes for its own account in exchange for Private Notes, where such
Private Notes were acquired by such broker-dealer as a result of market-making
activities or any other trading activities, must acknowledge that it will
deliver a prospectus in connection with any resale of such Exchange Notes. See
"The Exchange Offer."
CONSEQUENCES OF NOT EXCHANGING PRIVATE NOTES
Private Notes that are not exchanged for Exchange Notes pursuant to the
Exchange Offer will continue to be deemed restricted securities under the
Securities Act and subject to the restrictions on transfer of such Private
Notes a set forth in the legend thereon. Accordingly, the Private Notes may
not be offered or sold, unless registered under the Securities Act or sold
pursuant to an exemption from, or in a transaction not subject to, the
Securities Act and applicable state securities laws. Furthermore, any and all
registration rights under the Registration Rights Agreement held by holders of
Private Notes eligible to participate in the Exchange Offer will be
extinguished as a result of the completion of the Exchange Offer. To the
extent that Private Notes are tendered and accepted in the Exchange Offer, the
trading market for untendered and tendered but unaccepted Private Notes could
be adversely affected due to the limited amount, or "float," of the Private
Notes that are expected to remain outstanding following the Exchange Offer.
Generally, a lower "float" of a security could result in less demand to
purchase such security and could, therefore, result in lower prices for such
security. For the same reason, to the extent that a large amount of Private
Notes are not tendered or are tendered and not accepted in the Exchange Offer,
the trading market for the Exchange Notes could be adversely affected. See
"The Exchange Offer--Consequences of Not Exchanging Private Notes."
LEVERAGE
The Company incurred substantial indebtedness in connection with the Merger
and as a result, the Company is highly leveraged. As of March 31, 1996, the
Company had total indebtedness of approximately $191.8 million and
stockholders' equity (including preferred stock) of approximately $60.5
million. Also, after giving pro forma effect to the Merger and the related
financing transactions, including the sale of the Private Notes, the Company's
earnings would have been insufficient to cover its fixed charges by
approximately $7.1 million for 1995. Pro forma interest expense for 1995 would
have been approximately $18.6 million. The Company intends to incur additional
indebtedness in the future as it executes its acquisition and exploitation
strategy. See "--Ability to Obtain Capital to Finance Acquisitions,"
"Capitalization" and Pro Forma Condensed Financial Statements.
18
<PAGE>
The Company's ability to make scheduled payments of principal of, or to pay
interest on, or to refinance its indebtedness (including the Notes) depends on
its future performance, which, to a certain extent, is subject to general
economic, financial, competitive, legislative, regulatory and other factors
beyond its control, as well as to the prevailing market prices for oil and
natural gas. There can be no assurance that the Company's business will
generate sufficient cash flow from operations or that future bank credit will
be available in an amount sufficient to enable the Company to service its
indebtedness, including the Notes, or make necessary capital expenditures. In
addition, the Company anticipates that it is likely to find it necessary to
refinance a portion of the principal amount of the Notes at or prior to their
maturity. However, there can be no assurance that the Company will be able to
obtain financing to complete a refinancing of the Notes. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations--
Liquidity and Capital Resources."
The degree to which the Company is leveraged as a result of the sale of the
Private Notes could have important consequences to holders of the Notes,
including, but not limited to, the following: (i) a substantial portion of the
Company's cash flow from operations will be required to be dedicated to debt
service and will not be available for other purposes; (ii) the Company's
ability to obtain additional financing in the future could be limited; (iii)
certain of the Company's borrowings are at variable rates of interest, which
could result in higher interest expense in the event of increases in interest
rates; and (iv) the Company will be subject to a variety of restrictive
covenants and the failure of the Company to comply with such covenants could
result in events of default which, if not cured or waived, could have a
material adverse effect on the Company and its ability to make payments of
principal of, and interest on, the Notes. See "Description of Exchange Notes"
and "Description of Other Indebtedness."
ACQUISITION RISKS; DEPLETION OF RESERVES
The Company's strategy is to increase oil and natural gas reserves and cash
flow by selectively acquiring and exploiting producing oil and natural gas
properties, primarily in the mid-continent region of the United States, rather
than engaging in exploratory drilling. The Company's business strategy assumes
that major integrated oil companies and independent oil companies will
continue to divest many of their domestic oil and natural gas properties.
There can be no assurance, however, that such divestitures will continue or
that the Company will be able to acquire such properties at acceptable prices
or develop additional reserves in the future. If such acquisition
opportunities should cease to exist, the Company may be required to alter its
business strategy.
Although the Company performs a review of the properties proposed to be
acquired, such reviews are subject to uncertainties. It is not feasible to
review in detail every individual property involved in each acquisition.
Ordinarily, the Company will focus its review efforts on the higher-valued
properties. However, even a detailed review of all properties and records may
not necessarily reveal existing or potential problems; nor will it permit the
Company to become sufficiently familiar with the properties to assess fully
their deficiencies and capabilities. Inspections are not routinely performed
on every well, and many potential problems, for example, mechanical integrity
of equipment and environmental conditions that may require significant
remedial expenditures, are not necessarily detectable even when an inspection
is undertaken. See "Business--Strategy."
Producing oil and natural gas reservoirs are, in general, characterized by
declining production rates. The decline rate varies depending upon reservoir
characteristics and other factors. The Company's future oil and natural gas
reserves and production, and, therefore, cash flow and income, are highly
dependent upon the Company's level of success in exploiting its current
reserves and acquiring or finding additional reserves. Without reserve
additions in excess of production through acquisition or exploitation and
development activities, the Company's reserves and production will decline
over the long term. There can be no assurance that the Company will be able to
find and develop or acquire additional reserves to replace its current and
future production.
19
<PAGE>
ABILITY TO OBTAIN CAPITAL TO FINANCE ACQUISITIONS
The Company's strategy of acquiring producing oil and natural gas properties
is dependent upon its ability to obtain financing for any such acquisitions.
The Company expects to utilize its Credit Agreement (the "Credit Agreement")
with NationsBank of Texas, N.A. ("NationsBank"), individually and as agent,
and certain other financial institutions as lenders, to borrow 60% to 100% of
the funds required on any given transaction. The Credit Agreement limits the
amounts the Company may borrow thereunder to amounts, determined by the
lenders in their sole discretion, based upon projected net revenues from the
Company's oil and natural gas properties and gas gathering and processing
assets and restricts the amounts the Company may borrow under other credit
facilities. The lenders can adjust the borrowings permitted to be outstanding
under the Credit Agreement semiannually. The lenders require that outstanding
borrowings in excess of the borrowing limit be repaid ratably over a period no
longer than six months. No assurances can be given that the Company will be
able to make any such mandatory principal payments required by the lenders.
Any future acquisition by the Company requiring bank financing in excess of
the amount then available under the Credit Agreement will depend upon the
lenders' evaluations of the properties proposed to be acquired. For a
description of the Credit Agreement and its principal terms and conditions,
see "Description of Other Indebtedness."
VOLATILITY OF OIL, NATURAL GAS AND NATURAL GAS LIQUIDS PRICES
The Company's financial results are significantly impacted by the price
received for the Company's oil, natural gas and natural gas liquids
production. Historically, the markets for oil, natural gas and natural gas
liquids have been volatile and are likely to continue to be volatile in the
future. Prices for oil, natural gas and natural gas liquids are subject to
wide fluctuation in response to market uncertainty, changes in supply and
demand and a variety of additional factors, all of which are beyond the
control of the Company. These factors include domestic and foreign political
conditions, the overall level of supply of and demand for oil, natural gas and
natural gas liquids, the price of imports of oil and natural gas, weather
conditions, the price and availability of alternative fuels and overall
economic conditions. The Company's future financial condition and results of
operations will be dependent, in part, upon the prices received for the
Company's oil and natural gas production, as well as the costs of acquiring,
finding, developing and producing reserves. If oil and natural gas prices fall
materially below their current levels, the availability of funds and the
Company's ability to repay outstanding amounts under its Credit Agreement and
the Notes could be materially adversely affected. See "--Ability to Obtain
Capital" and "Management's Discussion and Analysis of Financial Condition and
Results of Operations."
RELIANCE ON ESTIMATES OF PROVED RESERVES AND FUTURE NET REVENUES
There are numerous uncertainties in estimating quantities of proved reserves
and in projecting future rates of production and the timing of development
expenditures, including many factors beyond the control of the Company. The
reserve data set forth in this Prospectus are only estimates. Reserve
estimates are imprecise and may be expected to change as additional
information becomes available. Furthermore, estimates of oil and gas reserves,
of necessity, are projections based on engineering data, and there are
uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be exactly
measured, and the accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological interpretation and
judgment. Accordingly, estimates of the economically recoverable quantities of
oil and natural gas attributable to any particular group of properties,
classifications of such reserves based on risk of recovery and estimates of
the future net cash flows expected therefrom prepared by different engineers
or by the same engineers at different
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times may vary substantially. There also can be no assurance that the reserves
set forth herein will ultimately be produced or that the proved undeveloped
reserves will be developed within the periods anticipated. It is likely that
variances from the estimates will be material. In addition, the estimates of
future net revenues from proved reserves of the Company and the present value
thereof are based upon certain assumptions about future production levels,
prices and costs that may not be correct. The Company emphasizes with respect
to the estimates prepared by independent petroleum engineers that the
discounted future net cash flows should not be construed as representative of
the fair market value of the proved oil and natural gas properties belonging
to the Company, since discounted future net cash flows are based upon
projected cash flows which do not provide for changes in oil and natural gas
prices or for escalation of expenses and capital costs. The meaningfulness of
such estimates is highly dependent upon the accuracy of the assumptions upon
which they were based. Actual results are likely to differ materially from the
results estimated. Prospective investors in the Exchange Notes are cautioned
not to place undue reliance on the reserve data included in this Prospectus.
DRILLING AND OPERATIONAL RISKS
The Company's oil and natural gas business is also subject to all of the
operating risks associated with the drilling for and production and secondary
recovery of oil and natural gas, including, but not limited to, uncontrollable
flows of oil, natural gas, brine or well fluids (including fluids used in
waterflood activities) into the environment (including groundwater
contamination), fires, explosions, pollution and other risks, any of which
could result in substantial losses to the Company. The natural gas gathering
and processing business is also subject to certain of these risks, including
fires, explosions and environmental contamination. Although the Company
carries insurance at levels which it believes are consistent with industry
practices, it is not fully insured against all risks. Losses and liabilities
arising from uninsured and underinsured events could have a material adverse
effect on the financial condition and operations of the Company. See
"Business--Exploitation and Development Activities."
There are certain risks associated with secondary recovery operations,
especially the use of waterflooding techniques, and drilling activities in
general. Waterflooding involves significant capital expenditures and
uncertainty as to the total amount of secondary reserves that can be
recovered. In waterflood operations, there is generally a delay between the
initiation of water injection into a formation containing hydrocarbons and any
increase in production that may result. The unit production costs per Boe of
waterflood projects are generally higher during the initial phases of such
projects due to the purchase of injection water and related costs, as well as
during the later stages of the life of the project. The degree of success, if
any, of any secondary recovery program depends on a large number of factors,
including the porosity of the formation, the technique used and the location
of injector wells. Drilling activities carry the risk that no commercial
production will be obtained. The cost of drilling, completing and operating
wells is often uncertain, and drilling operations may be curtailed, delayed or
canceled as a result of many factors.
SUBORDINATION OF THE NOTES AND GUARANTEES
The Notes and Guarantees will be subordinated in right of payment to all
existing and future Senior Debt of the Company, which includes all
indebtedness under the Credit Agreement. As of March 31, 1996, the Company had
$81.8 million in Senior Debt and $35.0 million available for borrowing under
the Credit Agreement. In the event of a liquidation, dissolution,
reorganization, bankruptcy or any similar proceeding regarding the Company,
the assets of the Company will be available to pay obligations on the Notes
only after Senior Debt of the Company has been paid in full. Accordingly,
there may not be sufficient funds remaining to pay amounts due on all or any
of the Notes. See "Description of Exchange Notes--Subordination."
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The Company's oil and natural gas properties will not serve as collateral
under the Credit Agreement unless certain events occur. The Company will
provide the lenders with first lien deeds of trust on substantially all of the
Company's oil and natural gas properties. The lenders have agreed, however,
that the mortgages will not be effective and the lenders will not file the
deeds of trust on the oil and natural gas assets unless (i) 80% of any
outstanding borrowings in excess of the borrowing limit is not repaid within a
90 day period, (ii) cash collateral securing a hedging transaction exceeds 20%
of the borrowing limit or (iii) an event of default or a material adverse
event, as defined in the Credit Agreement, occurs.
In addition to being subordinated to all existing and future Senior Debt of
the Company, the Notes and Guarantees will not be secured by any of the
Company's assets.
GOVERNMENT LAWS AND REGULATIONS
The Company's operations are affected from time to time in varying degrees by
political developments and federal and state laws and regulations. In
particular, oil and natural gas production, operations and economics are or
have been affected by price controls, taxes and other laws relating to the oil
and natural gas industry, by changes in such laws and by changes in
administrative regulations. The Company cannot predict how existing laws and
regulations may be interpreted by enforcement agencies or court rulings,
whether additional laws and regulations will be adopted, or the effect such
changes may have on its business or financial condition. See "Business--
Regulation."
ENVIRONMENTAL REGULATIONS
The Company's operations are subject to complex and constantly changing
environmental laws and regulations adopted by federal, state and local
governmental authorities. The Company believes that compliance with such laws
has had no material adverse effect upon the Company's operations to date, and
that the cost of such compliance has not been material. Nevertheless, the
discharge of oil, natural gas or other pollutants into the air, soil or water
may give rise to liabilities on the part of the Company to the government and
third parties and may require the Company to incur costs of remediation.
Additionally, since a significant portion of the Company's reserves are
dependent upon waterflood operations, any change in produced water disposal
requirements or injection well permitting could have a material adverse effect
on the financial conditions and operations of the Company. Moreover, from time
to time the Company has agreed to indemnify both sellers of producing
properties from whom the Company acquires reserves and purchasers of properties
from the Company against certain liabilities for environmental claims
associated with the properties being purchased or sold by the Company. No
assurance can be given that existing environmental laws or regulations, as
currently interpreted or reinterpreted in the future, or future laws or
regulations, will not materially adversely affect the Company's operations and
financial condition or that material indemnity claims will not arise against
the Company with respect to properties acquired or sold by the Company. See
"Business--Environmental Matters."
USE AND RISKS OF HEDGING TRANSACTIONS
The Company has in the past and may in the future enter into oil and natural
gas hedging transactions. While intended to reduce the effects of volatility of
the price of oil and natural gas, such transactions may limit potential gains
by the Company if oil and natural gas prices were to rise substantially over
the price established by the hedge. If the Company is required to maintain cash
collateral on hedging transactions which exceeds 20% of the Company's borrowing
limit under its Credit Agreement, the Company may be required by the lenders to
pledge substantially all of its oil and natural gas properties as collateral
under the Credit Agreement. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Results of Operations" and Note
7 of Notes to Consolidated Financial Statements.
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CONFLICTS OF INTEREST
Enron Corp. ("Enron") is the parent of ECT and accordingly may be deemed to
control indirectly both JEDI and the Company. Enron and certain of its
subsidiaries and other affiliates collectively participate in nearly all
phases of the oil and natural gas industry and are, therefore, competitors of
the Company. In addition, ECT and JEDI have provided, and may in the future
provide, and ECT Securities Corp. has assisted, and may in the future assist,
in arranging, financing to non-affiliated participants in the oil and natural
gas industry who are or may become competitors of the Company.
ECT, the Company, JEDI and the Management Group have entered into a Business
Opportunity Agreement (the "Business Opportunity Agreement") that is intended
to make clear that Enron and its affiliates have no duty to make business
opportunities available to the Company in most circumstances. The Business
Opportunity Agreement also provides that ECT and its affiliates may pursue
certain business opportunities to the exclusion of the Company. Accordingly,
the Business Opportunity Agreement may limit the business opportunities
available to the Company. In addition, pursuant to the Business Opportunity
Agreement there may be circumstances in which the Company will be required to
offer business opportunities to certain affiliates of Enron. If an Enron
affiliate is offered such an opportunity and decides to pursue it, the Company
may be unable to pursue it.
In addition, the Company has in the past marketed a material portion of its
crude oil and natural gas production through certain Enron trading
subsidiaries and will likely continue to do so in the future. During 1994 and
1995, sales of oil and natural gas to EOTT Energy Operating Limited
Partnership (a subsidiary of Enron) accounted for 22% and 18%, respectively,
of the Company's consolidated revenues. The Indenture will not prohibit the
Company from conducting business with Enron and its subsidiaries and
affiliates, but will provide that certain requirements must be satisfied in
order for the Company to transact such business. See "Description of Exchange
Notes--Certain Covenants" and "Certain Transactions."
COMPETITION
The Company encounters substantial competition in acquiring properties,
marketing oil and natural gas and securing trained personnel. Many competitors
have financial resources, staffs and facilities which substantially exceed
those of the Company. See "Business--Markets and Competition."
DEPENDENCE ON KEY PERSONNEL
The Company believes that its operations are dependent to a significant
extent upon its senior management. The loss of the services of a significant
number of these key personnel could have a material adverse effect upon the
Company. The Credit Agreement contains a covenant that requires the continued
employment of certain members of management and requires that certain officers
of the Company maintain specified levels of equity ownership in the Company.
See "Management."
PAYMENT UPON A CHANGE OF CONTROL
Upon the occurrence of a Change of Control, each holder of the Notes may
require the Company to repurchase all or a portion of such holder's Notes at
101% of the principal amount of the Notes, together with accrued and unpaid
interest and Liquidated Damages, if any, to the date of repurchase. The
Indenture will require that prior to such a repurchase, the Company must
either repay all outstanding Senior Debt or obtain any required consents to
such repurchase. Further, under the Credit Agreement, an event of default is
deemed to occur if (i) JEDI, Enron, CalPERS or any wholly owned subsidiary of
either Enron or CalPERS ceases to own greater than 50% of every class of
issued and outstanding capital stock of the Company (on either an undiluted or
fully diluted basis), (ii) JEDI, Enron, CalPERS or any wholly owned subsidiary
of either Enron or CalPERS ceases to own a majority of the outstanding capital
stock of the Company (on either an undiluted or fully diluted basis) having
ordinary
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voting rights for the election of directors or (iii) certain officers cease to
serve in their current positions. In such circumstances, the lenders could
require the repayment of the borrowings under the Credit Agreement. Thus, if a
Change of Control were to occur, the Company may not have the financial
resources to repay all of the Senior Debt, the Notes and the other
indebtedness that would become payable upon the occurrence of such Change of
Control. See "Description of Exchange Notes--Repurchase at the Option of
Holders--Change of Control."
FRAUDULENT CONVEYANCE
Management of the Company believes that the indebtedness represented by the
Notes and the Guarantees was incurred for proper purposes and in good faith,
and that, based on present forecasts, asset valuations and other financial
information, after the consummation of the sale of the Private Notes and the
Exchange Offer, the Company will be solvent, will have sufficient capital for
carrying on its business and will be able to pay its debts as they mature.
See, however, "--Leverage." Notwithstanding management's belief, however, if a
court of competent jurisdiction in a suit by an unpaid creditor or a
representative of creditors (such as a trustee in bankruptcy or a debtor-in-
possession) were to find that, at the time of the incurrence of such
indebtedness, the Company or any of the Guarantors were insolvent, were
rendered insolvent by reason of such incurrence, were engaged in a business or
transaction for which its remaining assets constituted unreasonably small
capital, intended to incur, or believed that it would incur, debts beyond its
ability to pay such debts as they matured, or intended to hinder, delay or
defraud its creditors, and that the indebtedness was incurred for less than
reasonably equivalent value, then such court could, among other things, (i)
void all or a portion of the Company's or the Guarantors' obligations to the
holders of the Notes, the effect of which would be that the holders of the
Notes may not be repaid in full and/or (ii) subordinate the Company's or the
Guarantors' obligations to the holders of the Notes to other existing and
future indebtedness of the Company to a greater extent than would otherwise be
the case, the effect of which would be to entitle such other creditors to be
paid in full before any payment could be made on the Notes or the Guarantees.
LACK OF PUBLIC MARKET FOR THE NOTES; RESTRICTIONS ON RESALES
As of the date of this Prospectus, the only registered holder of the Private
Notes is Cede & Co., as nominee of DTC. The Company believes that, as of the
date of this Prospectus, such holder is not an "affiliate" (as such term is
defined in Rule 405 under the Securities Act) of the Company. Prior to the
offering of the Private Notes, there had been no existing trading market for
the Notes, and there can be no assurance regarding the future development of a
market for the Notes, or the ability of holders of the Notes to sell their
Notes or the price at which such holders may be able to sell their Notes. If
such a market were to develop, the Notes could trade at prices that may be
higher or lower than the initial offering price of the Private Notes depending
on many factors, including prevailing interest rates, the Company's operating
results and the market for similar securities. The Initial Purchasers (other
than ECT Securities Corp.) have advised the Company that they currently intend
to make a market in the Notes. The Purchasers are not obligated to do so,
however, and any market-making with respect to the Notes may be interrupted or
discontinued at any time without notice. In addition, such market making
activity may be limited during the Exchange Offer and the pendency of the
Shelf Registration Statement (as defined in the Registration Rights
Agreement), if any. There can be no assurance as to the liquidity of any
trading market for the Notes or that an active public market for the Notes
will develop. The Private Notes are eligible for trading in the Private
Offerings, Resales and Trading through Automatic Linkages (PORTAL) Market. The
Company does not intend to apply for listing or quotation of the Notes on any
securities exchange or stock market.
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THE EXCHANGE OFFER
PURPOSE OF THE EXCHANGE OFFER
The Private Notes were sold by the Company on March 18, 1996 (the "Closing
Date") to the Initial Purchasers pursuant to the Purchase Agreement. The
Initial Purchasers subsequently sold the Private Notes to (i) "qualified
institutional buyers" ("QIBs"), as defined in Rule 144A under the Securities
Act ("Rule 144A"), in reliance on Rule 144A and (ii) a limited number of
institutional "accredited investors" ("Accredited Institutions"), as defined
in Rule 501(a)(1), (2), (3) or (7) under the Securities Act. As a condition to
the sale of the Private Notes, the Company and the Initial Purchasers entered
into the Registration Rights Agreement on March 18, 1996. Pursuant to the
Registration Rights Agreement, the Company agreed that it would (i) file with
the Commission a Registration Statement under the Securities Act with respect
to the Exchange Notes within 30 days after the Closing Date and (ii) use its
best efforts to cause such Registration Statement to become effective under
the Securities Act within 90 days after the Closing Date. A copy of the
Registration Rights Agreement has been filed as an exhibit to the Registration
Statement. The Registration Statement is intended to satisfy certain of the
Company's obligations under the Registration Rights Agreement and the Purchase
Agreement.
RESALE OF THE EXCHANGE NOTES
With respect to the Exchange Notes, based upon an interpretation by the
staff of the Commission set forth in certain no-action letters issued to third
parties, the Company believes that a holder (other than (i) a broker-dealer
who purchases such Exchange Notes directly from the Company to resell pursuant
to Rule 144A or any other available exemption under the Securities Act or (ii)
any such holder that is an "affiliate" of the Company within the meaning of
Rule 405 under the Securities Act) who exchanges Private Notes for Exchange
Notes in the ordinary course of business and who is not participating, does
not intend to participate, and has no arrangement with any person to
participate, in a distribution of the Exchange Notes, will be allowed to
resell Exchange Notes to the public without further registration under the
Securities Act and without delivering to the purchasers of the Exchange Notes
a prospectus that satisfies the requirements of Section 10 of the Securities
Act. However, if any holder acquires Exchange Notes in the Exchange Offer for
the purpose of distributing or participating in the distribution of the
Exchange Notes or is a broker-dealer, such holder cannot rely on the position
of the staff of the Commission enumerated in certain no-action letters issued
to third parties and must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with any resale transaction,
unless an exemption from registration is otherwise available. Each broker-
dealer that receives Exchange Notes for its own account in exchange for
Private Notes, where such Private Notes were acquired by such broker-dealer as
a result of market-making activities or other trading activities, must
acknowledge that it will deliver a prospectus in connection with any resale of
such Exchange Notes. The Letter of Transmittal states that by so acknowledging
and by delivering a prospectus, a broker-dealer will not be deemed to admit
that it is an "underwriter" within the meaning of the Securities Act. This
Prospectus, as it may be amended or supplemented from time to time, may be
used by a broker-dealer in connection with resales of Exchange Notes received
in exchange for Private Notes where such Private Notes were acquired by such
broker-dealer as a result of market-making or other trading activities.
Pursuant to the Registration Rights Agreement, the Company has agreed to make
this Prospectus, as it may be amended or supplemented from time to time,
available to broker-dealers for use in connection with any resale for a period
of one year after the date the Registration Statement is declared effective.
See "Plan of Distribution."
TERMS OF THE EXCHANGE OFFER
Upon the terms and subject to the conditions set forth in this Prospectus
and in the Letter of Transmittal, the Company will accept any and all Private
Notes validly tendered and not withdrawn prior to the Expiration Date. The
Company will issue $1,000 principal amount of Exchange Notes in
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exchange for each $1,000 principal amount of outstanding Private Notes
surrendered pursuant to the Exchange Offer. Private Notes may be tendered only
in integral multiples of $1,000.
The form and terms of the Exchange Notes are the same as the form and terms
of the Private Notes except that (i) the Exchange Notes will bear a Series B
designation, (ii) the Exchange Notes will have been registered under the
Securities Act and, therefore, the Exchange Notes will not bear legends
restricting the transfer thereof and (iii) holders of the Exchange Notes will
not be entitled to certain rights of holders of the Private Notes under the
Registration Rights Agreement, which rights will terminate upon consummation
of the Exchange Offer. The Exchange Notes will evidence the same indebtedness
as the Private Notes (which they replace) and will be issued under, and be
entitled to the benefits of, the Indenture, which also authorized the issuance
of the Private Notes, such that both series of Notes will be treated as a
single class of debt securities under the Indenture.
As of the date of this Prospectus, $110,000,000 in aggregate principal
amount of the Private Notes are outstanding and registered in the name of Cede
& Co., as nominee for DTC. Only a registered holder of the Private Notes (or
such holder's legal representative or attorney-in-fact) as reflected on the
records of the Trustee under the Indenture may participate in the Exchange
Offer. There will be no fixed record date for determining registered holders
of the Private Notes entitled to participate in the Exchange Offer.
Holders of the Private Notes do not have any appraisal or dissenters' rights
under the Indenture in connection with the Exchange Offer. The Company intends
to conduct the Exchange Offer in accordance with the provisions of the
Registration Rights Agreement and the applicable requirements of the
Securities Act, the Securities Exchange Act of 1934, as amended (the "Exchange
Act"), and the rules and regulations of the Commission thereunder.
The Company shall be deemed to have accepted validly tendered Private Notes
when, as and if the Company has given oral or written notice thereof to the
Exchange Agent. The Exchange Agent will act as agent for the tendering holders
of Private Notes for the purposes of receiving the Exchange Notes from the
Company.
Holders who tender Private 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 Private
Notes pursuant to the Exchange Offer. The Company will pay all charges and
expenses, other than certain applicable taxes described below, in connection
with the Exchange Offer. See "--Fees and Expenses."
EXPIRATION DATE; EXTENSIONS; AMENDMENTS
The term "Expiration Date" shall mean 5:00 p.m., New York City time on July
12, 1996, unless the Company, in its sole discretion, extends the Exchange
Offer, in which case the term "Expiration Date" shall mean the latest date and
time to which the Exchange Offer is extended.
In order to extend the Exchange Offer, the Company will (i) notify the
Exchange Agent of any extension by oral or written notice, (ii) mail to the
registered holders an announcement thereof and (iii) issue a press release or
other public announcement which shall include disclosure of the approximate
number of Private Notes deposited to date, each prior to 9:00 a.m., New York
City time, on the next business day after the previously scheduled Expiration
Date. Without limiting the manner in which the Company may choose to make a
public announcement of any delay, extension, amendment or termination of the
Exchange Offer, the Company shall have no obligation to publish, advertise, or
otherwise communicate any such public announcement, other than by making a
timely release to an appropriate news agency.
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The Company reserves the right, in its sole discretion, (i) to delay
accepting any Private Notes, (ii) to extend the Exchange Offer or (iii) if any
conditions set forth below under "--Conditions" shall not have been satisfied,
to terminate the Exchange Offer by giving oral or written notice of such
delay, extension or termination to the Exchange Agent. 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. If
the Exchange Offer is amended in a manner determined by the Company to
constitute a material change, the Company will promptly disclose such
amendment by means of a prospectus supplement that will be distributed to the
registered holders of the Private Notes, and the Company will extend the
Exchange Offer for a period of five to ten business days, depending upon the
significance of the amendment and the manner of disclosure to the registered
holders, if the Exchange Offer would otherwise expire during such five to ten
business day period.
INTEREST ON THE EXCHANGE NOTES
The Exchange Notes will bear interest at a rate equal to 10 1/2% per annum.
Interest on the Exchange Notes will be payable semiannually in arrears on each
April 1 and October 1, commencing October 1, 1996. Holders of Exchange Notes
will receive interest on October 1, 1996 from and including the date of
initial issuance of the Exchange Notes, plus an amount equal to the accrued
interest on the Private Notes from the date of initial delivery to the date of
exchange thereof for Exchange Notes. Holders of Private Notes that are
accepted for exchange will be deemed to have waived the right to receive any
interest accrued on the Private Notes.
PROCEDURES FOR TENDERING
Only a registered holder of Private Notes may tender such Private Notes in
the Exchange Offer. To tender in the Exchange Offer, a holder of Private Notes
must complete, sign and date the Letter of Transmittal, or a facsimile
thereof, have the signatures thereon guaranteed if required by the Letter of
Transmittal, and mail or otherwise deliver such Letter of Transmittal or such
facsimile to the Exchange Agent at the address set forth below under "--
Exchange Agent" for receipt prior to the Expiration Date. In addition, either
(i) certificates for such Private Notes must be received by the Exchange Agent
along with the Letter of Transmittal, (ii) a timely confirmation of a book-
entry transfer (a "Book-Entry Confirmation") of such Private Notes, if such
procedure is available, into the Exchange Agent's account at the Depositary
pursuant to the procedure for book-entry transfer described below, must be
received by the Exchange Agent prior to the Expiration Date or (iii) the
holder must comply with the guaranteed delivery procedures described below.
The tender by a holder that is not withdrawn prior to the Expiration Date
will constitute an agreement between such holder and the Company in accordance
with the terms and subject to the conditions set forth herein and in the
Letter of Transmittal.
THE METHOD OF DELIVERY OF PRIVATE NOTES AND THE LETTER OF TRANSMITTAL AND
ALL OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT THE ELECTION AND RISK
OF THE HOLDER. INSTEAD OF DELIVERY BY MAIL, IT IS RECOMMENDED THAT HOLDERS USE
AN OVERNIGHT OR HAND DELIVERY SERVICE, PROPERLY INSURED. IN ALL CASES,
SUFFICIENT TIME SHOULD BE ALLOWED TO ASSURE DELIVERY TO THE EXCHANGE AGENT
BEFORE THE EXPIRATION DATE. NO LETTER OF TRANSMITTAL OR PRIVATE NOTES SHOULD
BE SENT TO THE COMPANY. HOLDERS MAY REQUEST THEIR RESPECTIVE BROKERS, DEALERS,
COMMERCIAL BANKS, TRUST COMPANIES OR NOMINEES TO EFFECT THE ABOVE TRANSACTIONS
FOR SUCH HOLDERS.
Any beneficial owner(s) of the Private Notes whose Private Notes are
registered in the name of a broker, dealer, commercial bank, trust company or
other nominee and who wishes to tender should contact the registered holder
promptly and instruct such registered holder to tender on such beneficial
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owner's behalf. If such beneficial owner wishes to tender on such owner's own
behalf, such owner must, prior to completing and executing the Letter of
Transmittal and delivering such owner's Private Notes, either make appropriate
arrangements to register ownership of the Private Notes in such owner's name
or obtain a properly completed bond power from the registered holder. The
transfer of registered ownership may take considerable time.
Signatures on a Letter of Transmittal or a notice of withdrawal described
below (see "--Withdrawal of Tenders"), as the case may be, must be guaranteed
by an Eligible Institution (as defined below) unless the Private Notes
tendered pursuant thereto are tendered (i) by a registered holder who has not
completed the box titled "Special Delivery Instructions" on the Letter of
Transmittal or (ii) for the account of an Eligible Institution. In the event
that signatures on a Letter of Transmittal or a notice of withdrawal, as the
case may be, are required to be guaranteed, such guarantee must be made 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 Exchange
Act which is a member of one of the recognized signature guarantee programs
identified in the Letter of Transmittal (an "Eligible Institution").
If the Letter of Transmittal is signed by a person other than the registered
holder of any Private Notes listed therein, such Private Notes must be
endorsed or accompanied by a properly completed bond power, signed by such
registered holder as such registered holder's name appears on such Private
Notes.
If the Letter of Transmittal or any Private Notes or bond powers are signed
by trustees, executors, administrators, guardians, attorneys-in-fact, officers
of corporations or others acting in a fiduciary or representative capacity,
such persons should so indicate when signing, and unless waived by the
Company, evidence satisfactory to the Company of their authority to so act
must be submitted with the Letter of Transmittal.
The Exchange Agent and the Depositary have confirmed that any financial
institution that is a participant in the Depositary's system may utilize the
Depositary's Automated Tender Offer Program to tender Private Notes.
All questions as to the validity, form, eligibility (including time of
receipt), acceptance and withdrawal of tendered Private Notes will be
determined by the Company in its sole discretion, which determination will be
final and binding. The Company reserves the absolute right to reject any and
all Private Notes not properly tendered or any Private Notes the Company's
acceptance of which would, in the opinion of counsel for the Company, be
unlawful. The Company also reserves the right to waive any defects,
irregularities or conditions of tender as to particular Private 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 Private Notes must be cured within such time as the
Company shall determine. Although the Company intends to notify holders of
defects or irregularities with respect to tenders of Private Notes, neither
the Company, the Exchange Agent nor any other person shall incur any liability
for failure to give such notification. Tenders of Private Notes will not be
deemed to have been made until such defects or irregularities have been cured
or waived.
While the Company has no present plan to acquire any Private Notes that are
not tendered in the Exchange Offer or to file a registration statement to
permit resales of any Private Notes that are not tendered pursuant to the
Exchange Offer, the Company reserves the right in its sole discretion to
purchase or make offers for any Private Notes that remain outstanding
subsequent to the Expiration Date or, as set forth below under "--Conditions,"
to terminate the Exchange Offer and, to the extent permitted by applicable
law, purchase Private Notes in the open market, in privately negotiated
28
<PAGE>
transactions or otherwise. The terms of any such purchases or offers could
differ from the terms of the Exchange Offer.
By tendering, each holder of Private Notes will represent to the Company
that, among other things, (i) Exchange Notes to be acquired by such holder of
Private Notes in connection with the Exchange Offer are being acquired by such
holder in the ordinary course of business of such holder, (ii) such holder has
no arrangement or understanding with any person to participate in the
distribution of the Exchange Notes, (iii) such holder acknowledges and agrees
that any person who is a broker-dealer registered under the Exchange Act or is
participating in the Exchange Offer for the purposes of distributing the
Exchange Notes must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with a secondary resale
transaction of the Exchange Notes acquired by such person and cannot rely on
the position of the staff of the Commission set forth in certain no-action
letters, (iv) such holder understands that a secondary resale transaction
described in clause (iii) above and any resales of Exchange Notes obtained by
such holder in exchange for Private Notes acquired by such holder directly
from the Company should be covered by an effective registration statement
containing the selling securityholder information required by Item 507 or Item
508, as applicable, of Regulation S-K of the Commission and (v) such holder is
not an "affiliate," as defined in Rule 405 under the Securities Act, of the
Company. If the holder is a broker-dealer that will receive Exchange Notes for
such holder's own account in exchange for Private Notes that were acquired as
a result of market-making activities or other trading activities, such holder
will be required to acknowledge in the Letter of Transmittal that such holder
will deliver a prospectus in connection with any resale of such Exchange
Notes; however, by so acknowledging and by delivering a prospectus, such
holder will not be deemed to admit that it is an "underwriter" within the
meaning of the Securities Act.
RETURN OF PRIVATE NOTES
If any tendered Private Notes are not accepted for any reason set forth in
the terms and conditions of the Exchange Offer or if Private Notes are
withdrawn or are submitted for a greater principal amount than the holders
desire to exchange, such unaccepted, withdrawn or non-exchanged Private Notes
will be returned without expense to the tendering holder thereof (or, in the
case of Private Notes tendered by book-entry transfer into the Exchange
Agent's account at the Depositary pursuant to the book-entry transfer
procedures described below, such Private Notes will be credited to an account
maintained with the Depositary) as promptly as practicable.
BOOK-ENTRY TRANSFER
The Exchange Agent will make a request to establish an account with respect
to the Private Notes at the Depositary for purposes of the Exchange Offer
within two business days after the date of this Prospectus, and any financial
institution that is a participant in the Depositary's systems may make book-
entry delivery of Private Notes by causing the Depositary to transfer such
Private Notes into the Exchange Agent's account at the Depositary in
accordance with the Depositary's procedures for transfer. However, although
delivery of Private Notes may be effected through book-entry transfer at the
Depositary, the Letter of Transmittal or facsimile thereof, with any required
signature guarantees and any other required documents, must, in any case, be
transmitted to and received by the Exchange Agent at the address set forth
below under "--Exchange Agent" on or prior to the Expiration Date or pursuant
to the guaranteed delivery procedures described below.
GUARANTEED DELIVERY PROCEDURES
Holders who wish to tender their Private Notes and (i) whose Private Notes
are not immediately available or (ii) who cannot deliver their Private Notes,
the Letter of Transmittal or any other required documents to the Exchange
Agent prior to the Expiration Date, may effect a tender if:
29
<PAGE>
(a) The tender is made through an Eligible Institution;
(b) Prior to the Expiration Date, the Exchange Agent receives from such
Eligible Institution a properly completed and duly executed Notice of
Guaranteed Delivery substantially in the form provided by the Company (by
facsimile transmission, mail or hand delivery) setting forth the name and
address of the holder, the certificate number(s) of such Private Notes and
the principal amount of Private Notes tendered, stating that the tender is
being made thereby and guaranteeing that, within five New York Stock
Exchange trading days after the Expiration Date, the Letter of Transmittal
(or a facsimile thereof), together with the certificate(s) representing the
Private Notes in proper form for transfer or a Book-Entry Confirmation, as
the case may be, and any other documents required by the Letter of
Transmittal, will be deposited by the Eligible Institution with the
Exchange Agent; and
(c) Such properly executed Letter of Transmittal (or facsimile thereof),
as well as the certificate(s) representing all tendered Private Notes in
proper form for transfer and all other documents required by the Letter of
Transmittal are received by the Exchange Agent within five New York Stock
Exchange trading days after the Expiration Date.
Upon request to the Exchange Agent, a Notice of Guaranteed Delivery will be
sent to holders who wish to tender their Private Notes according to the
guaranteed delivery procedures set forth above.
WITHDRAWAL OF TENDERS
Except as otherwise provided herein, tenders of Private Notes may be
withdrawn at any time prior to the Expiration Date.
To withdraw a tender of Private Notes in the Exchange Offer, a written or
facsimile transmission notice of withdrawal must be received by the Exchange
Agent at its address set forth herein prior to the Expiration Date. Any such
notice of withdrawal must (i) specify the name of the person having deposited
the Private Notes to be withdrawn (the "Depositor"), (ii) identify the Private
Notes to be withdrawn (including the certificate number or numbers and
principal amount of such Private Notes) and (iii) be signed by the holder in
the same manner as the original signature on the Letter of Transmittal by
which such Private Notes were tendered (including any required signature
guarantees). All questions as to the validity, form and eligibility (including
time of receipt) of such notices will be determined by the Company in its sole
discretion, whose determination shall be final and binding on all parties. Any
Private Notes so withdrawn will be deemed not to have been validly tendered
for purposes of the Exchange Offer and no Exchange Notes will be issued with
respect thereto unless the Private Notes so withdrawn are validly retendered.
Properly withdrawn Private Notes may be retendered by following one of the
procedures described above under "The Exchange Offer--Procedures for
Tendering" at any time prior to the Expiration Date.
CONDITIONS
Notwithstanding any other term of the Exchange Offer, the Company shall not
be required to accept for exchange, or exchange the Exchange Notes for, any
Private Notes, and may terminate the Exchange Offer as provided herein before
the acceptance of such Private Notes, if the Exchange Offer violates
applicable law, rules or regulations or an applicable interpretation of the
staff of the Commission.
If the Company determines in its sole discretion that any of these
conditions are not satisfied, the Company may (i) refuse to accept any Private
Notes and return all tendered Private Notes to the tendering holders, (ii)
extend the Exchange Offer and retain all Private Notes tendered prior to the
expiration of the Exchange Offer, subject, however, to the rights of holders
to withdraw such Private Notes (see "--Withdrawal of Tenders") or (iii) waive
such unsatisfied conditions with respect to the
30
<PAGE>
Exchange Offer and accept all properly tendered Private Notes that have not
been withdrawn. If such waiver constitutes a material change to the Exchange
Offer, the Company will promptly disclose such waiver by means of a prospectus
supplement that will be distributed to the registered holders of the Private
Notes, and the Company will extend the Exchange Offer for a period of five to
ten business days, depending upon the significance of the waiver and the
manner of disclosure to the registered holders, if the Exchange Offer would
otherwise expire during such five to ten business day period.
TERMINATION OF CERTAIN RIGHTS
All rights under the Registration Rights Agreement (including registration
rights) of holders of the Private Notes eligible to participate in the
Exchange Offer will terminate upon consummation of the Exchange Offer except
with respect to the Company's continuing obligations (i) to indemnify such
holders (including any broker-dealers) and certain parties related to such
holders against certain liabilities (including liabilities under the
Securities Act), (ii) to provide, upon the request of any holder of a
transfer-restricted Private Note, the information required by Rule 144A(d)(4)
under the Securities Act in order to permit resales of such Private Notes
pursuant to Rule 144A, (iii) to use its best efforts to keep the Registration
Statement effective to the extent necessary to ensure that it is available for
resales of transfer-restricted Private Notes by broker-dealers for a period of
up to one year from the date the Registration Statement is declared effective
and (iv) to provide copies of the latest version of the Prospectus to broker-
dealers upon their request for a period of up to one year from the date the
Registration Statement is declared effective.
ADDITIONAL INTEREST
In the event of a Registration Default (as defined in the Registration
Rights Agreement), the Company is required to pay as liquidated damages,
Additional Interest (as defined in the Registration Rights Agreement) to each
holder of Transfer Restricted Securities (as defined below), during the first
90-day period immediately following the occurrence of such Registration
Default in an amount equal to $0.05 per week per $1,000 principal amount of
Private Notes constituting Transfer Restricted Securities held by such holder.
Transfer Restricted Securities shall mean each Private Note until (i) the date
on which such Private Note has been exchanged for an Exchange Note in the
Exchange Offer and is entitled to be resold to the public by the holder
thereof without complying with the prospectus delivery requirements of the
Securities Act, (ii) the date on which such Private Note has been effectively
registered under the Securities Act and disposed of in accordance with the
Shelf Registration Statement (as defined in the Registration Rights Agreement)
and (iii) the date on which such Private Note is distributed to the public
pursuant to Rule 144(k) under the Securities Act or by a broker-dealer
pursuant to the "Plan of Distribution" set forth in this Prospectus (including
delivery of this Prospectus). The amount of the Additional Interest will
increase by an additional $0.05 per week per $1,000 principal amount of
Private Notes constituting Transfer Restricted Securities for each subsequent
90-day period until all Registration Defaults have been cured, up to a maximum
Additional Interest of $0.50 per week per $1,000 principal amount of Private
Notes constituting Transfer Restricted Securities. Following the cure of all
Registration Defaults, the payment of Additional Interest will cease. The
filing and effectiveness of the Registration Statement of which this
Prospectus is a part and the consummation of the Exchange Offer will eliminate
all rights of the holders of Private Notes eligible to participate in the
Exchange Offer to receive damages that would have been payable if such actions
had not occurred.
EXCHANGE AGENT
Texas Commerce Bank National Association has been appointed as Exchange
Agent of the Exchange Offer. Questions and requests for assistance, requests
for additional copies of this Prospectus or of the Letter of Transmittal and
requests for Notice of Guaranteed Delivery should be directed to the Exchange
Agent addressed as follows:
31
<PAGE>
By Registered or Certified Mail: By Overnight or Hand Delivery:
Texas Commerce Bank National Texas Commerce Bank National
Association Association
P.O. Box 2320 One Main Place, 19th Floor
Dallas, Texas 75221-2320 1201 Main Street
Attn: Frank Ivins Dallas, Texas 75201
Attn: Frank Ivins
By Facsimile: Confirm by Telephone:
(214) 672-5744 (214) 672-5678
FEES AND EXPENSES
The expenses of soliciting tenders will be borne by the Company. The
principal solicitation is being made by mail; however, additional solicitation
may be made by telegraph, telephone or in person by officers and regular
employees of the Company and its affiliates.
The Company has not retained any dealer-manager in connection with the
Exchange Offer and will not make any payments to brokers, dealers or others
soliciting acceptances of the Exchange Offer. The Company, however, will pay
the Exchange Agent reasonable and customary fees for its services and will
reimburse it for its reasonable out-of-pocket expenses in connection
therewith.
The cash expenses to be incurred in connection with the Exchange Offer will
be paid by the Company and are estimated in the aggregate to be approximately
$70,000. Such expenses include registration fees, fees and expenses of the
Exchange Agent and the Trustee, accounting and legal fees and printing costs,
among others.
The Company will pay all transfer taxes, if any, applicable to the exchange
of Private Notes pursuant to the Exchange Offer. If, however, a transfer tax
is imposed for any reason other than the exchange of the Private Notes
pursuant to the Exchange Offer, then the amount of any such transfer taxes
(whether imposed on the registered holder or any other persons) will be
payable by the tendering holder. If satisfactory evidence of payment of such
taxes or exemption therefrom is not submitted with the Letter of Transmittal,
the amount of such transfer taxes will be billed directly to such tendering
holder.
CONSEQUENCES OF NOT EXCHANGING PRIVATE NOTES
Participation in the Exchange Offer is voluntary. Holders of the Private
Notes are urged to consult their financial and tax advisors in making their
own decisions on what action to take.
Private Notes that are not exchanged for Exchange Notes pursuant to the
Exchange Offer will continue to be deemed restricted securities under the
Securities Act and subject to the restrictions on transfer of such Private
Notes as set forth in the legend thereon. Accordingly, the Private Notes may
not be offered or sold, unless registered under the Securities Act or sold
pursuant to an exemption from, or in a transaction not subject to, the
Securities Act and applicable state securities laws. Furthermore, any and all
registration rights under the Registration Rights Agreement held by holders of
Private Notes eligible to participate in the Exchange Offer will be
extinguished as a result of the completion of the Exchange Offer. See "Risk
Factors--Consequences of Not Exchanging Private Notes."
ACCOUNTING TREATMENT
For accounting purposes, the Company will recognize no gain or loss as a
result of the Exchange Offer. The expenses of the Exchange Offer will be
amortized over the term of the Exchange Notes.
32
<PAGE>
THE MERGER
On October 31, 1995, the Company announced that it had entered into an
Agreement and Plan of Merger dated as of October 30, 1995, by and among Coda,
JEDI and CAI, whereby JEDI would acquire in the Merger all outstanding shares
of common stock, par value $0.02 per share, of Coda (the "Common Stock").
Concurrently with the execution of the Merger Agreement, JEDI and CAI entered
into certain agreements with the Management Group providing for a continuing
role of management in the Company after the Merger. The per share purchase
price for the Common Stock was $7.75 in cash (for an aggregate purchase price
of approximately $176.2 million). The Merger was completed on February 16,
1996.
JEDI was formed as a limited partnership between CalPERS and an affiliate of
ECT, with the ECT affiliate designated as the general partner. The purpose of
the partnership is to invest in a diversified portfolio of energy related
assets.
The Management Group entered into written agreements with JEDI and CAI
concerning their employment with and/or equity participation in the Company.
The Management Group holds an aggregate of approximately 1.5% of the Company's
common stock (approximately 5% on a fully diluted basis, including options
granted to such persons). See "Executive Compensation and Other Information."
The sources and uses of funds related to financing the Merger were as
follows:
SOURCES OF FUNDS
(in millions)
<TABLE>
<S> <C>
Credit Agreement.................................................. $ 95.0
JEDI Debt(1)...................................................... 100.0
Redeemable Preferred Stock issued to JEDI......................... 20.0
Common Stock issued to JEDI....................................... 90.0
------
Total......................................................... $305.0
======
</TABLE>
USES OF FUNDS
(in millions)
<TABLE>
<S> <C>
Payments to Coda stockholders, warrantholders and optionholders.. $176.2
Repayment of former credit facility and other indebtedness....... 122.7
Merger costs and other expenses.................................. 6.1
------
Total........................................................ $305.0
======
</TABLE>
--------
(1) Represents indebtedness incurred by CAI and assumed by Coda to
fund a portion of the consideration paid in the Merger. See "Use
of Proceeds."
33
<PAGE>
USE OF PROCEEDS
The net proceeds of the sale of the Private Notes were approximately $107.25
million and $100 million of such proceeds were used to repay all of the
principal amount of the indebtedness owed to JEDI (the "JEDI Debt") incurred
by CAI in connection with the Merger and assumed by the Company upon the
Company's merger with CAI. The JEDI Debt bore interest at the rate of U.S.
Treasury instruments with a maturity closest to the maturity date of the JEDI
Debt plus 6.25% per annum; however, during the first six months, the Company
could choose an interest rate option which provided for interest at the rate
of LIBOR plus 4.25% per annum. The JEDI Debt had a maturity date of February
16, 2003. See "The Merger" and "Certain Transactions."
The remaining net proceeds of approximately $7.25 million, together with
available corporate cash of $2.75 million, were used to repay indebtedness
outstanding under the Credit Agreement (which had an outstanding balance of
approximately $122.0 million at December 31, 1995 and approximately $80.0
million at March 31, 1996). The indebtedness under the Credit Agreement was
incurred primarily in connection with acquisitions of producing properties and
for other general corporate purposes. After application of such net proceeds
of the sale of the Private Notes, approximately $35.0 million is available as
of March 31, 1996 for reborrowing under the Credit Agreement to be used for
general corporate purposes, which may include acquiring producing oil and
natural gas properties or companies owning the same. The Company has no
current understandings or agreements in respect of any pending material
acquisition. See "Description of Other Indebtedness--Credit Agreement" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources."
34
<PAGE>
CAPITALIZATION
The following table sets forth the unaudited capitalization of the Company
as of December 31, 1995, and March 31, 1996 on an historical basis. The
following table should be read in conjunction with the Company's Historical
Financial Statements, and the other information contained elsewhere in this
Prospectus, including the information set forth in "Management's Discussion
and Analysis of Financial Condition and Results of Operations." For further
information regarding the terms of the long-term debt reflected in the
following table, see "Description of Other Indebtedness" and the Notes to
Historical Financial Statements.
<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31,
1995 1996
------------ ----------
(in thousands)
<S> <C> <C>
Current maturities of long-term debt(1)............... $ 453 $ 120
Long-term debt:
Former credit facility.............................. 122,000 --
Credit Agreement(1)................................. -- 80,000
12% Senior Subordinated Debentures due 2000(1)...... 988 1,153
10 1/2% Senior Subordinated Notes due 2006.......... -- 110,000
Other(1)............................................ 919 566
----------- ----------
Total long-term debt.............................. 123,907 191,719
----------- ----------
15% Cumulative Redeemable Preferred Stock(2).......... -- --
Additional paid-in capital.......................... -- 20,000
----------- ----------
Total preferred stock............................. -- 20,000
----------- ----------
Common stockholders' equity of management, subject to
put and call rights:
Common stock(3)..................................... -- --
Additional paid-in capital.......................... -- 4,560
Less related notes receivable....................... -- (937)
----------- ----------
Total common stockholders' equity of management... -- 3,623
----------- ----------
Other common stockholders' equity:
Common stock(3)..................................... 442 9
Additional paid-in capital.......................... 68,671 89,991
Retained earnings (deficit)......................... 10,075 (53,136)
----------- ----------
Total other common stockholders' equity........... 79,188 36,864
----------- ----------
Total capitalization.................................. $ 203,548 $ 252,326
=========== ==========
Shares authorized
Preferred stock; par value $0.001 historical; par
value $0.01 pro forma.............................. 7,500,000 40,000
Common stock; par value $0.02 historical; par value
$0.01 pro forma.................................... 40,000,000 1,000,000
</TABLE>
- --------
(1) Such indebtedness is senior in right of payment to the Notes.
(2) At December 31, 1995, there were no shares of preferred stock (par value
$0.001 per share) issued or outstanding. At March 31, 1996, there were
20,000 shares (par value $0.01 per share) issued and outstanding. The 15%
Cumulative Redeemable Preferred Stock, par value $0.01 per share (the
"Preferred Stock"), was issued to JEDI in connection with the Merger and
can be paid cash dividends or redeemed for cash only to the extent
permitted by the Indenture and the Credit Agreement. See "Description of
Exchange Notes--Certain Covenants--Restricted Payments" and "Description
of Capital Stock--Preferred Stock."
(3) At December 31, 1995, there were 22,088,903 shares (par value $0.02 per
share) of Common Stock issued and outstanding. At March 31, 1996, 913,611
shares (par value $0.01 per share) were issued and outstanding (13,611
shares held by the Management Group and 900,000 shares held by JEDI). The
outstanding share numbers exclude 2,416,632 shares and 31,989 shares
reserved for issuance at December 31, 1995 and March 31, 1996,
respectively, upon exercise of outstanding options and warrants to
purchase Common Stock. At December 31, 1995, the Common Stock held by
management is included in other common stockholders' equity. See "Certain
Transactions--Stockholders Agreement" and "Description of Capital Stock--
Common Stock."
35
<PAGE>
SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA
The following table sets forth for the period indicated selected historical
and pro forma financial data for the Company. The selected historical
financial data as of and for each of the years in the five-year period ended
December 31, 1995, have been derived from the historical financial statements
of the Company, which were audited by Ernst & Young LLP, independent auditors.
The selected historical financial data as of and for the periods ended March
31, 1995, February 16, 1996 and March 31, 1996 have been derived from the
unaudited consolidated financial statements of the Company included elsewhere
herein. The Company acquired significant producing oil and natural gas
properties in all the periods presented which affect the comparability of the
historical financial and operating data for the periods presented. As a result
of the Merger, JEDI acquired Coda effective February 16, 1996. The Merger has
been accounted for using the purchase method of accounting. As such, JEDI's
cost of acquiring Coda has been allocated to the assets and liabilities
acquired based on estimated fair values. As a result, the Company's financial
position and operating results subsequent to the date of the Merger reflect a
new basis of accounting and are not comparable to prior periods. The pro forma
condensed financial data presented in the table below are derived from the Pro
Forma Condensed Financial Statements included elsewhere in this Prospectus.
The information below should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations," the
Historical Financial Statements of the Company and the notes thereto, as well
as the Pro Forma Condensed Financial Statements and the notes thereto included
elsewhere in this Prospectus.
<TABLE>
<CAPTION>
HISTORICAL PRO FORMA
----------------------------------------------------------------------------- -------------------------
THREE MONTHS 47 DAYS 44 DAYS YEAR THREE MONTHS
YEAR ENDED DECEMBER 31, ENDED ENDED ENDED ENDED ENDED
----------------------------------------- MARCH 31, FEBRUARY 16, MARCH 31, DECEMBER 31, MARCH 31,
1991 1992 1993 1994 1995 1995 1996 1996 1995(1) 1996(1)
------- ------- ------- ------- ------- ------------ ------------ --------- ------------ ------------
(in thousands, except ratios)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT
DATA:
Oil and gas
sales........... $16,512 $18,631 $38,877 $50,683 $60,997 $14,948 $8,079 $8,964 $66,156 $17,043
Gas gathering
and
processing(2)... 5,246 4,709 732 20,081 35,634 7,904 5,322 4,799 35,634 10,121
Total revenues.. 22,782 23,637 40,050 71,586 97,838 23,039 13,569 13,964 102,997 27,533
Interest
expense......... 2,420 2,752 4,834 5,281 8,676 2,068 1,102 2,087 18,563 4,300
Total costs and
expenses(3)..... 21,865 24,778 36,398 65,676 88,881 20,938 15,378 97,015 110,066 27,816
Income (loss)
before income
taxes........... 917 (1,141) 3,652 5,910 8,957 2,101 (1,809) (83,051) (7,069) (283)
Net income
(loss).......... (65) (734) 2,334 3,329 5,755 1,305 (1,298) (53,136) (4,493) (279)
Ratio of
earnings to
fixed
charges(4)...... 1.4x -- 1.8x 2.1x 2.0x 2.0x -- -- -- --
CASH FLOW
DATA(5):
Net income
(loss).......... $ (65) $ (734) $ 2,334 $ 3,329 $ 5,755 $ 1,305 $(1,298) $(53,136) $ (4,493) $ (279)
Depletion,
depreciation and
amortization.... 4,823 4,813 10,808 16,419 19,715 4,870 2,583 3,498 28,509 6,897
Net cash
provided by
operating
activities...... 6,127 2,241 16,443 22,987 24,301 5,122 3,136 1,461 17,069 3,487
OTHER DATA(6):
EBITDA.......... 8,160 6,424 19,294 27,610 37,348 9,039 1,876 5,839 40,003 10,914
EBITDA/interest
expense......... 3.4x 2.3x 4.0x 5.2x 4.3x 4.4x 1.7x 2.8x 2.2x 2.5x
Debt/EBITDA..... 3.8x 9.2x 3.2x 3.8x 3.3x
CAPITAL
EXPENDITURES:
Oil and gas
property
acquisitions.... $21,650 $23,318 $42,223 $40,109 $25,363 $ 498 $ 305 $ 92
Oil and gas
development and
other........... 4,404 7,550 10,403 12,450 14,464 4,457 1,412 678
Gas plant and
gathering
systems and
other property
additions....... 687 1,365 646 7,380 8,500 7,346 114 43
</TABLE>
36
<PAGE>
<TABLE>
<CAPTION>
AT DECEMBER 31,
------------------------------------------ MARCH 31,
1991 1992 1993 1994 1995 1996
------- ------- -------- -------- -------- ---------
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Total assets............. $56,010 $82,226 $132,754 $203,102 $229,064 $304,435
Notes.................... -- -- -- -- -- 110,000
Other long-term debt,
less current
maturities.............. 28,794 56,563 59,651 105,063 123,907 81,719
Redeemable Preferred
Stock................... -- -- -- -- -- 20,000
Common stockholders'
equity.................. 19,502 18,949 58,231 74,741 79,188 40,487
</TABLE>
- --------
(1) Reflects the pro forma effect of the Snyder Acquisition, the Merger, the
sale of the Private Notes and the application of the proceeds thereof to
retire the JEDI Debt and pay down a portion of the outstanding borrowings
under the Credit Agreement. See the Company's Pro Forma Condensed
Financial Statements, included elsewhere in this Prospectus, for a
discussion of the preparation of this data. The pro forma combined
results of operations exclude a charge of approximately $53.3 million
(net of related deferred taxes of $30.0 million) representing the
adjustment of the carrying value of proved oil and gas properties
pursuant to the full cost method of accounting. Such adjustment has been
included in the historical results of operations of the Company in the
period the Merger was consummated. Pro forma net cash provided by
operating activities was obtained by adjusting the historical amount for
the pro forma changes in oil and natural gas sales, oil and natural gas
production expenses, general and administrative expenses and interest
expense. The exchange of the Exchange Notes for the Private Notes would
have no effect on the pro forma information. See also "Use of Proceeds"
and "Capitalization."
(2) The Company ceased its third party natural gas marketing operations in
1992. The Company acquired Taurus in April 1994.
(3) Total costs and expenses for the periods ended February 16, 1996 and
March 31, 1996 include approximately $3.2 million of stock option
compensation expense and $83.3 million for the writedown of oil and gas
properties, respectively.
(4) For purposes of computing the ratio of earnings to fixed charges,
earnings consist of income before income taxes plus fixed charges. Fixed
charges consist of interest expense. For the periods ended December 31,
1992, February 16, 1996 and March 31, 1996, earnings were inadequate to
cover fixed charges by approximately $1.1 million, $1.8 million and $83.1
million, respectively. Pro forma earnings for the year ended December 31,
1995 and three months ended March 31, 1996, would have been inadequate to
cover fixed charges by approximately $7.1 million and $283,000,
respectively.
(5) In addition to cash flows provided by operating activities, the Company
also has significant cash flows which are provided by or used in
investing and financing activities. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and
Capital Resources," "--Effects of the Merger, the Sale of the Private
Notes and the Exchange Offer--Credit Agreement" and the Historical
Financial Statements of the Company.
(6) EBITDA is calculated as operating income before interest, income taxes,
depletion, depreciation and amortization. EBITDA is not a measure of cash
flow as determined by generally accepted accounting principles ("GAAP").
The Company has included information concerning EBITDA because EBITDA is
a measure used by certain investors in determining the Company's
historical ability to service its indebtedness. EBITDA should not be
considered as an alternative to, or more meaningful than, net income or
cash flows as determined in accordance with GAAP as an indicator of the
Company's operating performance or liquidity. Debt/EBITDA is calculated
only for the historical annual periods. EBITDA for the period ended
February 16, 1996 is net of approximately $3.2 million of stock option
compensation expense which is a non-cash charge.
37
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
GENERAL
The Company is an independent energy company principally engaged in the
acquisition and exploitation of producing oil and natural gas properties. The
Company also owns and operates natural gas processing and liquids extraction
facilities and natural gas gathering systems. The Company seeks to acquire
properties whose predominant economic value is attributable to proved
producing reserves and to enhance that value through control of operations,
reduction of costs, and property development.
The Company's principal strategy is to increase oil and natural gas
reserves, production and cash flow by selectively acquiring and exploiting
producing oil and natural gas properties, especially those properties with
enhanced recovery and other lower risk development potential. The Company's
exploitation efforts include, where appropriate, the drilling of lower risk
development wells, the initiation of secondary recovery projects, the
renegotiation of marketing agreements and the reduction of drilling,
completion and lifting costs. Cost savings may be principally achieved through
reductions in field staff and the more effective utilization of field
facilities and equipment by virtue of geographic concentration. The success of
the Company's strategy is dependent upon a number of factors, some of which
are beyond its control. See "Risk Factors."
As a result of the Company's successful acquisition and exploitation
activities, the Company has shown significant growth in reserves, production
and EBITDA over the last five years. From January 1, 1991 to December 31,
1995, the Company completed acquisitions with an aggregate purchase price of
$172.2 million and estimated reserves at the date of acquisition of 47.1 Mmboe
(treating the acquisition of Diamond for this purpose as a purchase). The
Company's producing properties are concentrated onshore in the mid-continent
region of the United States. At December 31, 1995, the Company had proved
reserves of 42.6 Mmbbls of oil and 37.1 Bcf of natural gas, aggregating 48.8
Mmboe. The Company has two principal operating sources of cash: (i) net oil
and natural gas sales from its oil and natural gas properties and (ii) net
margins earned from gas gathering and processing operations.
The Company expects to continue its efforts to acquire additional oil and
natural gas properties. Future acquisitions, if any, would necessitate, in
most cases, borrowing additional funds under the Credit Agreement. The ability
to borrow such funds is dependent upon the Company's borrowing base under the
Credit Agreement.
On February 16, 1996, the Company completed the Merger. The Merger has been
accounted for using the purchase method of accounting. As such, JEDI's cost of
acquiring Coda has been allocated to the assets and liabilities acquired using
estimated fair values. As a result, the Company's financial position and
operating results subsequent to the date of the Merger reflect a new basis of
accounting and are not comparable to prior periods. The immediately following
sections, "--Results of Operations" and "--Liquidity and Capital Resources,"
discuss the Company's historical financial position and operating results. For
a discussion of the expected impact of the Merger and the sale of the Private
Notes on the Company's financial position and results of operations see "--
Effects of the Merger, the Sale of the Private Notes and the Exchange Offer."
38
<PAGE>
RESULTS OF OPERATIONS
The following table sets forth certain operating data regarding the
production and sales volumes, average sales prices, and costs associated with
the Company's oil and natural gas operations and gas gathering and processing
operations for the periods indicated on an historical basis.
<TABLE>
<CAPTION>
PRO FORMA
THREE COMBINED
MONTHS 47 DAYS 44 DAYS THREE MONTHS
YEAR ENDED DECEMBER 31, ENDED ENDED ENDED ENDED
----------------------- MARCH 31, FEBRUARY 16, MARCH 31, MARCH 31,
1993 1994 1995 1995 1996 1996 1996
------- ------- ------- --------- ------------ --------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
OIL AND NATURAL GAS
OPERATING DATA:
Net production:
Oil (Mbbls)............ 1,766 2,650 3,165 772 408 427 835
Natural Gas (Mmcf)..... 4,703 4,982 4,416 1,186 500 512 1,012
Average sales price:
Oil (per Bbl).......... $ 16.88 $ 15.86 $ 17.08 $ 17.03 $ 17.57 $ 18.89 $ 18.25
Natural Gas (per Mcf).. 1.92 1.74 1.57 1.52 1.82 1.75 1.78
Production cost per
Boe.................... 6.90 6.22 6.95 6.77 7.33 7.59 7.46
GAS GATHERING AND
PROCESSING OPERATING
DATA:
Sales:
Total revenue (in
thousands)............ $ 732 $20,081 $35,634 $ 7,904 $ 5,322 $ 4,799 $ 10,121
Gas sales (MMBTU,
in thousands)......... -- 6,725 13,356 3.079 1,555 1,430 2,985
Gas sales average
price................. -- $ 1.82 $ 1.58 $ 1.49 $ 2.24 $ 2.07 $ 2.16
Natural gas liquids
sales (M gallons)..... 2,467 26,193 53,284 12,568 5,868 5,487 11,355
Natural gas liquids
average price......... $0.2966 $0.2967 $0.2739 $0.2640 $0.3173 $0.3313 $ 0.3241
Costs and expenses (in
thousands):
Gas purchases.......... 146 15,121 26,547 5,912 3,760 3,390 7,450
Plant operating
expenses.............. 424 2,203 3,926 818 506 499 1,005
</TABLE>
COMPARISON OF THE THREE MONTHS ENDED MARCH 31, 1995 AND 1996
The unaudited pro forma combined information was prepared as if the Merger
and the issuance of $110.0 million of Notes had occurred on January 1, 1995.
The unaudited pro forma information was prepared by combining the two 1996
periods and giving effect to adjustments affecting (i) depletion, depreciation
and amortization, (ii) interest expense, (iii) income taxes and (iv) certain
other costs resulting from the Merger as more fully outlined in the Notes to
Pro Forma Condensed Financial Statements contained elsewhere in this
Prospectus. The comparisons below compare the unaudited pro forma combined
information to historical information for 1995.
Oil and natural gas sales for the three months ended March 31, 1996
increased 14% to approximately $17.0 million from approximately $14.9 million
in the comparable period in 1995 primarily due to an 8% increase in oil
production and an increase of $1.22 per barrel and $0.26 per Mcf in the
average sales price of oil and natural gas, respectively. The increase in
production is a result of the acquisition of producing oil and natural gas
properties in the fourth quarter of 1995, the Company's development drilling
program and favorable responses from certain of the Company's waterflood
units. This increase was partially offset by a 15% decrease in natural gas
production (due primarily to sales of properties). During the three months
ended March 31, 1996, 89% of oil and natural gas sales was attributable to oil
production. Oil and natural gas prices remain unpredictable. See "--Changes in
Prices and Hedging Activities" below.
39
<PAGE>
Gas gathering and processing revenues for the three months ended March 31,
1996 increased 28% to approximately $10.1 million from approximately $7.9
million in the comparable period in 1995 primarily due to a 45% and a 23%
increase in the average sales price for natural gas and natural gas liquids,
respectively. This increase was partially offset by a decrease in natural gas
liquids volumes.
Gas gathering and processing expenses for the three months ended March 31,
1996 increased 26% to approximately $8.5 million from approximately $6.7
million in the comparable period in 1995 primarily due to an increase in the
purchase price paid to producers. Gas gathering and processing expenses
usually fluctuate in direct proportion to gas gathering and processing
revenues.
Oil and natural gas production expenses (including production taxes) for the
three months ended March 31, 1996 increased 14% to approximately $7.5 million
from approximately $6.6 million for the same period in 1995 reflecting the
effects of production from the properties acquired during the fourth quarter
of 1995 and from new wells drilled. Oil and natural gas production expenses
for the three months ended March 31, 1996 were $7.46 per Boe and are expected
to remain near this level for the remainder of the year.
Pro forma depletion, depreciation and amortization expense for the three
months ended March 31, 1996 increased 42% to approximately $6.9 million from
approximately $4.9 million for the historical period in 1995 reflecting the
increase in the carrying value of the Company's assets as a result of the
Merger and an increase in oil production from acquisitions during the fourth
quarter of 1995 and property development. Oil and natural gas depletion,
depreciation and amortization expense increased from $4.33 per Boe for the
three months ended March 31, 1995, to $5.94 per Boe on a pro forma basis for
the three months ended March 31, 1996. The Company anticipates that the
depletion, depreciation and amortization rate per Boe will be approximately
$5.94 for 1996 absent significant additional acquisitions.
General and administrative expenses for the three months ended March 31,
1996 were essentially unchanged from 1995. This is primarily due to increased
overhead charges billed to working interest owners on the properties acquired
in 1995 being largely offset by additional employees needed as a result of
acquisitions of oil and natural gas properties. The Company expects base
general and administrative expenses, net of overhead recoveries, to remain
near this level, absent significant additional acquisitions.
Pro forma interest expense for the three months ended March 31, 1996
increased 108% to approximately $4.3 million from approximately $2.1 million
for the historical period in 1995 primarily due to increases in outstanding
debt levels as a result of the Merger which reduced the Company's bank debt,
but added $110.0 million of subordinated debt bearing interest at 10 1/2% per
annum. Also contributing to the increase were amounts borrowed during 1995 to
fund development drilling and property acquisitions.
The historical results of operations for the period ended February 16, 1996
include approximately $3.2 million of stock option compensation expense as a
result of the replacement of certain outstanding options and warrants with new
options subject to a lower exercise price.
The historical results for the period ended March 31, 1996 includes a
writedown of oil and natural gas properties of approximately $83.3 million to
the full cost pool ceiling based on product prices at the date of the Merger.
The allocation of JEDI's purchase price to the assets and liabilities of Coda
resulted in a significant increase in the carrying value of the Company's oil
and gas properties. Under the full cost method of accounting, the carrying
value of oil and gas properties (net of related deferred taxes) is generally
not permitted to exceed the sum of the present value (10% discount rate) of
estimated future net cash flows (after tax) from proved reserves, based on
current prices and costs, plus the lower of cost or estimated fair value of
unproved properties (the "cost center ceiling"). Based upon the allocation of
40
<PAGE>
JEDI's purchase price and estimated proved reserves and product prices in
effect at the date of the Merger, the purchase price allocated to oil and gas
properties was in excess of the cost center ceiling by approximately $83.3
million ($53.3 million net of related deferred taxes). The resulting writedown
is a non-cash charge and has been included in the results of operations for
the period ended March 31, 1996.
The pro forma net loss for the three months ended March 31, 1996 was
approximately $279,000 compared to net income of approximately $1.3 million
for the historical period in 1995. This decrease resulted primarily from
increases in depletion, depreciation and amortization and interest expense as
a result of the Merger partially offset by an increase in oil production and
higher oil prices.
COMPARISON OF THE YEARS ENDED DECEMBER 31, 1994 AND 1995
Oil and natural gas sales for the year ended December 31, 1995 increased 20%
to approximately $61.0 million from approximately $50.7 million in 1994
primarily due to a 19% increase in oil production and an increase of $1.22 per
barrel in the average sales price for oil. The increase in production was a
result of the acquisition of producing oil and natural gas properties during
the fourth quarters of 1994 and 1995, the Company's development drilling
program and favorable responses from certain of the Company's waterflood
units. This increase was partially offset by an 11% decrease in natural gas
production (due primarily to sales of properties) and a decrease in the
average sales price for natural gas of $0.17 per Mcf. During the year ended
December 31, 1995, 89% of oil and natural gas sales was attributable to oil
production. Oil and natural gas prices remain unpredictable. See "--Changes in
Prices and Hedging Activities."
As a result of the acquisition of Taurus on April 29, 1994, gas gathering
and processing revenues, expenses and gross profit increased significantly for
the year ended December 31, 1995, compared to 1994. The year ended December
31, 1994 only includes eight months of Taurus' operations. Contributing to the
increases in revenues and expenses was the acquisition in January 1995 of the
remaining ownership interest in one of Taurus' gas plants and associated
facilities for $6.5 million. The levels of revenues and expenses attributed to
Taurus' operations are largely dependent on natural gas and natural gas
liquids prices and plant throughput volumes and, therefore, may fluctuate
significantly.
Oil and natural gas production expenses (including production taxes) for the
year ended December 31, 1995 increased 25% to approximately $27.1 million from
approximately $21.6 million for 1994, reflecting the effects of the increased
production from the properties acquired in 1994 and from new wells drilled.
Oil and natural gas production expenses for the year ended December 31, 1995
were $6.95 per Boe. Absent additional significant acquisitions, the Company
expects production expenses to be between $7.00 and $7.50 per Boe in 1996.
Depletion, depreciation and amortization expense for the year ended December
31, 1995 increased 20% to approximately $19.7 million from approximately $16.4
million for 1994, reflecting the increase in oil production from acquisitions
in 1994, property development and the acquisition of Taurus in April 1994. The
increase attributable to Taurus was approximately $1.2 million. Oil and
natural gas depletion, depreciation and amortization expense increased to
$4.33 per Boe for the year ended December 31, 1995 from $4.27 per Boe for
1994. The increase reflects the relatively higher purchase price of the
reserves related to the properties acquired during 1994.
General and administrative expenses for the year ended December 31, 1995
decreased to approximately $2.9 million from approximately $3.1 million for
1994. This decrease was primarily due to increased overhead charges billed to
working interest owners on the properties acquired during the fourth quarters
of 1994 and 1995, being partially offset by additional employees needed as a
result of acquisitions of oil and natural gas properties and the acquisition
of Taurus.
41
<PAGE>
Interest expense for the year ended December 31, 1995 increased 64% to
approximately $8.7 million from approximately $5.3 million for 1994, primarily
due to increases in outstanding debt levels used to fund development drilling,
oil and natural gas property acquisitions and the acquisition of Taurus and
related assets, and higher market interest rates in 1995.
Business combination expenses of $1.8 million in 1994 were related to the
acquisition of Diamond pursuant to a merger. The merger with Diamond was
accounted for as a pooling of interests and accordingly the transaction costs
were expensed when incurred.
Net income for the year ended December 31, 1995 increased to approximately
$5.8 million from approximately $3.3 million for 1994, primarily due to (i) an
increase in oil production from the Company's waterflood units, the Company's
development drilling program and the oil and natural gas property acquisitions
during the fourth quarters of 1994 and 1995, (ii) an increase in the average
sales price of oil by $1.22 per barrel and (iii) the lack of business
combination expenses in 1995.
COMPARISON OF THE YEARS ENDED DECEMBER 31, 1993 AND 1994
Oil and natural gas sales for the year ended December 31, 1994 increased 30%
to approximately $50.7 million from approximately $38.9 million in 1993
primarily due to an increase in oil and natural gas production of 50% and 6%,
respectively, as a result of the acquisition of producing oil and natural gas
properties in the third quarter of 1993, the Company's development drilling
program and the favorable response of Diamond's waterflood units, partially
offset by a decrease in oil prices. During the year ended December 31, 1994,
83% of oil and natural gas sales was attributable to oil production.
On April 29, 1994, the Company acquired 100% of the issued and outstanding
common stock of Taurus, a privately held Texas corporation, in exchange for
1.5 million shares of the Company's Common Stock, valued at approximately $7.3
million, and approximately $3.3 million cash. The Company assumed existing
Taurus debt of approximately $9.8 million. Taurus owns and operates three gas
processing and liquids extraction facilities and approximately 700 miles of
gas gathering systems located primarily in west central Texas.
As a result of this acquisition, gas gathering and processing revenues,
expenses and gross profit increased significantly for the year ended December
31, 1994, which reflects eight months of activity for Taurus. In January 1995,
Taurus purchased for $6.5 million the remaining interest in one of the plants
that it operates. The level of revenues and expenses for Taurus is largely
dependent on natural gas and natural gas liquids prices and plant throughput
volumes and, therefore, may fluctuate significantly.
Other income for the year ended December 31, 1994 increased to approximately
$822,000 from approximately $441,000 for 1993, due primarily to the receipt in
1994 of $107,000 of interest income attributable to the receipt in December
1993 of previously suspended oil and natural gas sales proceeds and to the
receipt of $117,000 related to the settlement of claims which arose in
connection with an unsuccessful acquisition effort in a prior year. Also
contributing to the increase was an increase in rental income from the
Company's office building.
Oil and natural gas production expenses (including production taxes) for the
year ended December 31, 1994 increased 23% to approximately $21.6 million from
approximately $17.6 million for 1993, reflecting the effects of increased
production from the properties acquired in the third quarter of 1993 and from
new wells drilled. Oil and natural gas production expenses per Boe decreased
in 1994 to $6.22 per Boe from $6.90 per Boe in 1993, reflecting the effect of
the relatively lower lifting cost related to the properties acquired in the
third quarter of 1993 and the effect of increased production response from the
Diamond waterflood units.
42
<PAGE>
Depletion, depreciation and amortization expense for the year ended December
31, 1994 increased 52% to approximately $16.4 million from approximately $10.8
million for 1993, reflecting the increases in production from the acquisitions
in the third quarter of 1993 and the acquisition of Taurus in April 1994. The
increase attributable to Taurus was approximately $1.4 million. Oil and
natural gas depletion, depreciation and amortization expense increased from
$4.15 per Boe for the year ended December 31, 1993, to $4.27 per Boe for 1994.
The increase reflects the relatively higher purchase price of the reserves
related to the properties acquired during the third quarter of 1993.
General and administrative expenses for the year ended December 31, 1994
increased to approximately $3.1 million from approximately $2.6 million for
1993. This increase was primarily due to additional employees needed as a
result of the 1993 acquisitions and the acquisition of Taurus, partially
offset by increased overhead charges billed to working interest owners on the
properties acquired during 1993. The increase attributable to Taurus was
approximately $483,000.
Interest expense for the year ended December 31, 1994 increased 10% to
approximately $5.3 million from approximately $4.8 million for 1993, primarily
as a result of increases in outstanding debt levels used to fund development
drilling, property acquisitions and the acquisition of Taurus, partially
offset by lower market interest rates in the first half of 1994.
In connection with the merger with Diamond, the Company incurred
approximately $1.8 million of legal, accounting, printing and other costs
related to the combination of the previously separate entities. Included in
these expenses is the writeoff of approximately $316,000 of Diamond's deferred
financing costs. Under pooling of interests accounting, these costs were
expensed in September 1994. Furthermore, certain of these expenses are neither
deductible nor amortizable for income tax purposes, resulting in a higher than
expected effective tax rate.
Net income for the year ended December 31, 1994 increased to approximately
$3.3 million from approximately $2.3 million for 1993, primarily due to an
increase in oil and natural gas production from Diamond's waterflood units,
the Company's development drilling program and the acquisitions in the third
quarter of 1993, partially offset by a $1.02 per barrel decrease in average
oil prices and $1.8 million in business combination expenses.
CHANGES IN PRICES AND HEDGING ACTIVITIES
Annual average oil and natural gas prices have fluctuated significantly over
the past three years. The Company's weighted average oil price per Bbl during
1995 and at December 31, 1995 was $17.08 and $18.31, respectively. For the
three months ended March 31, 1996, the Company averaged $1.33 per barrel less
(including an oil hedging price decrease of $0.32 per barrel) and $0.65 per
Mcf less for its oil and natural gas sales, respectively, than the average
NYMEX prices for the same period. For the year ended December 31, 1995, the
Company averaged $1.32 per Bbl less (including an oil hedging price increase
of $0.09 per barrel) and $0.13 per Mcf less for its oil and natural gas sales,
respectively, than the average NYMEX prices for the same period. The Company's
weighted average price per Bbl during 1994 and at December 31, 1994, was
$15.86 and $16.24, respectively. For the year ended December 31, 1994, the
Company averaged $1.33 per Bbl and $0.20 per Mcf, respectively, less for its
oil and natural gas sales than the average NYMEX prices for the same period.
Pursuant to the loan agreements with Diamond's former primary lender,
Diamond entered into an agreement with a refining and marketing company to
sell a fixed number of barrels attributable to its share of production of
liquid hydrocarbons from certain formerly secured properties at a price of
$15.25 per barrel. The effect of this contract was to lower the Company's 1995
and first quarter of 1996 oil revenue by approximately $1.0 million ($0.32 per
barrel) and $123,000 ($0.15 per barrel), respectively. The remaining
commitment under this agreement at December 31, 1995, was 47,000 barrels. The
Company fulfilled this commitment during the first quarter of 1996.
43
<PAGE>
In an effort to reduce the effects of the volatility of the price of oil and
natural gas on the Company's operations, management has adopted a policy of
hedging oil and natural gas prices through the use of commodity futures,
options, and swap agreements whenever market prices are in excess of the
prices anticipated in the Company's operating budget and profit plan. While
the use of these hedging arrangements limits the downside risk of adverse
price movements, it may also limit future gains from favorable movements. All
hedging is accomplished pursuant to exchange-traded contracts or master swap
agreements based upon standard forms. The Company addresses market risk by
selecting instruments whose value fluctuations correlate strongly with the
underlying commodity being hedged. Credit risk related to hedging activities,
which is minimal, is managed by requiring minimum credit standards for
counterparties, periodic settlements and mark-to-market valuations. The
Company has not historically been required to provide any significant amount
of collateral in connection with its hedging activities. The following table
sets forth the barrels and weighted average NYMEX prices hedged under various
swap agreements entered into as of March 31, 1996.
<TABLE>
<CAPTION>
WEIGHTED
AVERAGE
PERIODS COVERED BARRELS SOLD PRICE
--------------- ------------ --------
<S> <C> <C>
Nine months ending December 31, 1996................ 530,000 $18.81
Year ending December 31, 1997....................... 375,000 $19.02
</TABLE>
As of March 31, 1996, the Company had open positions for sold call options
covering 25,000 Bbls of oil per month at an option price of $18.30 per Bbl for
the period April 1996 to August 1996, increasing to $20.00 per Bbl for the
period from September 1996 to August 1997. Under the standard form swap
agreements in use by the Company, the Company has a potential liability when
the NYMEX price exceeds the swap price. The total potential liability is equal
to the difference between the swap price and the NYMEX price for the
production month hedged multiplied by the number of barrels swapped. To the
extent this total liability exceeds the credit limit established by the
counterparty, the Company may be required to utilize cash to fund a margin
account. The Company has not historically had to fund a margin account.
During the years ended December 31, 1993 and 1994, the Company's oil and
natural gas sales were reduced by $289,000 and $5,000, respectively as a
result of hedging transactions. During the year ended December 31, 1995, the
Company's oil sales were increased by $298,000, representing an average price
increase of $0.09 per barrel of oil, as a result of hedging transactions.
During the periods ended February 16, 1996 and March 31, 1996, the Company's
oil revenues were decreased by $14,000 and $250,000, respectively, as a result
of hedging transactions. See Note 7 of the Notes to the Company's Historical
Financial Statements for a further discussion of the Company's hedging
activities.
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 1996, the Company had cash and cash equivalents aggregating
approximately $3.5 million and working capital of approximately $9.4 million.
Cash provided by operating activities for the three months ended March 31,
1996 decreased to approximately $4.6 million compared to $5.1 million for the
comparable period in 1995 due primarily to an increase in interest expense
partially offset by an increase in oil production and an oil price increase.
Excluding the impact of the Merger, cash flows used in investing activities
decreased from $11.6 million for the three months ended March 31, 1995 to $2.2
million for the comparable period in 1996, as a result of a higher level of
additions to property and equipment in 1995. Investing activities in 1996 also
include the impact of the purchase of Coda by JEDI. Cash flows provided by
financing activities increased to $176.6 million for the three months ended
March 31, 1996 from $3.1 million for the comparable period in 1995, primarily
due to financing transactions related to the Merger. See "Effects of the
Merger, the Sale of the Private Notes and the Exchange Offer--The Merger"
below.
44
<PAGE>
At December 31, 1995, the Company had cash and cash equivalents aggregating
approximately $4.6 million and working capital of approximately $8.3 million.
Cash provided by operating activities for the year ended December 31, 1995
increased to approximately $24.3 million compared to $23.0 million for 1994,
due primarily to an increase in oil production and an oil price increase. Cash
flows used in investing activities decreased from $56.8 million for the year
ended December 31, 1994 to $43.0 million in 1995. This decrease was a result
of the sale of assets in 1995 for almost $5.7 million and a slight decrease in
the total spending on oil and natural gas properties in 1995, partially offset
by the acquisition by Taurus of an additional interest in one of its plants
for $6.5 million. Cash flows provided by financing activities decreased to
$16.9 million for the year ended December 31, 1995 from $36.2 million for
1994, primarily due to a decrease in net borrowings under the Company's then-
existing credit agreement. As a result of the Merger, the Company's financial
position and results of operations reflect a new basis of accounting and are
not comparable to prior periods. The following section discusses the expected
impact of the Merger, the sale of the Private Notes and the Exchange Offer on
the Company's financial position and results of operations.
EFFECTS OF THE MERGER, THE SALE OF THE PRIVATE NOTES AND THE EXCHANGE OFFER
THE MERGER
On February 16, 1996, the Company completed the Merger. The Merger has been
accounted for using the purchase method of accounting. As such, JEDI's cost of
acquiring Coda has been allocated to the assets and liabilities acquired using
estimated fair values. As a result, the Company's financial position and
operating results subsequent to the date of the Merger reflect a new basis of
accounting and are not comparable to prior periods. Concurrently with the
execution of the Merger Agreement, JEDI and CAI entered into certain
agreements with the Management Group providing for a continuing role of
management in the Company after the Merger. The sources and uses of funds
related to financing the Merger were as follows:
SOURCES OF FUNDS
(in millions)
<TABLE>
<S> <C>
Credit Agreement.................................................. $ 95.0
JEDI Debt(1)...................................................... 100.0
Redeemable Preferred Stock issued to JEDI......................... 20.0
Common Stock issued to JEDI....................................... 90.0
------
Total........................................................... $305.0
======
</TABLE>
USES OF FUNDS
(in millions)
<TABLE>
<S> <C>
Payments to Coda stockholders, warrantholders and
optionholders.................................................. $176.2
Repayment of former credit facility and other indebtedness...... 122.7
Merger costs and other expenses................................. 6.1
------
Total......................................................... $305.0
======
</TABLE>
--------
(1) Represents indebtedness incurred by CAI and assumed by Coda to
fund a portion of the consideration paid in the Merger. See "Use
of Proceeds."
The Company incurred substantial indebtedness in connection with the Merger
and is highly leveraged. As of March 31, 1996, the Company had total
indebtedness of approximately $191.8 million and stockholders' equity
(including Preferred Stock) of approximately $60.5 million. After giving pro
forma effect to the Merger and the related financing transactions, including
the sale of the Private
45
<PAGE>
Notes and the Exchange Offer, and the Snyder Acquisition, the Company's
earnings would have been insufficient to cover its fixed charges by
approximately $7.1 million for 1995. Pro forma interest expense for 1995 would
have been approximately $18.6 million. Pro forma cash flow from operations
(assuming that the additional interest was paid in cash) would have been
approximately $17.1 million. Based upon the Company's current level of
operations and anticipated growth, management of the Company believes that
available cash, together with available borrowings under the Credit Agreement,
will be adequate to meet the Company's budgeted requirements for capital
expenditures and scheduled payments of principal of, and interest on, its
indebtedness, including the Notes. There can be no assurance that such
anticipated growth will be realized, that the Company's business will generate
sufficient cash flow from operations or that future borrowings will be
available in an amount sufficient to enable the Company to service its
indebtedness, including the Notes, or make necessary capital expenditures. In
addition, the Company anticipates that it is likely to find it necessary to
refinance a portion of the principal amount of the Notes at or prior to their
maturity. However, there can be no assurance that the Company will be able to
obtain financing to complete a refinancing of the Notes. See "Risk Factors--
Leverage."
The Company has planned development and exploitation activities for all of
its major operating areas. The Company has budgeted capital spending of
approximately $18 million in 1996, but is not contractually committed to
expend these funds. During the first three months of 1996, the Company
incurred approximately $1.9 million of these costs. In addition, the Company
is continuing to evaluate oil and natural gas properties for future
acquisitions. Historically, the Company has used the public equity market (i)
to raise cash to fund acquisitions or repay indebtedness incurred for
acquisitions and (ii) as a medium of exchange for other companies' capital
stock or assets in connection with acquisitions. As a result of being 95%
owned by JEDI (on a fully diluted basis), the Company does not expect to
utilize the public equity market to finance acquisitions in the near term.
Accordingly, any material expenditures in connection with acquisitions would
require borrowing under the Credit Agreement or from other sources. There can
be no assurance that such funds will be available to the Company. Furthermore,
the Company's ability to borrow in the future is subject to restrictions
imposed by the Credit Agreement and the Indenture as more fully described
below. See "Description of Other Indebtedness" and "Description of Exchange
Notes--Certain Covenants--Incurrence of Indebtedness and Issuance of Preferred
Stock."
CREDIT AGREEMENT
In connection with the Merger, the Company entered into the Credit Agreement
to replace a prior credit facility. The borrowing base under the Credit
Agreement currently is $115.0 million. As of March 31, 1996, approximately
$35.0 million was available for borrowing under the Credit Agreement. The
borrowing base is scheduled to be redetermined on July 1, 1996; however, the
Credit Agreement allows the lenders to redetermine the borrowing base upon the
occurrence of either of the following events: (i) the sale of all, or
substantially all, of the assets or common stock of Taurus or (ii) the
issuance of public subordinated debt in an amount greater than $100.0 million.
The lenders under the Credit Agreement have agreed to waive their right to
redetermine the borrowing base with respect to the issuance of the Notes. As a
result of the sale of the Private Notes, ECT Securities Corp., an affiliate of
ECT, refunded to the Company $2.0 million in fees paid by the Company to ECT
Securities Corp. for arranging the JEDI Debt. These additional funds, together
with other available cash of $550,000 and the remaining net proceeds of the
sale of the Private Notes were used to repay approximately $10.0 million of
the indebtedness outstanding under the Credit Agreement.
The Credit Agreement is unsecured. The Company has provided the bank lenders
with first lien deeds of trust on its oil and natural gas assets that will not
become effective, and that the lenders have agreed to not file, unless: (i)
80% of any outstanding borrowings in excess of the borrowing limit are not
repaid within a 90 day period, (ii) cash collateral securing a hedging
transaction exceeds 20% of
46
<PAGE>
the borrowing limit or (iii) an event of default or a material adverse event,
as defined in the Credit Agreement, occurs.
The Credit Agreement contains various restrictive covenants, including
limitations on the granting of liens, restrictions on the issuance of
additional debt, restrictions on investments, a requirement to maintain
positive working capital, and restrictions on dividends and stock repurchases.
The Credit Agreement also contains requirements that JEDI, Enron, CalPERS or
any wholly owned subsidiary of either Enron or CalPERS must continue to own a
majority of the outstanding equity of the Company and must have the ability to
elect the majority of the Board of Directors and that certain members of
management maintain specified levels of equity ownership in the Company and
continue their employment with the Company.
So long as no default (as defined in the Credit Agreement) is continuing,
the Company has the option of having all or any portion of the amount borrowed
under the Credit Agreement be the subject of one of the following interest
rates: (i) NationsBank's prime rate, (ii) the CD Rate plus 1 1/4% to 1 5/8%
based upon the ratio of outstanding debt to the available borrowing base and
(iii) LIBOR plus 1 1/4% to 1 5/8% based upon the ratio of outstanding debt to
the available borrowing base. The Company must also pay a commitment fee of
between 0.375% to 0.425% on the unused portion of the borrowing base facility.
JEDI DEBT
The principal amount of JEDI Debt outstanding after the Merger was $100.0
million. A portion of the net proceeds of the sale of the Private Notes was
used to repay the JEDI Debt. The Company also paid approximately $823,000 of
accrued interest thereon. See "Use of Proceeds."
10 1/2% SENIOR SUBORDINATED NOTES
On March 18, 1996, the Company completed the sale of $110 million principal
amount of Notes. The proceeds of the Notes were used to fully repay the JEDI
Debt assumed in the Merger and to partially repay bank debt. The Notes bear
interest at an annual rate of 10 1/2% payable semiannually in arrears on April
1 and October 1 of each year. The Notes are general, unsecured obligations of
the Company, are subordinated in right of payment to all Senior Debt (as
defined in the Indenture governing the Notes) of Coda, and are senior in right
of payment to all future subordinated debt of the Company. The claims of the
holders of the Notes will be subordinated to Senior Debt, which, as of March
31, 1996, was $81.8 million.
Coda's payment obligations under the Notes are fully, unconditionally and
jointly and severally guaranteed on a senior subordinated basis by all of
Coda's current subsidiaries and future Restricted Subsidiaries (as defined in
the Indenture). Such guarantees are subordinated to the guarantees of Senior
Debt issued by the Guarantors under the Credit Agreement and to other
guarantees of Senior Debt issued in the future.
The Notes were issued pursuant to an Indenture, which contains certain
covenants that, among other things, limit the ability of Coda and its
Restricted Subsidiaries to incur additional indebtedness and issue
Disqualified Stock (as defined in the Indenture), pay dividends, make
distributions, make investments, make certain other restricted payments, enter
into certain transactions with affiliates, dispose of certain assets, incur
liens securing pari passu or subordinated indebtedness of Coda and engage in
mergers and consolidations.
The Notes are not redeemable at Coda's option prior to April 1, 2001. After
April 1, 2001, the Notes will be subject to redemption at the option of Coda,
in whole or in part, at the redemption prices set forth in the Indenture, plus
accrued and unpaid interest thereon to the applicable redemption date.
47
<PAGE>
In addition, until March 12, 1999, up to $27.5 million in aggregate
principal amount of Notes is redeemable, at the option of Coda on any one or
more occasions from the net proceeds of an offering of common equity of Coda,
at a price of 110.5% of the aggregate principal amount of the Notes, together
with accrued and unpaid interest thereon to the date of the redemption;
provided, however, that at least $82.5 million in aggregate principal amount
of Notes must remain outstanding immediately after the occurrence of such
redemption; provided, further, that any such redemption shall occur within 75
days of the date of the closing of such offering of common equity.
In the event of a Change of Control (as defined in the Indenture), holders
of the Notes will have the right to require Coda to repurchase their Notes, in
whole or in part, at a price in cash equal to 101% of the aggregate principal
amount thereof, plus accrued and unpaid interest thereon to the date of
repurchase. The Indenture requires that, prior to such a repurchase but in any
event within 90 days of such Change of Control, Coda must either repay all
Senior Debt or obtain any required consent to such repurchase of Notes.
OTHER LONG-TERM DEBT
The Company's 12% Senior Subordinated Debentures due 2000 (the "Debentures")
bear interest at 12% per annum, payable semiannually. At March 31, 1996,
approximately $1.2 million in aggregate principal amount of the Debentures was
outstanding. On March 28, 1996, the Company gave notice of redemption, prior
to maturity, to each of the record holders of the outstanding Debentures. The
outstanding Debentures were redeemed on May 1, 1996 at a redemption price of
100.0% of the principal amount of the Debentures plus accrued and unpaid
interest thereon. On May 1, 1996, the Company deposited with the trustee of
the Debentures funds sufficient to so redeem the Debentures, and thereafter
interest on the Debentures ceased to accrue.
15% CUMULATIVE PREFERRED STOCK
The Company's Certificate of Incorporation authorizes the issuance of up to
40,000 shares of Preferred Stock. In conjunction with the Merger, the Company
issued 20,000 shares of Preferred Stock to JEDI for $20.0 million in cash.
Additional shares of Preferred Stock in excess of 20,000 shares may be issued
only for the purpose of paying dividends on the issued and outstanding
Preferred Stock. The holders of each share of Preferred Stock are entitled to
receive, when and as declared by the Board of Directors, cumulative
preferential dividends at the rate of $150.00 per share per annum, payable in
equal semi-annual installments. Dividend payments will be made in cash or
through the issuance of additional shares of Preferred Stock. The payment of
Preferred Stock dividends in cash is restricted by the Credit Agreement and
the Indenture.
The Company's Certificate of Incorporation requires that the Company redeem
all the issued and outstanding shares of Preferred Stock at a redemption price
of $1,000 per share, plus all accrued and unpaid dividends (including
undeclared dividends) to the date of redemption, if the Company has sufficient
funds legally available for such redemption and if such redemption would not
violate or conflict with any loan agreement, credit agreement, note agreement,
indenture or other agreement relating to indebtedness to which the Company is
a party, on or before the fifth business day after the earliest to occur of
the following: (i) the closing of the sale by the Company of Taurus and (ii) a
Trigger Event, as such term is defined in the Stockholders Agreement. The
Preferred Stock may be redeemed by the Company at its option, as a whole or in
part, to the extent the Company shall have funds legally available for such
redemption, at any time or from time to time at a redemption price of $1,000
per share, plus all accrued and unpaid dividends (including undeclared
dividends) to the date of redemption. Such redemption, whether required or
optional, is restricted by the Credit Agreement and the Indenture.
48
<PAGE>
ENRON
Enron is the parent of ECT and accordingly may be deemed to control
indirectly both JEDI and the Company. Enron and certain of its subsidiaries
and other affiliates collectively participate in nearly all phases of the oil
and natural gas industry and are, therefore, competitors of the Company. In
addition, ECT and JEDI have provided, and may in the future provide, and ECT
Securities Corp. has assisted, and may in the future assist, in arranging
financing to non-affiliated participants in the oil and natural gas industry
who are or may become competitors of the Company. Because of these various
conflicting interests, ECT, the Company, JEDI and the Management Group have
entered into the Business Opportunity Agreement which is intended to make it
clear that Enron and its affiliates have no duty to make business
opportunities available to the Company in most circumstances. The Business
Opportunity Agreement also provides that ECT and its affiliates may pursue
certain business opportunities to the exclusion of the Company. The Business
Opportunity Agreement may limit the business opportunities available to the
Company. In addition, pursuant to the Business Opportunity Agreement there may
be circumstances in which the Company will offer business opportunities to
certain affiliates of Enron. If an Enron affiliate is offered such an
opportunity and decides to pursue it, the Company may be unable to pursue it.
RESULTS OF OPERATIONS
As a result of the Merger, the Company has significantly more debt
outstanding at a higher weighted average interest rate than before the Merger.
On a pro forma basis reflecting the effects of the Snyder Acquisition, the
Merger and the sale of the Private Notes, as if such transactions had occurred
on January 1, 1995, pro forma depletion, depreciation and amortization
increased by $8.8 million, pro forma interest expense increased by $9.9
million and pro forma general and administrative expenses decreased by
$921,000, compared to the actual amounts reported for 1995. Pro forma EBITDA
would have increased to $40.0 million from $37.3 million on a historical
basis. Pro forma net loss for 1995 would have been $4.5 million compared to
historical net income of $5.8 million. The pro forma combined results of
operations exclude a charge of approximately $53.3 million (net of related
deferred taxes of $30.0 million) representing the adjustment of the carrying
value of proved oil and gas properties pursuant to the full cost method of
accounting. Such adjustment has been included in the results of operations of
the Company in the period the Merger was consummated.
Based on the allocation of purchase price, the Company expects oil and
natural gas property depletion, depreciation and amortization to be
approximately $5.94 per Bbl in 1996. Absent significant changes in the
Company's operations or interest rates, general and administrative expenses
are expected to be approximately $3 million in 1996 and interest expense for
1996 should be approximately $17 million. Absent significant increases in
prices or increases in production through development or acquisition
activities, the Company will continue to incur net losses. In addition, the
Company will be incurring a 15% cumulative dividend on $20.0 million of
Preferred Stock (payable in cash or shares of Preferred Stock) issued to JEDI
in connection with the Merger. See Pro Forma Condensed Financial Statements
included elsewhere in this Prospectus.
The Company estimates that it has approximately $15.4 million in available
net operating loss carryforwards ("NOLs"). While the Merger will result in a
change in control pursuant to (S)382 of the Internal Revenue Code, the Company
does not expect such change to have any significant impact on its ability to
utilize its NOLs.
49
<PAGE>
BUSINESS
GENERAL
The Company is an independent energy company that is principally engaged in
the acquisition and exploitation of oil and natural gas properties. The
Company also owns and operates natural gas processing and liquids extraction
facilities and natural gas gathering systems. The Company seeks to acquire oil
and natural gas properties whose predominant economic value is attributable to
proved producing reserves and to enhance that value through control of
operations, reduction of costs and property development. The Company's
producing properties are concentrated in the mid-continent region of the
United States. At December 31, 1995, the Company had proved reserves of 42.6
Mmbbls of oil and 37.1 Bcf of natural gas, aggregating 48.8 Mmboe. Company
operated properties accounted for approximately 94% of its 1995 production of
3.9 Mmboe.
As a result of the Company's successful acquisition and exploitation
activities, the Company has shown significant growth in reserves, production
and EBITDA over the last five years. From 1991 through 1995, the Company
achieved an average annual reserve replacement of 480% at an average cost of
$3.67 per Boe (with the acquisition of Diamond treated as a purchase instead
of a pooling). To achieve these results, management estimates that the Company
evaluated, over the last five years, in excess of 1,400 acquisition
opportunities with an aggregate market value estimated by management to exceed
$15 billion. Over the same period (with the acquisition of Diamond treated as
a purchase instead of a pooling), management estimates that the Company made
approximately 280 offers totaling more than $3 billion and successfully closed
in excess of 50 transactions having an aggregate purchase price of $172.2
million. This strategy enabled the Company to increase average net daily
production from 3,329 Boe in 1991 to 10,688 Boe in 1995, representing a
compound annual growth rate of 34%. Similarly, EBITDA increased at a 46%
compound annual growth rate from $8.2 million in 1991 to $37.3 million in
1995.
STRATEGY
The Company's strategy is to increase oil and natural gas reserves,
production and cash flow by selectively acquiring and exploiting oil and
natural gas properties, especially those properties with enhanced recovery and
other lower risk development potential. In order to implement its strategy,
the Company principally seeks to acquire oil and natural gas properties with
the following characteristics:
. Geographic Focus--The Company has focused its acquisition activities in
the mid-continent region of the United States. This region includes oil
and natural gas basins with geological and production characteristics
potentially responsive to the Company's exploitation and development
techniques. Management believes that it has considerable experience in,
and knowledge of, this region. The Company presently has four core
operating areas: west Texas, north Texas, west central Oklahoma and
southwestern Kansas. The geographic proximity of the Company's various
properties allows the Company to minimize the number of operations and
field production offices that it must maintain and the number of
supervisory personnel that it must employ.
. Proved Developed Reserves--The Company prefers to acquire properties
where the majority of the reserves are proved developed reserves
producing from relatively shallow horizons. Management believes these
properties generally present lower geologic and mechanical risks for
drilling, recompleting and operating activities. Substantially all of
the Company's wells are under 10,000 feet deep.
. Operated, High Working Interest Properties--The Company prefers to
operate the properties it acquires and to own the majority working
interest in those properties. This allows the Company greater control
over (i) timing and plans for future development, (ii) drilling,
completing and lifting costs and (iii) marketing of production. At
December 31, 1995, the
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<PAGE>
Company operated approximately 2,052 of the 2,190 gross producing and
active water injection wells in which it owned an interest, and its
weighted average working interest in its properties was approximately
82%.
. Exploitation Potential--The Company seeks to increase production and
recoverable reserves through exploitation efforts on the properties it
acquires. Exploitation efforts include workovers and/or recompletions of
existing wells; the initiation of, or improvements to, secondary
recovery projects, particularly the use of waterflooding; and the
drilling of lower risk development and/or infill wells. The Company
believes that it has been able to enhance the value and to extend the
economic life of many of the properties that it has acquired by
utilizing techniques such as these.
. Cost Reduction Potential--The Company seeks to acquire properties where
significant economic value can be created by lowering operating costs.
The Company believes that it has been able to lower the lifting costs on
certain properties it has acquired in comparison to the costs incurred
by the major oil companies and larger independents that previously
operated the properties. These savings were achieved through reductions
in labor, electricity, materials and other costs.
. Price Improvement Potential--Whenever possible, the Company attempts to
negotiate more favorable marketing agreements than those in place under
prior owners. After the Company has begun its exploitation activities on
its properties, it may attempt to negotiate more favorable prices as the
volumes of oil increase. Certain of the Company's oil purchasers have
paid and are currently paying a premium over posted prices and have
eliminated certain quality and marketing deductions for a portion of the
Company's oil production due to the Company's control over a significant
volume of oil production in its core geographic areas.
The Company believes that future acquisitions, like its past acquisitions,
will come from several categories of sellers including : (i) major oil
companies; (ii) companies that are consolidating operations to achieve cost
savings; (iii) companies and individuals owning interests in wells in which
the Company owns a substantial working interest; and (iv) companies with
limited capital resources.
The success of the Company's strategy depends upon a number of factors
outside of the Company's control, including the availability of attractive
acquisition opportunities. In recent years, major oil companies have been
divesting many of their higher cost domestic oil and natural gas properties.
In addition, the oil and natural gas industry continues to consolidate as
smaller independents exit the business. The Company believes these trends will
continue. By increasing production and lowering operating costs, the Company
believes that it can increase economic value and cash flow as well as extend
the productive lives of these properties. See "--Exploitation and Development
Activities" and "Risk Factors--Acquisition Risks; Depletion of Reserves."
ACQUISITION AND EXPLOITATION OF PRINCIPAL PROPERTIES
GENERAL
Management estimates that the Company evaluated, over the last five years,
in excess of 1,400 acquisition opportunities with an aggregate market value
estimated by management to exceed $15 billion. Over the same period (with the
acquisition of Diamond treated as a purchase instead of a pooling), management
estimates that the Company made approximately 280 offers totaling more than $3
billion and successfully closed in excess of 50 transactions having an
aggregate purchase price of $172.2 million. Management estimates that in 1995,
the Company evaluated more than $4.5 billion of acquisition opportunities,
offered to purchase more than $1.2 billion of such opportunities and closed
transactions worth $25.4 million. The Company generally prefers to focus on
larger acquisitions. It is management's opinion that operating larger
properties will allow even greater cost savings due to economies of scale, as
well as higher prices for oil and natural gas due to the concentration of
production in a given geographic area.
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The table below presents the results of the Company's acquisition activities
since January 1, 1991, showing the aggregate net purchase price and the
estimated proved oil and natural gas reserves purchased (with the acquisition
of Diamond treated as a purchase instead of a pooling). The reserve estimates
are shown as of the dates of acquisition, were generally derived from the
studies prepared by in-house engineers prior to the acquisition, and have not
been adjusted for subsequent revisions, if any.
<TABLE>
<CAPTION>
PROVED RESERVES WHEN ACQUIRED
AGGREGATE NET ---------------------------------
PURCHASE PRICE(1) OIL GAS COMBINED ACQUISITION
YEAR ENDED DECEMBER 31, (IN THOUSANDS) (MBBLS) (MMCF) MBOE COST (PER BOE)
- ----------------------- ----------------- ---------- --------- ---------- --------------
<S> <C> <C> <C> <C> <C>
1991.................... $16,368 8,100 808 8,235 $1.99
1992.................... 20,546 5,448 2,466 5,859 3.51
1993.................... 36,872 5,521 8,881 7,001 5.27
1994.................... 73,100 15,900 9,123 17,421 4.20
1995.................... 25,363 7,324 7,298 8,540 2.97
</TABLE>
- --------
(1) Includes the value attributable to cash and non-cash consideration and
reflects credits against the gross purchase price for production from the
effective date of the acquisition through the actual closing date. Does
not include future development costs.
HISTORICAL ACQUISITIONS
Since 1991, the Company has been actively engaged in the acquisition of
producing oil and natural gas properties located primarily in north Texas, the
Permian Basin in west Texas, west central Oklahoma and southwestern Kansas.
These acquisitions have permitted the Company to develop concentrated
ownership positions in certain producing fields, building on the Company's
knowledge of the reservoir characteristics in these areas and enhancing the
Company's ability to operate these properties more efficiently than prior
owners.
1991 Acquisitions. During 1991, the Company consummated three major
purchases in north Texas and the Permian Basin in west Texas, which
established those areas as core operating areas for the Company. In March
1991, the Company paid approximately $2.9 million to acquire an existing
waterflood project located in the Wichita County Regular Field of the West
Burkburnett Area of north Texas. In May 1991, the Company paid approximately
$2.7 million to acquire 16 producing wells in the McElroy Field located in
Upton County in west Texas. The Company subsequently initiated a waterflood
project on this lease. In July 1991, the Company paid $10.5 million to acquire
an existing waterflood project and a natural gas processing plant and
gathering facility located in Wichita and Wilberger Counties in north Texas
(the "Electra Properties").
1992 Acquisitions. The December 1992 purchase of producing oil and natural
gas properties located in the Permian Basin in west Texas and in north Texas
furthered the Company's objective of acquiring proved reserves in concentrated
geographic locations in which the Company was familiar with the geology and
other reservoir characteristics. These properties already were operating on
waterflood recovery. In the first of these acquisitions, the Company paid an
aggregate of approximately $17.2 million to acquire interests in 13 producing
oil and natural gas properties located in the Permian Basin of west Texas and
Lea County, New Mexico. One of these properties, the Shafter Lake Unit, is a
12,720 acre San Andres formation waterflood project. In the second
acquisition, the Company paid approximately $4.1 million to acquire working
interests in an existing waterflood project plus ancillary assets located in
Wichita, Wilberger and Hardeman Counties in north Texas. These properties are
adjacent to the Company's Electra Properties, which were acquired in 1991.
1993 Acquisitions. In 1993, the Company concluded two significant
acquisitions. The first acquisition created the Company's core operating area
in southwestern Kansas. These properties were acquired from Mobil Oil
Corporation for approximately $15.8 million. The second acquisition, MJM
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Oil & Gas, Inc. ("MJM"), added properties in the Company's core operating
areas of north Texas, the Permian Basin of west Texas and west central
Oklahoma.
1994 Acquisitions. The most significant acquisition of oil and natural gas
properties during 1994 was the Company's acquisition of Diamond, whose
properties are principally concentrated in west central Oklahoma.
Substantially all of Diamond's properties are waterflood recovery projects
which were initiated and developed by Diamond. This acquisition also brought
to the Company additional management with experience in waterflood recovery
projects. The Company also completed two acquisitions of properties located in
west Texas in December 1994, as well as several other smaller acquisitions.
The Company paid an aggregate of $73.1 million in connection with its
acquisitions during 1994 (including $21.4 million of the Company's Common
Stock issued in connection with the Diamond merger).
1995 Acquisitions. On October 6, 1995, the Company acquired 63 producing oil
and natural gas properties and related assets from Snyder. The majority of
these properties are located in the Permian Basin in west Texas. The total
purchase price of these properties was $17.1 million in cash, of which $16.0
million was financed with borrowings under the Company's then-existing credit
agreement. The Company believes that these properties present exploitation
opportunities, including opportunities to implement cost-cutting strategies
and initiate or improve secondary recovery operations and lower risk
development drilling activities. The Snyder Acquisition complements the
Company's core operating areas within the mid-continent region of the United
States. In addition to the Snyder Acquisition, the Company completed several
other smaller acquisitions during 1995. The aggregate purchase price of the
Company's acquisitions during 1995 was $25.4 million.
The Company does not have a specific acquisition budget since the timing and
size of acquisitions are difficult to forecast. The Company is constantly
reviewing acquisition possibilities and anticipates acquisitions in 1996 and
thereafter. The Company may expand its geographic core areas if it identifies
properties that complement its current activities and that it believes will
likely be responsive to the Company's exploitation strategy. At the present
time, the Company has no binding agreements with respect to any significant
acquisitions.
EXPLOITATION AND DEVELOPMENT ACTIVITIES
GENERAL
The Company concentrates on exploiting proved producing properties,
including those with development potential, through workovers, behind the pipe
recompletions, secondary recovery operations, the drilling of development
wells or infill wells and other exploitation techniques. The Company has
conducted or intends to conduct significant secondary recovery/infill drilling
programs on many of the properties it has acquired.
Secondary recovery projects have represented the Company's primary
development focus over the past four years. Generally, "secondary recovery"
refers to methods of oil extraction in which fluid or gas (usually water,
natural gas or CO/2/) is injected into a formation through input (injector)
wells, and oil is removed from surrounding wells. "Waterflooding" is one
proven method of secondary recovery in which water is injected into an oil
reservoir for the purpose of forcing the oil out of the reservoir rock and
into the bore of a producing well. Waterflood projects are engineered to suit
the type of reservoir, depth and condition of the field. The Company has
considerable experience with and actively employs waterflood techniques in
many of its fields in order to stimulate production.
The Company also seeks to exploit its properties through cost reduction
measures, including the reduction of labor, electrical and materials costs. It
seeks to take advantage of volume discounts in the purchase of equipment and
supplies and more effectively utilize field facilities and equipment by virtue
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<PAGE>
of its geographical concentration. The Company attempts to negotiate more
favorable marketing agreements upon completion of an acquisition, particularly
for oil production. Certain oil purchasers have paid in the past and are
currently paying a premium over posted prices and have eliminated certain
quality and marketing deductions for a portion of the Company's oil production
due to the Company's control over a significant volume of oil production in
its core geographic areas.
The Company makes only limited investments in exploratory drilling.
EXPLOITATION RESULTS
The properties presented in this table represent the ten largest properties
in which the Company had an ownership position as of January 1, 1995, based
upon the present value of estimated future net revenues at December 31, 1995.
These ten properties represent 65% of the present value of estimated future
net revenues at December 31, 1995, as estimated by the Company's independent
engineers, and are among the Company's most successful projects to date. The
present value of estimated future net revenues at December 31, 1995 and the
financial data presented provide an indication of the results of the Company's
exploitation strategy to date; however, certain of the properties acquired by
the Company have not been as successful as those described below and there can
be no assurance that the results presented below will be indicative of the
Company's future exploitation activities. The present value of future net
revenues shown below has been computed on the same basis as the Standardized
Measure, but without deducting income taxes, which is not in accordance with
generally accepted accounting principles. The amounts cannot be computed on an
after tax basis because the tax attributes of the Company's net operating loss
carryforwards cannot be allocated to specific properties. The Company believes
the present value of future net revenues is an important financial measure for
evaluating the relative significance of oil and natural gas properties, but it
should not be construed as an alternative to the Standardized Measure.
<TABLE>
<CAPTION>
A B C (A+B+C) D E (D+E)
PRESENT VALUE
OF ESTIMATED
PROPERTY (INITIAL ORIGINAL COST OF FUTURE NET
ACQUISITION/ PURCHASE ADDITIONAL CAPITAL NET REVENUES
UNITIZATION DATE)(1) PRICE(2) PURCHASES(3) EXPENDITURES(4) TOTAL REVENUES(5) PRETAX(6) TOTAL
-------------------- -------- ------------ --------------- ------- ----------- ------------- --------
(in thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Andrews Wolfcamp Field (Various)......... $ 7,690 $ 7,565 $ 606 $15,861 $ 6,968 $ 50,406 $ 57,374
Oakdale Red Fork Unit (4/1/91)........... 3,217 8,205 2,269 13,691 5,350 31,925 37,275
Shafter Lake San Andres Unit (10/1/92)... 7,613 836 3,771 12,220 4,210 28,949 33,159
Calumet Cottage Grove Unit (5/1/92)...... 6,855 7,134 2,830 16,819 11,764 23,132 34,896
Chadbourne Ranch (9/30/93)............... 8,252 222 6,002 14,476 8,424 11,662 20,086
McElroy (5/1/91)......................... 2,730 403 2,084 5,217 976 10,013 10,989
S.M.A. Unit "B" (3/1/91)................. 1,760 -- 6,149 7,909 4,832 9,385 14,217
Cutter South Unit (6/1/93)............... 1,343 332 642 2,317 536 6,984 7,520
B.A. Bywaters (7/1/91)................... 1,694 -- 4,154 5,848 2,821 5,931 8,752
L.K. Johnson (9/30/93)................... 2,501 100 1,071 3,672 1,235 4,833 6,068
------- ------- ------- ------- ------- -------- --------
Totals.................................. $43,655 $24,797 $29,578 $98,030 $47,116 $183,220 $230,336
======= ======= ======= ======= ======= ======== ========
</TABLE>
- --------
(1) Shows the effective date of acquisition by the Company or the date that
unitization was approved by the appropriate regulatory agency.
(2) Represents the amount of the original purchase price allocated to this
property.
(3) Represents the amount of the purchase price of additional interests
acquired in the property.
(4) Represents capital expenditures incurred in the Company's exploitation of
each of the indicated properties.
(5) Represents the sum of all revenues recorded by the Company on the property
since the date of acquisition less the total of all operating expenses
(excluding overhead charged by the Company) and severance and other taxes
on the property.
(6) Represents the present value of estimated future net revenues before
income taxes at December 31, 1995, discounted at an annual rate of 10%, as
determined by the Company's independent engineers. See "Glossary."
54
<PAGE>
Andrews Wolfcamp Field. On January 1, 1993, as part of a larger acquisition,
the Company took over operations of three leases in the Andrews Wolfcamp
Field. These leases produce primarily from the Wolfcamp and Pennsylvanian
formations at an average depth of 9,000 feet and are located in Andrews
County, Texas. The Company recognized the waterflood potential of this field
and thus began acquiring offset leases. In July 1994, the Company purchased a
100% working interest in three adjacent properties with five active wells. In
December 1994, the Company purchased 100% working interests in two additional
leases and a 93.8% working interest in a third lease. The Company purchased
several additional minor leases in 1995. The Company produced an average of
475 Bbls and 1,196 Mcf per day from 36 wells on these leases in December 1995.
The Company has begun the process of unitizing the field and under the
proposed plan of participation, the Company will have a 96.4% working interest
in the unit. The Company anticipates initiating waterflood activities in the
third quarter of 1996. Remaining proved reserves, net to the Company's
interest, were estimated by the Company's independent engineers to be 7,551
Mbbls and 2,107 Mmcf at December 31, 1995.
Oakdale Red Fork Unit. Recognizing that the Oakdale Red Fork Field located
in Woods County, Oklahoma was an excellent candidate for secondary recovery,
the Company began acquiring leases in 1991. At that time, cumulative
production from the field was a total of 4.9 Mmbbls of oil from the Red Fork
Formation at an average depth of 5,800 feet. In April 1991, even though a
prior attempt by another party to unitize the field had failed, the Company
was able to effect unitization and assume operational control of the unit. The
unit was producing 30 Bbls per day when the Company installed a waterflood
project in 1991. Average daily oil and natural gas production in December 1995
was 1,471 Bbls per day. The Company increased its ownership in the unit to an
89% working interest through acquisitions in December 1994 and February 1995.
Remaining proved reserves, net to the Company's interest, were estimated by
the Company's independent engineers to be 4,246 Mbbls and 659 Mmcf at December
31, 1995.
Shafter Lake San Andres Unit. On January 1, 1993, the Company became the
operator of the Shafter Lake San Andres Unit in Andrews County, Texas by
acquiring a 49% working interest in the unit from the prior operator. At that
time, this 12,720 acre unit was producing 743 Bbls per day from the
Grayburg/San Andres formation at an average depth of 4,500 feet. The Company
has since acquired an additional 14% working interest in this property through
eleven different acquisitions. In 1993, the Company expanded an east-west line
drive waterflood pattern by converting eight wells to water injection. The
Company continued expanding this pattern in 1994 and 1995 by drilling 21
additional producing wells and converting nine existing wells to water
injection. In December 1995, average daily production was 1,071 Bbls from 111
producing wells and 36 water injection wells. The Company has identified 58
additional drilling locations. Remaining proved reserves, net to the Company's
interest, were estimated by the Company's independent engineers to be 4,871
Mbbls and 1,407 Mmcf at December 31, 1995.
Calumet Cottage Grove Unit. The Company recognized the secondary recovery
potential of this field, located in Canadian County, Oklahoma, in 1991. The
Company made approximately 100 separate acquisitions of leases prior to
forming the unit. During the unitization of this 11,440 acre unit, the Company
solicited approvals from 801 working interest and royalty interest owners. The
acquisition and unitization process took over 18 months to complete before the
unit was finally formed in May 1992. Average daily oil production increased
from 229 Bbls to over 3,300 Bbls within 26 months of initiating water
injection and in December 1995 was 2,986 Bbls. Remaining proved reserves, net
to the Company's 43.8% working interest, were estimated by the Company's
independent engineers to be 2,511 Mbbls at December 31, 1995.
Chadbourne Ranch. The Company obtained 14 leases in the West Fort Chadbourne
Field located in Coke and Runnels Counties, Texas in September 1993 as part of
the acquisition of MJM. The Company has also leased 240 offsetting acres.
While there are multiple pay zones in this field,
55
<PAGE>
the production is primarily from the Odom formation at a depth of
approximately 5,500 feet. The Company has drilled 18 wells in this field. In
December 1995, the average daily production was 632 Bbls and 1,670 Mcf from 39
wells. The Company has produced, net to its interest, 559 Mbbls and 1,379 Mmcf
since acquisition. The Company has identified four additional drilling
locations. Remaining proved reserves, net to the Company's interest, were
estimated by the Company's independent engineers to be 1,089 Mbbls and 3,151
Mmcf at December 31, 1995.
McElroy. On July 1, 1991, the Company acquired a 100% working interest in
the Hardwicke University Section 48 lease in Upton County, Texas. The lease is
on the eastern flank of the McElroy Field and produces from the Grayburg/San
Andres formation from an average depth of 3,600 feet. Cumulative primary
production from this 160 acre lease is over 3.0 Mmbbls of primary oil. In
October 1992, the Company initiated a waterflood program by drilling six
injection wells and one producing well and converting one existing well to
injection. In September 1993, the Company acquired a 100% working interest in
four offsetting leases totaling 240 acres. Response from the waterflood has
not met the initial projections of the Company's engineers and as a result,
the expansion of waterflood operations on these leases will not occur until
performance on the existing waterflood improves. Average production in the
field in December 1995 was 112 Bbls and 143 Mcf per day. Remaining proved
reserves, net to the Company's interest, were estimated by the Company's
independent engineers to be 1,755 Mbbls and 754 Mmcf at December 31, 1995.
S.M.A. Unit "B". In March 1991, the Company acquired the S.M.A. Unit "B"
along with six smaller leases in the Wichita County Regular Field in Wichita
County, Texas. Initially, the Company acquired only an 89% working interest in
the S.M.A. Unit "B." Later in 1991, the Company purchased the remaining 11%
working interest. At the time of acquisition, there were 37 producing wells
and 24 water injection wells producing 165 Bbls per day from an average depth
of 1,750 feet. The Company has since implemented a five spot waterflood
pattern by drilling 60 producing wells and 46 water injection wells and
converting 15 wells to water injection. Average daily production in December
1995 was 475 Bbls from 94 producing wells and 77 water injection wells. The
Company has identified 14 additional drilling locations. Remaining proved
reserves, net to the Company's interest, were estimated by the Company's
independent engineers to be 1,597 Mbbls at December 31, 1995. The Company is
planning to install a pilot test of an enhanced recovery process on this
property in 1996.
Cutter South Mississippian Unit. In June 1993, the Company acquired nine
leases and assumed operations of 11 producing wells in the Cutter South Field
in Stevens County, Kansas. Average daily production was 80 Bbls when the
Company took over operation of these leases. Production is from the Chester
formation at an average depth of 6,000 feet, which lies below the Hugoton Gas
Field. While performing its evaluation prior to acquisition, the Company
recognized that these properties could be successfully exploited by secondary
recovery. The Company acquired three additional edge leases in this field in
1994 and 1995. On June 1, 1995, the Company was able to complete the
unitization of the field. The injection of water into the producing formation
began in November 1995. Ultimately, the Company plans to have 14 water
injection wells in the unit. The Company's working interest in the unit is
93.5% and average daily production was 82 Bbls in December 1995. Remaining
proved reserves, net to the Company's interest, were estimated by the
Company's independent engineers to be 793 Mbbls and 110 Mmcf at December 31,
1995.
B.A. Bywaters. The Company acquired a 100% working interest in the B.A.
Bywaters lease on July 1, 1991. This lease is in the Wichita County Special
Field in Wichita County, Texas and produces from multiple Pennsylvanian sands
ranging from 300 to 2,000 feet. There were 26 wells producing 85 Bbls per day
when the Company took over operations in July 1991. The Company has since
drilled 33 producing wells and 29 injector wells and converted seven wells to
water injection. Production from 55 wells in December 1995 averaged 372 Bbls
per day. The Company has identified four additional drilling locations.
Remaining proved reserves, net to the Company's interest, were estimated by
the Company's independent engineers to be 1,101 Mbbls and 104 Mmcf at December
31, 1995.
56
<PAGE>
L.K. Johnson. The Company acquired a 50% working interest in, and the
operations of, the L.K. Johnson lease in Foard County, Texas as part of the
MJM acquisition in September 1993. The Company has since acquired an
additional 1.5% working interest in the lease. In September 1993, production
from 18 wells averaged 163 Bbls per day from five productive horizons ranging
in depth from 2,400 to 4,000 feet. The Company has since drilled eight
additional producing wells. A pilot waterflood project began in February 1996
in the Cisco "K" field on this lease. Average daily production was 160 Bbls
and 309 Mcf in December 1995. The Company has identified 14 additional
drilling locations. Remaining proved reserves, net to the Company's interest,
were estimated by the Company's independent engineers to be 763 Mbbls and
1,104 Mmcf at December 31, 1995.
MARKETING
With the exception of the Taurus operations (see "--Gas Plants and Gathering
Systems Operations" below), the Company does not refine or process any of the
oil and natural gas it produces. The Company's oil and natural gas production
is sold to various purchasers typically in the areas where the oil or natural
gas is produced. The Company is currently able to sell, under contract or in
the spot market, all of the oil and most of the natural gas it is capable of
producing at current market prices. Substantially all of the Company's oil and
natural gas is sold under short term contracts or contracts providing for
periodic adjustments or in the spot market; therefore, its revenue streams are
highly sensitive to changes in current market prices. Certain of the Company's
oil purchasers have paid in the past and are currently paying a premium over
posted prices and have eliminated certain quality and marketing deductions for
a portion of the Company's oil production due to the Company's control over a
significant volume of oil production in its core geographic areas. The
Company's principal market for natural gas is pipeline companies as opposed to
end users.
In an effort to reduce the effects of the volatility of the price of crude
oil and natural gas on the Company's operations, management has adopted a
policy of hedging oil and gas prices whenever market prices are in excess of
the prices anticipated in the Company's operating budget and profit plan
through the use of commodity futures, options and swap agreements. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Changes in Prices and Hedging Activities" and Note 7 of Notes to
the Company's Historical Financial Statements.
During the year ended December 31, 1994, sales of oil and natural gas to
Amoco Production Company and EOTT Energy Operating Limited Partnership, a
subsidiary of Enron ("EOTT"), accounted for 13% and 22%, respectively, of the
Company's consolidated revenues. During the year ended December 31, 1995,
sales of oil and natural gas to Amoco Production Company and EOTT accounted
for 10% and 18%, respectively, of the Company's consolidated revenues. EOTT is
a subsidiary of Enron and an affiliate of the Company, ECT and ECT Securities,
Inc. See "Certain Transactions." Management believes that in the event these
purchasers were to discontinue their purchases, the Company could quickly
locate other buyers and, therefore, the loss of these purchasers would not
have a material impact on the Company's financial condition or results of
operations. However, short term disruptions could occur while the Company
sought alternative buyers.
OIL AND NATURAL GAS RESERVES
The following tables summarize certain information regarding the Company's
estimated proved oil and natural gas reserves as of December 31, 1993, 1994
and 1995. Such estimated reserves, as set forth herein and in Note 10 of Notes
to Consolidated Financial Statements, are based upon reports prepared by Lee
Keeling and Associates, Inc., independent consulting petroleum engineers. A
summary of the December 31, 1995 report is included in this Prospectus as
Annex A. Reserve estimates as of December 31, 1993 for Diamond were prepared
by Diamond's in-house engineers. All such reserves are located in the United
States. All reserves are evaluated at contract temperature and pressure which
can affect the measurement of natural gas reserves. For further information,
see Note
57
<PAGE>
10 of Notes to Consolidated Financial Statements. Reserve estimates are
inherently imprecise and there can be no assurance that the reserves set forth
below will ultimately be produced at all or at the prices and costs assumed in
the estimates of future net revenues. See "Risk Factors--Reliance on Estimates
of Proved Reserves and Future Net Revenues" and "Experts."
The following table sets forth proved reserves considered to be economically
recoverable under normal operating methods and existing conditions, at prices
and operating costs prevailing at the dates indicated below.
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------------------
1993 1994 1995
------------- ------------- -------------
(in thousands)
OIL GAS OIL GAS OIL GAS
(BBLS) (MCF) (BBLS) (MCF) (BBLS) (MCF)
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Proved developed reserves............ 16,230 30,573 20,151 32,890 25,877 31,496
Proved undeveloped reserves.......... 13,854 5,623 19,056 6,918 16,713 5,634
------ ------ ------ ------ ------ ------
Total proved reserves.............. 30,084 36,196 39,207 39,808 42,590 37,130
====== ====== ====== ====== ====== ======
</TABLE>
No major discovery or other favorable or adverse event is believed to have
caused a significant change in these estimates of the Company's proved
reserves since January 1, 1996.
Except for Form EIA 23, "Annual Survey of Domestic Oil and Gas Reserves,"
filed with the United States Department of Energy, no other estimates of total
proven net oil or gas reserves have been filed by the Company with, or
included in any report to, any United States authority or agency pertaining to
the Company's individual reserves since the beginning of the Company's last
fiscal year. Reserves reported in Form EIA 23 are comparable to the reserves
reported by the Company herein.
OPERATIONS DATA
Productive Wells. The following table sets forth the total gross and net
productive wells in which the Company owned an interest as of December 31,
1995. Substantially all of the Company's wells are under 10,000 feet deep.
<TABLE>
<CAPTION>
GROSS (1) NET (1)
---------- ----------
OIL(2) GAS OIL(2) GAS
------ --- ------ ---
<S> <C> <C> <C> <C>
Texas................................................ 1,802 16 1,561 8
Oklahoma............................................. 258 27 145 8
Kansas............................................... 76 5 67 4
Other................................................ 6 -- 1 --
----- --- ----- ---
Total.............................................. 2,142 48 1,774 20
===== === ===== ===
</TABLE>
--------
(1) The number of gross wells is the total number of wells in which a
fractional working interest is owned. The number of net wells is
the sum of the fractional working interests owned by the Company in
gross wells.
(2) The oil well category includes 615 gross and 524 net active water
injection and utility wells which are necessary for the operation
of the Company's waterflood projects.
Production Economics. The following table shows the approximate net
production attributable to the Company's oil and natural gas interests, the
average sales price and the average production and depletion, depreciation and
amortization expenses per Bbl of oil and Mcf of natural gas attributable to
the Company's oil and natural gas production for the periods indicated.
Production and sales information relating to properties acquired or disposed
of is reflected in this table only since or up to the closing date of their
respective acquisition or sale and may affect the comparability of the data
between the periods presented.
58
<PAGE>
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------
1993 1994 1995
-------- -------- --------
<S> <C> <C> <C>
OIL AND NATURAL GAS PRODUCTION
Oil (Mbbls)...................................... 1,766 2,650 3,165
Natural gas (Mmcf)............................... 4,703 4,982 4,416
AVERAGE SALES PRICES (1)
Oil (Bbl)........................................ $16.88 $15.86 $17.08
Natural gas (Mcf)................................ 1.92 1.74 1.57
PRODUCTION COST (2)
Per equivalent Bbl (3)........................... $6.90 $6.22 $6.95
Per dollar of sales.............................. 0.45 0.43 0.44
DEPLETION, DEPRECIATION AND AMORTIZATION
Per equivalent Bbl (3)........................... $4.15 $4.27 $4.33
Per dollar of sales.............................. 0.27 0.29 0.28
</TABLE>
--------
(1) Before deduction of production taxes and net of hedging results for
the three years ended December 31, 1995.
(2) Excludes depletion, depreciation and amortization. Production cost
includes lease operating expenses and production and ad valorem taxes,
if applicable.
(3) Natural gas production is converted to equivalent barrels of oil at
the rate of six Mcf of natural gas per barrel, representing the
estimated relative energy content of natural gas and oil.
The following table sets forth the results of the Company's annual drilling
activities (wells completed or abandoned) as of fiscal year end. During the
four months ended April 30, 1996, the Company drilled eight wells. At April
30, 1996, the Company was in the process of drilling one well.
<TABLE>
<CAPTION>
1993 1994 1995
--------------- --------------- ---------------
GROSS(1) NET(1) GROSS(1) NET(1) GROSS(1) NET(1)
-------- ------ -------- ------ -------- ------
<S> <C> <C> <C> <C> <C> <C>
EXPLORATORY:
Oil........................ -- -- -- -- -- --
Gas........................ -- -- 1 0.38 2 0.75
Dry........................ -- -- -- -- -- --
--- ----- --- ----- --- -----
Total.................... -- -- 1 0.38 2 0.75
=== ===== === ===== === =====
DEVELOPMENT:
Oil........................ 57 55.09 86 66.68 109 98.88
Gas........................ -- -- -- -- -- --
Dry........................ -- -- 1 0.50 -- --
--- ----- --- ----- --- -----
Total.................... 57 55.09 87 67.18 109 98.88
=== ===== === ===== === =====
TOTAL:
Oil........................ 57 55.09 86 66.68 109 98.88
Gas........................ -- -- 1 0.38 2 0.75
Dry........................ -- -- 1 0.50 -- --
--- ----- --- ----- --- -----
Total.................... 57 55.09 88 67.56 111 99.63
=== ===== === ===== === =====
</TABLE>
--------
(1) The number of gross wells is the total number of wells in which the
Company owns a fractional working interest. The number of net wells is
the sum of the fractional working interests owned by the Company in
gross wells.
For purposes of the table above, an "exploratory well" is a well drilled to
find and produce oil or natural gas in an unproved area, to find a reservoir
in a field previously found to be productive of oil or gas in another
reservoir or to extend a known reservoir. A "development well" is a well
drilled within the proven boundaries of an oil or natural gas reservoir with
the intention of completing the
59
<PAGE>
stratigraphic horizon known to be productive. A "dry well" is an exploratory
or development well found to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or natural gas well.
DEVELOPED AND UNDEVELOPED ACREAGE
The following table sets forth the approximate gross acres and net acres of
productive properties in which the Company owned a leasehold interest as of
December 31, 1995. Gross acres refers to the total acres in which the Company
has a working interest, and net acres refers to the fractional working
interests owned by or attributable to the Company multiplied by the gross
acres in which the Company has a working interest. Developed acreage is that
acreage spaced or assignable to productive wells. Undeveloped acreage is
considered to be that acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether or not such acreage contains
proved reserves. At December 31, 1995, the Company had no significant amount
of undeveloped acreage.
<TABLE>
<CAPTION>
DEVELOPED
--------------
GROSS NET
------- ------
<S> <C> <C>
Texas....................................................... 93,615 51,998
Oklahoma.................................................... 49,585 24,559
Kansas...................................................... 16,199 13,856
Other....................................................... 5,341 1,817
------- ------
Total..................................................... 164,740 92,230
======= ======
</TABLE>
Essentially all of the Company's oil and gas interests are leasehold working
interests or overriding royalty interests under standard onshore oil and
natural gas leases, rather than mineral or fee interests.
GAS PLANTS AND GATHERING SYSTEM OPERATIONS
On April 29, 1994, the Company acquired by merger all of the issued and
outstanding common stock of Taurus, in exchange for 1.5 million shares of
Coda's Common Stock, valued at approximately $7.3 million, and approximately
$3.3 million in cash. The Company assumed existing Taurus indebtedness of
approximately $9.8 million. Taurus owns and operates three natural gas
processing facilities and approximately 700 miles of natural gas gathering
systems, primarily located in west central Texas. Taurus represented
approximately nine percent of the Company's consolidated 1995 EBITDA of
approximately $37.3 million.
In July 1994, Taurus acquired ownership of the Shackelford gas processing
plant and gathering system ("Shackelford"). Taurus had previously been
operating the Shackelford system and plant under operating leases. Shackelford
consists of approximately 250 miles of pipeline located in Shackelford,
Callahan, Stephens and Throckmorton Counties, Texas. The plant is a 30,000 Mcf
per day capacity refrigerated lean oil absorption plant located near Putnam,
Texas. The steel gathering lines range in size from 3 inches to 10 inches in
diameter. There are over 100 purchase, check and sales meters. The system
utilizes 20 compressors with over 4,500 total horsepower.
In January 1995, Taurus acquired the remaining 42% interest in the Hamlin
gas processing plant and gathering system ("Hamlin"). The Hamlin gathering
system consists of about 450 miles of low pressure gathering lines and twelve
compressor stations in Fisher, Cottle, Taylor, Stonewall, Jones, Haskell, King
and Knox Counties, Texas. The Hamlin plant utilizes a cryogenic process and
has a processing capacity of 20,000 Mcf per day. Gas supply to the system
consists almost entirely of high BTU casinghead gas. The Hamlin plant produces
a demethanized stream which is delivered into a products pipeline.
60
<PAGE>
The following table shows certain financial data in respect of the Company's
gas gathering and processing operations, including Taurus, for the three years
ended December 31, 1995.
<TABLE>
<CAPTION>
1993 1994 1995
------ ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Gas sales.......................................... $ -- $12,261 $21,038
Natural gas liquids sales.......................... 732 7,771 14,597
Operating margin................................... 162 2,724 5,161
EBITDA............................................. 7 2,073 3,354
Total assets....................................... 1,157 32,577 38,040
</TABLE>
The Merger Agreement originally required as a condition to JEDI's
consummation of the Merger that the Company sell Taurus on terms acceptable to
JEDI. However, negotiations with prospective purchasers for Taurus failed to
progress beyond preliminary stages and by December 1995, the Company's
management and JEDI had concluded a timely sale of Taurus upon terms
satisfactory to JEDI was not feasible or likely. Subsequently, the Merger
Agreement was amended to remove this condition. The Company intends to study
alternatives for maximizing the value of its investment in Taurus. These
alternatives could include a sale of Taurus, whether by merger, sale of all or
substantially all of the assets of Taurus or sale of all of the capital stock
of Taurus.
Sales and markets. Taurus' two largest plants and gathering systems,
Shackelford and Hamlin, account for the majority of Taurus' revenue.
Taurus sells its residue gas from Shackelford to a variety of large natural
gas purchasers under short-term contracts at market sensitive prices. Residue
gas from Shackelford can be delivered into either one of two major pipeline
systems. These connections provide significant marketing flexibility by giving
access to major marketing hubs in east Texas, west Texas and the Gulf Coast.
Major natural gas consuming markets in California, the Midwest, the Northeast
and along the Texas Gulf Coast can be accessed through these market hubs.
Generally, residue gas is sold under short-term contracts either at the
tailgate of the Shackelford Plant or out of the intrastate pipeline.
The Shackelford Plant produces a demethanized stream which is delivered into
a products pipeline. Ethane, normal butane and natural gasoline components of
the product stream are generally sold as they enter the pipeline. The
remaining components of the product stream are then sold under short term
agreements to various customers at a central marketing point in Mont Belvieu,
Texas. A transportation and fractionation fee is paid on all gallons not sold
to the pipeline owner.
Residue gas from Hamlin can be delivered into either the Palo Duro Pipeline
or the Lone Star Gas pipeline. These connections afford Taurus the opportunity
to offer residue gas from both Hamlin and Shackelford as a package which
increases the marketing flexibility and leverage of both plants. Since
assuming operation of Hamlin, Taurus has sold all residue gas under short term
contracts at market sensitive prices to a variety of large purchasers.
The Hamlin Plant produces a demethanized stream which is delivered into a
products pipeline. All of Hamlin's liquids production is being sold under
agreements that provide for market index prices less a transportation and
fractionation fee.
Purchases. Taurus purchases gas for Shackelford from approximately 250 wells
in Shackelford, Callahan, Stephens and Throckmorton Counties, Texas. The
majority of the production connected to the gathering system is low volume
casinghead gas. The system is operated at low pressure with lateral line
pressures ranging from 15 to 150 psi. The mainline pressure averages about 300
psi.
61
<PAGE>
Taurus utilizes two base forms of gas purchase agreements: percentage of
proceeds and fixed price. Percentage contracts provide that the seller is
allocated its proportionate share of residue gas sales and natural gas liquids
production. Fixed price contracts, which generally provide for acreage
dedications, are for primary terms of up to 20 years with annual renewals
thereafter. The purchase price to be paid is stated in the contract and is
subject to annual price redetermination if certain specific conditions are met.
The natural gas connected to Shackelford is purchased under both percentage
and fixed price contracts. The majority of the natural gas connected to Hamlin
is being purchased utilizing percentage of proceeds contracts. There are about
200 natural gas purchase agreements covering over 450 wells connected to
Hamlin. Less than two percent of Taurus' purchases are from the Company's
wells.
MARKETS AND COMPETITION
The oil and natural gas industry is highly competitive. Competitors include
major oil companies, other independent oil and natural gas concerns, and
individual producers and operators, many of which have financial resources,
staffs and facilities substantially greater than those of the Company. In
addition, the Company encounters substantial competition in acquiring oil and
natural gas properties, marketing oil and natural gas and securing trained
personnel. When possible, the Company tries to avoid open competitive bidding
for acquisition opportunities. The principal means of competition with respect
to the sale of oil and natural gas production are product availability and
price. While it is not possible for the Company to state accurately its
position in the oil and natural gas industry, the Company believes that it
represents a minor competitive factor.
The market for oil, natural gas and natural gas liquids produced by the
Company depends on factors beyond its control, including domestic and foreign
political conditions, the overall level of supply of and demand for oil,
natural gas and natural gas liquids, the price of imports of oil and natural
gas, weather conditions, the price and availability of alternative fuels, the
proximity and capacity of natural gas pipelines and other transportation
facilities and overall economic conditions. The oil and natural gas industry as
a whole also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual consumers.
REGULATION
The Company's operations are affected in various degrees by political
developments, federal and state laws and regulations. In particular, oil and
natural gas production operations and economics are affected by price controls,
tax and other laws relating to the petroleum industry, by changes in such laws
and by changes in administrative regulations and the interpretation and
application of such rules and regulations.
Sales of oil and natural gas liquids by the Company are not regulated and are
made at market prices. The price the Company receives from the sale of these
products is affected by the cost of transporting the products to market.
Effective as of January 1, 1995, the Federal Energy Regulatory Commission
implemented regulations establishing an indexing system for transportation
rates for oil pipelines, which, generally, would index such rates to inflation,
subject to certain conditions and limitations. These regulations could increase
the cost of transporting oil and natural gas liquids by pipeline, although the
most recent adjustment generally decreased rates. These regulations are subject
to pending petitions for judicial review. The Company is not able to predict
with certainty what effect, if any, these regulations will have on it, but,
other factors being equal, the regulations may, over time, tend to increase
transportation costs or reduce wellhead prices for oil and natural gas liquids.
62
<PAGE>
ENVIRONMENTAL MATTERS
Operations of the Company are subject to numerous and constantly changing
federal, state and local laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection. These laws and regulations may require the acquisition of certain
permits, restrict or prohibit the types, quantities and concentration of
substances that can be released into the environment in connection with
drilling and production, restrict or prohibit drilling activities that could
impact wetlands, endangered or threatened species or other protected natural
resources and impose substantial liabilities for pollution resulting from the
Company's operations. Such laws and regulations may substantially increase the
cost of exploring for, developing or producing oil and natural gas and may
prevent or delay the commencement or continuation of a given project. In the
opinion of the Company's management, the Company is in substantial compliance
with current applicable environmental laws and regulations, and the cost of
compliance with such laws and regulations has not been material and is not
expected to be material during the next fiscal year. However, changes in
existing environmental laws and regulations or in interpretations thereof could
have a significant impact on the operating costs of the Company, as well as the
oil and natural gas industry in general. For instance, legislation has been
proposed in Congress from time to time that would reclassify certain oil and
natural gas production wastes as "hazardous wastes," which reclassification
would make exploration and production wastes subject to much more stringent
handling, disposal and clean-up requirements. State initiatives to further
regulate the disposal of oil and natural gas wastes and naturally occurring
radioactive materials are also pending in certain states, including Texas, and
these various initiatives could have a similar impact on the Company.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons that are considered to have contributed to the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or site where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. Persons who are or were responsible for releases of hazardous substances
under CERCLA may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances
released into the environment. The Company is able to control directly the
operation of only those wells with respect to which it acts as operator.
Notwithstanding the Company's lack of control over wells operated by others,
the failure of the operator to comply with applicable environmental regulations
may, in certain circumstances, be attributed to the Company. The Company has no
material commitments for capital expenditures to comply with existing
environmental requirements.
EMPLOYEES
As of March 31, 1996, the Company's staff consisted of 156 full-time
employees, of whom 67 were administrative personnel, 60 were field and service-
related personnel, and 29 were personnel whose duties related to Taurus. The
Company also engages independent consulting petroleum engineers, environmental
professionals, geologists, landmen, accountants and attorneys on a fee basis.
LEGAL PROCEEDINGS
The Company is a defendant or codefendant in minor lawsuits that have arisen
in the ordinary course of business. The Company does not expect any of these to
have a material adverse effect on the Company's consolidated financial
position.
63
<PAGE>
MANAGEMENT
The executive officers and directors of the Company following completion of
the Merger are listed below, together with a description of their experience
and certain other information. Each of the directors serve for a one year
term. Executive officers are appointed by the Board of Directors. The
Company's Bylaws provide that the Chairman of the Board and the Vice Chairman
of the Board (or the President if there is no Vice Chairman) shall be
directors of the Company.
<TABLE>
<CAPTION>
NAME AGE OFFICE SINCE POSITION WITH COMPANY
---- --- ------------ -------------------------------
<S> <C> <C> <C>
Douglas H. Miller.............. 48 1989 Chairman of the Board and Chief
Executive Officer
Jarl P. Johnson................ 66 1994 President of Diamond, Vice
Chairman of the Board and
Chief Operating Officer
Grant W. Henderson............. 37 1993 President, Chief Financial
Officer and Director
J. William Freeman............. 55 1990 Vice President--Engineering
J.W. Spencer, III.............. 45 1991 Vice President--Operations
Randell A. Bodenhamer.......... 41 1995 Vice President--Land
Richard A. Causey.............. 36 1995 Director
James V. Derrick, Jr........... 51 1995 Director
Gene E. Humphrey............... 49 1995 Director
C. John Thompson............... 43 1995 Director
</TABLE>
Douglas H. Miller was elected Chairman of the Board and Chief Executive
Officer of the Company in October 1989 and has served as a director of Coda
since 1987. Beginning in 1983, Mr. Miller also served as president of a
securities broker/dealer which Mr. Miller sold in 1993.
Jarl P. Johnson has been active in the oil and natural gas industry since
1953. Mr. Johnson worked for Phillips Petroleum from 1953 to 1955, and for
Kewanee Oil Co. from 1955 to 1978 where he served as Manager of Engineering
for 14 years. He worked for Hamilton Brothers Oil Company from 1978 to 1980 as
Vice President of Engineering. From 1980 to 1986 he was Vice President of
Operations for Ensource Inc. Mr. Johnson formed his own company, PetroJarl,
Inc., in 1986 to own non-operated oil and gas interests. He became President
and a director of Diamond in October 1989. Mr. Johnson joined the Company as
Vice Chairman of the Company in 1994 in connection with the Company's
acquisition of Diamond and became Chief Operating Officer of the Company upon
consummation of the Merger.
Grant W. Henderson joined the Company in October 1993 as Executive Vice
President and Chief Financial Officer of the Company. He was elected a
director of Coda in 1995 and became President of the Company upon consummation
of the Merger. Mr. Henderson also will continue to serve as Chief Financial
Officer of the Company. Mr. Henderson was previously employed by NationsBank,
beginning 1981, last serving as a Senior Vice President in its Energy Banking
Group.
J. William Freeman is a registered Professional Engineer in the State of
Texas and joined the Company in 1990 as its senior reservoir and economics
engineer. Mr. Freeman has worked in the oil and natural gas industry for 27
years, principally in the area of acquisitions of oil and natural gas
properties. Prior to 1985 Mr. Freeman was employed by Gulf Oil Corporation.
From 1985 to November 1989 he worked as an independent oil and gas engineer.
64
<PAGE>
J.W. Spencer, III has been involved in production and reservoir engineering
since 1973. From 1985 until March 1991, when he joined the Company as Vice
President--Operations of the Company, he was manager of production operations
for Conquest Exploration Company. Prior to 1985, Mr. Spencer was employed as
an engineer by Gulf Oil Corporation.
Randell A. Bodenhamer joined the Company in 1994 as Executive Vice President
of Diamond in conjunction with the Company's acquisition of Diamond. Mr.
Bodenhamer was appointed Vice President--Land of the Company in August 1995.
Prior to joining Diamond as an employee, Mr. Bodenhamer was owner of R.A.
Bodenhamer & Associates, Inc., a Tulsa-based land service company. From 1986
through 1994, Mr. Bodenhamer worked primarily for Diamond acquiring and
unitizing waterflood projects on its behalf.
Richard A. Causey currently is a Vice President of ECT and is responsible
for the treasury activities of ECT. He has been associated with ECT since
1991.
James V. Derrick, Jr. is Senior Vice President and General Counsel of Enron.
He serves on the Management Committee of Enron and is a director of Enron
Global Power & Pipelines LLC, a New York Stock Exchange-listed entity that
owns interests in certain international pipeline and power projects. He has
been associated with Enron since 1991.
Gene E. Humphrey has been with ECT since its inception in 1990, most
recently serving as Managing Director. Previously, he was a Vice President in
Citibank's Petroleum Department where he specialized in financial and
investment banking services for the oil and natural gas industry.
C. John Thompson has been employed by ECT since its inception in 1990,
serving as Vice President of the Domestic Corporate Finance Group. Previously,
he was a Partner with James C. Cooper, Inc., an investment banking firm based
in Houston, Texas.
65
<PAGE>
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT
The following table sets forth the name and address of the only stockholder
of the Company who is known by the Company to beneficially own more than five
percent of the Company's outstanding common stock, the number of shares
beneficially owned by such stockholder, and the percentage of outstanding
common stock so owned, as of May 1, 1996. As of May 1, 1996, there were
913,611 shares of common stock outstanding.
<TABLE>
<CAPTION>
AMOUNT AND
NAME AND ADDRESS NATURE OF PERCENT OF
TITLE OF CLASS OF BENEFICIAL OWNER BENEFICIAL OWNERSHIP CLASS
-------------- -------------------------------- -------------------- ----------
<S> <C> <C> <C>
Common Joint Energy Development 900,000 98.5
Stock Investments Limited Partnership
1400 Smith Street
Houston, Texas 77002
</TABLE>
The table appearing below sets forth information as of May 1, 1996 with
respect to shares of common stock beneficially owned by each of the Company's
directors, the Company's Chief Executive Officer and the four other most
highly compensated executive officers for 1995, and all directors and
executive officers as a group, and the percent of the outstanding common stock
so owned by each.
<TABLE>
<CAPTION>
AMOUNT AND
NATURE OF
BENEFICIAL PERCENT OF
TITLE OF CLASS DIRECTORS AND NAMED EXECUTIVE OFFICERS OWNERSHIP (1) CLASS
-------------- -------------------------------------- ------------- ----------
<C> <S> <C> <C>
Common Stock Richard A. Causey..................... -- --
Common Stock James V. Derrick, Jr.................. -- --
Common Stock T. W. Eubank (2)...................... -- --
Common Stock Grant W. Henderson.................... 4,750(4) (8)
Common Stock Gene E. Humphrey...................... -- --
Common Stock Jarl P. Johnson....................... 3,800(5) (8)
Common Stock Tommie E. Lohman(3)................... -- --
Common Stock Douglas H. Miller..................... 23,750(6) 2.5
Common Stock C. John Thompson...................... -- --
Common Stock All directors and executive officers
as a group
(12 persons)......................... 39,425(7) 4.2
</TABLE>
- --------
(1) Unless otherwise indicated, all shares are owned directly by the named
person and such person has sole voting and investment power with respect
to such shares.
(2) Mr. Eubank retired from the Company in February 1996.
(3) Mr. Lohman retired from Taurus in April 1996.
(4) Includes options to purchase 2,375 shares exercisable within 60 days.
(5) Includes options to purchase 1,185 shares exercisable within 60 days.
(6) Includes options to purchase 23,750 shares exercisable within 60 days.
(7) Includes all options referenced in notes (3) through (5) above; 4,708
shares held directly by other executive officers of the Company and
options to purchase 2,417 shares exercisable within 60 days held by other
executive officers of the Company.
(8) Less than one percent.
66
<PAGE>
EXECUTIVE COMPENSATION AND OTHER INFORMATION
SUMMARY COMPENSATION TABLE
The following table sets forth the annual and long-term compensation for the
Company's Chief Executive Officer and the four other most highly compensated
executive officers for 1995, as well as the total compensation paid to each
such individual during the Company's last three fiscal years. Such individuals
are sometimes referred to as the "named executive officers."
<TABLE>
<CAPTION>
LONG-TERM
COMPENSATION
------------
ANNUAL COMPENSATION AWARDS
-------------------------------------- ------------
SECURITIES
OTHER ANNUAL UNDERLYING
NAME AND COMPENSATION OPTIONS/SARS ALL OTHER
PRINCIPAL POSITION YEAR SALARY($) BONUS($) ($)(6) (#) COMPENSATION($)
------------------ ---- --------- -------- ------------ ------------ ---------------
<S> <C> <C> <C> <C> <C> <C>
Douglas H. Miller....... 1995 218,968 16,826 13,500(7) -- 7,340(12)
Chief Executive 1994 201,469 15,938 12,000(7) 28,865 7,131(13)
Officer; Chairman of 1993 181,563 24,811 12,000(7) 17,500 6,769(14)
the Board
T. W. Eubank(1)......... 1995 187,687 14,644 13,500(7) -- 9,650(15)
President; Chief 1994 172,688 13,604 12,000(7) 24,750 9,629(16)
Operating Officer 1993 155,625 21,498 12,000(7) 15,000 9,320(17)
Grant W.
Henderson(2)........... 1995 156,406 12,338 9,750(7)(8) 100,000(11) 5,335(18)
Executive Vice 1994 143,906 10,919 -- 20,620 4,958(19)
President; Chief 1993 30,501 3,996 -- 25,000 --
Financial Officer
Tommie E.
Lohman(3).............. 1995 152,474 8,275 13,500(7) -- 7,439(20)
President--Taurus 1994 100,781 7,475 6,500(7)(9) 107,500(11) 4,928(21)
Energy Corp. 1993 -- -- -- -- --
Jarl P. Johnson(4)...... 1995 175,000 9,165 13,500(7) -- 7,627(22)
Vice Chairman of the 1994 45,854 31,104(5) 1,500(7)(10) 108,750(11) 2,100(23)
Board; President-- 1993 -- -- -- -- --
Diamond Energy
Operating Company
</TABLE>
- --------
(1) Mr. Eubank retired from the Company in February 1996.
(2) Mr. Henderson's employment did not commence until October 15, 1993, when
he joined the Company as Executive Vice President and Chief Financial
Officer. Mr. Henderson's compensation is therefore reported from October
15, 1993 through December 31, 1995.
(3) Mr. Lohman's employment did not commence until April 29, 1994, when the
Company acquired Taurus. Mr. Lohman's compensation is therefore reported
from May 1, 1994 through December 31, 1995. Mr. Lohman retired from
Taurus in April 1996.
(4) Mr. Johnson's employment did not commence until September 30, 1994, when
the Company acquired Diamond. Mr. Johnson's compensation is therefore
reported from October 1, 1994 through December 31, 1995.
(5) Includes $27,936 paid to Mr. Johnson as compensation pursuant to the
terms of the acquisition of Diamond.
(6) For each of the named executive officers, the aggregate amount of
perquisites and other personal benefits did not exceed the lesser of
$50,000 or 10% of the officer's total annual salary and bonus.
(7) Reflects director's fees paid by the Company of $12,000 per year (in
years prior to 1995 as $6,000 in cash and $6,000 in Common Stock,
calculated quarterly at the average market price per quarter, and during
1995 as $9,000 in cash and $3,000 in Common Stock, calculated quarterly
at the average market price per quarter, all of which Common Stock was
paid in the first two quarters of 1995). The cash portion of the
director's fees is paid in the quarter earned while the stock portion of
the director's fees is paid after the end of such quarter.
(8) Director's fees paid to Mr. Henderson were prorated to reflect his
becoming a director on March 15, 1995.
67
<PAGE>
(9) Director's fees paid to Mr. Lohman were prorated to reflect his becoming
a director on April 29, 1994. Although Mr. Lohman accrued $8,000 in
director's fees, only $6,500 of those fees were paid in fiscal year 1994.
See Note (7).
(10) Director's fees paid to Mr. Johnson were prorated to reflect his becoming
a director on September 30, 1994. Although Mr. Johnson accrued $3,000 in
director's fees, only $1,500 of those fees were paid in fiscal year 1994.
See Note (7).
(11) Includes a warrant for the purchase of up to 100,000 shares which is
awarded to each director of the Company on the date of his election or
selection and vests 25,000 shares per year beginning on the first
anniversary of the grant.
(12) Includes $6,930 attributable to the Company's matching contribution to
its 401(k) Plan, and $410 paid by the Company for term life insurance
premium.
(13) Includes $6,742 attributable to the Company's matching contribution to
its 401(k) Plan, and $389 paid by the Company for term life insurance
premium.
(14) Includes $6,381 attributable to the Company's matching contribution to
its 401(k) Plan, and $389 paid by the Company for term life insurance
premium.
(15) Includes $9,240 attributable to the Company's matching contribution to
its 401(k) Plan, and $410 paid by the Company for term life insurance
premium.
(16) Includes $9,240 attributable to the Company's matching contribution to
its 401(k) Plan, and $389 paid by the Company for term life insurance
premium.
(17) Includes $8,931 attributable to the Company's matching contribution to
its 401(k) Plan, and $389 paid by the Company for term life insurance
premium.
(18) Includes $4,925 attributable to the Company's matching contribution to
its 401(k) Plan, and $410 paid by the Company for term life insurance
premium.
(19) Includes $4,569 attributable to the Company's matching contribution to
its 401(k) Plan, and $389 paid by the Company for term life insurance
premium.
(20) Includes $7,029 attributable to the Company's matching contribution to
its 401(k) Plan, and $410 paid by the Company for term life insurance
premium.
(21) Includes $4,747 attributable to the Company's matching contribution to
its 401(k) Plan, and $181 paid by the Company for term life insurance
premium.
(22) Includes $7,217 attributable to the Company's matching contribution to
its 401(k) Plan, and $410 paid by the Company for term life insurance
premium.
(23) Consists of $2,100 paid by the Company for term life insurance premium.
The following table sets forth certain information concerning options/SARs
granted during 1995 to the named executive officers of the Company.
<TABLE>
<CAPTION>
INDIVIDUAL GRANTS
------------------------------------------------
POTENTIAL REALIZABLE
PERCENT OF VALUE AT ASSUMED
NUMBER OF TOTAL ANNUAL RATES OF STOCK
SECURITIES OPTIONS/SARS PRICE APPRECIATION FOR
UNDERLYING GRANTED TO EXERCISE OR OPTION TERM(1)
OPTIONS/SARS EMPLOYEES IN BASE PRICE EXPIRATION ----------------------
NAME GRANTED FISCAL YEAR ($/SH) DATE 5%($) 10%($)
---- ------------ ------------ ----------- ---------- ----- -----------
<S> <C> <C> <C> <C> <C> <C>
Douglas H. Miller....... -- -- -- -- -- --
T.W. Eubank............. -- -- -- -- -- --
Grant W. Henderson...... 100,000 100 6.00 3/15/05 377,337 956,245
Tommie E. Lohman........ -- -- -- -- -- --
Jarl P. Johnson......... -- -- -- -- -- --
</TABLE>
- --------
(1) The amounts disclosed in these columns, which reflect appreciation at the
5% and 10% rates dictated by the Commission, are not intended to be a
forecast of Common Stock price and are not necessarily indicative of the
actual values which may be realized by the named executive officers.
68
<PAGE>
The following table shows aggregated option/SAR exercises in the last fiscal
year and fiscal year end option/SAR values for each of the named executive
officers:
<TABLE>
<CAPTION>
VALUE OF
UNEXERCISED
NUMBER OF SECURITIES IN-THE MONEY
UNDERLYING UNEXERCISED OPTIONS/SARS
SHARES OPTIONS/SARS AT FY-END ($)
ACQUIRED ON VALUE AT FY-END (#) EXERCISABLE/
NAME EXERCISE(#) REALIZED ($) EXERCISABLE/UNEXERCISABLE UNEXERCISABLE(1)
---- ----------- ------------ ------------------------- ----------------
<S> <C> <C> <C> <C>
Douglas H. Miller....... -- -- 558,660/18,955 2,422,723/35,994
T.W. Eubank............. -- -- 76,000/18,750 266,188/35,078
Grant W. Henderson...... -- -- 25,829/119,791 43,428/177,927
Tommie E. Lohman........ -- -- 27,500/80,000 68,594/201,250
Jarl P. Johnson......... -- -- 27,917/80,833 22,475/62,135
</TABLE>
- --------
(1) Values are calculated by subtracting the exercise price per share from the
market value per share of the Company's Common Stock at fiscal year end,
multiplied by the number of shares of Common Stock underlying the "in-the-
money" options, and assumes a fair market value at fiscal year end of
$7.4375 per share (the closing price of the Company's Common Stock on
December 29, 1995).
DIRECTORS' COMPENSATION
Following completion of the Merger, members of the Company's Board of
Directors will not receive compensation for any services provided in their
capacities as directors, other than the reimbursement of reasonable expenses
incurred in attending meetings of the Board of Directors.
Prior to completion of the Merger, the directors were compensated pursuant
to the terms of the Compensation Plan for Directors adopted during 1990 (the
"Plan"), which applied equally to non-employee directors and directors who
were also employees of the Company. The Plan provided a quarterly director's
fee of $3,000, half in cash and half in Common Stock (at the average market
price for the quarter), plus the one time grant to each director of a warrant
to purchase up to 100,000 shares of Common Stock, at an exercise price equal
to the greater of $3.00 per share or the closing trade price on the date of
the grant. Pursuant to the Merger, each of the outstanding warrants
(irrespective of whether or not such warrant was currently exercisable) was
canceled in exchange for either (i) the cash payment of the "in-the-money"
position of the warrant or (ii) equity positions with the Company following
the Merger.
Pursuant to the Plan, the cash portion of the director's compensation was
paid monthly in the month earned. The stock portion of the director's
compensation was paid quarterly, at the beginning of the quarter immediately
following the quarter in which the compensation was earned. The Plan was
amended on September 27, 1995 to provide that, effective July 1, 1995, all of
the compensation was to be paid in cash. During 1995, each director, except
for Mr. Henderson, was paid $9,000 in cash and 703 shares of Common Stock
under the Plan. Mr. Henderson was paid $8,000 in cash and 261 shares of Common
Stock under the Plan. Additionally, Messrs. Earl Ellis, David Keener and
Worthy Warnack received $20,000, $15,000 and $15,000, respectively, for their
service on the Board of Directors' Special Committee which was formed in April
1995.
EMPLOYMENT AGREEMENTS
Messrs. Douglas H. Miller, Jarl P. Johnson, Grant W. Henderson, Randell A.
Bodenhamer, J. William Freeman and J.W. Spencer, III, have entered into
employment agreements (the "Employment Agreements") with the Company which
became effective on February 16, 1996. The Employment Agreements are for a
period of five years from February 16, 1996 (three years in the case of
Messrs. Johnson and Spencer) and provide for the payment of base salaries,
together with other benefits generally available to employees of the Company,
and positions with the Company as set forth below:
69
<PAGE>
<TABLE>
<CAPTION>
NAME POSITION WITH THE COMPANY ANNUAL BASE SALARY
---- ------------------------- ------------------
<C> <S> <C>
Randell A. Bodenhamer.. Vice President--Land $145,000
J. William Freeman..... Vice President--Engineering $170,000
Grant W. Henderson..... President and Chief Financial Officer $225,000
Jarl P. Johnson........ Vice Chairman of the Board and Chief $250,000
Operating Officer
Douglas H. Miller...... Chairman of the Board and Chief Executive $350,000
Officer
J.W. Spencer, III...... Vice President--Operations $170,000
</TABLE>
Each of these persons would receive his salary for the remaining term of his
Employment Agreement if the Company were to terminate his Employment Agreement
other than for cause. The Employment Agreements provide that the employees
agree not to compete with the Company for a period of six months after their
voluntary termination or termination for cause; in the case of Mr. Miller, the
covenant not to compete is for a period of two years, except that the
noncompetition period is one year in the event of incapacity, involuntary
termination other than for cause or his resignation due to a breach by the
Company of Mr. Miller's Employment Agreement.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
The Board of Directors had a Compensation Committee consisting of Walter
Hailey and Frank Horlock. This committee did not meet in 1995.
CERTAIN TRANSACTIONS
CERTAIN INDEBTEDNESS
In connection with the acquisition of Taurus, Mr. Lohman made a loan to the
Company for the sum of $1.0 million in exchange for a subordinated promissory
note from the Company having a term of three years, payable in three equal
annual installments of principal plus accrued interest calculated at the rate
of 7% per annum. Such amount represented the highest outstanding balance owed
by the Company to Mr. Lohman in 1995. On December 31, 1995, the principal
balance remaining on the promissory note was $666,667. On February 16, 1996,
the Company repaid Mr. Lohman the aggregate amount of principal and interest
owed by the Company to Mr. Lohman.
Douglas H. Miller, Chairman of the Board and Chief Executive Officer of the
Company, was indebted to the Company in an aggregate amount of $83,589 as of
June 30, 1995. Such amount represented the highest outstanding balance owed by
Mr. Miller to the Company in 1995. The indebtedness consisted of three
promissory notes, dated as of May 31, 1992, October 1, 1994, and May 31, 1995,
in the original principal amounts of $19,022, $19,250 and $69,526,
respectively. The October 1, 1994 note bore interest at 3.75%, and the
remaining two notes bore interest at the prime rate charged by NationsBank
plus one percent. Except for the promissory note in the original principal
amount of $19,250, the proceeds from which were used to purchase Common Stock
under the Company's 1994 Employee Stock Purchase Plan, all indebtedness
represented Mr. Miller's miscellaneous personal expenses. On February 20,
1996, Mr. Miller repaid the Company an aggregate amount of $90,105
representing all indebtedness owed by Mr. Miller to the Company.
In May 1995, Jarl P. Johnson, Vice Chairman of the Board and President of
Diamond, repaid Diamond the sum of $236,194, representing full payment of
indebtedness evidenced by a promissory note, payable on demand, bearing
interest at the rate of 10% per annum. Such amount represented the highest
outstanding balance owed by Mr. Johnson to the Company in 1995. The
indebtedness was
70
<PAGE>
secured by a pledge of certain shares of Common Stock owned by Mr. Johnson.
The indebtedness arose in June 1990, prior to the Company's acquisition of
Diamond, when Mr. Johnson and certain other Diamond shareholders obtained
certain properties of Diamond Energy Operating Company in exchange for notes.
The properties were then contributed to Diamond A Inc. in exchange for shares
of Diamond A Inc., which shares were in turn pledged to secure the notes.
SUBSCRIPTION AGREEMENT
CAI entered into a Subscription Agreement dated as of October 30, 1995, as
amended by Amendment No. 1 to Subscription Agreement dated as of January 10,
1996, with members of the Management Group (as amended, the "Subscription
Agreement") which provided for the acquisition by such persons of CAI common
stock and the grant to them of nonqualified stock options to purchase shares
of post-Merger common stock (the "Replacement Options") of Coda. Under the
Subscription Agreement, each member of the Management Group who acquired CAI
common stock paid $100 per share for shares thereof, which is the same price
per share paid by JEDI for the remaining shares of CAI common stock. Under the
Subscription Agreement, the Management Group acquired CAI common stock
immediately prior to the effective time of the Merger in exchange for varying
combinations of (i) proceeds from limited recourse promissory notes payable to
CAI in the aggregate principal amount of $937,300 (the "Promissory Notes"),
(ii) Common Stock, which was valued for this purpose at $7.75 per share, and
(iii) cash. The CAI common stock so acquired was not registered under the
Securities Act or any state securities laws and does not have the benefit of
any registration rights, but is subject to the Stockholders Agreement
described below. See "--Stockholders Agreement." By virtue of the Merger, each
share of CAI common stock was converted into one share of Coda common stock.
The Subscription Agreement provided that the Specified Options (representing
certain options to purchase Common Stock held by certain members of the
Management Group) and Specified Warrants (representing certain warrants to
purchase Common Stock held by certain members of the Management Group) would
not be exercised prior to the effective time of the Merger and would, as of
the effective time, be canceled without exercise and without payment of
consideration. Concurrently, the Management Group entered into Nonstatutory
Stock Option Agreements governing the Replacement Options that provided for
the right for a period of 10 years from and after the effective time of the
Merger to purchase shares of post-Merger Coda common stock for $0.01 per
share. However, the Replacement Options may only be exercised while the holder
remains an employee of the Company and for a limited period of time
thereafter. The number of shares of Coda common stock underlying the
Replacement Options each member of the Management Group received is based on
the amount of cash the holder would have received if his Specified Options or
Specified Warrants had been converted into cash in the Merger on the same
basis as other outstanding options and warrants to purchase Common Stock were
converted, divided by the $100 per share purchase price paid by JEDI and the
other Management Group members for their shares of CAI common stock. Thus, if
the Replacement Options are exercised, the holders will have effectively paid
the same purchase price per share as JEDI and the Management Group paid for
their shares of common stock of Coda.
The Promissory Notes will be due on February 16, 2001, bear interest at the
mid-term applicable federal rate (annual compounding) for the month February
1996 (5.61%), are secured by the Company common stock purchased with the
proceeds thereof and certain rights of the maker under the Stockholders
Agreement described below, and provide that in no event will an individual
maker's liability thereunder for any deficiency on his respective Promissory
Note (after the sale and disposition of all collateral securing same) exceed
35% of the original principal balance of the Promissory Note.
71
<PAGE>
STOCKHOLDERS AGREEMENT
CAI, JEDI and the Management Group entered into a Stockholders Agreement
dated as of October 30, 1995, as amended by Amendment No. 1 to Stockholders
Agreement dated as of January 10, 1996 (as amended, the "Stockholders
Agreement"), which provides generally that all parties, including JEDI and the
Management Group, (i) have rights of first refusal to acquire additional shares
of common stock of Coda that may be issued by Coda and (ii) are restricted from
transferring their Coda common stock. Coda has a right to match any third party
offer to purchase shares of Coda common stock from any stockholder, and, in the
event that Coda does not purchase those shares, the other stockholders may have
a right to include a pro rata portion of their Coda common stock in the
transaction. The Stockholders Agreement provides that, if the employment of a
member of the Management Group terminates for any reason (including death or
disability) other than his voluntary termination (except upon retirement at age
65 or older or the expiration of the term of any employment agreement he has
with Coda) or his termination by Coda for cause, then Coda shall have a right
to purchase such member's shares of Coda common stock at a purchase price to be
determined from time to time by Coda pursuant to a formula that values the
shares on the basis of a comparison of the discretionary cash flow and EBITDA
(as defined therein) of the Company and a group of peer companies. The
Stockholders Agreement also provides that, if the employment of a member of the
Management Group terminates for any reason other than voluntary termination or
termination of such member for cause, then such member shall have the right to
require Coda to purchase such member's shares of Coda common stock based on the
previously described formula. The purchase price under the formula will vary
depending on the financial performance of the Company and the group of peer
companies. The Stockholders Agreement provides that each member of the
Management Group shall have the right (the "Special Management Rights") to
receive from JEDI, upon the occurrence of certain events (generally an initial
public offering, a business combination with another person or the liquidation
of Coda) (each, a "Trigger Event"), an amount, which is payable in cash or
additional shares of Coda common stock depending upon the cause of the Trigger
Event, designed to result in the Management Group receiving in connection with
the Trigger Event one-third of the proceeds, attributable to the shares of Coda
common stock purchased by JEDI, above the amount of proceeds necessary for JEDI
to achieve an internal annual rate of return on that investment of 15%. The
individual member's interest in such Special Management Rights is proportional
to such member's ownership of the fully diluted common stock of Coda. The
Stockholders Agreement also provides that if the employment of a member of the
Management Group terminates, his Special Management Rights shall terminate and,
if the termination is other than a voluntary termination or a termination for
cause, he may be entitled to receive an amount based on the discretionary cash
flow and EBITDA formula discussed above. The Stockholders Agreement further
provides that, after the effective time of the Merger, Coda will establish an
employee benefit plan for the benefit of its employees who are not members of
the Management Group and will contribute to the plan 1,900 shares of Coda
common stock. Furthermore, pursuant to the Stockholders Agreement, 4% of the
Special Management Rights will be allocated thereto.
The Stockholders Agreement will terminate and no party thereto will have any
further obligations or rights thereunder upon the earliest to occur of (i) the
termination of the Merger Agreement in accordance with its terms, (ii) October
30, 2005, (iii) the date on which an initial public offering of Coda common
stock or any business transaction involving Coda whereby Coda common stock
becomes a publicly traded security is consummated, (iv) the date of the
dissolution, liquidation or winding-up of Coda and (v) the date of the delivery
to Coda of a written termination notice executed by certain parties to the
Stockholders Agreement.
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ENRON
Enron is the parent of ECT and accordingly may be deemed to control
indirectly both JEDI and the Company. Enron and certain of its subsidiaries and
other affiliates collectively participate in nearly all phases of the oil and
natural gas industry and are, therefore, competitors of the Company. In
addition, ECT and JEDI have provided, and may in the future provide, and ECT
Securities Corp. has assisted, and may in the future assist, in arranging,
financing to non-affiliated participants in the oil and natural gas industry
who are or may become competitors of the Company. Because of these various
conflicting interests, ECT, the Company, JEDI and the Management Group have
entered into the Business Opportunity Agreement which is intended to make it
clear that Enron and its affiliates have no duty to make business opportunities
available to the Company in most circumstances. The Business Opportunity
Agreement also provides that ECT and its affiliates may pursue certain business
opportunities to the exclusion of the Company. The Business Opportunity
Agreement may limit the business opportunities available to the Company. In
addition, pursuant to the Business Opportunity Agreement there may be
circumstances in which the Company will offer business opportunities to certain
affiliates of Enron. If an Enron affiliate is offered such an opportunity and
decides to pursue it, the Company may be unable to pursue it. See "Offer and
Resale" for a discussion of ECT Securities, Inc.'s involvement in the Offering.
During the fiscal year ended December 31, 1995, EOTT made payments to the
Company aggregating approximately $17.7 million for oil purchases. See
"Business--Marketing." Furthermore, during the fiscal year ended December 31,
1995, Enron Industrial Natural Gas Company, an indirect subsidiary of Enron and
an affiliate of JEDI, made payments aggregating approximately $1.8 million for
purchases of natural gas from Taurus.
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DESCRIPTION OF EXCHANGE NOTES
GENERAL
The Exchange Notes will be issued pursuant to an Indenture (the "Indenture")
among the Company, the initial Guarantors and Texas Commerce Bank National
Association, as trustee (the "Trustee"). The Exchange Notes will evidence the
same indebtedness as the Private Notes (which they replace) and will be issued
under, and be entitled to the benefits of, the Indenture. The form and terms
of the Exchange Notes are the same as the form and terms of the Private Notes
except that (i) the Exchange Notes will bear the Series B designation, (ii)
the Exchange Notes will have been registered under the Securities Act and,
therefore, the Exchange Notes will not bear legends restricting the transfer
thereof and (iii) holders of the Exchange Notes will not be entitled to
certain rights of holders of the Private Notes under the Registration Rights
Agreement, which rights will terminate upon consummation of the Exchange
Offer. The terms of the Notes include those stated in the Indenture and those
made part of the Indenture by reference to the Trust Indenture Act of 1939
(the "Trust Indenture Act"). The Notes are subject to all such terms, and
Holders of Notes are referred to the Indenture and the Trust Indenture Act for
a statement thereof. The following summary of certain provisions of the
Indenture does not purport to be complete and is qualified in its entirety by
reference to the Indenture, including the definitions therein of certain terms
used below. The definitions of certain terms used in the following summary are
set forth below under "--Certain Definitions."
The Notes will be general unsecured obligations of the Company and will be
subordinated in right of payment to Senior Debt. See "Risk Factors--
Subordination." The Notes will be guaranteed on a senior subordinated basis by
all of the Company's current Subsidiaries and future Restricted Subsidiaries.
The obligation of the Restricted Subsidiaries under such guarantees will be
general unsecured obligations of such Restricted Subsidiaries and will be
subordinated in right of payment to all obligations of such Restricted
Subsidiaries in respect of Senior Debt. See "--Subsidiary Guarantees" and
"Risk Factors--Subordination."
While Coda itself owns and operates a significant portion of the Company's
consolidated assets, Coda currently depends to a large degree on cash flow
generated by Diamond, and to a lesser degree on cash flow generated by Taurus.
Electra does not currently hold or operate any assets. All of Coda's current
subsidiaries are guarantors of the Notes and are not obligors on any
indebtedness for borrowed money (excluding intercompany indebtedness and as
guarantors under the Credit Agreement). There are no contractual restrictions
on the ability to pay dividends or make any other distributions of funds by
the Guarantors to Coda. The corporation laws of each of the states under which
the Guarantors are chartered contain certain restrictions on the ability of
corporations to pay dividends or make other distributions to holders of such
corporation's capital stock.
As of the date of the Indenture, all of the Company's Subsidiaries will be
Restricted Subsidiaries. However, under certain circumstances, the Company
will be able to designate current or future Subsidiaries as Unrestricted
Subsidiaries. Unrestricted Subsidiaries will not be subject to many of the
restrictive covenants set forth in the Indenture.
For purposes of this section, the term "Company" means Coda Energy, Inc. and
the term "Taurus" has the meaning given under the caption "--Certain
Definitions."
SUBORDINATION
The payment of principal of, premium, if any, and interest and Liquidated
Damages, if any, on the Notes and any other payment obligations of the Company
in respect of the Notes (including any obligation to repurchase the Notes)
will be subordinated in certain circumstances in right of payment, as set
forth in the Indenture, to the prior payment in full of all Senior Debt,
whether outstanding on the date of the Indenture or thereafter incurred.
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Upon any distribution to creditors of the Company in a liquidation or
dissolution of the Company or in a bankruptcy, reorganization, insolvency,
receivership or similar proceeding relating to the Company or its property, or
in an assignment for the benefit of creditors or any marshalling of the
Company's assets and liabilities, the holders of Senior Debt will be entitled
to receive payment in full of all Obligations due in respect of such Senior
Debt (including interest after the commencement of any such proceeding at the
rate specified in the applicable Senior Debt) before the Holders of Notes will
be entitled to receive any payment with respect to the Notes, and until all
Obligations with respect to Senior Debt are paid in full, any distribution to
which the Holders of Notes would be entitled shall be made to the holders of
Senior Debt (except that Holders of Notes may receive securities that are
subordinated at least to the same extent as the Notes to Senior Debt and any
securities issued in exchange for Senior Debt (provided that receipt of such
securities will not cause the Notes to be treated in any case or proceeding or
similar event described in this paragraph in the same class of claims as
Senior Debt or any class of claims pari passu with Senior Debt for any payment
or distribution) and payments made from the trust described under "--Legal
Defeasance and Covenant Defeasance").
The Company also may not make any payment upon or in respect of the Notes
(except in such subordinated securities or from the trust described under "--
Legal Defeasance and Covenant Defeasance") if (i) a default in the payment of
the principal of, premium, if any, or interest on Designated Senior Debt
occurs and is continuing beyond any applicable period of grace or (ii) any
other default occurs and is continuing with respect to Designated Senior Debt
that permits, or with the giving of notice or passage of time or both (unless
cured or waived) will permit, holders of the Designated Senior Debt as to
which such default relates to accelerate its maturity and the Trustee receives
a notice of such default (a "Payment Blockage Notice") from the Company or the
holders of any Designated Senior Debt. Payments on the Notes shall be resumed
(a) in the case of a payment default, upon the date on which such default is
cured or waived and (b) in case of a nonpayment default, the earlier of the
date on which such nonpayment default is cured or waived or 179 days after the
date on which the applicable Payment Blockage Notice is received, unless the
maturity of any Designated Senior Debt has been accelerated. No new period of
payment blockage may be commenced unless and until (i) 360 days have elapsed
since the date of commencement of the payment blockage period resulting from
the immediately prior Payment Blockage Notice and (ii) all scheduled payments
of principal, premium, if any, and interest on the Notes that have come due
have been paid in full in cash. No nonpayment default that existed or was
continuing on the date of delivery of any Payment Blockage Notice to the
Trustee shall be, or be made, the basis for a subsequent Payment Blockage
Notice.
The Indenture will further require that the Company promptly notify holders
of Senior Debt if payment of the Notes is accelerated because of an Event of
Default.
As a result of the subordination provisions described above, in the event of
a liquidation or insolvency of the Company, Holders of Notes may recover less
ratably than creditors of the Company who are holders of Senior Debt. On a pro
forma basis, after giving effect to the Merger and the sale of the Private
Notes and the application of the proceeds therefrom, the principal amount of
Senior Debt outstanding at December 31, 1995 would have been approximately
$86.9 million, which includes $85.3 million of borrowings under the Credit
Agreement. See "Description of Other Debt." The Indenture will limit, subject
to certain financial tests, the amount of additional Indebtedness, including
Senior Debt, that the Company and its Restricted Subsidiaries can incur. See
"--Certain Covenants--Incurrence of Indebtedness and Issuance of Preferred
Stock."
SUBSIDIARY GUARANTEES
The Company's payment obligations under the Notes will be jointly and
severally and unconditionally guaranteed (the "Subsidiary Guarantees") by the
Guarantors. The Subsidiary
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Guarantee of each Guarantor will be subordinated (to the same extent and in the
same manner as the Notes are subordinated to the Senior Debt) to the prior
payment in full of all Senior Debt of such Guarantor, which, on a pro forma
basis, after giving effect to the Merger and the sale of the Private Notes and
the application of proceeds therefrom, would have been approximately $86.9
million as of December 31, 1995. The obligations of each Guarantor under its
Subsidiary Guarantee will be limited so as not to constitute a fraudulent
conveyance under applicable law. See, however, "Risk Factors--Fraudulent
Conveyances."
The Indenture will provide that no Guarantor may consolidate with or merge
with or into (whether or not such Guarantor is the surviving Person), another
corporation, Person or entity whether or not affiliated with such Guarantor
unless (i) subject to the provisions of the following paragraph, the Person
formed by or surviving any such consolidation or merger (if other than such
Guarantor) assumes all the obligations of such Guarantor, pursuant to a
supplemental indenture in form and substance reasonably satisfactory to the
Trustee in respect of the Notes, the Indenture and such Guarantor's Subsidiary
Guarantee; (ii) immediately after giving effect to such transaction, no Default
or Event of Default exists; and (iii) such transaction does not violate any of
the covenants described under the heading "--Certain Covenants."
The Indenture will provide that in the event of a sale or other disposition
of all or substantially all of the assets of any Guarantor to a third party or
an Unrestricted Subsidiary in a transaction that does not violate any of the
covenants in the Indenture, by way of merger, consolidation or otherwise, or a
sale or other disposition of all of the capital stock of any Guarantor, then
such Guarantor (in the event of a sale or other disposition, by way of such a
merger, consolidation or otherwise, of all of the capital stock of such
Guarantor) or the corporation acquiring the property (in the event of a sale or
other disposition of all of the assets of such Guarantor) will be released from
and relieved of any obligations under its Subsidiary Guarantee; provided that
the Net Proceeds of such sale or other disposition are applied in accordance
with the covenant described under the caption "--Repurchase at the Option of
Holders--Asset Sales."
Any Guarantor that is designated an Unrestricted Subsidiary in accordance
with the terms of the Indenture shall be released from and relieved of its
obligations under its Subsidiary Guarantee and any Unrestricted Subsidiary that
ceases to be an Unrestricted Subsidiary will be required to execute a
Subsidiary Guarantee in accordance with the terms of the Indenture.
PRINCIPAL, MATURITY AND INTEREST
The Notes will be limited in aggregate principal amount to $110.0 million and
will mature on April 1, 2006. Interest on the Notes will accrue at the rate of
10 1/2% per annum and will be payable semiannually in arrears on April 1 and
October 1, commencing on October 1, 1996, to Holders of record on the
immediately preceding March 15 and September 15. Interest on the Notes will
accrue from the most recent date on which interest has been paid or, if no
interest has been paid, from the date of original issuance of the Exchange
Notes, plus an amount equal to the accrued interest on the Private Notes from
the date of initial delivery to the date of exchange thereof for the Exchange
Notes. Interest will be computed on the basis of a 360-day year comprised of
twelve 30-day months. Principal, premium, if any, interest and Liquidated
Damages, if any, on the Notes will be payable at the office or agency of the
Company maintained for such purpose within the City and State of New York or,
at the option of the Company, payment of interest and Liquidated Damages, if
any, may be made by check mailed to the Holders of the Notes at their
respective addresses set forth in the register of Holders of Notes; provided
that all payments with respect to Notes having an aggregate principal amount of
$5.0 million or more the Holders of which have given wire transfer instructions
to the Company at least ten business days prior to the applicable payment date
will be required to be made by wire transfer of immediately available funds to
the accounts specified by the Holders thereof. Until otherwise designated by
the Company, the Company's office or agency in New York will be the office of
the
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Trustee maintained for such purpose. The Exchange Notes will be issued in
registered form, without coupons, and in denominations of $1,000 and integral
multiples of $1,000 in excess thereof.
OPTIONAL REDEMPTION
The Notes will not be redeemable at the Company's option prior to April 1,
2001, except as provided below. Thereafter, the Notes will be subject to
redemption at the option of the Company, in whole or in part, upon not less
than 30 nor more than 60 days' notice, at the redemption prices (expressed as
percentages of principal amount) set forth below plus accrued and unpaid
interest and Liquidated Damages, if any, thereon to the applicable redemption
date, if redeemed during the twelve-month period beginning on April 1 of the
years indicated below:
<TABLE>
<CAPTION>
YEAR PERCENTAGE
---- ----------
<S> <C>
2001........................................................... 105.25%
2002........................................................... 102.625%
2003 and thereafter............................................ 100%
</TABLE>
Notwithstanding the foregoing, before March 12, 1999, the Company may, on any
one or more occasions, redeem up to $27.5 million in aggregate principal amount
of Notes at a redemption price of 110.5% of the principal amount thereof plus
accrued and unpaid interest and Liquidated Damages, if any, thereon to the
redemption date, with the net proceeds of an offering of common equity of the
Company; provided that at least $82.5 million in aggregate principal amount of
Notes must remain outstanding immediately after the occurrence of such
redemption; and provided, further, that any such redemption shall occur within
75 days of the date of the closing of such offering of common equity of the
Company.
SELECTION AND NOTICE
If less than all of the Notes are to be redeemed at any time, selection of
Notes for redemption will be made by the Trustee in compliance with the
requirements of the principal national securities exchange, if any, on which
the Notes are listed, or, if the Notes are not so listed, on a pro rata basis,
by lot or by such method as the Trustee shall deem fair and appropriate;
provided that no Notes of $1,000 or less shall be redeemed in part. Notices 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. A new Note in principal amount equal to the
unredeemed portion thereof will be issued in the name of the Holder thereof
upon cancellation of the original Note. On and after the redemption date,
interest ceases to accrue on Notes or portions of them called for redemption.
MANDATORY REDEMPTION
Except as set forth below under "--Repurchase at the Option of Holders," the
Company is not required to make mandatory redemption or sinking fund payments
with respect to the Notes.
REPURCHASE AT THE OPTION OF HOLDERS
Change of Control
Upon the occurrence of a Change of Control (as defined below under "--Certain
Definitions"), each Holder of Notes will have the right to require the Company
to repurchase all or any part (equal to $1,000 or an integral multiple thereof)
of such Holder's Notes pursuant to the offer described below (the "Change of
Control Offer") at an offer price in cash equal to 101% of the aggregate
principal amount thereof plus accrued and unpaid interest and Liquidated
Damages, if any, thereon to the date
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of purchase (the "Change of Control Payment"). Within 30 days following any
Change of Control, the Company will mail a notice to each Holder describing the
transaction or transactions that constitute the Change of Control and offering
to repurchase Notes pursuant to the procedures required by the Indenture and
described in such notice. The Company will comply with the requirements of Rule
14e-1 under the Exchange Act and any other securities laws and regulations
thereunder to the extent such laws and regulations are applicable in connection
with the repurchase of the Notes as a result of a Change of Control.
On the Change of Control Payment Date, the Company will, to the extent
lawful, (i) accept for payment all Notes or portions thereof properly tendered
pursuant to the Change of Control Offer, (ii) deposit with the Paying Agent an
amount equal to the Change of Control Payment in respect of all Notes or
portions thereof so tendered and (iii) deliver or cause to be delivered to the
Trustee the Notes so accepted together with an Officers' Certificate stating
the aggregate principal amount of Notes or portions thereof being purchased by
the Company. The Paying Agent will promptly mail to each Holder of Notes so
tendered the Change of Control Payment for such Notes, and the Trustee will
promptly authenticate and mail (or cause to be transferred by book entry) to
each Holder a new Note equal in principal amount to any unpurchased portion of
the Notes surrendered, if any; provided that each such new Note will be in a
principal amount of $1,000 or an integral multiple thereof. The Indenture will
provide that, prior to complying with the provisions of this covenant, but in
any event within 90 days following a Change of Control, the Company will either
repay all outstanding Senior Debt or obtain the requisite consents, if any,
under all agreements governing outstanding Senior Debt to permit the repurchase
of Notes required by this covenant. The degree to which the Company is
leveraged upon a Change of Control could prevent it from repaying outstanding
Senior Debt (or obtaining the consent of the senior lenders to a repurchase of
Notes) and from repurchasing Exchange Notes tendered to it upon such Change of
Control. The Company will publicly announce the results of the Change of
Control Offer on or as soon as practicable after the Change of Control Payment
Date.
Holders of not less than a majority in aggregate principal amount of Notes
then outstanding may waive these Change of Control repurchase requirements. The
Change of Control provisions described above will be applicable whether or not
any other provisions of the Indenture are applicable. Except as described above
with respect to a Change of Control, the Indenture does not contain provisions
that permit the Holders of the Notes to require that the Company repurchase or
redeem the Notes in the event of a takeover, recapitalization or similar
transaction.
The Company will not be required to make a Change of Control Offer upon a
Change of Control if a third party makes the Change of Control Offer in the
manner, at the times and otherwise in compliance with the requirements set
forth in the Indenture applicable to a Change of Control Offer made by the
Company and purchases all Notes validly tendered and not withdrawn under such
Change of Control Offer.
The definition of Change of Control encompasses a transaction which is
approved by the Company's Board of Directors. The definition also includes a
phrase relating to the sale, lease, transfer, conveyance or other disposition
of "all or substantially all" of the assets of the Company and its Subsidiaries
taken as a whole. Although there is a developing body of case law interpreting
the phrase "substantially all," there is no precise established definition of
the phrase under applicable law. Accordingly, the ability of a Holder of Notes
to require the Company to repurchase such Notes as a result of a sale, lease,
transfer, conveyance or other disposition of less than all of the assets of the
Company and its Subsidiaries taken as a whole to another Person or group may be
uncertain.
The Credit Agreement currently prohibits the Company from purchasing any
Notes, and also provides that certain change of control events with respect to
the Company would constitute a default thereunder. Any future credit agreements
or other agreements relating to Senior Indebtedness to which the Company
becomes a party may contain similar restrictions and provisions. In the event a
Change
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of Control occurs at a time when the Company is prohibited from purchasing
Notes, the Company could seek the consent of its lenders to the purchase of
Notes or could attempt to refinance the borrowings that contain such
prohibition. If the Company does not obtain such a consent or repay such
borrowings, the Company will remain prohibited from purchasing Notes. In such
case, the Company's failure to purchase tendered Notes would constitute an
Event of Default under the Indenture. In such circumstances, the subordination
provisions in the Indenture would likely restrict payments to the Holders of
Notes by either Coda or the Guarantors.
The existence of a Holder's right to require the Company to repurchase such
Holder's Notes upon the occurrence of a Change of Control may deter a third
party from seeking to acquire the Company in a transaction that would
constitute a Change of Control.
Asset Sales
The Indenture will provide that the Company will not, and will not permit any
of its Restricted Subsidiaries to, engage in an Asset Sale unless (i) the
Company (or the Restricted Subsidiary, as the case may be) receives
consideration at the time of such Asset Sale at least equal to the fair market
value (as determined by a resolution of the Board of Directors set forth in an
Officers' Certificate delivered to the Trustee, which determination shall be
conclusive evidence of compliance with this provision) of the assets or Equity
Interests issued or sold or otherwise disposed of and (ii) at least 85% of the
consideration therefor received by the Company or such Restricted Subsidiary is
in the form of cash or Cash Equivalents; provided that the amount of (x) any
liabilities (as shown on the Company's or such Restricted Subsidiary's most
recent balance sheet), of the Company or any Restricted Subsidiary (other than
contingent liabilities and liabilities that are by their terms subordinated to
the Notes or any guarantee thereof) that are assumed by the transferee of any
such assets pursuant to a customary novation agreement that releases the
Company or such Restricted Subsidiary from further liability and (y) any Liquid
Securities received by the Company or any such Restricted Subsidiary from such
transferee that are converted by the Company or such Restricted Subsidiary into
cash within 180 days of closing such Asset Sale, shall be deemed to be cash for
purposes of this provision (to the extent of the cash received).
Within 270 days after the receipt of any Net Proceeds from an Asset Sale, the
Company may apply such Net Proceeds, at its option, (a) to reduce Senior Debt,
(b) to acquire a controlling interest in another Oil and Gas Business, to make
a Permitted Business Investment, to make capital expenditures in respect of the
Company's or its Restricted Subsidiaries' Oil and Gas Business, or to purchase
long-term assets that are used or useful in the Oil and Gas Business or (c) in
the case of any Net Proceeds derived from an Asset Sale in respect of Taurus,
to redeem JEDI Preferred Stock. Pending the final application of any such Net
Proceeds, the Company may temporarily reduce Senior Debt that is revolving debt
or otherwise invest such Net Proceeds in any manner that is not prohibited by
the Indenture. Any Net Proceeds from Asset Sales that are not applied or
invested as provided in the first sentence of this paragraph will (after the
expiration of the periods specified in this paragraph) be deemed to constitute
"Excess Proceeds."
When the aggregate amount of Excess Proceeds exceeds $10.0 million, the
Company will be required to make an offer to all Holders of Notes and, to the
extent required by the terms thereof, to all holders or lenders of Pari Passu
Indebtedness (an "Asset Sale Offer") to purchase the maximum principal amount
of Notes and any such Pari Passu Indebtedness to which the Asset Sale Offer
applies that may be purchased out of the Excess Proceeds, at an offer price in
cash in an amount equal to 100% of the principal amount thereof plus accrued
and unpaid interest and Liquidated Damages, if any, thereon to the date of
purchase, in accordance with the procedures set forth in the Indenture or the
agreements governing the Pari Passu Indebtedness, as applicable. To the extent
that the aggregate amount of Notes tendered or Pari Passu Indebtedness tendered
pursuant to an Asset Sale Offer is less than the Excess Proceeds, the Company
may use any remaining Excess Proceeds for
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general corporate purposes. If the aggregate principal amount of Notes
surrendered by Holders thereof and Pari Passu Indebtedness surrendered by
holders or lenders thereof, collectively, exceeds the amount of Excess
Proceeds, the Trustee shall select the Notes and Pari Passu Indebtedness to be
purchased on a pro rata basis, based on the aggregate principal amount (or
accreted value, as applicable) thereof surrendered in such Asset Sale Offer.
Upon completion of such Asset Sale Offer, the amount of Excess Proceeds shall
be reset at zero.
The Credit Agreement may prohibit the Company from purchasing any Notes and
also provides that certain change of control events with respect to the Company
would constitute a default thereunder. Any future credit agreements or other
agreements relating to Senior Debt to which the Company becomes a party may
contain similar restrictions and provisions. In the event a Change of Control
or Asset Sale Offer occurs at a time when the Company is prohibited from
purchasing Notes, the Company could seek the consent of its lenders to the
purchase of or could attempt to refinance the borrowings that contain such
prohibition. If the Company does not obtain such a consent or repay such
borrowings, the Company may remain prohibited from purchasing 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. In such circumstances, the subordination provisions
in the Indenture would likely restrict payments to the Holders of Notes.
CERTAIN COVENANTS
Restricted Payments
The Indenture will provide that the Company will not, and will not permit any
of its Restricted Subsidiaries to, directly or indirectly: (i) declare or pay
any dividend or make any other payment or distribution on account of the
Company's Equity Interests (including, without limitation, any payment in
connection with any merger or consolidation involving the Company) or to the
direct or indirect holders of the Company's Equity Interests in their capacity
as such (other than dividends or distributions payable in Equity Interests
(other than Disqualified Stock) of the Company); (ii) purchase, redeem or
otherwise acquire or retire for value any Equity Interests of the Company or
any direct or indirect parent or other Affiliate of the Company that is not a
Subsidiary of the Company; (iii) make any principal payment on, or purchase,
redeem, defease or otherwise acquire or retire for value any Indebtedness that
is subordinated to the Notes, except at final maturity; or (iv) make any
Restricted Investment (all such payments and other actions set forth in clauses
(i) through (iv) above being collectively referred to as "Restricted
Payments"), unless, at the time of and after giving effect to such Restricted
Payment:
(a) no Default or Event of Default shall have occurred and be continuing
or would occur as a consequence thereof; and
(b) the Company would, at the time of such Restricted Payment and after
giving pro forma effect thereto as if such Restricted Payment had been made
at the beginning of the applicable four-quarter period, have been permitted
to incur at least $1.00 of additional Indebtedness pursuant to the Fixed
Charge Coverage Ratio test set forth in the first paragraph of the covenant
described below under the caption "--Incurrence of Indebtedness and
Issuance of Preferred Stock"; and
(c) such Restricted Payment, together with the aggregate of all other
Restricted Payments made by the Company and its Restricted Subsidiaries
after the date of the Indenture (excluding Restricted Payments permitted by
clauses (2), (3), (5), (6) and (7) of the next succeeding paragraph), is
less than the sum of (i) 50% of the Consolidated Net Income of the Company
for the period (taken as one accounting period) from the beginning of the
first fiscal quarter commencing after the date of the Indenture to the end
of the Company's most recently ended fiscal quarter for which internal
financial statements are available at the time of such Restricted
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Payment (or, if such Consolidated Net Income for such period is a deficit,
less 100% of such deficit), plus (ii) 100% of the aggregate net cash
proceeds received by the Company from the issue or sale since the date of
the Indenture of Equity Interests of the Company (other than the JEDI
Preferred Stock) or of debt securities of the Company that have been
converted into or exchanged for such Equity Interests (other than Equity
Interests (or convertible debt securities) sold to a Subsidiary of the
Company and other than Disqualified Stock or debt securities that have been
converted into Disqualified Stock), plus (iii) to the extent that any
Restricted Investment that was made after the date of the Indenture is sold
for cash or otherwise liquidated or repaid for cash, the lesser of (A) the
net proceeds of such sale, liquidation or repayment and (B) the initial
amount of such Restricted Investment, plus (iv) 50% of any dividends
received by the Company or a Wholly Owned Restricted Subsidiary after the
date of the Indenture from an Unrestricted Subsidiary of the Company.
The foregoing provisions will not prohibit (1) the payment of any dividend
within 60 days after the date of declaration thereof, if at said date of
declaration such payment would have complied with the provisions of the
Indenture; (2) the redemption, repurchase, retirement or other acquisition of
any Equity Interests of the Company in exchange for, or out of the proceeds of,
the substantially concurrent sale (other than to a Subsidiary of the Company)
of other Equity Interests of the Company (other than any Disqualified Stock);
provided that the amount of any such net cash proceeds that are utilized for
any such redemption, repurchase, retirement or other acquisition shall be
excluded from clause (c)(ii) of the preceding paragraph; (3) the defeasance,
redemption or repurchase of subordinated Indebtedness with the net cash
proceeds from an incurrence of Permitted Refinancing Debt or the substantially
concurrent sale (other than to a Subsidiary of the Company) of Equity Interests
of the Company (other than Disqualified Stock); provided that the amount of any
such net cash proceeds that are utilized for any such redemption, repurchase,
retirement or other acquisition shall be excluded from clause (c)(ii) of the
preceding paragraph; (4) the repurchase, redemption or other acquisition or
retirement for value of any Equity Interests of the Company or any Restricted
Subsidiary of the Company held by any of the Company's (or any of its
Subsidiaries') employees pursuant to any management equity subscription
agreement or stock option agreement in effect as of the date of the Indenture;
provided that the aggregate price paid for all such repurchased, redeemed,
acquired or retired Equity Interests shall not exceed $1.5 million in any
twelve-month period (plus the aggregate cash proceeds received by the Company
during such twelve-month period from any issuance of Equity Interests by the
Company to any Principal and to employees of the Company and its Subsidiaries);
and provided further that no Default or Event of Default shall have occurred
and be continuing immediately after such transaction; (5) the redemption of the
JEDI Preferred Stock, at a redemption price equal to the liquidation preference
thereof plus accrued dividends thereon to the date of redemption, in each case
calculated in accordance with the provisions thereof as the same are in effect
on the date of the Indenture, with the net proceeds from the sale of the Equity
Interests in or all or substantially all of the assets of Taurus in accordance
with the covenant described under the caption "--Repurchase at the Option of
Holders--Asset Sales"; (6) repurchases of Equity Interests deemed to occur upon
exercise of stock options if such Equity Interests represent a portion of the
exercise price of such options; (7) the repayment of all amounts due in respect
of the JEDI Debt; and (8) other Restricted Payments in an aggregate amount not
to exceed $5.0 million.
The amount of all Restricted Payments (other than cash) shall be the fair
market value (as determined by a resolution of the Board of Directors set forth
in an Officers' Certificate delivered to the Trustee, which determination shall
be conclusive evidence of compliance with this provision) on the date of the
Restricted Payment of the asset(s) proposed to be transferred by the Company or
the applicable Restricted Subsidiary, as the case may be, pursuant to the
Restricted Payment. Not later than five days after the date of making any
Restricted Payment, the Company shall deliver to the Trustee an Officers'
Certificate stating that such Restricted Payment is permitted and setting forth
the basis upon which the calculations required by the covenant "Restricted
Payments" were computed.
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The Board of Directors may designate any Restricted Subsidiary to be an
Unrestricted Subsidiary if such designation would not cause a Default; provided
that in no event shall the properties currently operated by Diamond be
transferred to or held by an Unrestricted Subsidiary. For purposes of making
such determination, all outstanding Investments by the Company and its
Restricted Subsidiaries (except to the extent repaid in cash) in the Subsidiary
so designated will be deemed to be Restricted Payments at the time of such
designation and will reduce the amount available for Restricted Payments under
clause (c) of the first paragraph of this covenant and/or the applicable
provisions of the second paragraph of this covenant, as appropriate. All such
outstanding Investments will be deemed to constitute Investments in an amount
equal to the greatest of (x) the net book value of such Investments at the time
of such designation, (y) the fair market value of such Investments at the time
of such designation and (z) the original fair market value of such Investments
at the time they were made. Such designation will only be permitted if such
Restricted Payment would be permitted at such time and if such Restricted
Subsidiary otherwise meets the definition of an Unrestricted Subsidiary.
Incurrence of Indebtedness and Issuance of Disqualified Stock
The Indenture will provide that the Company will not, and will not permit any
of its Subsidiaries to, directly or indirectly, create, incur, issue, assume,
guarantee or otherwise become directly or indirectly liable, contingently or
otherwise, with respect to (collectively, "incur") any Indebtedness (including
Acquired Debt) and that the Company will not issue any Disqualified Stock and
will not permit any of its Subsidiaries to issue any shares of preferred stock;
provided, however, that the Company may incur Indebtedness (including Acquired
Debt) or issue shares of Disqualified Stock if:
(i) the Fixed Charge Coverage Ratio for the Company's most recently ended
four full fiscal quarters for which internal financial statements are
available immediately preceding the date on which such additional
Indebtedness is incurred or such Disqualified Stock is issued would have
been at least 2.5 to 1, determined on a pro forma basis as set forth in the
definition of Fixed Charge Coverage Ratio; and
(ii) no Default or Event of Default shall have occurred and be continuing
at the time such additional Indebtedness is incurred or such Disqualified
Stock is issued or would occur as a consequence of the incurrence of the
additional Indebtedness or the issuance of the Disqualified Stock.
Notwithstanding the foregoing, the Indenture will not prohibit any of the
following (collectively, "Permitted Indebtedness"): (a) the Indebtedness
evidenced by the Notes; (b) the incurrence by the Company of Indebtedness
pursuant to Credit Facilities, so long as the aggregate principal amount of all
Indebtedness outstanding under all Credit Facilities does not, at any one time,
exceed the Borrowing Base, provided that if the Company incurs any Indebtedness
pursuant to this clause (b) that would cause the total principal amount of
Indebtedness under this clause (b) to exceed an amount equal to $150.0 million
(less the aggregate amount of all Net Proceeds of Asset Sales including,
without limitation, an Asset Sale involving Taurus, applied to reduce Senior
Debt pursuant to clause (a) of the second paragraph of the covenant described
under the caption "--Repurchase at the Option of Holders--Asset Sales"), the
Fixed Charge Coverage Ratio for the Company's most recently ended four full
fiscal quarters for which internal financial statements are available
immediately preceding the date on which such additional Indebtedness is
incurred would have been at least 2.0 to 1, determined on a pro forma basis as
set forth in the definition of Fixed Charge Coverage Ratio; (c) the guarantee
by the Guarantors of any Indebtedness that is permitted by the Indenture to be
incurred by the Company; (d) Existing Indebtedness; (e) intercompany
Indebtedness between or among the Company and any of its Wholly Owned
Restricted Subsidiaries; provided, however, that (i) if the Company is the
obligor on such Indebtedness, such Indebtedness is expressly subordinate to the
payment in full of all Obligations with respect to the Notes and (ii)(A) any
subsequent issuance or transfer of Equity Interests that results in any such
Indebtedness being held by a Person other than the Company or a Wholly Owned
Restricted Subsidiary and (B) any sale or other transfer of any such
Indebtedness to a
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Person that is not either the Company or a Wholly Owned Restricted Subsidiary
shall be deemed, in each case, to constitute an incurrence of such Indebtedness
by the Company or such Restricted Subsidiary, as the case may be; (f)
Indebtedness in connection with one or more standby letters of credit,
Guarantees, performance bonds or other reimbursement obligations, in each case,
issued in the ordinary course of business and not in connection with the
borrowing of money or the obtaining of advances or credit (other than advances
or credit on open account, includible in current liabilities, for goods and
services in the ordinary course of business and on terms and conditions which
are customary in the Oil and Gas Business, and other than the extension of
credit represented by such letter of credit, Guarantee or performance bond
itself), not to exceed in the aggregate at any given time 5% of Total Assets;
(g) the incurrence by the Company or any of its Restricted Subsidiaries of
Indebtedness in connection with the acquisition of assets or a new Subsidiary;
provided that such Indebtedness was incurred by the prior owner of such assets
or such Subsidiary prior to such acquisition by the Company or one of its
Restricted Subsidiaries and was not incurred in connection with, or in
contemplation of, such acquisition by the Company or one of its Restricted
Subsidiaries; and provided further that (i) the Fixed Charge Coverage Ratio for
the Company's most recently ended four full fiscal quarters for which internal
financial statements are available immediately preceding the date on which such
additional Indebtedness is incurred would have been at least 2.5 to 1,
determined on a pro forma basis as set forth in the definition of Fixed Charge
Coverage Ratio and (ii) no Default or Event of Default shall have occurred and
be continuing at the time such additional Indebtedness is incurred or would
occur as a consequence of the incurrence of such additional Indebtedness; (h)
Indebtedness under Interest Rate Hedging Agreements entered into for the
purpose of limiting interest rate risks, provided that the obligations under
such agreements are related to payment obligations on Indebtedness otherwise
permitted by the terms of this covenant and that the aggregate notional
principal amount of such agreements does not exceed the principal amount of the
Indebtedness to which such agreements relate; (i) Indebtedness under Oil and
Gas Hedging Contracts, provided that such contracts were entered into in the
ordinary course of business for the purpose of limiting risks that arise in the
ordinary course of business of the Company and its Subsidiaries; (j) the
incurrence by the Company of Indebtedness not otherwise permitted to be
incurred pursuant to this paragraph, provided that the aggregate principal
amount (or accreted value, as applicable) of all Indebtedness incurred pursuant
to this clause (j), together with all Permitted Refinancing Debt incurred
pursuant to clause (k) of this paragraph in respect of Indebtedness previously
incurred pursuant to this clause (j), does not exceed $15.0 million at any one
time outstanding; (k) Permitted Refinancing Debt incurred in exchange for, or
the net proceeds of which are used to refinance, extend, renew, replace,
defease or refund, Indebtedness that was permitted by the Indenture to be
incurred (including Indebtedness previously incurred pursuant to this clause
(k)); (l) accounts payable or other obligations of the Company or any
Subsidiary to trade creditors created or assumed by the Company or such
Subsidiary in the ordinary course of business in connection with the obtaining
of goods or services; (m) Indebtedness consisting of obligations in respect of
purchase price adjustments, guarantees or indemnities in connection with the
acquisition or disposition of assets; (n) the incurrence by the Company's
Unrestricted Subsidiaries of Non-Recourse Debt, provided, however, that if any
such Indebtedness ceases to be Non-Recourse Debt of an Unrestricted Subsidiary,
such event shall be deemed to constitute an incurrence of Indebtedness by a
Restricted Subsidiary of the Company; and (o) production imbalances that do
not, at any one time outstanding, exceed two percent of the Total Assets of the
Company.
No Senior Subordinated Debt
The Indenture will provide that (i) the Company will not incur, create,
issue, assume, guarantee or otherwise become liable for any Indebtedness that
is subordinate or junior in right of payment to any Senior Debt and senior in
any respect in right of payment to the Notes and (ii) no Guarantor will
directly or indirectly incur, create, issue, assume, guarantee or otherwise
become liable for any Indebtedness that is subordinate or junior in right of
payment to any Guarantees issued in respect of Senior Debt
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and senior in any respect in right of payment to the Subsidiary Guarantees,
provided, however, that the foregoing limitations will not apply to
distinctions between categories of Indebtedness that exist by reason of any
Liens arising or created in respect of some but not all such Indebtedness.
Liens
The Indenture will provide that the Company will not, and will not permit any
of its Subsidiaries to, create, incur, assume or otherwise cause or suffer to
exist or become effective any Lien securing Indebtedness of any kind (other
than Permitted Liens) upon any of its property or assets, now owned or
hereafter acquired.
Sale and Leaseback Transactions
The Indenture will provide that the Company will not, and will not permit any
of its Restricted Subsidiaries to, enter into any sale and leaseback
transaction; provided that the Company may enter into a sale and leaseback
transaction if (i) the Company could have (a) incurred Indebtedness in an
amount equal to the Attributable Debt relating to such sale and leaseback
transaction pursuant to the test set forth in the first paragraph of the
covenant described above under the caption "--Incurrence of Additional
Indebtedness and Issuance of Disqualified Stock" and (b) incurred a Lien to
secure such Indebtedness pursuant to the covenant described above under the
caption "--Liens," (ii) the gross cash proceeds of such sale and leaseback
transaction are at least equal to the fair market value (as determined in good
faith by a resolution the Board of Directors set forth in an Officers'
Certificate delivered to the Trustee, which determination shall be conclusive
evidence of compliance with this provision) of the property that is the subject
of such sale and leaseback transaction and (iii) the transfer of assets in such
sale and leaseback transaction is permitted by, and the Company applies the net
proceeds of such transaction in compliance with, the covenant described above
under the caption "--Repurchase at the Option of Holders--Asset Sales."
Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries
The Indenture will provide that the Company will not, and will not permit any
of its Restricted Subsidiaries to, directly or indirectly, create or otherwise
cause or suffer to exist or become effective any encumbrance or restriction on
the ability of any Restricted Subsidiary to (i)(x) pay dividends or make any
other distributions to the Company or any of its Restricted Subsidiaries (1) on
its Capital Stock or (2) with respect to any other interest or participation
in, or measured by, its profits, or (y) pay any indebtedness owed to the
Company or any of its Restricted Subsidiaries, (ii) make loans or advances to
the Company or any of its Restricted Subsidiaries or (iii) transfer any of its
properties or assets to the Company or any of its Restricted Subsidiaries,
except for such encumbrances or restrictions existing under or by reason of (a)
the Credit Agreement as in effect as of the date of the Indenture, and any
amendments, modifications, restatements, renewals, increases, supplements,
refundings, replacements or refinancings thereof or any other Credit Facility,
provided that such amendments, modifications, restatements, renewals,
increases, supplements, refundings, replacements, refinancings or other Credit
Facilities are no more restrictive with respect to such dividend and other
payment restrictions than those contained in the Credit Agreement as in effect
on the date of the Indenture, (b) the Indenture and the Notes, (c) applicable
law, (d) any instrument governing Indebtedness or Capital Stock of a Person
acquired by the Company or any of its Restricted Subsidiaries as in effect at
the time of such acquisition (except, in the case of Indebtedness, to the
extent such Indebtedness was incurred in connection with or in contemplation of
such acquisition), which encumbrance or restriction is not applicable to any
Person, or the properties or assets of any Person, other than the Person and
its Subsidiaries, or the property or assets of the Person and its Subsidiaries,
so acquired, provided that, in the case of Indebtedness, such Indebtedness was
permitted by the terms of the Indenture to be incurred, (e) by reason of
customary non-assignment provisions in leases entered into in the ordinary
course of business and consistent with past practices,
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(f) purchase money obligations for property acquired in the ordinary course of
business that impose restrictions of the nature described in clause (iii) above
on the property so acquired, or (g) Permitted Refinancing Debt, provided that
the restrictions contained in the agreements governing such Permitted
Refinancing Debt are no more restrictive than those contained in the agreements
governing the Indebtedness being refinanced.
Merger, Consolidation, or Sale of Assets
The Indenture will provide that the Company may not consolidate or merge with
or into (whether or not the Company is the surviving corporation), or sell,
assign, transfer, lease, convey or otherwise dispose of all or substantially
all of its properties or assets, in one or more related transactions, to
another Person and the Company may not permit any of its Restricted
Subsidiaries to enter into any such transaction or series of transactions if
such transaction or series of transactions would, in the aggregate, result in a
sale, assignment, transfer, lease, conveyance, or other disposition of all or
substantially all of the properties or assets of the Company to another Person
unless (i) the Company is the surviving corporation or the Person formed by or
surviving any such consolidation or merger (if other than the Company) or to
which such sale, assignment, transfer, lease, conveyance or other disposition
shall have been made is a corporation organized or existing under the laws of
the United States, any state thereof or the District of Columbia; (ii) the
Person formed by or surviving any such consolidation or merger (if other than
the Company) or to which such sale, assignment, transfer, lease, conveyance or
other disposition shall have been made assumes all the obligations of the
Company under the Notes and the Indenture pursuant to a supplemental indenture
in a form reasonably satisfactory to the Trustee; (iii) immediately before and
after giving effect to such transaction no Default or Event of Default exists;
and (iv) except in the case of a merger of the Company with or into a Wholly
Owned Subsidiary of the Company, the Company or the Person formed by or
surviving any such consolidation or merger (if other than the Company), or to
which such sale, assignment, transfer, lease, conveyance or other disposition
shall have been made (A) will have Total Assets immediately after the
transaction equal to or greater than the Total Assets of the Company
immediately preceding the transaction and (B) will, at the time of such
transaction and after giving pro forma effect thereto as if such transaction
had occurred at the beginning of the applicable four-quarter period, be
permitted to incur at least $1.00 of additional Indebtedness pursuant to the
test set forth in the first paragraph of the covenant described above under the
caption "--Incurrence of Indebtedness and Issuance of Preferred Stock."
Transactions with Affiliates
The Indenture will provide that the Company will not, and will not permit any
of its Restricted Subsidiaries to, make any payment to, or sell, lease,
transfer or otherwise dispose of any of its properties or assets to, or
purchase any property or assets from, or enter into or make or amend any
contract, agreement, understanding, loan, advance or guarantee with, or for the
benefit of, any of its Affiliates (each of the foregoing, an "Affiliate
Transaction"), unless (i) such Affiliate Transaction is on terms that are no
less favorable to the Company or the relevant Restricted Subsidiary than those
that would have been obtained in a comparable transaction by the Company or
such Restricted Subsidiary with an unrelated Person and (ii) the Company
delivers to the Trustee (a) with respect to any Affiliate Transaction or series
of related Affiliate Transactions involving aggregate consideration in excess
of $1.0 million, a resolution of the Board of Directors set forth in an
Officers' Certificate certifying that such Affiliate Transaction complies with
clause (i) above and that such Affiliate Transaction has been approved by a
majority of the members of the Board of Directors who are disinterested with
respect to such Affiliate Transaction, which resolution shall be conclusive
evidence of compliance with this provision, and (b) with respect to any
Affiliate Transaction or series of related Affiliate Transactions involving
aggregate consideration in excess of $5.0 million, an opinion as to the
fairness to the Holders of such Affiliate Transaction from a financial point of
view issued by an accounting, appraisal, engineering or investment banking firm
of national standing; provided that the following shall not be
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deemed Affiliate Transactions: (1) any sale of hydrocarbons or other mineral
products or the entering into or performance of Oil and Gas Hedging Contracts,
gas gathering, transportation or processing contracts or oil or natural gas
marketing or exchange contracts, in each case, in the ordinary course of
business, so long as the terms of any such transaction are approved by a
majority of the members of the Board of Directors who are disinterested with
respect to such transaction as being the most favorable of at least (x) two
bids, quotes or proposals, at least one of which is from a Person that is not
an Affiliate of the Company (in the event that the Company determines in good
faith that it is able to obtain only two bids, quotes or proposals with respect
to such transaction) or (y) three bids, quotes or proposals, at least two of
which are from Persons that are not Affiliates of the Company (in all other
circumstances), (2) the repayment of all amounts due in respect of the JEDI
Debt, (3) the sale to an Affiliate of the Company of Equity Interests in the
Company that do not constitute Disqualified Stock, (4) transactions
contemplated by any employment agreement or other compensation plan or
arrangement entered into by the Company or any of its Restricted Subsidiaries
in the ordinary course of business and consistent with the past practice of the
Company or such Restricted Subsidiary, including those described in this
Prospectus under the caption "Executive Compensation and Other Information--
Employment Agreements," (5) transactions between or among the Company and/or
its Restricted Subsidiaries, (6) Restricted Payments and Permitted Investments
that are permitted by the provisions of the Indenture described above under the
caption "--Restricted Payments," (7) the transactions described in this
Prospectus under the caption "Certain Transactions" and (8) the payment of
dividends on, or the redemption of, the JEDI Preferred Stock, in either case,
to the extent otherwise permitted by the Indenture.
Additional Subsidiary Guarantees
The Indenture will provide that if the Company or any of its Subsidiaries
shall acquire or create another Subsidiary after the date of the Indenture,
then such newly acquired or created Subsidiary will be required to execute a
Subsidiary Guarantee and deliver an opinion of counsel, in accordance with the
terms of the Indenture, provided that the foregoing requirement shall not apply
to any newly acquired or created Subsidiary that has been properly designated
as an Unrestricted Subsidiary in accordance with the Indenture for so long as
it continues to constitute an Unrestricted Subsidiary.
Business Activities
The Company and the Guarantors will not, and will not permit any Restricted
Subsidiary to, engage in any material respect in any business other than the
Oil and Gas Business.
Reports
Pursuant to Section 15(d) of the Exchange Act, upon effectiveness of the
Registration Statement, the Company and the Guarantors will be required to file
with the Commission reports on Form 10-K, Form 10-Q and Form 8-K for the
remainder of 1996, at a minimum. In addition, the Company and the Guarantors
have covenanted to file with the Commission, to the extent such filings are
accepted by the Commission 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 and the Guarantors would be
required to file if the Company were subject to Section 13 or 15 of the
Exchange Act, in each case on or before the dates on which such reports and
other documents would have been required to have been filed with the Commission
if the Company had been subject to Section 13 or 15 of the Exchange Act
beginning with the Company's fiscal quarter ended March 31, 1996. The Company
will also be required (a) to file with the Trustee (with exhibits), and provide
to each Holder of Notes (without exhibits), 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 Commission or the date on
which the Company would be required to file such reports and documents if the
Company were so required and (b) if filing such reports and documents with the
Commission is not accepted by
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the Commission or is prohibited under the Exchange Act, to supply at the
Company's cost copies of such reports and documents (including any exhibits
thereto) to any Holder of Notes promptly upon written request. In addition, the
Company and the Guarantors have agreed that, for so long as any Notes remain
outstanding, they will furnish to the Holders and to prospective investors,
upon their request, the information required to be delivered pursuant to Rule
144A(d)(4) under the Securities Act.
EVENTS OF DEFAULT AND REMEDIES
The Indenture will provide that each of the following constitutes an Event of
Default: (i) default for 30 days in the payment when due of interest on the
Notes (whether or not prohibited by the subordination provisions of the
Indenture); (ii) default in payment when due of the principal of or premium, if
any, on the Notes (whether or not prohibited by the subordination provisions of
the Indenture); (iii) failure by the Company for 30 days after notice from the
Trustee or the Holders of at least 25% in aggregate principal amount of the
Notes then outstanding to comply with the provisions described under the
captions "--Repurchase at the Option of Holders--Change of Control," "--
Repurchase at the Option of Holders--Asset Sales," "--Certain Covenants--
Restricted Payments," "--Certain Covenants--Incurrence of Indebtedness and
Issuance of Preferred Stock" or "--Certain Covenants--Merger, Consolidation, or
Sale of Assets"; (iv) failure by the Company for 60 days after notice from the
Trustee or the Holders of at least 25% in aggregate principal amount of the
Notes then outstanding to comply with any of its other agreements in the
Indenture or the Notes; (v) except as permitted by the Indenture, any
Subsidiary Guarantee of a Significant Subsidiary shall be held in any judicial
proceeding to be unenforceable or invalid or shall cease for any reason to be
in full force and effect or any Guarantor that is a Significant Subsidiary, or
any Person acting on behalf of any such Guarantor, shall deny or disaffirm its
obligations under its Subsidiary Guarantee; (vi) default under any mortgage,
indenture or instrument under which there may be issued or by which there may
be secured or evidenced any Indebtedness for money borrowed by the Company or
any of its Restricted Subsidiaries (or the payment of which is guaranteed by
the Company or any of its Restricted Subsidiaries) whether such Indebtedness or
Guarantee now exists, or is created after the date of the Indenture, which
default (a) is caused by a failure to pay principal of or premium, if any, or
interest on such Indebtedness prior to the expiration of the grace period
provided in such Indebtedness on the date of such default (a "Payment Default")
or (b) results in the acceleration of such Indebtedness prior to its express
maturity and, in each case, the principal amount of any such Indebtedness,
together with the principal amount of any other such Indebtedness under which
there is then existing a Payment Default or the maturity of which has been so
accelerated, aggregates $10.0 million or more; (vii) failure by the Company or
any of its Restricted Subsidiaries to pay final, non-appealable judgments
aggregating in excess of $5.0 million, which judgments remain unpaid or
undischarged for a period of 60 days; and (viii) certain events of bankruptcy
or insolvency with respect to the Company or any of its Restricted Subsidiaries
that constitute a Significant Subsidiary or any group of Restricted
Subsidiaries that, taken together, would constitute a Significant Subsidiary.
If any Event of Default occurs and is continuing, the Trustee or the Holders
of at least 25% in principal amount of the then outstanding Notes may declare
all the Notes to be due and payable immediately. Notwithstanding the foregoing,
in the case of an Event of Default arising from certain events of bankruptcy or
insolvency, with respect to the Company, any Restricted Subsidiary that
constitutes a Significant Subsidiary or any group of Restricted Subsidiaries
that, taken together, would constitute a Significant Subsidiary, all
outstanding Notes will become due and payable without further action or notice.
Holders of the Notes may not enforce the Indenture or the Notes except as
provided in the Indenture. Subject to certain limitations, Holders of a
majority in principal amount of the then outstanding Notes may direct the
Trustee in its exercise of any trust or power. The Trustee may withhold from
Holders of the Notes notice of any continuing Default or Event of Default
(except a Default or Event of Default relating to the payment of principal or
interest) if it determines that withholding notice is in their interest.
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In the case of any Event of Default occurring by reason of any willful action
(or inaction) taken (or not taken) by or on behalf of the Company with the
intention of avoiding payment of the premium that the Company would have had to
pay if the Company then had elected to redeem the Notes pursuant to the
optional redemption provisions of the Indenture, an equivalent premium shall
also become and be immediately due and payable to the extent permitted by law
upon the acceleration of the Notes. If an Event of Default occurs prior to
April 1, 2001 by reason of any willful action (or inaction) taken (or not
taken) by or on behalf of the Company with the intention of avoiding the
prohibition on redemption of the Notes prior to April 1, 2001, then the premium
specified in the Indenture shall also become immediately due and payable to the
extent permitted by law upon the acceleration of the Notes.
The Holders of a majority in aggregate principal amount of the Notes then
outstanding by notice to the Trustee may on behalf of the Holders of all of the
Notes waive any existing Default or Event of Default and its consequences under
the Indenture except a continuing Default or Event of Default in the payment of
interest, premium or Liquidated Damages, if any, on, or the principal of, the
Notes.
The Company is required to deliver to the Trustee annually a statement
regarding compliance with the Indenture, and the Company is required, within
five business days of becoming aware of any Default or Event of Default, to
deliver to the Trustee a statement specifying such Default or Event of Default.
NO PERSONAL LIABILITY OF DIRECTORS, OFFICERS, EMPLOYEES AND STOCKHOLDERS
No director, officer, employee, incorporator or stockholder of the Company,
as such, shall have any liability for any obligations of the Company under the
Notes or the Indenture or for any claim based on, in respect of, or by reason
of, such obligations or their creation. Each Holder of Notes, by accepting a
Note, waives and releases all such liability. The waiver and release are part
of the consideration for issuance of the Notes. Such waiver may not be
effective to waive liabilities under the federal securities laws and it is the
view of the Commission that such a waiver is against public policy.
LEGAL DEFEASANCE AND COVENANT DEFEASANCE
The Company may, at its option and at any time, elect to have all of its
obligations discharged with respect to the outstanding Notes ("Legal
Defeasance") except for (i) the rights of Holders of outstanding Notes to
receive payments in respect of the principal of, premium, if any, interest and
Liquidated Damages, if any, on such Notes when such payments are due from the
trust referred to below, (ii) the Company's obligations with respect to the
Notes concerning issuing temporary Notes, registration of Notes, mutilated,
destroyed, lost or stolen Notes and the maintenance of an office or agency for
payment and money for security payments held in trust, (iii) the rights,
powers, trusts, duties and immunities of the Trustee, and the Company's
obligations in connection therewith and (iv) the Legal Defeasance provisions of
the Indenture. In addition, the Company may, at its option and at any time,
elect to have the obligations of the Company released with respect to certain
covenants that are described in the Indenture ("Covenant Defeasance") and
thereafter any omission to comply with such obligations shall not constitute a
Default or Event of Default with respect to the Notes. In the event Covenant
Defeasance occurs, certain events (not including non-payment, bankruptcy,
receivership, rehabilitation and insolvency events) described under "Events of
Default" will no longer constitute an Event of Default with respect to the
Notes.
In order to exercise either Legal Defeasance or Covenant Defeasance, (i) the
Company or the Guarantors must irrevocably deposit with the Trustee, in trust,
for the benefit of the Holders of the Notes, cash in U.S. dollars, non-callable
Government Securities, 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, interest and
Liquidated Damages, if any, on the outstanding Notes on the stated maturity or
on the applicable redemption date, as the case may be,
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and the Company or the Guarantors must specify whether the Notes are being
defeased to maturity or to a particular redemption date; (ii) in the case of
Legal Defeasance, the Company or the Guarantors shall have delivered to the
Trustee an opinion of counsel in the United States reasonably acceptable to the
Trustee confirming that (A) the Company or the Guarantors has received from, or
there has been published by, the Internal Revenue Service a ruling or (B) since
the date of the Indenture, there has been a change in the applicable federal
income tax law, in either case to the effect that, and based thereon such
opinion of counsel shall confirm that, the Holders of the outstanding Notes
will not recognize income, gain or loss for federal income tax purposes as a
result of such Legal 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 had not occurred; (iii) in the case of
Covenant Defeasance, the Company or the Guarantors shall have delivered to the
Trustee an opinion of counsel in the United States reasonably acceptable to the
Trustee confirming that the Holders of the outstanding Notes will not recognize
income, gain or loss for federal income tax purposes as a result of such
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 Covenant Defeasance had not occurred; (iv) no Default or Event of
Default shall have occurred and be continuing on the date of such deposit
(other than a Default or Event of Default resulting from the borrowing of funds
to be applied to such deposit) or insofar as Events of Default from bankruptcy
or insolvency events are concerned, at any time in the period ending on the
91st day after the date of deposit; (v) such Legal Defeasance or Covenant
Defeasance will not result in a breach or violation of, or constitute a default
under any material agreement or instrument (other than the Indenture) to which
the Company or any of its Restricted Subsidiaries is a party or by which the
Company or any of its Restricted Subsidiaries is bound; (vi) the Company or the
Guarantors must have delivered to the Trustee an opinion of counsel to the
effect that after the 91st day following the deposit, the trust funds will not
be subject to the effect of any applicable bankruptcy, insolvency,
reorganization or similar laws affecting creditors' rights generally; (vii) the
Company or the Guarantors must deliver to the Trustee an Officers' Certificate
stating that the deposit was not made by the Company or the Guarantors, as
applicable, with the intent of preferring the Holders of Notes over the other
creditors of the Company or the Guarantors, as applicable, with the intent of
defeating, hindering, delaying or defrauding creditors of the Company or the
Guarantors, as applicable, or others; and (viii) the Company must deliver to
the Trustee an Officers' Certificate and an opinion of counsel, each stating
that all conditions precedent provided for relating to the Legal Defeasance or
the Covenant Defeasance have been complied with.
TRANSFER AND EXCHANGE
A Holder may transfer or exchange Notes in accordance with the Indenture. The
Registrar and the Trustee may require a Holder, among other things, to furnish
appropriate endorsements and transfer documents and the Company may require a
Holder to pay any taxes and fees required by law or permitted by the Indenture.
The Company is not required to transfer or exchange any Note selected for
redemption. Also, the Company is not required to transfer or exchange any Note
for a period of 15 days before a selection of Notes to be redeemed.
The registered Holder of a Note will be treated as the owner of it for all
purposes.
AMENDMENT, SUPPLEMENT AND WAIVER
Except as provided in the next two succeeding paragraphs, the Indenture or
the Notes may be amended or supplemented with the consent of the Holders of at
least a majority in principal amount of the Notes then outstanding (including,
without limitation, consents obtained in connection with a purchase of, or
tender offer or exchange offer for, Notes), and any existing default or
compliance with any provision of the Indenture or the Notes may be waived with
the consent of the Holders of a majority in principal amount of the then
outstanding Notes (including consents obtained in connection with a tender
offer or exchange offer for Notes).
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Without the consent of each Holder affected, an amendment or waiver may not
(with respect to any Notes held by a non-consenting Holder): (i) reduce the
principal amount of Notes whose Holders must consent to an amendment,
supplement or waiver, (ii) reduce the principal of or change the fixed maturity
of any Note or alter the provisions with respect to the redemption of the Notes
(other than provisions relating to the covenants described above under the
caption "--Repurchase at the Option of Holders"), (iii) reduce the rate of or
change the time for payment of interest or Liquidated Damages on any Note, (iv)
waive a Default or Event of Default in the payment of principal of or premium,
if any, or interest or Liquidated Damages, if any, on the Notes (except a
rescission of acceleration of the Notes by the Holders of at least a majority
in aggregate principal amount of the Notes and a waiver of the payment default
that resulted from such acceleration), (v) make any Note payable in money other
than that stated in the Notes, (vi) make any change in the provisions of the
Indenture relating to waivers of past Defaults or the rights of Holders of
Notes to receive payments of principal of or premium, if any, or interest or
Liquidated Damages, if any, on the Notes, (vii) waive a redemption payment with
respect to any Note (other than a payment required by one of the covenants
described above under the caption "--Repurchase at the Option of Holders") or
(viii) make any change in the foregoing amendment and waiver provisions.
Without the consent of at least 66 2/3% in aggregate principal amount of the
Notes then outstanding (including consents obtained in connection with a
purchase of, or tender offer or exchange offer for, Notes), no waiver or
amendment to the Indenture may make any change in the provisions described
above under the captions "--Repurchase at the Option of Holders--Change of
Control" and "--Repurchase at the Option of Holders--Assets Sales" that
adversely affect the rights of any Holder of Notes. In addition, any amendment
to the provisions of Article 10 of the Indenture (which relate to
subordination) will require the consent of the Holders of at least 66 2/3% in
aggregate principal amount of the Notes then outstanding if such amendment
would adversely affect the rights of Holders of Notes.
Notwithstanding the foregoing, without the consent of any Holder of Notes,
the Company and the Trustee may amend or supplement the Indenture or the Notes
to cure any ambiguity, defect or inconsistency, to provide for uncertificated
Notes in addition to or in place of certificated Notes, to provide for the
assumption of the Company's obligations to Holders of Notes in the case of a
merger or consolidation, to make any change that would provide any additional
rights or benefits to the Holders of Notes or that does not adversely affect
the legal rights under the Indenture of any such Holder, or to comply with
requirements of the Commission in order to effect or maintain the qualification
of the Indenture under the Trust Indenture Act.
CONCERNING THE TRUSTEE
The Indenture contains certain limitations on the rights of the Trustee,
should it become a creditor of the Company, to obtain payment of claims in
certain cases, or to realize on certain property received in respect of any
such claim as security or otherwise. The Trustee will be permitted to engage in
other transactions; however, if it acquires any conflicting interest it must
eliminate such conflict within 90 days, apply to the Commission for permission
to continue or resign. The Trustee is a lender to the Company under the Credit
Agreement and is an affiliate of Chemical Securities Inc. See "Description of
Other Indebtedness--Credit Agreement" and "Offer and Resale."
The Holders of a majority in principal amount of the then outstanding Notes
will have the right to direct the time, method and place of conducting any
proceeding for exercising any remedy available to the Trustee, subject to
certain exceptions. The Indenture provides that in case an Event of Default
shall occur (which shall not be cured), the Trustee will be required, in the
exercise of its power, to use the degree of care of a prudent man in the
conduct of his own affairs. Subject to such provisions, the Trustee will be
under no obligation to exercise any of its rights or powers under the Indenture
at the request of any Holder of Notes, unless such Holder shall have offered to
the Trustee security and indemnity satisfactory to it against any loss,
liability or expense.
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BOOK-ENTRY, DELIVERY AND FORM
The Notes to be issued as set forth herein will initially be issued in the
form of one or more permanent global certificates in definitive, fully-
registered form ("Global Note"). Each Global Note will be deposited on the date
of the closing of the exchange of the Private Notes for the Exchange Notes
offered hereby (the "Closing Date") with, or on behalf of, DTC and registered
in the name of Cede & Co., as nominee of the Depositary (such nominee being
referred to herein as the "Global Note Holder").
The Depositary is a limited-purpose trust company that was created to hold
securities for its participating organizations (collectively, the
"Participants" or the "Depositary's Participants") and to facilitate the
clearance and settlement of transactions in such securities between
Participants through electronic book-entry changes in accounts of its
Participants. The Depositary's Participants include securities brokers and
dealers (including the Initial Purchasers), banks and trust companies, clearing
corporations and certain other organizations. Access to the Depositary's system
is also available to other entities such as banks, brokers, dealers and trust
companies (collectively, the "Indirect Participants" or the "Depositary's
Indirect Participants") that clear through or maintain a custodial relationship
with a Participant, either directly or indirectly. Persons who are not
Participants may beneficially own securities held by or on behalf of the
Depositary only thorough the Depositary's Participants or the Depositary's
Indirect Participants.
The Company expects that pursuant to procedures established by the Depositary
(i) upon deposit of the Global Note, the Depositary will credit the accounts of
Participants designated by the Initial Purchasers with portions of the
principal amount of the Global Note and (ii) ownership of the Notes evidenced
by the Global Note will be shown on, and the transfer of ownership thereof will
be effected only through, records maintained by the Depositary (with respect to
the interests of the Depositary's Participants), the Depositary's Participants
and the Depositary's Indirect Participants. Prospective purchasers are advised
that the laws of some states require that certain persons take physical
delivery in definitive form of securities that they own. Consequently, the
ability to transfer Notes evidenced by the Global Note will be limited to such
extent.
So long as the Global Note Holder is the registered owner of any Notes, the
Global Note Holder will be considered the sole Holder under the Indenture of
any Notes evidenced by the Global Note. Beneficial owners of Notes evidenced by
the Global Note will not be considered the owners or Holders thereof under the
Indenture for any purpose, including with respect to the giving of any
directions, instructions or approvals to the Trustee thereunder. Neither the
Company nor the Trustee will have any responsibility or liability for any
aspect of the records of the Depositary or for maintaining, supervising or
reviewing any records of the Depositary relating to the Notes.
Payments in respect of the principal of, premium, if any, and interest on any
Notes registered in the name of the Global Note Holder on the applicable record
date will be payable by the Trustee to or at the direction of the Global Note
Holder in its capacity as the registered Holder under the Indenture. Under the
terms of the Indenture, the Company and the Trustee may treat the persons in
whose names Notes, including the Global Note, are registered as the owners
thereof for the purpose of receiving such payments. Consequently, neither the
Company nor the Trustee has or will have any responsibility or liability for
the payment of such amounts to beneficial owners of Notes. The Company
believes, however, that it is currently the policy of the Depositary to
immediately credit the accounts of the relevant Participants with such
payments, in amounts proportionate to their respective holdings of beneficial
interests in the relevant security as shown on the records of the Depositary.
Payments by the Depositary's Participants and the Depositary's Indirect
Participants to the beneficial owners of Notes will be governed by standing
instructions and customary practice and will be the responsibility of the
Depositary's Participants or the Depositary's Indirect Participants.
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DTC has advised the Company that neither DTC nor Cede & Co. will consent or
vote with respect to the Notes. Under its usual procedures, DTC mails an
omnibus proxy to the issuer as soon as possible after the record date. The
omnibus proxy assigns Cede & Co.'s consenting or voting rights to those
Participants to whose accounts the Notes are credited on the record date
(identified in a listing attached to the omnibus proxy).
DTC may discontinue providing its services as securities depository with
respect to the Notes at any time. Neither the Company, the Trustee nor any
registrar or paying agent will have any responsibility for the performance by
DTC or its Participants or Indirect Participants of their respective
obligations under the rules and procedures governing their operations. The
information in this section concerning DTC and DTC's book-entry system has been
obtained from sources that the Company believes to be reliable, but the Company
takes no responsibility for the accuracy thereof.
Certificated Securities
Subject to certain conditions, any person having a beneficial interest in the
Global Note may, upon request to the Trustee, exchange such beneficial interest
for Notes in the form of Certificated Securities. Upon any such issuance, the
Trustee is required to register such Certificated Securities in the name of,
and cause the same to be delivered to, such person or persons (or the nominee
of any thereof). In addition, if (i) the Depositary notifies the Company that
the Depositary is no longer willing or able to act as a depositary and the
Company is unable to locate a qualified successor within 90 days or (ii) the
Company, at its option, notifies the Trustee in writing that it elects to cause
the issuance of Notes in the form of Certificated Securities under the
Indenture, then, upon surrender by the Global Note Holder of its Global Note,
Notes in such form will be issued to each person that the Global Note Holder
and the Depositary identify as being the beneficial owner of the related Notes.
Neither the Company nor the Trustee will be liable for any delay by the
Global Note Holder or the Depositary in identifying the beneficial owners of
Notes and the Company and the Trustee may conclusively rely on, and will be
protected in relying on, instructions from the Global Note Holder or the
Depositary for all purposes.
Same-Day Settlement and Payment
The Indenture will require that payments in respect of the Notes represented
by the Global Note (including principal, premium, if any, and interest) be made
by wire transfer of immediately available funds to the accounts specified by
the Global Note Holder. With respect to Certificated Securities, the Company
will make all payments of principal, premium, if any, and interest, by wire
transfer of immediately available funds to the accounts specified by the
Holders thereof that hold at least $5.0 million in aggregate principal amount
of the Notes or, if no such account is specified or if a Holder holds less than
$5.0 million in aggregate principal amount of the Notes, by mailing a check to
each such Holder's registered address. The Notes represented by the Global Note
are expected to be eligible to trade in the Depositary's Same-Day Funds
Settlement System, and any permitted secondary market trading activity in such
Notes will, therefore, be required by the Depositary to be settled in
immediately available funds.
CERTAIN DEFINITIONS
Set forth below are certain defined terms used in the Indenture. Reference is
made to the Indenture for a full disclosure of all such terms, as well as any
other capitalized terms used herein for which no definition is provided.
"Acquired Debt" means, with respect to any specified Person, (i) Indebtedness
of any other Person existing at the time such other Person is merged with or
into or became a Subsidiary of such
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specified Person, including, without limitation, Indebtedness incurred in
connection with, or in contemplation of, such other Person merging with or into
or becoming a Subsidiary of such specified Person, and (ii) Indebtedness
secured by a Lien encumbering any asset acquired by such specified Person.
"Affiliate" of any specified Person means any other Person directly or
indirectly controlling or controlled by or under direct or indirect common
control with such specified Person. For purposes of this definition, "control"
(including, with correlative meanings, the terms "controlling," "controlled by"
and "under common control with"), as used with respect to any Person, shall
mean the possession, directly or indirectly, of the power to direct or cause
the direction of the management or policies of such Person, whether through the
ownership of voting securities, by agreement or otherwise; provided that
beneficial ownership of 10% or more of the voting securities of a Person shall
be deemed to be control.
"Asset Sale" means (i) the sale, lease, conveyance or other disposition (but
excluding the creation of a Lien) of any assets including, without limitation,
by way of a sale and leaseback (provided that the sale, lease, conveyance or
other disposition of all or substantially all of the assets of the Company and
its Subsidiaries taken as a whole will be governed by the provisions of the
Indenture described above under the caption "--Repurchase at the Option of
Holders--Change of Control" and/or the provisions described above under the
caption "--Certain Covenants--Merger, Consolidation, or Sale of Assets" and not
by the provisions described above under "--Repurchase at the Option of
Holders--Asset Sales"), and (ii) the issue or sale by the Company or any of its
Restricted Subsidiaries of Equity Interests of any of the Company's
Subsidiaries (including the sale by a Restricted Subsidiary of Equity Interests
in an Unrestricted Subsidiary), in the case of either clause (i) or (ii),
whether in a single transaction or a series of related transactions (a) that
have a fair market value in excess of $2.0 million or (b) for net proceeds in
excess of $2.0 million. Notwithstanding the foregoing, the following shall not
be deemed to be Asset Sales: (i) a transfer of assets by the Company to a
Wholly Owned Subsidiary of the Company or by a Wholly Owned Subsidiary of the
Company to the Company or to another Wholly Owned Subsidiary of the Company,
(ii) an issuance of Equity Interests by a Wholly Owned Subsidiary of the
Company to the Company or to another Wholly Owned Subsidiary of the Company,
(iii) a Restricted Payment or Permitted Investment that is permitted by the
covenant described above under the caption "--Certain Covenants--Restricted
Payments," (iv) the sale or transfer (whether or not in the ordinary course of
business) of oil and gas properties or direct or indirect interests in real
property, provided that at the time of such sale or transfer such properties do
not have associated with them any proved reserves, (v) the abandonment, farm-
out, lease or sublease of developed or undeveloped oil and gas properties in
the ordinary course of business, (vi) the trade or exchange by the Company or
any Subsidiary of the Company of any oil and gas property owned or held by the
Company or such Subsidiary for any oil and gas property owned or held by
another Person or (vii) the sale or transfer of hydrocarbons or other mineral
products or surplus or obsolete equipment in the ordinary course of business.
"Attributable Debt" in respect of a sale and leaseback transaction means, at
the time of determination, the present value (discounted at the rate of
interest implicit in such transaction, determined in accordance with GAAP) of
the obligation of the lessee for net rental payments during the remaining term
of the lease included in such sale and leaseback transaction (including any
period for which such lease has been extended or may, at the option of the
lessor, be extended).
"Borrowing Base" means, as of any date, the aggregate amount of borrowing
availability as of such date under all Credit Facilities that determine
availability on the basis of a borrowing base or other asset-based calculation,
provided that in no event shall the Borrowing Base exceed $250.0 million.
"Capital Lease Obligation" means, at the time any determination thereof is to
be made, the amount of the liability in respect of a capital lease that would
at such time be required to be capitalized on a balance sheet in accordance
with GAAP.
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"Capital Stock" means (i) in the case of a corporation, corporate stock, (ii)
in the case of an association or business entity, any and all shares,
interests, participations, rights or other equivalents (however designated) of
corporate stock, (iii) in the case of a partnership, partnership interests
(whether general or limited) and (iv) any other interest or participation that
confers on a Person the right to receive a share of the profits and losses of,
or distributions of assets of, the issuing Person.
"Cash Equivalents" means (i) United States dollars, (ii) securities issued or
directly and fully guaranteed or insured by the United States government or any
agency or instrumentality thereof having maturities of not more than six months
from the date of acquisition, (iii) certificates of deposit and eurodollar time
deposits with maturities of six months or less from the date of acquisition,
bankers' acceptances with maturities not exceeding six months and overnight
bank deposits, in each case with any lender party to the Credit Agreement or
with any domestic commercial bank having capital and surplus in excess of $500
million and a Thompson Bank Watch Rating of "B" or better, (iv) repurchase
obligations with a term of not more than seven days for underlying securities
of the types described in clauses (ii) and (iii) above entered into with any
financial institution meeting the qualifications specified in clause (iii)
above and (v) commercial paper having a rating of at least P1 from Moody's
Investors Service, Inc. and a rating of at least A1 from Standard & Poor's
Corporation.
"Change of Control" means the occurrence of any of the following: (i) the
sale, lease, transfer, conveyance or other disposition (other than by way of
merger or consolidation), in one or a series of related transactions, of all or
substantially all of the assets of the Company and its Restricted Subsidiaries
taken as a whole to any "person" (as such term is used in Section 13(d)(3) of
the Exchange Act) other than a Person controlled by the Principals, (ii) the
adoption of a plan relating to the liquidation or dissolution of the Company,
(iii) the consummation of any transaction (including, without limitation, any
purchase, sale, acquisition, disposition, merger or consolidation) the result
of which is that (x) the Principals cease to "beneficially own" (as such term
is described in Rule 13d-3 and Rule 13d-5 under the Exchange Act), in the
aggregate, at least 33% of the aggregate voting power of all classes of Capital
Stock of the Company having the right to elect directors under ordinary
circumstances or (y) any "person" (as defined above) becomes the "beneficial
owner" (as such term is defined in Rule 13d-3 and Rule 13d-5 under the Exchange
Act) of more of the aggregate voting power of all classes of Capital Stock of
the Company having the right to elect directors under ordinary circumstances
than is owned at that time by the Principals in the aggregate or (iv) the first
day on which a majority of the members of the Board of Directors of the Company
are not Continuing Directors.
"Commission" means the Securities and Exchange Commission.
"Consolidated Cash Flow" means, with respect to any Person for any period,
the Consolidated Net Income of such Person for such period plus (i) an amount
equal to any extraordinary loss plus any net loss realized in connection with
an Asset Sale (together with any related provision for taxes), to the extent
such losses were deducted in computing such Consolidated Net Income, plus (ii)
provision for taxes based on income or profits of such Person and its
Restricted Subsidiaries for such period, to the extent that such provision for
taxes was included in computing such Consolidated Net Income, plus
(iii) consolidated interest expense of such Person and its Restricted
Subsidiaries for such period, whether paid or accrued (including, without
limitation, amortization of original issue discount, non-cash interest
payments, the interest component of any deferred payment obligations, the
interest component of all payments associated with Capital Lease Obligations,
imputed interest with respect to Attributable Debt, commissions, discounts and
other fees and charges incurred in respect of letter of credit or bankers'
acceptance financings, and net payments (if any) pursuant to Interest Rate
Hedging Agreements), to the extent that any such expense was deducted in
computing such Consolidated Net Income, plus (iv) depreciation, depletion and
amortization expenses (including amortization of goodwill and other intangibles
but excluding amortization of prepaid cash expenses that were paid in a prior
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period) for such Person and its Restricted Subsidiaries for such period to the
extent that such depreciation, depletion and amortization expenses were
deducted in computing such Consolidated Net Income, plus (v) other non-cash
charges (excluding any such non-cash charge to the extent that it represents an
accrual of or reserve for cash charges in any future period or amortization of
a prepaid cash expense that was paid in a prior period) of such Person and its
Restricted Subsidiaries for such period to the extent that such other non-cash
charges were deducted in computing such Consolidated Net Income, in each case,
on a consolidated basis and determined in accordance with GAAP. Notwithstanding
the foregoing, the provision for taxes on the income or profits of, and the
depreciation, depletion and amortization and other non-cash charges and
expenses of, a Restricted Subsidiary of the referent Person shall be added to
Consolidated Net Income to compute Consolidated Cash Flow only to the extent
(and in same proportion) that the Net Income of such Restricted Subsidiary was
included in calculating the Consolidated Net Income of such Person and only if
a corresponding amount would be permitted at the date of determination to be
dividended to the Company by such Restricted Subsidiary without prior
governmental approval (that has not been obtained), and without direct or
indirect restriction pursuant to the terms of its charter and all agreements,
instruments, judgments, decrees, orders, statutes, rules and governmental
regulations applicable to that Restricted Subsidiary or its stockholders.
"Consolidated Net Income" means, with respect to any Person for any period,
the aggregate of the Net Income of such Person and its Restricted Subsidiaries
for such period, on a consolidated basis, determined in accordance with GAAP;
provided that (i) the Net Income (but not loss) of any Person that is not a
Restricted Subsidiary or that is accounted for by the equity method of
accounting shall be included only to the extent of the amount of dividends or
distributions paid in cash to the referent Person or a Wholly Owned Restricted
Subsidiary thereof, (ii) the Net Income of any Restricted Subsidiary shall be
excluded to the extent that the declaration or payment of dividends or similar
distributions by that Restricted Subsidiary of that Net Income is not at the
date of determination permitted without any prior governmental approval (that
has not been obtained) or, 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, (iii) the Net Income of any Person acquired in a pooling of
interests transaction for any period prior to the date of such acquisition
shall be excluded, (iv) the cumulative effect of a change in accounting
principles shall be excluded and (v) the Net Income of any Unrestricted
Subsidiary shall be excluded, whether or not distributed to the Company or one
of its Subsidiaries.
"Consolidated Net Working Capital" of any Person as of any date of
determination means the difference (shown on the balance sheet of such Person
and its consolidated Subsidiaries determined on a consolidated basis in
accordance with GAAP as of the end of the most recent fiscal quarter of such
Person for which internal financial statements are available) between (i) all
current assets of such Person and its consolidated Subsidiaries and (ii) all
current liabilities of such Person and its consolidated Subsidiaries except the
current portion of long-term Indebtedness.
"Continuing Directors" means, as of any date of determination, any member of
the Board of Directors of the Company who (i) was a member of such Board of
Directors on the date of the Indenture or (ii) was nominated for election or
elected to such Board of Directors with the approval of a majority of the
Continuing Directors who were members of such Board at the time of such
nomination or election.
"Credit Agreement" means that certain Credit Agreement, dated as of February
14, 1996, by and among the Company and NationsBank of Texas, N.A., as agent and
as a lender, and certain other institutions, as lenders, providing for up to
$250.0 million of Indebtedness, including any related notes, guarantees,
collateral documents, instruments and agreements executed in connection
therewith, and in each case as amended, restated, modified, renewed, refunded,
replaced or refinanced, in whole or in part, from time to time.
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"Credit Facilities" means, with respect to the Company, one or more debt
facilities (including, without limitation, the Credit Agreement) or commercial
paper facilities with banks or other institutional lenders providing for
revolving credit loans, term loans, production payments, receivables financing
(including through the sale of receivables to such lenders or to special
purpose entities formed to borrow from such lenders against such receivables)
or letters of credit, in each case, as amended, restated, modified, renewed,
refunded, replaced or refinanced in whole or in part from time to time.
Indebtedness under Credit Facilities outstanding on the date on which Notes are
first issued and authenticated under the Indenture shall be deemed to have been
incurred on such date in reliance on the exception provided by clause (b) of
the definition of Permitted Indebtedness.
"Default" means any event that is or with the passage of time or the giving
of notice or both would be an Event of Default.
"Designated Senior Debt" means (i) the Credit Agreement and (ii) any other
Senior Debt permitted under the Indenture the principal amount of which is $25
million or more and that has been designated by the Company as "Designated
Senior Debt."
"Disqualified Stock" means any Capital Stock that, by its terms (or by the
terms of any security into which it is convertible or for which it is
exchangeable), or upon the happening of any event, matures or is mandatorily
redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable
at the option of the Holder thereof, in whole or in part, on or prior to the
date that is 91 days after the date on which the Notes mature, provided that
the JEDI Preferred Stock shall not constitute Disqualified Stock.
"Dollar-Denominated Production Payments" means production payment obligations
recorded as liabilities in accordance with GAAP, together with all undertakings
and obligations in connection therewith.
"Equity Interests" means Capital Stock and all warrants, options or other
rights to acquire Capital Stock (but excluding any debt security that is
convertible into, or exchangeable for, Capital Stock).
"Existing Indebtedness" means up to $3.0 million in aggregate principal
amount of Indebtedness of the Company and its Subsidiaries (other than
Indebtedness under the Credit Facilities and the JEDI Debt) in existence on the
date of the Indenture, until such amounts are repaid.
"Fixed Charges" means, with respect to any Person for any period, the sum of
(i) the consolidated interest expense of such Person and its Restricted
Subsidiaries for such period, whether paid or accrued (including, without
limitation, amortization of original issue discount, non-cash interest
payments, the interest component of any deferred payment obligations, the
interest component of all payments associated with Capital Lease Obligations,
imputed interest with respect to Attributable Debt, commissions, discounts and
other fees and charges incurred in respect of letter of credit or bankers'
acceptance financings, and net payments (if any) pursuant to Interest Rate
Hedging Agreements) and (ii) the consolidated interest expense of such Person
and its Restricted Subsidiaries that was capitalized during such period, and
(iii) any interest expense on Indebtedness of another Person that is Guaranteed
by such Person or any of its Restricted Subsidiaries or secured by a Lien on
assets of such Person or any of its Restricted Subsidiaries (whether or not
such Guarantee or Lien is called upon) and (iv) the product of (a) all cash
dividend payments (and non-cash dividend payments in the case of a Person that
is a Restricted Subsidiary) on any series of preferred stock of such Person or
any of its Restricted Subsidiaries, times (b) a fraction, the numerator of
which is one and the denominator of which is one minus the then current
combined federal, state and local statutory tax rate of such Person, expressed
as a decimal, in each case, on a consolidated basis and in accordance with
GAAP.
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"Fixed Charge Coverage Ratio" means with respect to any Person for any
period, the ratio of the Consolidated Cash Flow of such Person for such period
to the Fixed Charges of such Person for such period. In the event that the
Company or any of its Restricted Subsidiaries incurs, assumes, Guarantees or
redeems any Indebtedness (other than revolving credit borrowings) or issues
preferred stock subsequent to the commencement of the period for which the
Fixed Charge Coverage Ratio is being calculated but prior to the date on which
the calculation of the Fixed Charge Coverage Ratio is made (the "Calculation
Date"), then the Fixed Charge Coverage Ratio shall be calculated giving pro
forma effect to such incurrence, assumption, Guarantee or redemption of
Indebtedness, or such issuance or redemption of preferred stock, as if the same
had occurred at the beginning of the applicable four-quarter reference period.
In addition, for purposes of making the computation referred to above, (i)
acquisitions that have been made by the Company or any of its Restricted
Subsidiaries, including through mergers or consolidations and including any
related financing transactions, during the four-quarter reference period or
subsequent to such reference period and on or prior to the Calculation Date
(including, without limitation, any acquisition to occur on the Calculation
Date) shall be deemed to have occurred on the first day of the four-quarter
reference period and Consolidated Cash Flow for such reference period shall be
calculated without giving effect to clause (iii) of the proviso set forth in
the definition of Consolidated Net Income, (ii) the net proceeds of
Indebtedness incurred or Disqualified Stock issued by the Company pursuant to
the first paragraph of the covenant described under the caption "--Certain
Covenants--Incurrence of Indebtedness and Issuance of Preferred Stock" during
the four-quarter reference period or subsequent to such reference period and on
or prior to the Calculation Date shall be deemed to have been received by the
Company on the first day of the four-quarter reference period and applied to
its intended use on such date, (iii) the Consolidated Cash Flow attributable to
discontinued operations, as determined in accordance with GAAP, and operations
or businesses disposed of prior to the Calculation Date, shall be excluded, and
(iv) the Fixed Charges attributable to discontinued operations, as determined
in accordance with GAAP, and operations or businesses disposed of prior to the
Calculation Date, shall be excluded, but only to the extent that the
obligations giving rise to such Fixed Charges will not be obligations of the
referent Person or any of its Restricted Subsidiaries following the Calculation
Date.
"GAAP" means generally accepted accounting principles 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 have been approved by a significant segment of the accounting
profession, which are in effect from time to time.
"Guarantee" means a guarantee (other than by endorsement of negotiable
instruments for collection in the ordinary course of business), direct or
indirect, in any manner (including, without limitation, letters of credit and
reimbursement agreements in respect thereof), of all or any part of any
Indebtedness.
"Guarantors" means each of (i) Diamond Energy Operating Company, Taurus
Energy Corp. and Electra Resources, Inc. and (ii) any other subsidiary of the
Company that executes a Subsidiary Guarantee in accordance with the provisions
of the Indenture, and, in each case, their respective successors and assigns.
"Indebtedness" means, with respect to any Person, without duplication, (a)
any indebtedness of such Person, whether or not contingent, (i) in respect of
borrowed money, (ii) evidenced by bonds, notes, debentures or similar
instruments, (iii) evidenced by letters of credit (or reimbursement agreements
in respect thereof) or banker's acceptances, (iv) representing Capital Lease
Obligations, (v) representing the balance deferred and unpaid of the purchase
price of any property, except any such balance that constitutes an accrued
expense or trade payable, (vi) representing any obligations in respect of
Interest Rate Hedging Agreements or Oil and Gas Hedging Contracts, (vii) in
respect of
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obligations to pay rent or other amounts with respect to a sale and leaseback
transaction to which such Person is a party, and (viii) in respect of any
Production Payment, (b) all indebtedness of others secured by a Lien on any
asset of such Person (whether or not such indebtedness is assumed by such
Person), (c) obligations of such Person in respect of production imbalances and
(d) to the extent not otherwise included in the foregoing, the Guarantee by
such Person of any indebtedness of any other Person, provided that the
indebtedness described in clauses (a)(i), (ii), (iv) and (v) shall be included
in this definition of Indebtedness only if, and to the extent that, the
indebtedness described in such clauses would appear as a liability upon a
balance sheet of such Person prepared in accordance with GAAP.
"Interest Rate Hedging Agreements" means, with respect to any Person, the
obligations of such Person under (i) interest rate swap agreements, interest
rate cap agreements and interest rate collar agreements and (ii) other
agreements or arrangements designed to protect such Person against fluctuations
in interest rates.
"Investments" means, with respect to any Person, all investments by such
Person in other Persons (including Affiliates) in the forms of direct or
indirect loans (including guarantees of Indebtedness or other obligations, but
excluding trade credit and other ordinary course advances customarily made in
the oil and gas industry), advances or capital contributions (excluding
commission, travel and similar advances to officers and employees made in the
ordinary course of business), purchases or other acquisitions for consideration
of Indebtedness, Equity Interests or other securities, together with all items
that are or would be classified as investments on a balance sheet prepared in
accordance with GAAP; provided that the following shall not constitute
Investments: (i) an acquisition of assets, Equity Interests or other securities
by the Company for consideration consisting of common equity securities of the
Company, (ii) Interest Rate Hedging Agreements entered into in accordance with
the limitations set forth in clause (h) of the second paragraph of the covenant
described under the caption "--Certain Covenants--Incurrence of Indebtedness
and Issuance of Disqualified Stock" and (iii) Oil and Gas Hedging Agreements
entered into in accordance with the limitations set forth in clause (i) of the
second paragraph of the covenant described under the caption "--Certain
Covenants--Incurrence of Indebtedness and Issuance of Disqualified Stock." If
the Company or any Subsidiary of the Company sells or otherwise disposes of any
Equity Interests of any direct or indirect Subsidiary of the Company such that,
after giving effect to any such sale or disposition, such Person is no longer a
Subsidiary of the Company, the Company shall be deemed to have made an
Investment on the date of any such sale or disposition equal to the fair market
value of the Equity Interests of such Subsidiary not sold or disposed of.
"JEDI Preferred Stock" means all outstanding shares of the Company's 15%
Cumulative Preferred Stock held by JEDI as in effect on the date of the
Indenture, including any shares of the Company's 15% Cumulative Preferred Stock
issued thereafter as payment of accrued dividends thereon in accordance with
the terms thereof as in effect on the date of the Indenture.
"Lien" means, with respect to any asset, any mortgage, lien, pledge, charge,
security interest or encumbrance of any kind in respect of such asset, whether
or not filed, recorded or otherwise perfected under applicable law (including
any conditional sale or other title retention agreement, any lease in the
nature thereof, any option or other agreement to sell or give a security
interest in and any filing of or agreement to give any financing statement
under the Uniform Commercial Code (or equivalent statutes) of any
jurisdiction).
"Liquid Securities" means securities (i) of an issuer that is not an
Affiliate of the Company and (ii) that are publicly traded on the New York
Stock Exchange, the American Stock Exchange or the Nasdaq National Market;
provided, that securities meeting the requirements of clauses (i) and
(ii) above shall be treated as Liquid Securities from the date of receipt
thereof until and only until the earlier of (x) the date on which such
securities are sold or exchanged for cash or cash equivalents and
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(y) 180 days following the date of the closing of the Asset Sale in connection
with which such Liquid Securities were received. In the event such securities
are not sold or exchanged for cash or cash equivalents within such 180-day
period, for purposes of determining whether the transaction pursuant to which
the Company or a Restricted Subsidiary received the securities was in
compliance with the covenant described under the caption "--Repurchase at the
Option of Holders--Asset Sales," such securities shall be deemed not to have
been Liquid Securities at any time.
"Net Income" means, with respect to any Person, the net income (loss) of such
Person, determined in accordance with GAAP and before any reduction in respect
of preferred stock dividends, excluding, however, (i) any gain (but not loss),
together with any related provision for taxes on such gain (but not loss),
realized in connection with (a) any Asset Sale (including, without limitation,
dispositions pursuant to sale and leaseback transactions) or (b) the
disposition of any securities by such Person or any of its Restricted
Subsidiaries or the extinguishment of any Indebtedness of such Person or any of
its Restricted Subsidiaries and (ii) any extraordinary or nonrecurring gain
(but not loss), together with any related provision for taxes on such
extraordinary or nonrecurring gain (but not loss).
"Net Proceeds" means the aggregate cash proceeds received by the Company or
any of its Restricted Subsidiaries in respect of any Asset Sale (including,
without limitation, any cash received upon the sale or other disposition of
Liquid Securities or any other any non-cash consideration received in any Asset
Sale, but excluding cash amounts placed in escrow, until such amounts are
released to the Company), net of the direct costs relating to such Asset Sale
(including, without limitation, legal, accounting and investment banking fees,
and sales commissions) and any relocation expenses incurred as a result
thereof, taxes paid or payable as a result thereof (after taking into account
any available tax credits or deductions and any tax sharing arrangements),
amounts required to be applied to the repayment of Indebtedness (other than
Indebtedness under any Credit Facility) secured by a Lien on the asset or
assets that were the subject of such Asset Sale and any reserve for adjustment
in respect of the sale price of such asset or assets established in accordance
with GAAP and any reserve established for future liabilities.
"Non-Recourse Debt" means Indebtedness (i) as to which neither the Company
nor any of its Restricted Subsidiaries (a) provides credit support of any kind
(including any undertaking, agreement or instrument that would constitute
Indebtedness), (b) is directly or indirectly liable (as a guarantor or
otherwise), or (c) constitutes the lender; and (ii) no default with respect to
which (including any rights that the holders thereof may have to take
enforcement action against an Unrestricted Subsidiary) would permit (upon
notice, lapse of time or both) any holder of any other Indebtedness of the
Company or any of its Restricted Subsidiaries to declare a default on such
other Indebtedness or cause the payment thereof to be accelerated or payable
prior to its stated maturity; and (iii) as to which the lenders have been
notified in writing that they will not have any recourse to the stock or assets
of the Company or any of its Restricted Subsidiaries.
"Obligations" means any principal, interest, penalties, fees,
indemnifications, reimbursements, damages and other liabilities payable under
the documentation governing any Indebtedness.
"Oil and Gas Business" means (i) the acquisition, exploration, development,
operation and disposition of interests in oil, gas and other hydrocarbon
properties, (ii) the gathering, marketing, treating, processing, storage,
selling and transporting of any production from such interests or properties,
(iii) any business relating to exploration for or development, production,
treatment, processing, storage, transportation or marketing of oil, gas and
other minerals and products produced in association therewith and (iv) any
activity that is ancillary to or necessary or appropriate for the activities
described in clauses (i) through (iii) of this definition.
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"Oil and Gas Hedging Contracts" means any oil and gas purchase or hedging
agreement, and other agreement or arrangement, in each case, that is designed
to provide protection against oil and gas price fluctuations.
"Pari Passu Indebtedness" means Indebtedness that ranks pari passu in right
of payment to the Notes.
"Permitted Business Investments" means investments made in the ordinary
course of, and of a nature that is or shall have become customary in, the Oil
and Gas Business as a means of actively exploiting, exploring for, acquiring,
developing, processing, gathering, marketing or transporting oil and gas
through agreements, transactions, interests or arrangements which permit one to
share risks or costs, comply with regulatory requirements regarding local
ownership or satisfy other objectives customarily achieved through the conduct
of Oil and Gas Business jointly with third parties, including, without
limitation, (i) ownership interests in oil and gas properties, processing
facilities, gathering systems or ancillary real property interests and (ii)
Investments in the form of or pursuant to operating agreements, processing
agreements, farm-in agreements, farm-out agreements, development agreements,
area of mutual interest agreements, unitization agreements, pooling agreements,
joint bidding agreements, service contracts, joint venture agreements,
partnership agreements (whether general or limited), subscription agreements,
stock purchase agreements and other similar agreements with third parties.
"Permitted Indebtedness" has the meaning given in the covenant described
under the caption "--Certain Covenants--Incurrence of Indebtedness and Issuance
of Disqualified Stock."
"Permitted Investments" means (a) any Investment in the Company or in a
Wholly Owned Restricted Subsidiary of the Company; (b) any Investment in Cash
Equivalents or securities issued or directly and fully guaranteed or insured by
the United States government or any agency or instrumentality thereof having
maturities of not more than one year from the date of acquisition; (c) any
Investment by the Company or any Subsidiary of the Company in a Person, if as a
result of such Investment and any related transactions that, at the time of
such Investment are contractually mandated to occur (i) such Person becomes a
Wholly Owned Restricted Subsidiary of the Company or (ii) such Person is
merged, consolidated or amalgamated with or into, or transfers or conveys
substantially all of its assets to, or is liquidated into, the Company or a
Wholly Owned Restricted Subsidiary of the Company; (d) any Investment made as a
result of the receipt of non-cash consideration from an Asset Sale that was
made pursuant to and in compliance with the covenant described above under the
caption "--Repurchase at the Option of Holders--Asset Sales"; (e) other
Investments in any Person having an aggregate fair market value (measured on
the date each such Investment was made and without giving effect to subsequent
changes in value), when taken together with all other Investments made pursuant
to this clause (e) that are at the time outstanding, not to exceed the greater
of $5.0 million or two percent of Total Assets of the Company; (f) Permitted
Business Investments; (g) any Investment acquired by the Company in exchange
for Equity Interests in the Company (other than Disqualified Stock); (h)
Investments in Unrestricted Subsidiaries with net cash proceeds contributed to
the common equity capital of the Company since the date of the Indenture,
provided that the amount of any such net cash proceeds that are utilized for
any such Investment shall be excluded from clause (c)(ii) of the first
paragraph of the covenant described under the caption "--Certain Covenants--
Restricted Payments" and (i) shares of Capital Stock received in connection
with any good faith settlement of a bankruptcy proceeding involving a trade
creditor.
"Permitted Liens" means (i) Liens securing Indebtedness of a Subsidiary or
Senior Debt that is outstanding on the date of issuance of the Notes or that is
permitted by the terms of the Indenture to be incurred; (ii) Liens securing
Attributable Debt with respect to sale and leaseback transactions permitted by
the terms of the Indenture; (iii) Liens in favor of the Company; (iv) Liens on
property existing at the time of acquisition thereof by the Company or any
Subsidiary of the Company and Liens
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on property or assets of a Subsidiary existing at the time it became a
Subsidiary, provided that such Liens were in existence prior to the
contemplation of the acquisition and do not extend to any assets other than the
acquired property; (v) Liens incurred or deposits made in the ordinary course
of business in connection with workers' compensation, unemployment insurance or
other kinds of social security, or to secure the payment or performance of
tenders, statutory or regulatory obligations, surety or appeal bonds,
performance bonds or other obligations of a like nature incurred in the
ordinary course of business (including lessee or operator obligations under
statutes, governmental regulations or instruments related to the ownership,
exploration and production of oil, gas and minerals on state or federal lands
or waters); (vi) Liens existing on the date of the Indenture; (vii) Liens for
taxes, assessments or governmental charges or claims that are not yet
delinquent or that are being contested in good faith by appropriate proceedings
promptly instituted and diligently concluded, provided that any reserve or
other appropriate provision as shall be required in conformity with GAAP shall
have been made therefor; (viii) statutory liens of landlords, mechanics,
suppliers, vendors, warehousemen, carriers or other like Liens arising in the
ordinary course of business; (ix) judgment Liens not giving rise to an Event of
Default so long as any appropriate legal proceeding that 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; (x) Liens on, or related to, properties or assets to secure
all or part or the costs incurred in the ordinary course of the Oil and Gas
Business for the exploration, drilling, development, or operation thereof; (xi)
Liens in pipeline or pipeline facilities that arise under operation of law;
(xii) Liens arising under operating agreements, joint venture agreements,
partnership agreements, oil and gas leases, farm-out agreements, division
orders, contracts for the sale, transportation or exchange of oil or natural
gas, unitization and pooling declarations and agreements, area of mutual
interest agreements and other agreements that are customary in the Oil and Gas
Business; (xiii) Liens reserved in oil and gas mineral leases for bonus or
rental payments and for compliance with the terms of such leases; (xiv) Liens
not otherwise permitted by clauses (i) through (xiii) and that are incurred in
the ordinary course of business of the Company or any Subsidiary of the Company
with respect to obligations that do not exceed $5.0 million at any one time
outstanding; and (xv) Liens on assets of Unrestricted Subsidiaries that secure
Non-Recourse Debt of Unrestricted Subsidiaries.
"Permitted Refinancing Debt" means any Indebtedness of the Company or any of
its Restricted Subsidiaries issued in exchange for, or the net proceeds of
which are used to extend, refinance, renew, replace, defease or refund other
Indebtedness (other than Indebtedness incurred under a Credit Facility) of the
Company or any of its Restricted Subsidiaries; provided that: (i) the principal
amount (or accreted value, if applicable) of such Permitted Refinancing
Indebtedness does not exceed the principal amount (or accreted value, if
applicable) of the Indebtedness so extended, refinanced, renewed, replaced,
defeased or refunded (plus the amount of reasonable expenses incurred in
connection therewith); (ii) such Permitted Refinancing Indebtedness has a final
maturity date on or later than the final maturity date of, and has a Weighted
Average Life to Maturity equal to or greater than the Weighted Average Life to
Maturity of, the Indebtedness being extended, refinanced, renewed, replaced,
defeased or refunded; (iii) if the Indebtedness being extended, refinanced,
renewed, replaced, defeased or refunded is subordinated in right of payment to
the Notes, such Permitted Refinancing Indebtedness has a final maturity date
later than the final maturity date of, and is subordinated in right of payment
to, the Notes on terms at least as favorable to the Holders of Notes as those
contained in the documentation governing the Indebtedness being extended,
refinanced, renewed, replaced, defeased or refunded; and (iv) such Indebtedness
is incurred either by the Company or by the Restricted Subsidiary who is the
obligor on the Indebtedness being extended, refinanced, renewed, replaced,
defeased or refunded.
"Principal(s)" means (a) Enron Corp., (b) the California Public Employees
Retirement System, or (c) JEDI or another entity or entities, as long as JEDI
or such other entity or entities is controlled by (i) Enron Corp., (ii) the
California Public Employees' Retirement System, (iii) any direct or indirect
wholly owned subsidiary of either such entity or (iv) any combination of any of
the foregoing entities.
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"Production Payments" means Dollar-Denominated Production Payments and
Volumetric Production Payments, collectively.
"Restricted Investment" means an Investment other than a Permitted
Investment.
"Restricted Subsidiary" of a Person means any Subsidiary of the referent
Person that is not an Unrestricted Subsidiary.
"Senior Debt" means (i) Indebtedness of the Company or any Subsidiary of the
Company under or in respect of any Credit Facility and (ii) any other
Indebtedness permitted under the terms of the Indenture, unless the instrument
under which such Indebtedness is incurred expressly provides that it is on a
parity with or subordinated in right of payment to the Notes. Notwithstanding
anything to the contrary in the foregoing sentence, Senior Debt will not
include (w) any liability for federal, state, local or other taxes owed or
owing by the Company, (x) any Indebtedness of the Company to any of its
Subsidiaries or other Affiliates, (y) any trade payables or (z) any
Indebtedness that is incurred in violation of the Indenture (other than
Indebtedness under any Credit Facility that is incurred on the basis of a
representation by the Company to the applicable lenders that it is permitted to
incur such Indebtedness under the Indenture).
"Significant Subsidiary" means any Subsidiary that would be a "significant
subsidiary" as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated
pursuant to the Act, as such Regulation is in effect on the date hereof.
"Subsidiary" means, with respect to any Person, (i) any corporation,
association or other business entity of which more than 50% of the total voting
power of shares of Capital Stock entitled (without regard to the occurrence of
any contingency) to vote in the election of directors, managers or trustees
thereof is at the time owned or controlled, directly or indirectly, by such
Person or one or more of the other Subsidiaries of that Person (or a
combination thereof) and (ii) any partnership (a) the sole general partner or
the managing general partner of which is such Person or a Subsidiary of such
Person or (b) the only general partners of which are such Person or of one or
more Subsidiaries of such Person (or any combination thereof).
"Taurus" means the Company's gas gathering and processing business and the
properties and other assets related thereto, whether or not held by Taurus
Energy Corp.
"Total Assets" means, with respect to any Person, the total consolidated
assets of such Person and its Restricted Subsidiaries, as shown on the most
recent balance sheet of such Person.
"Unrestricted Subsidiary" means (i) any Subsidiary (other than Diamond or any
successor to Diamond) that is designated by the Board of Directors as an
Unrestricted Subsidiary pursuant to a Board Resolution, and any Subsidiary of
an Unrestricted Subsidiary; but only to the extent that such Subsidiary: (a)
has no Indebtedness other than Non-Recourse Debt; (b) is not party to any
agreement, contract, arrangement or understanding with the Company or any
Restricted Subsidiary of the Company unless the terms of any such agreement,
contract, arrangement or understanding are no less favorable to the Company or
such Restricted Subsidiary than those that might be obtained at the time from
Persons who are not Affiliates of the Company; (c) is a Person with respect to
which neither the Company nor any of its Restricted Subsidiaries has any direct
or indirect obligation (x) to subscribe for additional Equity Interests or (y)
to maintain or preserve such Person's financial condition or to cause such
Person to achieve any specified levels of operating results; (d) has not
guaranteed or otherwise directly or indirectly provided credit support for any
Indebtedness of the Company or any of its Restricted Subsidiaries; and (e) has
at least one director on its board of directors that is not a director or
executive officer of the Company or any of its Restricted Subsidiaries and has
at least one executive officer that is not a director or executive officer of
the Company or any of its Restricted
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Subsidiaries, provided, however, that the death or resignation of any such
director or executive officer shall not cause a Subsidiary that would otherwise
be an Unrestricted Subsidiary to be deemed to be a Restricted Subsidiary unless
ten days has elapsed in which the Company has failed to appoint or elect a
successor to replace such director or executive officer who satisfies the
criteria set forth in this clause (e). Any such designation by the Board of
Directors shall be evidenced to the Trustee by filing with the Trustee a
certified copy of the Board Resolution giving effect to such designation and an
Officers' Certificate certifying that such designation complied with the
foregoing conditions and was permitted by the covenant described above under
the caption "--Certain Covenants--Restricted Payments." If, at any time, any
Unrestricted Subsidiary would fail to meet the foregoing requirements as an
Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted
Subsidiary for purposes of the Indenture and any Indebtedness of such
Subsidiary shall be deemed to be incurred by a Restricted Subsidiary of the
Company as of such date (and, if such Indebtedness is not permitted to be
incurred as of such date under the covenant described under the caption "--
Certain Covenants--Incurrence of Indebtedness and Issuance of Disqualified
Stock," the Company shall be in default of such covenant). The Board of
Directors of the Company may at any time designate any Unrestricted Subsidiary
to be a Restricted Subsidiary; provided that such designation shall be deemed
to be an incurrence of Indebtedness by a Restricted Subsidiary of the Company
of any outstanding Indebtedness of such Unrestricted Subsidiary and such
designation shall only be permitted if (i) such Indebtedness is permitted under
the covenant described under the caption "--Certain Covenants--Incurrence of
Indebtedness and Issuance of Disqualified Stock," and (ii) no Default or Event
of Default would be in existence following such designation.
"Volumetric Production Payments" means production payment obligations
recorded as deferred revenue in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"Weighted Average Life to Maturity" means, when applied to any Indebtedness
at any date, the number of years obtained by dividing (i) the sum of the
products obtained by multiplying (a) the amount of each then remaining
installment, sinking fund, serial maturity or other required payments of
principal, including payment at final maturity, in respect thereof, by (b) the
number of years (calculated to the nearest one-twelfth) that will elapse
between such date and the making of such payment, by (ii) the then outstanding
principal amount of such Indebtedness.
"Wholly Owned Restricted Subsidiary" of any Person means a Restricted
Subsidiary of such Person all of the outstanding Capital Stock or other
ownership interests of which (other than directors' qualifying shares) shall at
the time be owned, directly or indirectly, by such Person or by one or more
Wholly Owned Restricted Subsidiaries of such Person.
103
<PAGE>
DESCRIPTION OF OTHER INDEBTEDNESS
CREDIT AGREEMENT
On February 14, 1996, the Company entered into the Credit Agreement with
NationsBank, as lender and as agent, and additional lenders named therein. The
Credit Agreement is guaranteed by all of the Company's subsidiaries and
provides for a revolving credit facility in the amount of $250.0 million. The
current borrowing base is $115.0 million and is subject to redetermination: (i)
semi-annually, (ii) upon the sale of Taurus and (iii) upon issuance of public
subordinated debt in an amount greater than $100.0 million. The lenders under
the Credit Agreement have agreed to waive their right to redetermine the
borrowing base with respect to the issuance of the Notes. At March 31, 1996,
$80.0 million was outstanding under the Credit Agreement and $35.0 million was
available for borrowing thereunder. See "Use of Proceeds."
The Credit Agreement is unsecured. The Company has provided the lenders with
first lien deeds of trust on its oil and natural gas assets which will not
become effective, and the lenders have agreed not to file, unless (i) 80% of
any outstanding borrowings in excess of the borrowing limit is not repaid
within a 90 day period, (ii) cash collateral securing a hedge transaction
exceeds 20% of the borrowing limit or (iii) an event of default or a material
adverse event, as defined in the Credit Agreement, occurs.
So long as no default (as defined in the Credit Agreement) is continuing, the
Company has the option of having all or any portion of the amount borrowed
under the Credit Agreement be the subject of one of the following interest
rates: (i) NationsBank's prime rate, (ii) the CD Rate plus 1 1/4% to 1 5/8%
based upon the ratio of outstanding debt to the available borrowing base and
(iii) LIBOR plus 1 1/4% to 1 5/8% based upon the ratio of outstanding debt to
the available borrowing base. The Company must also pay a commitment fee of
between 0.375% to 0.425% on the unused portion of the credit facility. The
Credit Agreement contains various restrictive covenants, including limitations
on the granting of liens, restrictions on the issuance of additional debt,
restrictions on investments, a requirement to maintain positive working
capital, and restrictions on dividends and stock repurchases. The Credit
Agreement also contains requirements that JEDI, Enron, CalPERS or any wholly
owned subsidiary of either Enron or CalPERS must continue to own a majority of
the outstanding equity of the Company and must have the ability to elect the
majority of the Board of Directors and that certain members of management
maintain specified levels of equity ownership in the Company and continue their
employment with the Company. The Credit Agreement matures on February 16, 2001.
104
<PAGE>
DESCRIPTION OF CAPITAL STOCK OF CODA
COMMON STOCK
The authorized common stock of Coda aggregates 1,000,000 shares, par value
$0.01 per share. As of May 1, 1996, 913,611 shares of common stock were
outstanding. The holders of shares of common stock possess full voting power
for the election of directors and for all other purposes, each holder of
common stock being entitled to one vote for each share of common stock held of
record by such holder. The shares of common stock do not have cumulative
voting rights. Holders of a majority of the shares of common stock represented
at a meeting at which a quorum is present may currently approve most actions
submitted to the stockholders except for certain corporate actions (e.g.,
mergers, sale of assets and charter amendments), which require the approval of
holders of a majority of the total outstanding shares of common stock. Coda
has never paid dividends on its common stock.
Subject to the rights of holders of any outstanding shares of Preferred
Stock, dividends may be paid on the common stock as and when declared by
Coda's Board of Directors out of any funds of Coda legally available for the
payment thereof. Holders of common stock have no subscription, redemption,
sinking fund, conversion or preemptive rights, except for certain put and call
rights described in "Certain Transactions." The outstanding shares of common
stock are fully paid and nonassessable. After payment is made in full to the
holders of any outstanding shares of Preferred Stock in the event of any
liquidation, dissolution or winding up of the affairs of Coda, the remaining
assets and funds of Coda will be distributed to the holders of common stock
according to their respective shares. The common stock is held by 16 holders
of record. There is no established trading market for the common stock.
PREFERRED STOCK
Under Coda's Restated Certificate of Incorporation, the Board of Directors
is authorized to issue up to 40,000 shares of preferred stock, par value $0.01
per share. All 40,000 shares of preferred stock are designated as "15%
Cumulative Preferred Stock." The holders of each share of Preferred Stock are
entitled to receive, when and as declared by the Board of Directors,
cumulative preferential dividends, at the rate of $150.00 per share per annum.
There are currently 20,000 shares of Preferred Stock issued and outstanding.
Shares of Preferred Stock in excess of such 20,000 shares shall be issuable
only for the purpose of paying dividends on the Preferred Stock.
As long as any shares of Preferred Stock are outstanding, no dividends
whatsoever, whether paid in cash, stock or otherwise (except for dividends
paid in shares of common stock, either in the form of a stock split or stock
dividend), may be paid or declared, nor may any distribution be made, on any
common stock to the holders of such stock, unless certain conditions are met.
Coda's Restated Certificate of Incorporation requires that Coda redeem all
the issued and outstanding shares of Preferred Stock at a redemption price of
$1,000 per share, plus all accrued and unpaid dividends (including undeclared
dividends) to the date of redemption, if Coda has sufficient funds legally
available for such redemption and if such redemption would not violate or
conflict with any loan agreement, credit agreement, note agreement, indenture
or other agreement relating to indebtedness to which Coda is a party, on or
before the fifth business day after the earliest to occur of the following:
(i) the closing of the sale by Coda of Taurus and (ii) a Trigger Event, as
such term is defined in the Stockholders Agreement. The Preferred Stock may be
redeemed by Coda at its option, as a whole or in part, to the extent Coda
shall have funds legally available for such redemption, at any time or from
time to time at a redemption price of $1,000 per share, plus all accrued and
unpaid dividends (including undeclared dividends) to the date of redemption.
Such redemption, whether required or optional, is restricted by the Credit
Agreement and the Indenture.
105
<PAGE>
Upon the complete liquidation, dissolution, or winding up of Coda, whether
voluntarily or involuntarily, the holders of Preferred Stock shall be
entitled, after payment or provision for payment of the debts and other
liabilities of Coda but before any distribution is made to the holders of any
common stock, to be paid $1,000 per share plus all accrued and unpaid
dividends (including undeclared dividends), and shall not be entitled to any
further payment.
Except as otherwise provided herein or required by law, the holders of
shares of Preferred Stock shall not be entitled to vote on any matters to be
voted on by the stockholders of Coda; provided, however, that so long as any
shares of the Preferred Stock are outstanding, Coda shall not, without the
written consent or the affirmative vote of holders of at least a majority of
the total number of shares of Preferred Stock then outstanding and voting as a
class, (i) amend its Certificate of Incorporation or Bylaws or (ii) authorize
the merger (whether or not Coda is a surviving corporation in such merger) of
Coda, in each case, if such amendment or merger would alter, change or abolish
the powers, preference or rights of the Preferred Stock so as to affect the
holders of the Preferred Stock adversely.
CERTAIN FEDERAL INCOME TAX CONSIDERATIONS
In the opinion of Haynes and Boone, LLP, counsel to the Company, the
following discussion describes the material federal income tax consequences
expected to result to holders whose Private Notes are exchanged for Exchange
Notes in the Exchange Offer. Such opinion is based upon 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 with respect to the Exchange Offer. Legislative,
judicial or administrative changes or interpretations may be forthcoming that
could alter or modify the statements and conclusions set forth herein. Any
such changes or interpretations may or may not be retroactive and could affect
the tax consequences to holders. Certain holders (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. EACH
HOLDER OF PRIVATE NOTES SHOULD CONSULT ITS OWN TAX ADVISOR AS TO THE
PARTICULAR TAX CONSEQUENCES OF EXCHANGING PRIVATE NOTES FOR EXCHANGE NOTES,
INCLUDING THE APPLICABILITY AND EFFECT OF ANY STATE, LOCAL OR FOREIGN LAWS.
The exchange of Private Notes for Exchange Notes will be treated as a "non-
event" for federal income tax purposes because the Exchange Notes will not be
considered to differ materially in kind or extent from the Private Notes. As a
result, no material federal income tax consequences will result to holders
exchanging Private Notes for Exchange Notes.
PLAN OF DISTRIBUTION
Each broker-dealer that receives Exchange Notes for its own account pursuant
to the Exchange Offer must acknowledge that it will deliver a prospectus in
connection with any resale of such Exchange Notes. This Prospectus, as it may
be amended or supplemented from time to time, may be used by a broker-dealer
in connection with the resales of Exchange Notes received in exchange for
Private Notes where such Private Notes were acquired as a result of market-
making activities or other trading activities. The Company has agreed that for
a period of up to one year after the effective date of the Registration
Statement, it will make this Prospectus, as amended or supplemented, available
to any broker-dealer that requests such document in the Letter of Transmittal
for use in connection with any such resale.
106
<PAGE>
The Company will not receive any proceeds from any sale of Exchange Notes by
broker-dealers or any other persons. Exchange Notes received by broker-dealers
for their own account pursuant to the Exchange Offer may be sold from time to
time in one or more transactions in the over-the-counter market, in negotiated
transactions, through the writing of options on the Exchange Notes or a
combination of such methods of resale, at market prices prevailing at the time
of resale, at prices related to such prevailing market prices or negotiated
prices. Any such resale may be made directly to purchasers or to or through
brokers or dealers who may receive compensation in the form of commissions or
concessions from any such broker-dealer and/or the purchasers of any such
Exchange Notes. Any broker-dealer that resells Exchange Notes that were
received by it for its own account pursuant to the Exchange Offer and any
broker or dealer that participates in a distribution of such Exchange Notes
may be deemed to be an "underwriter" within the meaning of the Securities Act
and any profit on any such resale of Exchange 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 incident to the Company's
performance of, or compliance with, the Registration Rights Agreement and will
indemnify the holders of Private Notes (including any broker-dealers), and
certain parties related to such holders, against certain liabilities,
including liabilities under the Securities Act.
LEGAL MATTERS
Certain legal matters related to the Exchange Notes offered hereby are being
passed upon for the Company by Mr. Joe Callaway, Vice President and General
Counsel of the Company, and by Haynes and Boone, LLP, Dallas, Texas. Mr.
Callaway currently holds 475 shares, and options to purchase 475 shares, of
Coda common stock.
EXPERTS
The consolidated financial statements of the Company as of December 31, 1994
and 1995, and for each of the three years in the period ended December 31,
1995, appearing in this Prospectus and Registration Statement have been
audited by Ernst & Young LLP, independent auditors, as set forth in their
report thereon appearing elsewhere herein, and are included in reliance upon
such report given upon the authority of such firm as experts in accounting and
auditing.
The estimates as of December 31, 1991, 1992, 1993, 1994 and 1995 relating to
the Company's proved oil and natural gas reserves, future net revenues of oil
and natural gas reserves and present value of future net revenues of oil and
natural gas reserves included herein are based upon estimates of such reserves
prepared by Lee Keeling and Associates, Inc. in reliance upon its reports and
upon the authority of this firm as experts in petroleum engineering, except
that such estimates related to the reserves of Diamond as of December 31,
1991, 1992 and 1993 were prepared by Diamond's in-house engineers.
107
<PAGE>
AVAILABLE INFORMATION
The Company has filed with the Commission a Registration Statement on Form
S-4 under the Securities Act with respect to the Exchange Notes offered
hereby. As permitted by the rules and regulations of the Commission, this
Prospectus omits certain information, exhibits and undertakings contained in
the Registration Statement. For further information with respect to the
Company and the Exchange Notes offered hereby, reference is made to the
Registration Statement, including the exhibits thereto and the financial
statements, notes and schedules filed as a part thereof. As a result of the
Exchange Offer, the Company will become subject to the informational
requirements of the Exchange Act. The Registration Statement (and the exhibits
and schedules thereto), as well as the periodic reports and other information
filed by the Company with the Commission, may be inspected and copied at the
Public Reference Section of the Commission at Room 1024, Judiciary Plaza, 450
Fifth Street, N.W., Washington, D.C. 20549 and at the regional offices of the
Commission located at Room 1400, 75 Park Place, New York, New York 10007 and
Suite 1400, Northwestern Atrium Center, 500 West Madison Street, Chicago,
Illinois 6061-2511. Copies of such materials may be obtained from the Public
Reference Section of the Commission, Room 1024, Judiciary Plaza, 450 Fifth
Street, N.W., Washington, D.C. 20549, and its public reference facilities in
New York, New York and Chicago, Illinois at the prescribed rates. Statements
contained in this Prospectus as to the contents of any contract or other
document are not necessarily complete, and in each instance reference is made
to the copy of such contract or document filed as an exhibit to the
Registration Statement, each such statement being qualified in all respects by
such reference.
Pursuant to the Indenture, the Company has agreed that, to the extent such
filings are accepted by the Commission and whether or not it has a class of
securities registered under the Exchange Act, it will file 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 of the Exchange Act, in each case
on or before the dates on which such reports and other documents would have
been required to have been filed with the Commission if the Company had been
subject to Section 13 or 15 of the Exchange Act. The Company will also be
required (i) to file with the Trustee (with exhibits), and provide to each
holder of Notes (without exhibits), 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 Commission or the date on which the
Company would be required to file such reports and documents if the Company
were so required and (ii) if filing such reports and documents with the
Commission is not accepted by the Commission or is prohibited under the
Exchange Act, to supply at its cost copies of such reports and documents
(including any exhibits thereto) to any holder of Notes promptly upon written
request.
The principal address of the Company is 5735 Pineland Drive, Suite 300,
Dallas, Texas 75231, and the Company's telephone number is (214) 692-1800.
108
<PAGE>
GLOSSARY
The terms defined in this glossary are used throughout this Prospectus.
"AVERAGE NYMEX PRICE." The average of the NYMEX closing prices for the near
month.
BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.
BCF. One billion cubic feet of natural gas.
"BEHIND THE PIPE." Hydrocarbons in a potentially producing horizon
penetrated by a well bore the production of which has been postponed pending
the production of hydrocarbons from another formation penetrated by the well
bore. These hydrocarbons are classified as proved but non-producing reserves.
BOE. Barrels of oil equivalent (converting six Mcf of natural gas to one Bbl
of oil).
"DEVELOPMENT WELL." A well drilled within the proven boundaries of an oil or
natural gas reservoir with the intention of completing the stratigraphic
horizon known to be productive.
"GROSS WELLS." The total number of wells in which a working interest is
owned.
"INFILL WELL." A well drilled between known producing wells to better
exploit the reservoir.
MBBLS. One thousand barrels of crude oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
MMBTU. One million British thermal units.
MCF. One thousand cubic feet of natural gas.
M GALLONS. One thousand U.S. gallons liquid volume, used herein in reference
to natural gas liquids.
MMBBLS. One million barrels of crude oil or other liquid hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMCF. One million cubic feet of natural gas.
"NET WELLS." The sum of the fractional working interests owned in gross
wells.
NYMEX. New York Mercantile Exchange.
"PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES." The present value of
estimated future net revenues is an estimate of future net revenues from a
property at its acquisition date, at December 31, 1995, or as otherwise
indicated, after deducting production and ad valorem taxes, future capital
costs and operating expenses, but before deducting federal income taxes. The
future net revenues have been discounted at an annual rate of 10% to determine
their "present value." The present value is shown to indicate the effect of
time on the value of the revenue stream and should not be construed as being
the fair market value of the properties. Estimates have been made using
constant oil and natural gas prices and operating costs at the acquisition
date, at December 31, 1995, or as otherwise indicated. The Company believes
that the present value of estimated future net revenues before
109
<PAGE>
income taxes, while not in accordance with generally accepted accounting
principles, is an important financial measure used by investors in independent
oil and natural gas producers for evaluating the relative significance of oil
and natural gas properties and acquisitions. The present value of estimated
future net revenues should not be construed as an alternative to the
Standardized Measure, as determined in accordance with generally accepted
accounting principles.
"PRODUCING WELL," "PRODUCTION WELL" OR "PRODUCTIVE WELL." A well that is
producing oil or natural gas or that is capable of production.
"PROVED DEVELOPED RESERVES." Proved developed reserves are those quantities
of crude oil, natural gas and natural gas liquids that, upon analysis of
geological and engineering data, are expected with reasonable certainty to be
recoverable in the future from known oil and natural gas reservoirs under
existing economic and operating conditions. This classification includes: (a)
proved developed producing reserves, which are those expected to be recovered
from currently producing zones under continuation of present operating
methods; and (b) proved developed non-producing reserves, which consist of (i)
reserves from wells that have been completed and tested but are not yet
producing due to lack of market or minor completion problems that are expected
to be corrected, and (ii) reserves currently behind the pipe in existing wells
which are expected to be productive due to both the well log characteristics
and analogous production in the immediate vicinity of the well.
"PROVED RESERVES." The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
"PROVED UNDEVELOPED RESERVES." Proved reserves that may be expected to be
recovered from existing wells that will require a relatively major expenditure
to develop or from undrilled acreage adjacent to productive units that are
reasonably certain of production when drilled.
"ROYALTY INTEREST." An interest in an oil and natural gas property entitling
the owner to a share of oil and natural gas production free of costs of
production.
"STANDARDIZED MEASURE." The standardized measure of discounted net cash
flows related to the Company's proved oil, natural gas and natural gas liquids
reserves net of future production and development costs and future income
taxes calculated in accordance with generally accepted accounting principles.
The calculation is based on a valuation of proved reserves using discounted
cash flows based on year-end prices, costs and economic conditions and a 10%
discount rate.
"WORKING INTEREST." The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and to a share
of production, subject to all royalties, overriding royalties and other
burdens and to all costs of exploration, development and operations and all
risks in connection therewith.
110
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Pro Forma Condensed Financial Statements:
Pro Forma Condensed Statement of Operations for the three months ended
March 31, 1996......................................................... F-3
Pro Forma Condensed Statement of Operations for the year ended December
31, 1995............................................................... F-4
Notes to Pro Forma Condensed Financial Statements....................... F-5
Historical Financial Statements:
Unaudited Consolidated Balance Sheet as of March 31, 1996............... F-8
Unaudited Consolidated Statements of Operations for the three months
ended March 31, 1995, the 47 day period ended February 16, 1996 and the
44 day period ended March 31, 1996..................................... F-9
Unaudited Consolidated Statements of Cash Flows for the three months
ended March 31, 1995, the 47 day period ended February 16, 1996 and the
44 day period ended March 31, 1996..................................... F-10
Unaudited Consolidated Statement of Stockholders' Equity for the 47 day
period ended February 16, 1996 and the 44 day period ended March 31,
1996................................................................... F-11
Notes to Unaudited Consolidated Financial Statements.................... F-12
Report of Ernst and Young LLP, Independent Auditors..................... F-20
Consolidated Balance Sheets as of December 31, 1994 and 1995............ F-21
Consolidated Statements of Operations for the years ended December 31,
1993, 1994 and 1995.................................................... F-22
Consolidated Statements of Cash Flows for the years ended December 31,
1993, 1994 and 1995.................................................... F-23
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 1993 1994 and 1995........................................ F-24
Notes to Consolidated Financial Statements.............................. F-25
</TABLE>
F-1
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
PRO FORMA CONDENSED FINANCIAL STATEMENTS
The accompanying unaudited pro forma condensed statements of operations of
Coda Energy, Inc. (the "Company") for the year ended December 31, 1995 and the
three months ended March 31, 1996, have been prepared as if the acquisition of
the Snyder Properties, the Merger, the sale of the Private Notes and the
Exchange Offer (each as more fully described in the notes to pro forma
condensed financial statements) had occurred on January 1, 1995. Because the
Exchange Notes are being issued under the same financial terms and conditions
as the Private Notes, the Exchange Offer has no impact on the pro forma data.
The historical financial information for the Company was obtained from the
historical consolidated financial statements of the Company contained
elsewhere in this document. The historical financial information of the Snyder
Properties was obtained from internal reports prepared by the seller and is
unaudited. The unaudited pro forma condensed financial statements do not
purport to represent the results of operations which would have occurred had
such transactions been consummated on the dates indicated or the results of
operation for any future date or period. These unaudited pro forma condensed
financial statements should be read in conjunction with the historical
financial statements of the Company.
F-2
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
PRO FORMA CONDENSED STATEMENT OF OPERATIONS
THREE MONTHS ENDED MARCH 31, 1996
(UNAUDITED, IN THOUSANDS)
<TABLE>
<CAPTION>
HISTORICAL PRO FORMA
---------------------- ADJUSTMENTS FOR
47 DAYS 44 DAYS THE MERGER, THE
ENDED ENDED SALE OF THE PRIVATE
FEBRUARY 16, MARCH 31, NOTES AND THE
1996 1996 EXCHANGE OFFER PRO FORMA
------------ --------- ------------------- ---------
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales..... $ 8,079 $ 8,964 $17,043
Gas gathering and
processing........... 5,322 4,799 10,121
Other income.......... 168 201 369
------- -------- -------
13,569 13,964 27,533
------- -------- -------
Costs and expenses:
Oil and gas
production........... 3,607 3,885 7,492
Gas gathering and
processing........... 4,567 3,888 8,455
Depletion,
depreciation and
amortization......... 2,583 3,498 $ 816 (/1/) 6,897
General and
administrative....... 320 352 672
(333)(/2/)
Interest.............. 1,102 2,087 4,300
1,444 (/3/)
Stock option
compensation......... 3,199 -- (3,199)(/4/) --
Writedown of oil and
gas properties....... -- 83,305 (83,305)(/5/) --
------- -------- -------- -------
15,378 97,015 (84,577) 27,816
------- -------- -------- -------
Income (loss) before
income taxes........... (1,809) (83,051) 84,577 (283)
Income tax expense
(benefit).............. (511) (29,915) 30,422 (/6/) (4)
------- -------- -------- -------
Net income (loss)....... (1,298) (53,136) 54,155 (279)
Preferred stock dividend
requirements........... -- 361 389 (/7/) 750
------- -------- -------- -------
Net income (loss)
available for common
stockholders'.......... $(1,298) $(53,497) $ 53,766 $(1,029)
======= ======== ======== =======
</TABLE>
F-3
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
PRO FORMA CONDENSED STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 1995
(IN THOUSANDS)
<TABLE>
<CAPTION>
PRO FORMA PRO FORMA
ADJUSTMENTS ADJUSTMENTS
SNYDER FOR THE FOR THE MERGER,
PROPERTIES ACQUISITION OF THE SALE OF THE
COMPANY NINE MONTHS THE SNYDER PRIVATE NOTES AND
HISTORICAL HISTORICAL PROPERTIES THE EXCHANGE OFFER PRO FORMA
---------- ----------- -------------- ------------------ ---------
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales..... $60,997 $5,159 $ 66,156
Gas marketing,
gathering, and
processing........... 35,634 35,634
Other income.......... 1,207 921 $ (921)(/8/) 1,207
------- ------ ------- --------
97,838 6,080 (921) 102,997
------- ------ ------- --------
Costs and expenses:
Oil and gas
production........... 27,119 3,425 30,544
Gas gathering and
processing........... 30,473 30,473
Depletion,
depreciation, and
amortization......... 19,715 1,295 (/9/) $ 7,499 (/1/) 28,509
General and
administrative....... 2,898 (921)(/8/) 1,977
(2,562)(/2/)
Interest.............. 8,676 899 (/1//0/) 18,563
11,550 (/3/)
------- ------ ------- --------- --------
88,881 3,425 1,273 16,487 110,066
------- ------ ------- --------- --------
Income (loss) before
income taxes........... 8,957 2,655 (2,194) (16,487) (7,069)
Income tax expense
(benefit).............. 3,202 157 (/1//1/) (5,935)(/6/) (2,576)
------- ------ ------- --------- --------
Net income (loss)....... 5,755 2,655 (2,351) (10,552) (4,493)
Preferred stock
dividends.............. -- 3,000 (/7/) 3,000
------- ------ ------- --------- --------
Net income (loss)
applicable to common
stockholders........... $ 5,755 $2,655 $(2,351) $ (13,552) $ (7,493)
======= ====== ======= ========= ========
</TABLE>
F-4
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO PRO FORMA CONDENSED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE A--PRO FORMA ADJUSTMENTS FOR THE MERGER, THE SALE OF THE PRIVATE NOTES
AND THE EXCHANGE OFFER
On February 16, 1996, pursuant to an Agreement and Plan of Merger dated as
of October 30, 1995 (as subsequently amended, the "Merger Agreement") by and
among Coda Energy, Inc. ("Coda"), Joint Energy Development Investments Limited
Partnership ("JEDI"), an affiliate of Enron Capital & Trade Resources Corp.,
and Coda Acquisition, Inc. ("Purchaser"), a subsidiary of JEDI, JEDI acquired
Coda through a merger (the "Merger") at a price of $7.75 per share in cash.
The sources and uses of funds related to the Merger are as follows (in
millions):
<TABLE>
<S> <C>
Sources of funds:
Credit agreement...................................................... $ 95.0
JEDI debt............................................................. 100.0
Redeemable preferred stock issued to JEDI............................. 20.0
Common stock issued to JEDI........................................... 90.0
------
$305.0
======
Uses of funds:
Payments to Coda stockholders, warrantholders and optionholders....... $176.2
Repayment of former credit facility and other indebtedness............ 122.7
Merger costs and other expenses....................................... 6.1
------
$305.0
======
</TABLE>
Concurrently with the execution of the Merger Agreement, JEDI and Purchaser
entered into certain agreements with members of management of the Company
concerning their employment with and/or equity participation in the Company
after the Merger.
The Merger has been accounted for using the purchase method of accounting.
As such, JEDI's cost of acquiring Coda has been allocated to the assets and
liabilities acquired based on estimated fair values. As a result, the
Company's financial position and operating results subsequent to the date of
the Merger reflect a new basis of accounting and are not comparable to prior
periods.
Following the Merger, the Company issued $110 million principal amount of
Senior Subordinated Notes due 2006 and used $100 million of the proceeds
therefrom to repay all of the subordinated debt owed to JEDI. The remaining
net proceeds together with the reimbursements described below and other
available cash were used to repay approximately $10.0 million in debt
outstanding under the Credit Agreement. ECT Securities Corp. refunded to the
Company $2.0 million in fees paid in connection with the issuance of the JEDI
debt. Further, the Purchasers of the Private Notes reimbursed the Company for
costs and expenses in the amount of $550,000.
The Company is offering to exchange the Exchange Notes for the Private
Notes. The Private Notes were sold in transactions exempt from registration
under the Securities Act on March 18, 1996. The Exchange Offer is intended to
satisfy certain of the Company's obligations under the Registration Rights
Agreement and Purchase Agreement. Because the Exchange Notes are being issued
under the same financial terms and conditions as the Private Notes, the
Exchange Offer has no impact on the pro forma data.
F-5
<PAGE>
The accompanying unaudited pro forma condensed statement of operations has
been prepared as if the Merger, the sale of the Private Notes and the Exchange
Offer had occurred on January 1, 1995 and reflects the following adjustments:
(1) To adjust depletion, depreciation, and amortization to reflect JEDI's
purchase price allocated to property and equipment.
(2) To adjust interest expense to give effect to the net reduction of
approximately $36.8 million under the Company's credit facility and
repayment of the note payable to an officer of the Company, partially
offset by an increase in the interest rate on borrowings under the new
credit facility of .25%.
(3) To record interest on the Notes at an interest rate of 10 1/2%.
(4) To eliminate stock option compensation expense resulting from the
Merger.
(5) To eliminate the writedown of oil and gas properties resulting from
the Merger.
(6) To adjust the provision for income taxes for the change in financial
taxable income resulting from adjustments (1), (2), (3), (4) and (5).
(7) To record the cumulative dividend requirements of the redeemable
preferred stock issued to JEDI.
NOTE B--PRO FORMA ADJUSTMENTS FOR THE ACQUISITION OF THE SNYDER PROPERTIES
In October 1995, the Company acquired interests in 63 producing oil and gas
properties located in west Texas from Snyder Oil Company (the "Snyder
Properties"). The aggregate purchase price was $17.1 million in cash, of which
$16.0 million was financed by borrowings under the Company's then-existing
credit agreement. The acquisition was accounted for by the purchase method of
accounting. Prior to the acquisition, the Snyder Properties were included in
the consolidated financial statements of the seller and were not accounted for
as a separate entity.
The accompanying unaudited pro forma condensed statement of operations has
been prepared as if the acquisition of the Snyder Properties occurred on
January 1, 1995 and reflects the following adjustments:
(8) To reclassify fees from overhead charges billed to working interest
owners, which are classified as a reduction of general and administrative
expenses in the Company's consolidated statements of operations.
(9) To adjust depletion, depreciation and amortization to reflect the
effect of the acquisition of the Snyder Properties. Depletion, depreciation
and amortization of oil and gas properties is computed using the unit-of-
production method.
(10) To adjust interest expense for the estimated amounts the Company
would have incurred on the incremental borrowings pursuant to the Company's
credit facility used to acquire the Snyder Properties. The interest rate
used was based on the interest rate options provided for in the Company's
credit facility in effect at the time.
(11) To adjust the provision for income taxes for the change in financial
taxable income resulting from inclusion of the historical results of the
Snyder Properties and adjustments (9) and (10).
F-6
<PAGE>
NOTE C--PRO FORMA SUPPLEMENTAL OIL AND GAS RESERVE AND STANDARDIZED MEASURE
INFORMATION
The following summary of pro forma quantities of proved reserves was
prepared by adjusting the Company's historical quantities for the effects of
the acquisition of the Snyder Properties assuming such acquisition had been
consummated January 1, 1995.
PRO FORMA PROVED RESERVES
<TABLE>
<CAPTION>
OIL (MBBLS) GAS (MMCF)
----------- ----------
<S> <C> <C>
December 31, 1994........................................ 43,789 47,093
Purchases of reserves in place........................... 3,017 492
Extensions............................................... 783 3,173
Revision of previous estimates........................... (1,011) 1,459
Production............................................... (3,440) (4,895)
Sales of reserves in place............................... (548) (10,192)
------ -------
December 31, 1995........................................ 42,590 37,130
====== =======
PRO FORMA PROVED DEVELOPED RESERVES
<CAPTION>
OIL (MBBLS) GAS (MMCF)
----------- ----------
<S> <C> <C>
December 31, 1994........................................ 23,379 39,089
December 31, 1995........................................ 25,877 31,496
</TABLE>
The following are the principal sources of changes in the pro forma
standardized measure of discounted future net cash flows (in thousands):
<TABLE>
<S> <C>
Pro forma standardized measure of discounted future net cash flows
at December 31, 1994............................................... $188,132
Pro forma changes in the standardized measure of discounted future
net cash flows:
Sales and transfers of oil and gas produced, net of production
costs............................................................ (35,612)
Net changes in prices and production costs........................ 38,972
Extensions and discoveries, net of future development and
production costs................................................. 15,932
Development costs incurred during the period...................... 14,464
Revisions of previous quantity estimates.......................... (19,084)
Sales of reserves in place........................................ (6,323)
Purchases of reserves in place.................................... 15,337
Accretion of discount............................................. 40,719
Changes in income taxes........................................... (31,795)
--------
Net change...................................................... 32,610
--------
Standardized measure of discounted future net cash flows at December
31, 1995........................................................... $220,742
========
</TABLE>
F-7
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED BALANCE SHEET
MARCH 31, 1996
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
<TABLE>
<S> <C>
ASSETS
Current Assets:
Cash and cash equivalents......................................... $ 3,491
Accounts receivable--revenue...................................... 11,536
Accounts receivable--joint interest and other..................... 2,768
Other current assets.............................................. 2,303
--------
20,098
--------
Oil and gas properties (full cost accounting method):
Proved oil and gas properties..................................... 245,080
Unproved oil and gas properties................................... 1,000
Less accumulated depletion, depreciation and amortization....... 3,035
--------
243,045
--------
Gas plants and gathering systems.................................... 33,705
Less accumulated depreciation..................................... 329
--------
33,376
--------
Other properties, net............................................... 4,169
--------
Other assets........................................................ 3,747
--------
$304,435
========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt and notes payable............ $ 120
Accounts payable--trade........................................... 6,213
Accounts payable--revenue and other............................... 3,572
Accrued interest.................................................. 738
Income taxes payable.............................................. 93
--------
10,736
--------
Long-term debt--less current maturities............................. 81,719
--------
10 1/2% Senior Subordinated Notes................................... 110,000
--------
Deferred income taxes............................................... 41,493
--------
Commitments and contingent liabilities
15% Cumulative redeemable preferred stock, 40 shares of $.01 par
value authorized; 20 shares issued and outstanding................. 20,000
--------
Common stockholders' equity of management, subject to put and call
rights............................................................. 4,560
Less related notes receivable..................................... (937)
--------
3,623
--------
Other common stockholders' equity:
Common stock...................................................... 9
Additional paid-in capital........................................ 89,991
Retained earnings (deficit)....................................... (53,136)
--------
36,864
--------
$304,435
========
</TABLE>
See Notes to Unaudited Consolidated Financial Statements.
F-8
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)
<TABLE>
<CAPTION>
PRE MERGER POST MERGER
---------------------- -----------
THREE
MONTHS 47 DAYS 44 DAYS
ENDED ENDED ENDED
MARCH 31, FEBRUARY 16, MARCH 31,
1995 1996 1996
--------- ------------ -----------
<S> <C> <C> <C>
Revenues:
Oil and gas sales........................................................................ $14,948 $ 8,079 $ 8,964
Gas gathering and processing............................................................. 7,904 5,322 4,799
Other income............................................................................. 187 168 201
------- ------- --------
23,039 13,569 13,964
------- ------- --------
Costs and expenses:
Oil and gas production................................................................... 6,563 3,607 3,885
Gas gathering and processing............................................................. 6,730 4,567 3,888
Depletion, depreciation and amortization................................................. 4,870 2,583 3,498
General and administrative............................................................... 707 320 352
Interest................................................................................. 2,068 1,102 2,087
Stock option compensation................................................................ -- 3,199 --
Writedown of oil and gas properties...................................................... -- -- 83,305
------- ------- --------
20,938 15,378 97,015
------- ------- --------
Income (loss) before income taxes.......................................................... 2,101 (1,809) (83,051)
Income tax expense (benefit)............................................................... 796 (511) (29,915)
------- ------- --------
Net income (loss).......................................................................... 1,305 (1,298) (53,136)
Preferred stock dividend requirements...................................................... -- -- 361
------- ------- --------
Net income (loss) available for common stockholders'....................................... $ 1,305 $(1,298) $(53,497)
- --------------------------------------------------
======= ======= ========
</TABLE>
See Notes to Unaudited Consolidated Financial Statements
F-9
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
PRE MERGER POST MERGER
------------------------- -----------
THREE MONTHS 47 DAYS 44 DAYS
ENDED ENDED ENDED
MARCH 31, FEBRUARY 16, MARCH 31,
1995 1996 1996
------------ ------------ -----------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income (loss)...................................................................... $ 1,305 $(1,298) $ (53,136)
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization............................................. 4,870 2,583 3,498
Writedown of oil and gas properties.................................................. -- -- 83,305
Deferred income tax expense (benefit)................................................ 657 (511) (30,000)
Stock option compensation............................................................ -- 3,199 --
Other................................................................................ 160 6 --
Effect of changes in:
Accounts receivable................................................................. (628) 3,386 (4,630)
Other current assets................................................................ (127) (63) (207)
Accounts payable and other current liabilities...................................... (1,115) (4,166) 2,631
-------- ------- ---------
Net cash provided by operating activities......................................... 5,122 3,136 1,461
-------- ------- ---------
Cash flows from investing activities:
Additions to oil and gas properties.................................................... (4,955) (1,717) (770)
Proceeds from sale of assets........................................................... 1,193 110 53
Purchase of Coda by JEDI, net of $740 cash acquired.................................... -- -- (179,373)
Gas plant and gathering systems and other property additions........................... (7,346) (114) (43)
Investment in marketable equity securities............................................. (573) -- --
Payments received on amounts due from stockholders..................................... -- 130 124
Other.................................................................................. 52 -- --
-------- ------- ---------
Net cash used by investing activities............................................. (11,629) (1,591) (180,009)
-------- ------- ---------
Cash flows from financing activities:
Proceeds from bank borrowings.......................................................... 7,500 -- --
Proceeds from issuance of subordinated debt............................................ -- -- 210,000
Proceeds from issuances of common and preferred stock.................................. -- -- 110,026
Repayment of bank borrowings and subordinated debt..................................... (2,727) (5,019) (137,667)
Proceeds from exercise of options and warrants......................................... 402 -- --
Repurchases of common stock............................................................ (2,125) -- --
Financing costs........................................................................ -- (390) (320)
-------- ------- ---------
Net cash provided (used) by financing activities.................................. 3,050 (5,409) 182,039
-------- ------- ---------
Increase (decrease) in cash............................................................ (3,457) (3,864) 3,491
Cash at beginning of period............................................................ 6,474 4,604 --
-------- ------- ---------
Cash at end of period.................................................................. $ 3,017 $ 740 $ 3,491
======== ======= =========
Supplemental cash flow information:
Interest paid.......................................................................... $ 2,545 $ 1,544 $ 1,317
======== ======= =========
Income taxes paid...................................................................... $ 500 $ -- $ 120
- --------------------------------------------------
======== ======= =========
</TABLE>
See Notes to Unaudited Consolidated Financial Statements
F-10
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
15% CUMULATIVE COMMON STOCKHOLDERS' EQUITY
REDEEMABLE OF MANAGEMENT, SUBJECT TO OTHER COMMON
PREFERRED STOCK PUT AND CALL RIGHTS STOCKHOLDER'S EQUITY
----------------- ------------------------------ -----------------------
ADDITIONAL RETAINED
NOTES PAR PAID-IN EARNINGS
SHARES AMOUNT SHARES AMOUNT RECEIVABLE SHARES VALUE CAPITAL (DEFICIT)
------- --------- ------- --------- ----------- ------ ----- ---------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Pre Merger:
Balances at December
31, 1995.............. 22,089 $442 $68,671 $ 10,075
Stock option
compensation.......... 3,199
Net loss for the period
January 1, 1996
through February 16,
1996.................. (1,298)
----- --------- ------ --------- -------- ------ ---- ------- --------
Balances at February 16,
1996................... -- -- -- -- -- 22,089 $442 $71,870 $ 8,777
===== ========= ====== ========= ======== ====== ==== ======= ========
Post Merger:
Transactions related to
the merger:
Common stock issued to
management investors
in exchange for common
stock, options,
warrants, notes
receivable and cash... 14 $4,560 $(937)
Common stock issued to
JEDI for cash......... 900 $ 9 $89,991
Preferred stock issued
to JEDI for cash...... 20 $20,000
Net loss for the period
from February 17, 1996
through March 31,
1996.................. $(53,136)
----- --------- ------ --------- -------- ------ ---- ------- --------
Balances at March 31,
1996................... 20 $20,000 14 $4,560 $(937) 900 $ 9 $89,991 $(53,136)
===== ========= ====== ========= ======== ====== ==== ======= ========
</TABLE>
See Notes to Unaudited Consolidated Financial Statements
F-11
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
1. THE MERGER
On February 16, 1996, pursuant to an Agreement and Plan of Merger dated as
of October 30, 1995 (as amended, the "Merger Agreement"), by and among Coda
Energy, Inc. ("Coda" or together with its subsidiaries the "Company"), Joint
Energy Development Investments Limited Partnership ("JEDI"), which is an
affiliate of Enron Capital & Trade Resources Corp. ("ECT"), and Coda
Acquisition, Inc. ("CAI"), which was a subsidiary of JEDI, JEDI acquired Coda
through a merger (the "Merger") at a price of $7.75 per share in cash (for an
aggregate purchase price of approximately $176.2 million). Concurrently with
the execution of the Merger Agreement, JEDI and CAI entered into certain
agreements with members of the Company's management (the "Management Group"),
providing for a continuing role of management in the Company after the Merger.
Following consummation of the Merger, the Management Group owns approximately
5% of Coda's common stock on a fully-diluted basis. JEDI owns the remaining
95%.
The sources and uses of funds related to financing the Merger were as
follows:
SOURCES OF FUNDS
(IN MILLIONS)
<TABLE>
<S> <C>
Credit Agreement.................................................. $ 95.0
JEDI Debt(1)...................................................... 100.0
Redeemable Preferred Stock issued to JEDI......................... 20.0
Common Stock issued to JEDI....................................... 90.0
------
Total........................................................... $305.0
======
USES OF FUNDS
(IN MILLIONS)
Payments to Coda stockholders, warrantholders and optionholders... $176.2
Repayment of former credit facility and other indebtedness........ 122.7
Merger costs and other expenses................................... 6.1
------
Total........................................................... $305.0
======
</TABLE>
--------
(1) Represents indebtedness incurred by CAI and assumed by Coda to
fund a portion of the consideration paid in the Merger.
The Merger has been accounted for using the purchase method of accounting.
As such, JEDI's cost of acquiring Coda has been allocated to the assets and
liabilities acquired based on estimated fair values. As a result, the
Company's financial position and operating results subsequent to the date of
the Merger reflect a new basis of accounting and are not comparable to prior
periods.
The allocation of JEDI's purchase price to the assets and liabilities of
Coda resulted in a significant increase in the carrying value of the Company's
oil and gas properties. Under the full cost method of accounting, the carrying
value of oil and gas properties (net of related deferred taxes) is generally
not permitted to exceed the sum of the present value (10% discount rate) of
estimated future net cash flows (after tax) from proved reserves, based on
current prices and costs, plus the lower of cost or estimated fair value of
unproved properties (the "cost center ceiling"). Based upon the allocation of
JEDI's purchase price and estimated proved reserves and product prices in
effect at the date of the
F-12
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Merger, the purchase price allocated to oil and gas properties was in excess
of the cost center ceiling by approximately $83.3 million ($53.3 million net
of related deferred taxes). The resulting writedown is a non-cash charge and
has been included in the results of operations for the period ended March 31,
1996.
2. ACCOUNTING AND REPORTING POLICIES
The consolidated financial statements include the accounts of Coda Energy,
Inc., its majority-owned subsidiaries and its pro rata share of the assets,
liabilities and operations of oil and gas partnerships and joint ventures. All
significant intercompany balances and transactions have been eliminated in
consolidation. Certain reclassifications have been made to prior years'
amounts to conform to the current year presentation.
The accompanying consolidated financial statements, which should be read in
conjunction with the audited consolidated financial statements for the year
ended December 31, 1995, reflect all adjustments (consisting only of normal
recurring accruals) which are, in the opinion of management, necessary to
present fairly the financial position as of March 31, 1996, and the results of
operations and cash flows for the periods ended March 31, 1995, February 16,
1996 and March 31, 1996. The results for the period ended March 31, 1996, are
not necessarily indicative of results for a full year.
Fees from overhead charges billed to working interest owners, including the
Company, of $1.2 million, $848,000 and $808,000 for the periods ended March
31, 1995, February 16, 1996 and March 31, 1996, respectively, have been
classified as a reduction of general and administrative expenses in the
accompanying consolidated statements of operations.
3. CREDIT AGREEMENT
On February 14, 1996, the Company entered into a credit agreement with
NationsBank of Texas, N.A. ("NationsBank"), as lender and as agent, and
additional lenders named therein (the "Credit Agreement"). The Credit
Agreement is guaranteed by all of the Company's subsidiaries and provides for
a revolving credit facility in an amount up to $250.0 million. The current
borrowing base is $115.0 million and is subject to redetermination: (i)
semiannually, (ii) upon the sale of Taurus and (iii) upon issuance of public
subordinated debt in an amount greater than $100.0 million. The lenders under
the Credit Agreement have agreed to waive their right to redetermine the
borrowing base with respect to the issuance of the Notes. At March 31, 1996,
$80.0 million was outstanding under the Credit Agreement and $35.0 million was
available for borrowing thereunder.
The Credit Agreement is unsecured. The Company has provided the lenders with
first lien deeds of trust on its oil and natural gas assets which will not
become effective, and the lenders have agreed not to file, unless (i) 80% of
any outstanding borrowings in excess of the borrowing base is not repaid
within a 90 day period, (ii) cash collateral securing a hedge transaction
exceeds 20% of the borrowing base or (iii) an event of default or a material
adverse event, as defined in the Credit Agreement, occurs.
So long as no default (as defined in the Credit Agreement) is continuing,
the Company has the option of having all or any portion of the amount borrowed
under the Credit Agreement be the subject of one of the following interest
rates: (i) NationsBank's prime rate, (ii) the CD Rate plus 1 1/4% to 1 5/8%
based upon the ratio of outstanding debt to the available borrowing base and
(iii) LIBOR plus 1 1/4% to 1 5/8% based upon the ratio of outstanding debt to
the available borrowing base. The Company must also pay a commitment fee of
between 0.375% to 0.425% on the unused portion of the credit facility.
F-13
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
The Credit Agreement contains various restrictive covenants, including
limitations on the granting of liens, restrictions on the issuance of
additional debt, restrictions on investments, a requirement to maintain
positive working capital, and restrictions on dividends and stock repurchases.
The Credit Agreement also contains requirements that JEDI, Enron, or certain
affiliates of JEDI must continue to own a majority of the outstanding equity
of the Company and must have the ability to elect the majority of the Board of
Directors and that certain members of management maintain specified levels of
equity ownership in the Company and continue their employment with the
Company. The Credit Agreement matures on February 16, 2001.
4. LONG-TERM DEBT
The Company's 12% Senior Subordinated Debentures due 2000 (the "Debentures")
bear interest at 12% per annum, payable semiannually. At March 31, 1996,
approximately $1.2 million in aggregate principal amount of the Debentures was
outstanding. On March 28, 1996, the Company gave notice of redemption, prior
to maturity, to each of the record holders of the outstanding Debentures. The
outstanding Debentures were redeemed on May 1, 1996 at a redemption price of
100.0% of the principal amount of the Debentures plus accrued and unpaid
interest thereon. On May 1, 1996, the Company deposited with the trustee of
the Debentures funds sufficient to so redeem the Debentures, and thereafter
interest on the Debentures ceased to accrue.
5. 10 1/2% SENIOR SUBORDINATED NOTES
On March 18, 1996, the Company completed the sale of $110 million principal
amount of 10 1/2% Senior Subordinated Notes due 2006 (the "Notes"). The
proceeds of the Notes were used to fully repay the JEDI debt assumed in the
Merger and to partially repay bank debt. The Notes bear interest at an annual
rate of 10 1/2% payable semiannually in arrears on April 1 and October 1 of
each year. The Notes are general, unsecured obligations of the Company, are
subordinated in right of payment to all Senior Debt (as defined in the
Indenture governing the Notes) of Coda, and are senior in right of payment to
all future subordinated debt of the Company. The claims of the holders of the
Notes will be subordinated to Senior Debt, which, as of March 31, 1996, was
$81.8 million.
The Notes were issued pursuant to an Indenture, which contains certain
covenants that, among other things, limit the ability of Coda and its
Restricted Subsidiaries to incur additional indebtedness and issue
Disqualified Stock, pay dividends, make distributions, make investments, make
certain other restricted payments, enter into certain transactions with
affiliates, dispose of certain assets, incur liens securing pari passu or
subordinated indebtedness of Coda and engage in mergers and consolidations.
The Notes are not redeemable at Coda's option prior to April 1, 2001. After
April 1, 2001, the Notes will be subject to redemption at the option of Coda,
in whole or in part, at the redemption prices set forth in the Indenture, plus
accrued and unpaid interest thereon to the applicable redemption date. In
addition, until March 12, 1999, up to $27.5 million in aggregate principal
amount of Notes are redeemable, at the option of Coda on any one or more
occasions from the net proceeds of an offering of common equity of Coda, at a
price of 110.5% of the aggregate principal amount of the Notes, together with
accrued and unpaid interest thereon to the date of the redemption; provided,
however, that at least $82.5 million in aggregate principal amount of Notes
must remain outstanding immediately after the occurrence of such redemption;
provided, further, that any such redemption shall occur within 75 days of the
date of the closing of such offering of common equity.
In the event of a Change of Control (as defined in the Indenture), holders
of the Notes will have the right to require Coda to repurchase their Notes, in
whole or in part, at a price in cash equal to 101% of the aggregate principal
amount thereof, plus accrued and unpaid interest thereon to the date of
F-14
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
repurchase. The Indenture requires that, prior to such a repurchase but in any
event within 90 days of such Change of Control, Coda must either repay all
Senior Debt or obtain any required consent to such repurchase.
Coda's payment obligations under the Notes are fully, unconditionally and
jointly and severally guaranteed on a senior subordinated basis by all of
Coda's current subsidiaries and future Restricted Subsidiaries (as defined in
the Indenture). Such guarantees are subordinated to the guarantees of Senior
Debt issued by the Guarantors under the Credit Agreement and to other
guarantees of Senior Debt issued in the future.
The combined condensed financial information of the Company's current
subsidiaries, the Guarantors, is as follows:
<TABLE>
<CAPTION>
MARCH 31,
1996
---------
<S> <C>
Current assets........................................................ $ 6,928
Oil and gas properties, net........................................... 55,601
Gas plants and gathering systems, net................................. 33,040
Other properties, net and other assets................................ 1,554
-------
Total assets........................................................ $97,123
=======
Current liabilities................................................... $ 4,965
Intercompany payables................................................. 49,699
Deferred income taxes................................................. 15,612
Stockholder's equity.................................................. 26,847
-------
Total liabilities and stockholder's equity.......................... $97,123
=======
</TABLE>
<TABLE>
<CAPTION>
POST
PRE MERGER MERGER
------------ ---------
47 DAYS 44 DAYS
ENDED ENDED
FEBRUARY 16, MARCH 31,
1996 1996
------------ ---------
<S> <C> <C>
Revenues:
Oil and gas sales.................................................................................... $ 2,529 $ 3,180
Gas gathering and processing......................................................................... 5,322 4,799
Other income......................................................................................... 2 47
------- ---------
7,853 8,026
Costs and expenses:
Oil and gas production............................................................................... 843 884
Gas gathering and processing......................................................................... 4,567 3,888
Depletion, depreciation and amortization............................................................. 1,039 1,350
General and administrative........................................................................... 435 504
Interest............................................................................................. 460 467
Writedown of oil and gas properties.................................................................. -- 19,159
------- ---------
7,344 26,252
------- ---------
Income (loss) before income taxes...................................................................... 509 (18,226)
Income tax expense (benefit)........................................................................... 277 (6,591)
- --------------------------------------------------
------- ---------
Net income (loss)...................................................................................... $ 232 $ (11,635)
======= =========
</TABLE>
F-15
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
6. PREFERRED STOCK
Under Coda's Restated Certificate of Incorporation, the Board of Directors
is authorized to issue up to 40,000 shares of preferred stock, par value $0.01
per share. All 40,000 shares of preferred stock are designated as "15%
Cumulative Preferred Stock." The holders of each share of Preferred Stock are
entitled to receive, when and as declared by the Board of Directors,
cumulative preferential dividends, at the rate of $150.00 per share per annum.
There are currently 20,000 shares of Preferred Stock issued and outstanding.
Shares of Preferred Stock in excess of such 20,000 shares shall be issuable
only for the purpose of paying dividends on the Preferred Stock.
As long as any shares of Preferred Stock are outstanding, no dividends
whatsoever, whether paid in cash, stock or otherwise (except for dividends
paid in shares of common stock, either in the form of a stock split or stock
dividend), may be paid or declared, nor may any distribution be made, on any
common stock to the holders of such stock, unless certain conditions are met.
Coda's Restated Certificate of Incorporation requires that Coda redeem all
the issued and outstanding shares of Preferred Stock at a redemption price of
$1,000 per share, plus all accrued and unpaid dividends (including undeclared
dividends) to the date of redemption, if Coda has sufficient funds legally
available for such redemption and if such redemption would not violate or
conflict with any loan agreement, credit agreement, note agreement, indenture
or other agreement relating to indebtedness to which Coda is a party, on or
before the fifth business day after the earliest to occur of the following:
(i) the closing of the sale by Coda of Taurus Energy Corp. and (ii) a Trigger
Event, as such term is defined in the Stockholders Agreement. The Preferred
Stock may be redeemed by Coda at its option, as a whole or in part, to the
extent Coda shall have funds legally available for such redemption, at any
time or from time to time at a redemption price of $1,000 per share, plus all
accrued and unpaid dividends (including undeclared dividends) to the date of
redemption. Such redemption, whether required or optional, is restricted by
the Credit Agreement and the Indenture.
Upon the complete liquidation, dissolution, or winding up of Coda, whether
voluntarily or involuntarily, the holders of Preferred Stock shall be
entitled, after payment or provision for payment of the debts and other
liabilities of Coda but before any distribution is made to the holders of any
common stock, to be paid $1,000 per share plus all accrued and unpaid
dividends (including undeclared dividends), and shall not be entitled to any
further payment.
Except as otherwise provided herein or required by law, the holders of
shares of Preferred Stock are not be entitled to vote on any matters to be
voted on by the stockholders of Coda; provided, however, that so long as any
shares of the Preferred Stock are outstanding, Coda shall not, without the
written consent or the affirmative vote of holders of at least a majority of
the total number of shares
of Preferred Stock then outstanding and voting as a class, (i) amend its
Certificate of Incorporation or Bylaws or (ii) authorize the merger (whether
or not Coda is a surviving corporation in such merger) of Coda, in each case,
if such amendment or merger would alter, change or abolish the powers,
preference or rights of the Preferred Stock so as to affect the holders of the
Preferred Stock adversely.
7. COMMON STOCK
At December 31, 1995, the Company had 40.0 million shares of $.02 par value
common stock authorized with 22.1 million shares issued and outstanding. At
March 31, 1996, the Company had 1.0 million shares of $.01 par value common
stock authorized with 14,000 shares issued to management subject to put and
call rights and 900,000 issued to JEDI for a total of 914,000 shares issued
and outstanding.
F-16
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
8. RELATED PARTY TRANSACTIONS
SUBSCRIPTION AGREEMENT
CAI entered into a Subscription Agreement dated as of October 30, 1995, as
amended by Amendment No. 1 to Subscription Agreement dated as of January 10,
1996, with members of the Management Group (as amended, the "Subscription
Agreement") which provided for the acquisition by such persons of CAI common
stock and the grant to them of nonqualified stock options to purchase shares
of post-Merger common stock (the "Replacement Options") of Coda. Under the
Subscription Agreement, each member of the Management Group who acquired CAI
common stock paid $100 per share for shares thereof, which is the same price
per share paid by JEDI for the remaining shares of CAI common stock. Under the
Subscription Agreement, the Management Group acquired CAI common stock
immediately prior to the effective time of the Merger in exchange for varying
combinations of (i) proceeds from limited recourse promissory notes payable to
CAI in the aggregate principal amount of $937,300 (the "Promissory Notes"),
(ii) Coda common stock, which was valued for this purpose at $7.75 per share,
and (iii) cash. The CAI common stock so acquired was not registered under the
Securities Act or any state securities laws and does not have the benefit of
any registration rights, but is subject to the Stockholders Agreement
described below. By virtue of the Merger, each share of CAI common stock was
converted into one share of Coda common stock.
The Subscription Agreement provided that the Specified Options (representing
certain options to purchase Common Stock held by certain members of the
Management Group) and Specified Warrants (representing certain warrants to
purchase Common Stock held by certain members of the Management Group) would
not be exercised prior to the effective time of the Merger and would, as of
the effective time, be canceled without exercise and without payment of
consideration. Concurrently, the Management Group entered into Nonstatutory
Stock Option Agreements governing the Replacement Options that provided for
the right for a period of 10 years from and after the effective time of the
Merger to purchase shares of post-Merger Coda common stock for $0.01 per
share. However, the Replacement Options may only be exercised while the holder
remains an employee of the Company and for a limited period of time
thereafter. The number of shares of Coda common stock underlying the
Replacement Options each member of the Management Group received is based on
the amount of cash the holder would have received if his Specified Options or
Specified Warrants had been converted into cash in the Merger on the same
basis as other outstanding options and warrants to purchase Common Stock were
converted, divided by the $100 per share purchase price paid by JEDI and the
other Management Group members for their shares of CAI common stock. Thus, if
the Replacement Options are exercised, the holders will have effectively paid
the same purchase price per share as JEDI and the Management Group paid for
their shares of common stock of Coda.
In connection with the issuance of the Replacement Options, the Company
recognized stock option compensation expense of approximately $3.2 million
representing the total amount of cash the holders of the Specified Options and
Specified Warrants would have received if such options and warrants had been
converted to cash in the Merger.
The Promissory Notes will be due on February 16, 2001, bear interest at
5.61%, are secured by the Company common stock purchased with the proceeds
thereof and certain rights of the maker under the Stockholders Agreement
described below, and provide that in no event will an individual maker's
liability thereunder for any deficiency on his respective Promissory Note
(after the sale and disposition of all collateral securing same) exceed 35% of
the original principal balance of the Promissory Note.
F-17
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
STOCKHOLDERS AGREEMENT
CAI, JEDI and the Management Group entered into a Stockholders Agreement
dated as of October 30, 1995, as amended by Amendment No. l to Stockholders
Agreement dated as of January 10, 1996 (as amended, the "Stockholders
Agreement"), which provides generally that all parties, including JEDI and the
Management Group, (i) have rights of first refusal to acquire additional
shares of common stock of Coda that may be issued by Coda and (ii) are
restricted from transferring their Coda common stock. Coda has a right to
match any third party offer to purchase shares of Coda common stock from any
stockholder, and, in the event that Coda does not purchase those shares, the
other stockholders may have a right to include a pro rata portion of their
Coda common stock in the transaction. The Stockholders Agreement provides
that, if the employment of a member of the Management Group terminates for any
reason (including death or disability) other than his voluntary termination
(except upon retirement at age 65 or older or the expiration of the term of
any employment agreement he has with Coda) or his termination by Coda for
cause, then Coda shall have a right to purchase such member's shares of Coda
common stock at a purchase price to be determined from time to time by Coda
pursuant to a formula that values the shares on the basis of a comparison of
the discretionary cash flow and EBITDA (as defined therein) of the Company and
a group of peer companies. The Stockholders Agreement also provides that, if
the employment of a member of the Management Group terminates for any reason
other than voluntary termination or termination of such member for cause, then
such member shall have the right to require Coda to purchase such member's
shares of Coda common stock based on the previously described formula. The
purchase price under the formula will vary depending on the financial
performance of the Company and the group of peer companies. The Stockholders
Agreement provides that each member of the Management Group shall have the
right (the "Special Management Rights") to receive from JEDI, upon the
occurrence of certain events (generally an initial public offering, a business
combination with another person or the liquidation of Coda) (each, a "Trigger
Event"), an amount, which is payable in cash or additional shares of Coda
common stock depending upon the cause of the Trigger Event, designed to result
in the Management Group receiving in connection with the Trigger Event one-
third of the proceeds, attributable to the shares of Coda common stock
purchased by JEDI, above the amount of proceeds necessary for JEDI to achieve
an internal annual rate of return on that investment of 15%. The individual
member's interest in such Special Management Rights is proportional to such
member's ownership of the fully diluted common stock of Coda. The Stockholders
Agreement also provides that if the employment of a member of the Management
Group terminates, his Special Management Rights shall terminate and, if the
termination is other than a voluntary termination or a termination for cause,
he may be entitled to receive an amount based on the discretionary cash flow
and EBITDA formula discussed above. The Stockholders Agreement further
provides that, after the effective time of the Merger, Coda will establish an
employee benefit plan for the benefit of its employees who are not
members of the Management Group and will contribute to the plan 1,900 shares
of Coda common stock. Furthermore, pursuant to the Stockholders Agreement, 4%
of the Special Management Rights will be allocated thereto.
The Stockholders Agreement will terminate and no party thereto will have any
further obligations or rights thereunder upon the earliest to occur of (i) the
termination of the Merger Agreement in accordance with its terms, (ii) October
30, 2005, (iii) the date on which an initial public offering of Coda common
stock or any business transaction involving Coda whereby Coda common stock
becomes a publicly traded security is consummated, (iv) the date of the
dissolution, liquidation or winding-up of Coda and (v) the date of the
delivery to Coda of a written termination notice executed by certain parties
to the Stockholders Agreement.
F-18
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
ENRON
Enron Corp. ("Enron") is the parent of ECT and accordingly may be deemed to
control indirectly both JEDI and the Company. Enron and certain of its
subsidiaries and other affiliates collectively participate in nearly all
phases of the oil and natural gas industry and are, therefore, competitors of
the Company. In addition, ECT and JEDI have provided, and may in the future
provide, and ECT Securities Corp. has assisted, and may in the future assist,
in arranging, financing to non-affiliated participants in the oil and natural
gas industry who are or may become competitors of the Company. Because of
these various conflicting interests, ECT, the Company, JEDI and the Management
Group have entered into the Business Opportunity Agreement which is intended
to make it clear that Enron and its affiliates have no duty to make business
opportunities available to the Company in most circumstances. The Business
Opportunity Agreement also provides that ECT and its affiliates may pursue
certain business opportunities to the exclusion of the Company. The Business
Opportunity Agreement may limit the business opportunities available to the
Company. In addition, pursuant to the Business Opportunity Agreement there may
be circumstances in which the Company will offer business opportunities to
certain affiliates of Enron. If an Enron affiliate is offered such an
opportunity and decides to pursue it, the Company may be unable to pursue it.
9. HEDGING TRANSACTIONS
The following table sets forth the barrels and weighted average NYMEX prices
hedged under various swap agreements entered into as of March 31, 1996.
<TABLE>
<CAPTION>
WEIGHTED
BARRELS AVERAGE
PERIODS COVERED HEDGED PRICE
--------------- ------- --------
<S> <C> <C>
Nine months ending December 31, 1996..................... 530,000 $18.81
Year ending December 31, 1997............................ 375,000 $19.02
</TABLE>
As of March 31, 1996 the Company has open positions for sold call options
covering 25,000 Bbls of oil per month at an option price of $18.30 per Bbl for
the period April 1996 to August 1996, and at an option price of $20.00 per Bbl
for the period from September 1996 to August 1997. During the period ended
February 16, 1996 and March 31, 1996 the Company's oil revenues were decreased
by $14,000 and $250,000, respectively, as a result of hedging transactions.
F-19
<PAGE>
REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS
The Board of Directors and Stockholders
Coda Energy, Inc.
We have audited the accompanying consolidated balance sheets of Coda Energy,
Inc., and subsidiaries (the "Company") as of December 31, 1994 and 1995, and
the related consolidated statements of operations, cash flows, and
stockholders' equity for each of the three years in the period ended December
31, 1995. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position
of Coda Energy, Inc., and subsidiaries at December 31, 1994 and 1995, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1995, in conformity with
generally accepted accounting principles.
ERNST & YOUNG LLP
Dallas, Texas
February 17, 1996, except for the first through the fifth paragraphs of Note
10 as to which the date is March 18, 1996
F-20
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1994 AND 1995
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1994 1995
-------- --------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents.................................. $ 6,474 $ 4,604
Accounts receivable--revenue............................... 7,551 10,598
Accounts receivable--joint interest and other.............. 1,766 2,463
Other current assets....................................... 1,276 2,206
-------- --------
17,067 19,871
Amounts due from stockholders................................ 1,375 81
Oil and gas properties (full cost accounting method)......... 190,967 226,650
Less accumulated depletion, depreciation, and amortiza-
tion...................................................... 39,154 56,042
-------- --------
Oil and gas properties, net.............................. 151,813 170,608
Gas plants and gathering systems, at cost.................... 29,835 38,068
Less accumulated depreciation.............................. 1,492 4,082
-------- --------
Gas plants and gathering systems, net.................... 28,343 33,986
Other properties, net........................................ 2,150 2,142
Other assets................................................. 2,354 2,376
-------- --------
$203,102 $229,064
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt....................... $ 424 $ 453
Accounts payable--trade.................................... 5,954 7,252
Accounts payable--revenue and other........................ 3,599 3,394
Accrued interest........................................... 1,375 342
Income taxes payable....................................... 733 128
-------- --------
12,085 11,569
Long-term debt, less current maturities...................... 105,063 123,907
Deferred income taxes........................................ 11,213 14,400
Commitments and contingencies
Stockholders' equity:
Preferred stock, 7,500 shares authorized; none issued...... -- --
Common stock, $.02 par value; 40,000 shares authorized;
22,228 and 22,089 shares issued at December 31, 1994 and
1995, respectively........................................ 445 442
Additional paid-in capital................................. 69,976 68,671
Retained earnings subsequent to June 30, 1989.............. 4,320 10,075
-------- --------
Total stockholders' equity............................... 74,741 79,188
-------- --------
$203,102 $229,064
======== ========
</TABLE>
See notes to consolidated financial statements.
F-21
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 1993, 1994, AND 1995
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1993 1994 1995
------- ------- -------
<S> <C> <C> <C>
Revenues:
Oil and gas sales.................................... $38,877 $50,683 $60,997
Gas gathering and processing......................... 732 20,081 35,634
Other income......................................... 441 822 1,207
------- ------- -------
40,050 71,586 97,838
Costs and expenses:
Oil and gas production............................... 17,590 21,646 27,119
Gas gathering and processing......................... 570 17,357 30,473
Depletion, depreciation, and amortization............ 10,808 16,419 19,715
General and administrative........................... 2,596 3,144 2,898
Business combination................................. -- 1,829 --
Interest............................................. 4,834 5,281 8,676
------- ------- -------
36,398 65,676 88,881
------- ------- -------
Income before income taxes............................. 3,652 5,910 8,957
Income tax expense..................................... 1,318 2,581 3,202
------- ------- -------
Net income............................................. $ 2,334 $ 3,329 $ 5,755
======= ======= =======
</TABLE>
See notes to consolidated financial statements.
F-22
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1993, 1994, AND 1995
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1993 1994 1995
-------- -------- --------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income...................................... $ 2,334 $ 3,329 $ 5,755
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation, and amortization..... 10,808 16,419 19,715
Deferred income tax expense................... 1,038 1,567 3,187
Amortization of deferred financing costs...... -- 554 101
Amortization of prepaid gas purchases......... -- -- 440
Other......................................... 183 123 55
Effect of changes in:
Accounts receivable.......................... (1,545) 589 (3,849)
Other current assets......................... (221) 60 (558)
Accounts payable and other current
liabilities................................. 3,846 346 (545)
-------- -------- --------
Net cash provided by operating activities.. 16,443 22,987 24,301
Cash flows from investing activities:
Additions to oil and gas properties............. (34,375) (49,732) (41,079)
Additions to gas plant and gathering systems and
other property................................. (646) (4,130) (8,500)
Business combinations........................... (5,074) (3,250) --
Investment in common equity securities.......... -- -- (573)
Payments received on amounts due from
stockholders................................... -- -- 1,294
Proceeds from sale of assets.................... 441 2,515 5,722
Prepaid long-term gas purchases................. -- (1,759) --
Other, net...................................... (137) (423) 106
-------- -------- --------
Net cash used in investing activities...... (39,791) (56,779) (43,030)
Cash flows from financing activities:
Proceeds from common stock offering, net........ 36,128 -- --
Repayment of long-term debt..................... (53,286) (41,542) (11,551)
Proceeds from bank borrowings................... 43,217 76,350 30,400
Proceeds from exercise of stock options and
warrants....................................... 972 2,370 772
Repurchases of common stock..................... (68) (812) (2,125)
Other, net...................................... (804) (140) (637)
-------- -------- --------
Net cash provided by financing activities.. 26,159 36,226 16,859
-------- -------- --------
Net increase (decrease) in cash and cash
equivalents..................................... 2,811 2,434 (1,870)
Cash and cash equivalents at beginning of year... 1,229 4,040 6,474
-------- -------- --------
Cash and cash equivalents at end of year......... $ 4,040 $ 6,474 $ 4,604
======== ======== ========
Supplemental cash flow information:
Interest paid................................... $ 4,364 $ 3,788 $ 9,584
======== ======== ========
Income taxes paid............................... $ 156 $ 300 $ 618
======== ======== ========
</TABLE>
See notes to consolidated financial statements.
F-23
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1993, 1994, AND 1995
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMMON STOCK TREASURY STOCK
-------------- ----------------
ADDITIONAL RETAINED
PAID-IN EARNINGS
SHARES AMOUNT CAPITAL (DEFICIT) SHARES AMOUNT
------ ------ ---------- --------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Balances December 31,
1992.................... 12,850 $257 $20,891 $(1,218) 524 $ 981
Common stock issued for
cash, net............... 6,789 136 35,992 -- -- --
Shares issued as director
compensation............ 8 -- 41 -- -- --
Shares issued upon
exercise of stock
options and warrants.... 339 7 965 -- -- --
Cancellation of treasury
stock................... (524) (11) (970) -- (524) (981)
Repurchase and
cancellation of common
stock................... (7) -- (68) -- -- --
Dividends on Diamond
Energy Operating Company
common stock............ -- -- -- (125) -- --
Net income............... -- -- -- 2,334 -- --
------ ---- ------- ------- ------ -------
Balances December 31,
1993.................... 19,455 389 56,851 991 -- --
Shares issued as director
compensation............ 7 -- 44 -- -- --
Shares issued upon
exercise of stock
options and warrants.... 788 16 2,355 -- -- --
Common stock issued to
purchase Taurus Energy
Corp.................... 1,500 30 7,265 -- -- --
Repurchase and
cancellation of common
stock................... (157) (3) (809) -- -- --
Common stock issued to
acquire reversionary
interests in oil and gas
properties.............. 635 13 4,270 -- -- --
Net income............... -- -- -- 3,329 -- --
------ ---- ------- ------- ------ -------
Balances December 31,
1994.................... 22,228 445 69,976 4,320 -- --
Shares issued as director
compensation............ 7 -- 45 -- -- --
Shares issued upon
exercise of stock
options and warrants.... 225 5 767 -- -- --
Repurchase and
cancellation of common
stock................... (371) (8) (2,117)
Net income............... -- -- -- 5,755 -- --
------ ---- ------- ------- ------ -------
Balances December 31,
1995.................... 22,089 $442 $68,671 $10,075 -- $ --
====== ==== ======= ======= ====== =======
</TABLE>
See notes to consolidated financial statements.
F-24
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995
1. SUMMARY OF SIGNIFICANT ACCOUNTING AND REPORTING POLICIES
PRINCIPLES OF CONSOLIDATION AND BASIS OF FINANCIAL STATEMENT PRESENTATION--
The consolidated financial statements include the accounts of Coda Energy,
Inc. ("Coda"), its majority owned subsidiaries, and its pro rata share of the
assets, liabilities, and operations of oil and gas limited partnerships and
joint ventures (the "Company"). See Note 2. All significant intercompany
balances and transactions have been eliminated in consolidation. Certain
reclassifications have been made to amounts reported in prior years to conform
with the current presentation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
CASH AND CASH EQUIVALENTS--Cash and cash equivalents include commercial
paper or deposits with major financial institutions with maturities of three
months or less when purchased.
ACCOUNTS RECEIVABLE--Substantially all of the Company's accounts receivable
arise from sales of oil, natural gas, or natural gas liquids or from
participants in oil and gas wells for which the Company serves as the
operator. Generally, operators of oil and gas properties have the right to
offset future revenues against unpaid charges related to operated wells. Oil
and gas sales are generally unsecured. Most of the Company's receivables are
from a broad and diverse group of oil and gas companies and, accordingly, do
not represent a significant credit risk. Credit losses are provided for in the
financial statements and have been within management's expectations. The
allowance for doubtful accounts receivable aggregated $185,000 and $158,000 at
December 31, 1994 and 1995, respectively.
OIL AND GAS PROPERTIES--Oil and gas properties are recorded at cost using
the full cost method of accounting, as prescribed by the Securities and
Exchange Commission (the "SEC"). Under the full cost method, all costs
associated with the acquisition, exploration, or development of oil and gas
properties are capitalized as part of the full cost pool. Sales, dispositions,
and other oil and gas property retirements are accounted for as adjustments to
the full cost pool, with no recognition of gain or loss unless such
disposition would significantly alter the amortization rate. Under rules of
the SEC for the full-cost method of accounting, the net carrying value of oil
and gas properties is limited to the sum of the present value (10% discount
rate) of estimated future net cash flows from proved reserves, based on
period-end prices and costs, plus the lower of cost or estimated fair value of
unproved properties.
Depletion, depreciation, and amortization of evaluated oil and gas
properties are provided using the unit-of-production method based on total
proved reserves, as determined by independent petroleum reservoir engineers.
GAS PLANTS AND GATHERING SYSTEMS--Gas plants and gathering systems are
recorded at cost and depreciated on a straight-line basis over their estimated
useful lives of 15 years.
OVERHEAD REIMBURSEMENT FEES--Fees from overhead charges billed to working
interest owners, including the Company, of $2,999,000, $3,372,000, and
$5,571,000 for the years ended December 31, 1993, 1994, and 1995,
respectively, have been classified as a reduction of general and
administrative expenses in the accompanying consolidated statements of
operations.
F-25
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
OIL AND GAS FINANCIAL INSTRUMENTS--The Company enters into swap agreements
to reduce the effects of the volatility of the price of crude oil and natural
gas on the Company's operations. These agreements involve the receipt of fixed
price amounts in exchange for variable payments based on NYMEX prices and
specific volumes. The differential to be paid or received is accrued in the
month of the related production and recognized as a component of oil and gas
revenues.
The Company also sells call options on crude oil. The strike price of these
agreements exceeds current market prices at the time they are entered into.
Option premiums received, which have not been material, are deferred. If the
applicable market price exceeds the strike price and option premium, the
differential is accrued and recognized as a reduction of oil revenues in the
month of the related production. Any remaining deferred option premiums are
recognized at the end of the option period.
The fair values of the swap agreements and sold call options are not
included in the financial statements.
INCOME TAXES--The Company has adopted the Financial Accounting Standards
Board's Statement No. 109, "Accounting for Income Taxes" ("FAS 109"), which
requires the use of the liability method in accounting for income taxes.
QUASI-REORGANIZATION--In 1989, the Company, with the approval of the Board
of Directors, implemented a quasi-reorganization and adjusted its assets and
liabilities to fair value at June 30, 1989; eliminated accumulated depletion,
depreciation, and amortization existing on all properties at June 30, 1989,
against the respective asset accounts; and transferred the accumulated deficit
at June 30, 1989, of $39,663,000 and the cost of canceled treasury stock of
$1,809,000 to additional paid-in capital.
NEW ACCOUNTING PRONOUNCEMENTS--In the first quarter of 1996, the Company
will adopt the Financial Accounting Standards Board ("FASB") Statement No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of" ("FAS 121"). Adoption of this statement will not
have a material effect on the Company's financial statements.
In October 1995, the FASB issued its statement No. 123, "Accounting for
Stock Based Compensation" ("FAS 123") which establishes an alternative method
of accounting for stock based compensation to the method set forth in
Accounting Principles Board Opinion No. 25 ("APB 25"). FAS 123 encourages, but
does not require, adoption of a fair value based method of accounting for
stock options and similar equity instruments granted to employees. The Company
will continue to account for such grants under the provisions of APB 25 and
will adopt the disclosure provisions of FAS 123 in the first quarter of 1996.
Accordingly, adoption of FAS 123 will not effect the Company's financial
statements.
2. MERGER WITH DIAMOND
On September 30, 1994, pursuant to an Agreement and Plan of Merger (the
"Merger Agreement"), the Company acquired all of the issued and outstanding
stock of Diamond Energy Operating Company and Diamond A Inc. ("DEOC" and
"Diamond A," respectively, and collectively, "Diamond"), and two newly formed,
wholly owned subsidiaries of the Company merged into DEOC and Diamond A. The
Company issued an aggregate of 3,647,715 shares of the Company's common stock
to the Diamond stockholders. Contemporaneously with the merger, Diamond
acquired the
F-26
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
overriding royalty and reversionary interests owned by Diamond's primary
lender in certain of Diamond's oil and gas properties for $9.0 million cash.
Coda provided the funds necessary to complete such acquisition and repay $18.5
million of existing Diamond indebtedness. If the price of oil received from
the Diamond properties averages more than $17.65 per barrel for the 48-month
period ending September 30, 1998, Diamond's former lender will be paid an
additional $1.0 million. In addition, other reversionary interests in oil and
gas properties in which Diamond owns an interest were purchased from certain
employees and former employees of, and consultants to, DEOC and from a
financial advisor to Diamond for 634,519 shares of the Company's common stock
and approximately $39,000 in cash.
The merger with Diamond has been accounted for as a pooling of interests.
Accordingly, the merger of the equity interests has been given retroactive
effect in these financial statements for periods prior to the merger to
represent the combined financial statements of the previously separate
entities. The acquisitions of the reversionary interests were accounted for as
purchases effective September 30, 1994.
Separate and combined results of Coda and Diamond for periods prior to the
merger are as follows (in thousands):
<TABLE>
<CAPTION>
CODA DIAMOND COMBINED
------- ------- --------
<S> <C> <C> <C>
Year ended December 31, 1993:
Revenues............................................ $27,226 $12,824 $40,050
Net income.......................................... 840 1,494 2,334
Nine months ended September 30, 1994 (unaudited):
Revenues............................................ 37,048 13,314 50,362
Net income.......................................... 194 1,831 2,025
</TABLE>
In connection with the merger, the Company incurred approximately $1.8
million of legal, accounting, printing, and other costs related to the
combination of the previously separate entities. Under pooling of interests
accounting, these costs were expensed in September 1994.
Amounts due from stockholders shown in the accompanying balance sheets are
primarily related to the sale by DEOC of its oil and gas properties to its
stockholders in July 1990 in exchange for a note receivable. The note bears
interest at 10% and is due on demand. Interest is added to the principal
balance as accrued. The note is secured by certain of the shares of Coda
common stock which the former Diamond stockholders received in the merger.
3. ACQUISITIONS
The Company is continually acquiring oil and gas properties. The significant
transactions that have occurred since January 1, 1993, are discussed below.
In July 1993, the Company acquired interests in 71 producing oil and gas
properties effective June 1, 1993, located primarily in the Morrow and Chester
formations in southwest Kansas (the "Kansas Properties"), from affiliates of
Mobil Oil Corp. The total purchase price for the Kansas Properties was
$15,800,000, all of which was funded pursuant to the Company's credit
agreement.
In September 1993, the Company purchased all of the issued and outstanding
shares of MJM Oil & Gas, Inc. ("MJM"). The total purchase price was
$5,650,000, all of which was funded from the net
F-27
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
proceeds of a public offering of common stock (Note 5). The acquisition was
accounted for as a purchase. As a result of the acquisition of MJM, the
Company acquired 147 producing oil and gas properties, located primarily in
north and west Texas and western Oklahoma, at a cost of approximately $19.9
million, including the assumption of approximately $11.7 million of MJM
indebtedness.
On April 29, 1994, Coda acquired 100% of the issued and outstanding common
stock of Taurus Energy Corporation ("Taurus"), a privately held Texas
corporation, in exchange for 1,500,000 shares of the Company's common stock,
valued at approximately $7.3 million, and $3.25 million cash. The Company
assumed existing Taurus indebtedness of approximately $9.75 million. The cash
portion of the purchase price was funded, and the assumed debt was refinanced,
under the Company's existing credit agreement. Taurus operates three natural
gas processing facilities and owns interests in approximately 700 miles of
natural gas gathering systems located primarily in west central Texas.
Contemporaneously with the consummation of the acquisition of Taurus, the
president and former principal stockholder of Taurus loaned the Company $1.0
million in exchange for a subordinated promissory note from the Company having
a term of three years, payable in three equal annual installments of principal
plus accrued interest calculated at the rate of 7% per annum.
In July 1994, Taurus acquired ownership of the Shackelford gas gathering
system and processing plant. Taurus had previously been operating the system
and plant under operating leases. Taurus paid $3.8 million for the system and
plant, which was funded under the Company's existing credit agreement. In
related transactions, Taurus entered into an agreement to sell 10,000 MMBTU
per day to the former owner of Shackelford for a period of 48 months.
Simultaneously, Taurus entered into a gas purchase agreement with an unrelated
third party for similar quantities over the same term. Pricing under both the
gas sales agreement and the gas purchase agreement is structured to allow
Taurus to earn a margin on all volumes sold during the term of the agreements.
In January 1995, Taurus acquired the remaining ownership interest in one of
Taurus' gas plants and related facilities for $6.5 million which was financed
under the Company's credit facility.
In December 1994, in two separate transactions, the Company acquired
interests in 31 producing oil and gas properties in west Texas from two major
oil companies. The acquisition prices were $13.3 million and $10.0 million,
respectively, all of which was financed under the Company's credit facility.
The acquisitions were accounted for as a purchase. The properties acquired for
$13.3 million are referred to herein as the Major Oil Company Properties.
In October 1995, Coda acquired from Snyder Oil Company interests in 63
producing oil and gas properties located in west Texas (the "Snyder
Properties"). The aggregate purchase price was $17.1 million in cash, of which
$16.0 million was financed by borrowings under the Company's existing credit
facility. The acquisition was accounted for by the purchase method of
accounting.
The following pro forma data present the consolidated results of operations
of the Company for the years ended December 31, 1994 and 1995, as if the
acquisitions of Taurus, the Major Oil Company Properties, and the Snyder
Properties had occurred on January 1, 1994. The pro forma results of
operations are presented for comparative purposes only and are not necessarily
indicative of the results that would have been obtained had such acquisitions
been consummated as presented. The following data reflect pro forma
adjustments for depletion, depreciation, and amortization related to the
acquired oil and gas properties, gas plants, and gathering systems;
anticipated changes in general and
F-28
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
administrative expenses; adjustments to interest expense on borrowed funds;
and resulting adjustments to income tax expense.
<TABLE>
<CAPTION>
PRO FORMA
(UNAUDITED, IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
--------------------------
1994 1995
------------ -------------
<S> <C> <C>
Revenues........................................ $89,970 $102,997
============ =============
Net income...................................... $ 3,664 $ 6,121
============ =============
</TABLE>
4. LONG-TERM DEBT
Long-term debt is summarized as follows (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1994 1995
-------- --------
<S> <C> <C>
NationsBank credit agreements............................ $102,700 $122,000
Note payable to NationsBank.............................. 723 606
Senior subordinated debentures........................... 964 988
Other.................................................... 1,100 766
-------- --------
105,487 124,360
Less current maturities.................................. 424 453
-------- --------
Long-term debt........................................... $105,063 $123,907
======== ========
</TABLE>
NATIONSBANK CREDIT AGREEMENTS--Until the merger with JEDI on February 16,
1996 (Note 9), the Company had a credit agreement (the "Credit Agreement")
with NationsBank of Texas, N.A. ("NationsBank") and three additional
participant banks. The Credit Agreement as last amended through August 1995
had a notional amount of $250.0 million, subject to borrowing base
limitations, based on the value of the Company's oil and gas properties and
its gas gathering and processing assets, as determined by the lenders from
time to time. Under the Credit Agreement, the Company was required to pay a
facility fee equal to one-quarter of one percent on any accepted increase in
the borrowing base in excess of the previously determined borrowing base and a
commitment fee of three-eighths of one percent on the unused portion of the
borrowing base. The maturity date of the Credit Agreement was May 31, 1999.
The Credit Agreement provided that the interest rate on borrowings will
range from NationsBank's prime rate to LIBOR plus between 1% and 1 3/8% based
on the ratio of outstanding debt to the available borrowing base. The weighted
average interest rate on borrowings outstanding under the Credit Agreement was
7.72% and 7.29% at December 31, 1994 and 1995, respectively.
There were no scheduled principal payments due on the Credit Agreement until
maturity. At December 31, 1995, the borrowing base was $125.0 million and
approximately $3.0 million was available for borrowing. A borrowing base
deficiency is created in the event that the outstanding loan balances exceed
the borrowing base, as determined by the lenders in their sole discretion.
Upon such event, the borrowing base deficiency must be repaid by mandatory
reductions of the loan balances over a period of not more than six months. The
Company did not anticipate a borrowing base
F-29
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
deficiency, and, accordingly, the current portion of long-term debt at
December 31, 1995, does not include any amount related to the Credit
Agreement.
Borrowings under the Credit Agreement were unsecured. The Credit Agreement
contained various restrictive covenants, including limitations on the granting
of liens, restrictions on the issuance of additional debt, requirements to
maintain net worth of at least $46.5 million and to maintain positive working
capital, as defined, and prohibited the payment of dividends on Coda's capital
stock.
NOTE PAYABLE TO NATIONSBANK--In December 1992, the Company purchased a
building in Dallas, Texas, containing approximately 65,000 square feet of
office space to serve as its corporate headquarters. The Company currently
occupies approximately two-thirds of the office space and has made the balance
available for lease. The purchase price was $950,000, of which $850,000 was
financed by NationsBank pursuant to a promissory note requiring monthly
principal and interest payments, with the remaining unpaid balance due
December 31, 1995. The promissory note bears interest at prime plus 1%. The
remainder of the purchase price was financed by the seller and is evidenced by
a second lien promissory note requiring quarterly interest payments. In
February 1995, NationsBank agreed to amend the note payable to reduce the
interest rate to NationsBank's prime rate and to extend the maturity date to
January 2, 1998.
SENIOR SUBORDINATED DEBENTURES--The Company's 12% Senior Subordinated
Debentures (the "Debentures") are presented net of unamortized issuance
discount of $189,000 and $165,000 at December 31, 1994 and 1995, respectively.
The effective interest rate on the Debentures is 16.61%. The remaining
outstanding Debentures are due in 2000.
Scheduled maturities of long-term debt as of December 31, 1995, are as
follows (in thousands):
<TABLE>
<S> <C>
1996.............................................................. $ 453
1997.............................................................. 453
1998.............................................................. 366
1999.............................................................. 122,100
2000.............................................................. 988
--------
$124,360
========
</TABLE>
The carrying value of the Company's long-term debt approximates fair value.
5. COMMON STOCK
COMMON STOCK--On September 30, 1994, the Company's stockholders approved an
amendment to the Company's Certificate of Incorporation increasing the number
of authorized shares of common stock from 30 million shares to 40 million
shares.
In September 1993, the Company sold 6,788,750 shares of common stock
pursuant to a public offering. The net proceeds of approximately $36.1 million
to the Company were used to purchase the capital stock of MJM (Note 3), to
repay certain MJM indebtedness (approximately $900,000), and to repay amounts
under the Company's Credit Agreement.
In December 1993, the Board of Directors authorized the repurchase of up to
3,000,000 shares of the Company's common stock, from time to time and
whenever, in the opinion of the Company's
F-30
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
management, market conditions make such repurchase a prudent use of Company
funds. In January 1994, the Company received written approval for such
repurchases from NationsBank provided that the amount paid does not exceed
$5,000,000 in the aggregate. No shares had been repurchased as of December 31,
1993. During the year ended December 31, 1994 and 1995, the Company
repurchased and canceled 136,500 and 371,000 shares of common stock,
respectively, in open market transactions at a cost of approximately $648,000
and $2.1 million, respectively.
STOCK OPTIONS AND WARRANTS--The Company has three stock option plans
providing for the granting of stock options to officers and key employees.
Compensation expense is not recognized at the time options are granted because
the option price per share represents the market value of the share at the
date of grant.
The 1986 Non-Qualified Stock Option Plan provides that options may be
granted, from time to time, to key employees and directors to purchase a
maximum of 180,000 shares of common stock. The 1989 Incentive Stock Option
Plan provides that options may be granted, from time to time, to key employees
to purchase a maximum of 750,000 shares of common stock. The 1993 Incentive
Stock Option Plan permits the granting of options to purchase up to 1,500,000
shares of common stock.
Option transactions are summarized below:
<TABLE>
<CAPTION>
NUMBER
OF SHARES OPTION PRICE RANGE
--------- ------------------
<S> <C> <C>
Outstanding at December 31, 1992................ 726,750 $2.25 --$3.50
Granted....................................... 343,584 5.13 -- 6.00
Exercised..................................... (163,750) 2.25 -- 3.00
Forfeited..................................... (7,500) 3.50
---------
Outstanding at December 31, 1993................ 899,084 2.25 -- 6.00
Granted....................................... 525,785 5.00 -- 6.50
Exercised..................................... (108,629) 2.25 -- 5.75
Forfeited..................................... (56,708) 3.50 -- 5.75
---------
Outstanding at December 31, 1994................ 1,259,532 2.25 -- 6.50
Granted....................................... --
Exercised..................................... (100,213) 2.25 -- 5.75
Forfeited..................................... (42,687) 3.50 -- 5.75
---------
Outstanding at December 31, 1995 (755,756 exer-
cisable)....................................... 1,116,632 2.25 -- 6.50
=========
Reserved for future options..................... 837,876
=========
</TABLE>
The following table summarizes warrants outstanding at December 31, 1995:
<TABLE>
<CAPTION>
EXERCISE
NUMBER OF NUMBER OF PRICE
SHARES UNDER WARRANTS EXPIRATION DATE SHARES EXERCISABLE PER SHARE
- --------------------- --------------- ------------------ ---------
<S> <C> <C> <C>
500,000 October 1999 500,000 $3.00
450,000 December 2000 450,000 3.13
50,000 April 2002 25,000 3.00
100,000 April 2004 25,000 4.88
100,000 September 2004 25,000 6.75
100,000 March 2005 -- 6.00
--------- ---------
1,300,000 1,025,000
========= =========
</TABLE>
F-31
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
The warrants that expire in October 1999 are held by an officer of the
Company. The remaining warrants are held by the Company's directors.
As a result of the merger described in Note 9, all outstanding options and
warrants are fully vested and the holders thereof are entitled to receive the
difference between $7.75 per share and the exercise price for each share
represented by the options and warrants. Certain members of the management of
the Company have exchanged their right to receive this payment for an equity
participation in the Company.
6. INCOME TAXES
At December 31, 1995, Coda has net operating loss carryforwards ("NOLs") for
income tax purposes that expire beginning in 1998. Utilization of the NOLs is
severely restricted because of a change in ownership, as defined by the Tax
Reform Act of 1986, of Coda, which occurred in March 1990. Coda estimates that
approximately $15.4 million of the NOLs is available to offset future taxable
income without limitation, while the remainder will become available in the
future at the rate of approximately $921,000 per year through 2004. Coda also
has available statutory depletion carryforwards of approximately $1,000,000.
For financial reporting purposes, a valuation allowance has been recognized to
offset the deferred tax assets related to carryforwards prior to Coda's quasi-
reorganization. The Company anticipates that the merger described in Note 9
will not have a material effect on its ability to utilize the remaining NOLs.
F-32
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes. Significant components
of the Company's deferred tax liabilities and assets are as follows (in
thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
----------------
1994 1995
------- -------
<S> <C> <C>
Deferred tax liabilities:
Book basis of oil and gas properties in excess of tax ba-
sis....................................................... $ 8,980 $11,441
Book basis of gas plants and gathering systems in excess of
tax basis................................................. 5,355 6,447
Revenues not recognized for tax purposes................... 360 --
Other...................................................... 40 1,074
------- -------
Total deferred tax liabilities........................... 14,735 18,962
Deferred tax assets:
Net operating loss carryforwards........................... 6,887 8,468
Credit carryforwards....................................... 569 --
Other...................................................... 108 136
Valuation allowance for deferred tax assets................ (4,042) (4,042)
------- -------
Net deferred tax assets.................................. 3,522 4,562
------- -------
Net deferred tax liabilities................................. $11,213 $14,400
======= =======
</TABLE>
Significant components of income tax expense are as follows (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------
1993 1994 1995
------- ------- -------
<S> <C> <C> <C>
Current............................................ $ 280 $ 733 $ 15
Deferred........................................... 1,104 1,848 3,187
Adjustments to the valuation allowance............. (66) -- --
------- ------- -------
$1,318 $2,581 $3,202
======= ======= =======
</TABLE>
The following is a reconciliation, stated as a percentage of pretax income
taxable at the corporate level, of the U.S. statutory federal income tax rate
to the Company's effective tax rate:
<TABLE>
<CAPTION>
1993 1994 1995
---- ---- ----
<S> <C> <C> <C>
U.S. federal statutory rate................................... 34% 34% 34%
State taxes................................................... 4 5 2
Non-deductible business combination expenses.................. -- 5 --
Adjustments to the valuation allowance........................ (2) -- --
--- --- ---
36% 44% 36%
=== === ===
</TABLE>
7. OPERATIONS
NATURE OF OPERATIONS
The Company is an independent energy company principally engaged in the
acquisition and exploitation of producing oil and natural gas properties. The
Company seeks to acquire properties
F-33
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
whose predominant economic value is attributable to proved producing reserves
and to enhance that value through control of operations, reduction of costs,
and property development. The Company's producing properties are concentrated
in the mid-continent region of the United States. Through a subsidiary,
Taurus, the Company also operates natural gas processing and liquid extraction
facilities and natural gas gathering systems.
OIL AND GAS PRODUCING ACTIVITIES
The results of operations from the Company's oil and gas producing
activities are as follows (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1993 1994 1995
-------- -------- --------
<S> <C> <C> <C>
Oil and gas sales.............................. $ 38,877 $ 50,683 $ 60,997
Production costs............................... (17,590) (21,646) (27,119)
Depletion, depreciation, and amortization...... (10,573) (14,853) (16,889)
Income tax expense............................. (3,643) (4,823) (5,776)
-------- -------- --------
$ 7,071 $ 9,361 $ 11,213
======== ======== ========
</TABLE>
Costs incurred in oil and gas producing activities are as follows (in
thousands, except per equivalent barrel amounts):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1993 1994 1995
-------- -------- --------
<S> <C> <C> <C>
Property acquisition costs...................... $ 42,223 $ 40,109 $ 25,363
Development costs............................... 10,403 12,450 14,464
Exploration costs............................... 46 206 511
Production costs................................ 17,590 21,646 27,119
Depletion, depreciation, and amortization rate
per equivalent barrel.......................... 4.15 4.27 4.33
</TABLE>
All of the Company's oil and gas revenues are from proved developed
properties located in the United States.
The Company has capitalized internal costs of $658,000, $712,000, and
$748,000 for the years ended December 31, 1993, 1994, and 1995, respectively.
Such capitalized costs include salaries and related benefits of individuals
directly involved in the Company's acquisition, exploration, and development
activities based on the percentage of their time devoted to such activities.
During the year ended December 31, 1993, sales of oil and gas to two
purchasers accounted for 21% and 22% of consolidated gross revenues. During
the year ended December 31, 1994, sales of oil and gas to two purchasers
accounted for 13% and 22% of consolidated gross revenues. During the year
ended December 31, 1995, sales of oil and gas to two purchasers accounted for
10% and 18% of consolidated gross revenues. Management believes that the loss
of these purchasers would not have a material impact on the Company's
consolidated financial condition or results of operations.
F-34
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
During the fourth quarter of 1993, the Company received a payment of oil and
gas revenues relating to a recalculation of interests owned in certain of the
Company's properties for the period from 1985 through 1993. Oil and gas sales
increased by $343,000 as a result.
OIL AND GAS HEDGING ACTIVITIES AND COMMITMENTS
In an effort to reduce the effects of the volatility of the price of crude
oil and natural gas on the Company's operations, management has adopted a
policy of hedging oil and gas prices whenever such prices are in excess of the
prices anticipated in the Company's operating budget and profit plan through
the use of commodity futures, options, and swap agreements. The Company does
not hold or issue financial instruments for trading purposes. Hedging
transactions require the approval of the Board of Directors.
While the use of these hedging arrangements limits the downside risk of
adverse price movements, it may also limit future gains from favorable
movements. All hedging is accomplished pursuant to exchange-traded contracts
or master swap agreements based upon standard forms. The Company addresses
market risk by selecting instruments whose value fluctuations correlate
strongly with the underlying commodity being hedged. Credit risk related to
hedging activities, which is minimal, is managed by requiring minimum credit
standards for counterparties, periodic settlements, and marked to market
valuations. The Company has not historically been required to provide any
significant amount of collateral relating to its hedging activities.
At December 31, 1995, the Company had entered into various swap agreements
to fix selling prices for crude oil at a weighted average NYMEX price of
$18.79 and $19.02 per barrel for 740,000 and 375,000 barrels during 1996 and
1997, respectively. While these contracts have no carrying value, their fair
value (the estimated amount that would have been received upon termination of
the swaps at December 31, 1995) was approximately $900,000.
The Company has also sold call options covering 25,000 Bbls of oil per month
at an option price of $18.30 per Bbl for the period October 1995 to August
1996, and at an option price of $20.00 per barrel for the period September
1996 to August 1997. While these call options have no carrying value, their
fair value (the estimated amount that would have been paid by the Company upon
termination of the call options at December 31, 1995) was approximately
$230,000.
During the years ended December 31, 1993, 1994, and 1995, oil and gas sales
were reduced by $289,000 and $5,000, and increased by $298,000, respectively,
as a result of hedging transactions.
Pursuant to the loan agreements with Diamond's former lender, Diamond
entered into an agreement with a refining and marketing company to sell a
fixed number of barrels attributable to its share of production of liquid
hydrocarbons from certain secured properties at a price of $15.25 per Bbl.
Under the purchase and sale agreement, the remaining commitment was
approximately 47,000 Bbls at December 31, 1995. The Company expects to fulfill
this commitment during the first quarter of 1996.
8. COMMITMENTS AND CONTINGENCIES
The Company does not believe that future costs related to site restoration,
dismantlement, and abandonment costs, net of estimated salvage values, will
have a significant effect on its results of
F-35
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
operations or financial position because the salvage value of equipment and
related facilities should approximate or exceed any future expenditures for
restoration, dismantlement, or abandonment. The Company has not incurred any
net expenditures for costs of this nature during the last three years.
The Company is a defendant or co-defendant in minor lawsuits that have
arisen in the ordinary course of business. In the lawsuits, management
believes, based in part on advice from legal counsel, that the Company has
meritorious defense against the claims asserted. Management believes that the
ultimate resolution of the lawsuits and claims will not have a material
adverse effect on the Company's results of operations or financial position.
9. AGREEMENT AND PLAN OF MERGER
On February 16, 1996, pursuant to an Agreement and Plan of Merger dated as
of October 30, 1995 (as amended, the "Merger Agreement") by and among Coda,
Joint Energy Development Investments Limited Partnership ("JEDI"), an
affiliate of Enron Capital & Trade Resources Corp., and Coda Acquisition, Inc.
("Purchaser"), a subsidiary of JEDI, JEDI acquired Coda through a merger (the
"Merger") at a price of $7.75 per share in cash. Concurrently with the
execution of the Merger Agreement, JEDI and Purchaser entered into certain
agreements with certain members of the Company's management concerning their
employment with and/or equity participation in the Company after the Merger.
The sources and uses of funds related to the Merger were as follows (in
millions):
<TABLE>
<S> <C>
Sources of funds:
Credit agreement................................................... $ 95.0
JEDI Debt.......................................................... 100.0
Redeemable preferred stock issued to JEDI.......................... 20.0
Common stock issued to JEDI........................................ 90.0
------
$305.0
======
Uses of funds:
Payments to Coda stockholders, warrantholders and optionholders.... $176.2
Repayment of former credit facility and other indebtedness......... 122.7
Merger costs and other expenses.................................... 6.1
------
$305.0
======
</TABLE>
The Merger has been accounted for using the purchase method of accounting.
As such, JEDI's cost of acquiring Coda has been allocated to the assets and
liabilities acquired based on estimated fair values. As a result, the
Company's financial position and operating results subsequent to February 16,
1996 will reflect a new basis of accounting and are not comparable to prior
periods.
10. 10 1/2% SENIOR SUBORDINATED NOTES
On March 18, 1996, the Company completed the sale of $110 million principal
amount of 10 1/2% Senior Subordinated Notes due 2006 (the "Notes"). The
proceeds of the Notes were used to fully repay the JEDI Debt assumed in the
Merger and to partially repay bank debt. The Notes bear interest at an annual
rate of 10 1/2% payable semiannually in arrears on April 1 and October 1 of
each year. The Notes are general, unsecured obligations of the Company, are
subordinated in right of payment to all Senior Debt (as defined in the
Indenture governing the Notes) of Coda, and are senior in right of payment to
all future subordinated debt of the Company. The claims of the holders of the
Notes will be subordinated to Senior Debt, which, as of March 31, 1996, was
$81.8 million.
F-36
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
The Notes were issued pursuant to an Indenture, which contains certain
covenants that, among other things, limit the ability of Coda and its
Restricted Subsidiaries (as defined in the Indenture) to incur additional
indebtedness and issue Disqualified Stock, pay dividends, make distributions,
make investments, make certain other restricted payments, enter into certain
transactions with affiliates, dispose of certain assets, incur liens securing
pari passu or subordinated indebtedness of Coda and engage in mergers and
consolidations.
The Notes are not redeemable at Coda's option prior to April 1, 2001. After
April 1, 2001, the Notes will be subject to redemption at the option of Coda,
in whole or in part, at the redemption prices set forth in the Indenture, plus
accrued and unpaid interest thereon to the applicable redemption date. In
addition, until March 12, 1999, up to $27.5 million in aggregate principal
amount of Notes are redeemable, at the option of Coda on any one or more
occasions from the net proceeds of an offering of common equity of Coda, at a
price of 110.5% of the aggregate principal amount of the Notes, together with
accrued and unpaid interest thereon to the date of the redemption; provided,
however, that at least $82.5 million in aggregate principal amount of Notes
must remain outstanding immediately after the occurrence of such redemption;
provided, further, that any such redemption shall occur within 75 days of the
date of the closing of such offering of common equity.
In the event of a Change of Control (as defined in the Indenture), holders
of the Notes will have the right to require Coda to repurchase their Notes, in
whole or in part, at a price in cash equal to 101% of the aggregate principal
amount thereof, plus accrued and unpaid interest thereon to the date of
repurchase. The Indenture requires that, prior to such a repurchase but in any
event within 90 days of such Change of Control, Coda must either repay all
Senior Debt or obtain any required consent to such repurchase.
Coda's payment obligations under the Notes are fully, unconditionally and
jointly and severally guaranteed on a senior subordinated basis by all of
Coda's current subsidiaries and future Restricted Subsidiaries. Such
guarantees are subordinated to the guarantees of Senior Debt issued by the
Guarantors under the Credit Agreement and to other guarantees of Senior Debt
issued in the future.
The combined condensed financial information of the Company's current
subsidiaries, the Guarantors, is as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
---------------
1994 1995
------- -------
<S> <C> <C>
Current assets................................................. $ 7,785 $ 5,394
Oil and gas properties, net.................................... 40,076 36,469
Gas plants and gathering systems, net.......................... 28,007 33,650
Other properties, net and other assets......................... 3,490 1,713
------- -------
Total assets................................................. $79,358 $77,226
======= =======
Current liabilities............................................ $ 6,082 $ 5,629
Long-term debt................................................. 1,200 --
Intercompany payables.......................................... 52,595 50,172
Deferred income taxes.......................................... 7,021 7,828
Stockholder's equity........................................... 12,460 13,597
------- -------
Total liabilities and stockholder's equity................... $79,358 $77,226
======= =======
</TABLE>
F-37
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1993 1994 1995
---------- ---------- ----------
<S> <C> <C> <C>
Revenues:
Oil and gas sales............................ $ 12,530 $ 17,660 $ 18,826
Gas gathering and processing................. 732 20,031 35,634
Other income................................. 322 251 244
---------- ---------- ----------
13,584 37,942 54,704
Costs and expenses:
Oil and gas production....................... 4,530 4,706 7,023
Gas gathering and processing................. 571 17,324 30,473
Depletion, depreciation and amortization..... 3,393 6,719 7,776
General and administrative................... 898 1,158 3,936
Business combination......................... -- 1,184 --
Interest..................................... 2,000 2,628 3,538
---------- ---------- ----------
11,392 33,719 52,746
---------- ---------- ----------
Income before income taxes..................... 2,192 4,223 1,958
Income tax expense............................. 949 1,813 822
---------- ---------- ----------
Net income..................................... $ 1,243 $ 2,410 $ 1,136
========== ========== ==========
</TABLE>
11. SUPPLEMENTAL OIL AND GAS RESERVE AND STANDARDIZED MEASURE INFORMATION
(UNAUDITED)
The Company retains independent engineering firms to provide annual year-end
estimates of the Company's future net recoverable oil, gas, and natural gas
liquids reserves. Estimated proved net recoverable reserves as shown below
include only those quantities that can be expected to be commercially
recoverable at prices and costs in effect at the balance sheet dates under
existing regulatory practices and with conventional equipment and operating
methods. Proved developed reserves represent only those reserves expected to
be recovered through existing wells. Proved undeveloped reserves include those
reserves expected to be recovered from new wells on undrilled acreage or from
existing wells on which a relatively major expenditure is required for
recompletion.
Reserve estimates are imprecise and may be expected to change as additional
information becomes available. Furthermore, estimates of oil and gas reserves,
of necessity, are projections based on engineering data, and there are
uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
way, and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Accordingly, there can be no assurance that the reserves set forth herein will
ultimately be produced nor can there be assurance that the proved undeveloped
reserves will be developed within the periods anticipated. The Company
emphasizes with respect to the estimates prepared by independent petroleum
engineers that the discounted future net cash inflows should not be construed
as representative of the fair market value of the proved oil and gas
properties belonging to the Company, since discounted future net cash inflows
are based upon projected cash inflows which do not provide for changes in oil
and gas prices nor for escalation of expenses and capital costs. The
meaningfulness of such estimates is highly dependent upon the accuracy of the
assumptions upon which they were based.
F-38
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
ESTIMATED QUANTITIES OF PROVED RESERVES
(IN THOUSANDS)
<TABLE>
<CAPTION>
OIL (BBL) GAS (MCF)
--------- ---------
<S> <C> <C>
December 31, 1992........................................... 18,941 27,830
Purchase of reserves in place............................... 5,872 13,274
Extensions.................................................. 7,165 2,259
Revisions of previous estimates............................. (113) (2,289)
Production.................................................. (1,766) (4,703)
Sales of reserves in place.................................. (15) (175)
------ -------
December 31, 1993........................................... 30,084 36,196
Purchase of reserves in place............................... 11,038 5,482
Extensions.................................................. 271 912
Revisions of previous estimates............................. 749 4,107
Production.................................................. (2,650) (4,982)
Sales of reserves in place.................................. (285) (1,907)
------ -------
December 31, 1994........................................... 39,207 39,808
Purchase of reserves in place............................... 7,324 7,298
Extensions.................................................. 783 3,173
Revisions of previous estimates............................. (1,011) 1,459
Production.................................................. (3,165) (4,416)
Sales of reserves in place.................................. (548) (10,192)
------ -------
December 31, 1995........................................... 42,590 37,130
====== =======
</TABLE>
ESTIMATED QUANTITIES OF PROVED DEVELOPED RESERVES
(IN THOUSANDS)
<TABLE>
<CAPTION>
OIL (BBL) GAS (MCF)
--------- ---------
<S> <C> <C>
December 31, 1992........................................... 14,413 22,852
December 31, 1993........................................... 16,230 30,573
December 31, 1994........................................... 20,151 32,890
December 31, 1995........................................... 25,877 31,496
</TABLE>
F-39
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
The following is a summary of a standardized measure of discounted net cash
flows related to the Company's proved oil, gas, and natural gas liquids
reserves. The information presented is based on a valuation of proved reserves
using discounted cash flows based on year-end prices, costs, and economic
conditions and a 10% discount rate. The additions to proved reserves from new
discoveries and extensions could vary significantly from year to year;
additionally, the impact of changes to reflect current prices and costs of
reserves proved in prior years could also be significant. Accordingly, the
information presented below should not be viewed as an estimate of the fair
value of the Company's oil and gas properties, nor should it be considered
indicative of any trends.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1994 1995
-------- --------
<S> <C> <C>
Future cash inflows........................................... $696,910 $860,180
Future production and development costs....................... 335,656 366,421
Future income taxes........................................... 81,962 113,775
-------- --------
Future net cash flows......................................... 279,292 379,984
Discount of future net cash flows at 10% per annum............ 110,676 159,242
-------- --------
Discounted future net cash flows after income taxes........... $168,616 $220,742
======== ========
</TABLE>
During recent years, there have been significant fluctuations in the prices
paid for crude oil in the world markets. This situation has had a
destabilizing effect on crude oil's posted prices in the United States,
including the posted prices paid by purchasers of the Company's crude oil. The
weighted average prices of oil and gas at December 31, 1994 and 1995, used in
the above table, were $16.24 and $18.31 per Bbl, respectively, and $1.45 and
$2.19 per Mcf, respectively.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1993 1994 1995
-------- -------- --------
<S> <C> <C> <C>
Sales and transfers of oil and gas produced, net
of production costs ........................... $(21,287) $(29,037) $(33,878)
Net changes in prices and production costs...... (62,305) 18,674 37,290
Extensions and discoveries, net of future
development and production costs............... 29,260 3,673 15,932
Development costs during the period............. 10,403 12,656 14,464
Revisions of previous quantity estimates........ (1,098) 3,579 (19,084)
Sales of reserves in place...................... (365) (1,755) (6,323)
Purchases of reserves in place.................. 52,732 54,672 35,680
Accretion of discount........................... 11,372 33,592 39,858
Change in income taxes.......................... 1,451 (43,461) (31,813)
-------- -------- --------
Net change...................................... $ 20,163 $ 52,593 $ 52,126
======== ======== ========
</TABLE>
F-40
<PAGE>
CODA ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
DECEMBER 31, 1995
12. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for 1994 and 1995 is as follows (in
thousands, except for per share amounts):
<TABLE>
<CAPTION>
THREE MONTHS ENDED
-----------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
<S> <C> <C> <C> <C>
1994:
Total revenues..................... $11,611 $17,143 $21,608 $21,224
Income before income taxes......... 958 2,003 912 2,037
Net income......................... 553 1,217 255 1,304
Net income per common and common
equivalent share.................. 0.03 0.06 0.01 0.06
1995:
Total revenues..................... 23,039 25,014 23,292 26,493
Income before income taxes......... 2,101 2,776 1,242 2,838
Net income......................... 1,305 1,814 798 1,838
Net income per common and common
equivalent share.................. 0.06 0.08 0.03 0.08
</TABLE>
Total revenues, income before income taxes and net income for the three
months ended March 31 and June 30, 1994 do not include the operations of
Taurus prior to its acquisition in April 1994. Income before income taxes for
the three months ended September 30, 1994, includes a charge of $1.8 million
for business combination expenses related to the merger with Diamond.
F-41
<PAGE>
ANNEX A
[LEE KEELING AND ASSOCIATES INC. LETTERHEAD]
February 2,1996
Coda Energy, Inc.
5735 Pineland Drive, Suite 300
Dallas, Texas 75231
Attention: Mr. T. W. Eubank, President
RE: Appraisal
Oil and Gas Properties-Coda Energy, Inc.
Constant Price Case
Gentlemen:
In accordance with your request, we have prepared an appraisal of the interests
owned by Coda Energy, Inc. in oil and gas leases located in the states of
Kansas, Louisiana, Michigan, Mississippi, Montana, North Dakota, Oklahoma and
Texas. The effective date of the appraisal is January 1, 1996, and the results
are summarized as follows:
<TABLE>
<CAPTION>
ESTIMATED REMAINING
NET RESERVES FUTURE NET REVENUE
--------------------------- -----------------------------
RESERVE Oil Gas Present Worth
CLASSIFICATION (Barrels) (MCF) Total Discounted@10%
- --------------------------------------------------------------------------------
Proved
- ----------------
<S> <C> <C> <C> <C>
Producing 22,163,582 28,294,514 $246,046,146 $164,328,638
Non-Producing 3,411,015 1,837,990 42,198,358 23,031,293
Behind-Pipe 302,825 1,363,229 5,815,305 2,256,265
Undeveloped 16,712,768 5,634,348 199,699,930 93,759,024
---------- ---------- ------------ ------------
Total Proved 42,590,190 37,130,081 $493,759,739 $283,375,220
Probable 3,808,161 166,958 $ 22,877,915 $ 4,845,438
Possible 3,414,725 3,038,336 $ 25,984,354 $ 8,048,330
---------- ---------- ------------ ------------
Total
All Reserves 49,813,076 40,335,375 $542,622,008 $296,268,988
</TABLE>
Note: Totals may differ from schedules due to computer round off.
A-1
<PAGE>
This report is based on assumptions provided by Coda Energy, Inc. Oil and gas
prices and expenses used in this appraisal were held constant throughout the
anticipated life of the properties.
Future net revenue is the amount, exclusive of state and federal income taxes,
which will accrue to the appraised interests from continued operation of the
properties to depletion. It should not be construed as a fair market or trading
value. No provision has been made for the cost of plugging and abandoning the
properties nor for the value of salvable equipment.
No attempt has been made to quantify or otherwise account for any accumulative
gas production imbalances that may exist. Neither has an attempt been made to
determine whether the wells and facilities are in compliance with various
governmental regulations, nor have costs been included in the event they are
not.
This report consists of two volumes. Volume I includes summary forecasts of
annual gross and net production, severance and ad valorem taxes, operating
income and net revenue, and present worth determinations at various discount
rates by reserve type. The company totals are summarized in Schedule No. 1.
Schedule No. 2 is a one-line summary of the individual properties arranged
alphabetically. Schedule No. 3 is a sequential listing of the individual
properties based on discounted future net revenue. Volume II contains
determination of future net revenue for the individual properties.
CLASSIFICATION OF RESERVES
- --------------------------
Reserves attributed to the appraised leases have been classified "proved
producing," "proved non-producing," proved behind-pipe," "proved
undeveloped," "probable," and "possible."
Proved producing reserves are those expected to be recovered from currently
- -------------------------
producing zones under continuation of present operating methods.
Proved non-producing reserves are those attributable to wells which have been
- -----------------------------
drilled, but for various reasons, cannot be classified as producing. This
category may also contain reserves attributable to developed waterflood units
for which no response has been experienced.
Proved behind-pipe reserves are those currently behind the pipe in existing
- ---------------------------
wells which are considered proved by virtue of successful testing or production
in offsetting wells.
Proved undeveloped reserves are those attributable to wells to be drilled at
- ---------------------------
locations which can be considered proved by virtue of favorable structural
position and which can be anticipated with a high degree of certainty.
A-2
<PAGE>
Proved undeveloped reserves also include those attributable to undeveloped
- ---------------------------
repressuring or pressure maintenance projects in zones whose reserves are
considered proved by virtue of successful pilot projects or successful projects
which involve those zones in the vicinity. Projects to which this category of
reserves has been assigned are either in the process of formation or can be
expected with a high degree of certainty to be formed in the near future.
Probable reserves are those anticipated from zones in existing wells or from
- -----------------
wells to be drilled at locations that cannot be considered proved for lack of
actual physical testing, production in the area and/or limited geologic control.
These can be either primary or secondary reserves.
Possible reserves are those based on criteria similar to those discussed under
- -----------------
probable reserves but which must be considered more speculative. These also can
be either primary or secondary reserves.
ESTIMATION OF RESERVES
- ----------------------
The majority of the appraised wells have been producing for a considerable
length of time. Reserves attributable to wells with well-defined production
trends and/or well-defined cumulative recovery-pressure relationships were based
upon extrapolation of these trends or relationships to economic limits and/or
abandonment pressures.
Reserves anticipated from new wells were based upon volumetric calculations or
analogy with similar properties which are producing from the same horizons in
the respective areas. Structural position, net pay thickness, well productivity,
gas/oil ratios, water production, pressures, and other pertinent factors were
considered in the estimations of these reserves.
Reserves assigned to behind-pipe zones have been estimated based on volumetric
calculation and/or analogy with other wells in the area producing from the same
horizon.
Primary reserves attributable to undeveloped locations have been based on
analogy with offsetting wells.
Undeveloped secondary reserves, attributable to additional development of
existing waterflood projects, have been based on analogy with the respective
projects or other secondary projects in the area with similar characteristics.
The proved reserves included in this report conform to the applicable definition
promulgated by the Securities and Exchange Commission.
A-3
<PAGE>
FUTURE NET REVENUE
- ------------------
Oil Income
- ----------
Income from the sale of oil was established using the December 31, 1995, posted
West Texas Intermediate price of $18.00 per barrel. A comparison was made
between the West Texas Intermediate price during 1995 and the prices actually
received for each lease during the same time period. A difference between West
Texas Intermediate and actual pricing was determined and this adjustment was
applied to the December 31, 1995, West Texas Intermediate posting on a lease
basis.
For leases with known contracts or fixed prices, that price was used instead of
the relationship to West Texas Intermediate posting. All prices were held
constant throughout the life of each lease. Provisions were made for state
severance and ad valorem taxes where applicable.
Gas Income
- ----------
Income from the sale of gas from each lease was based on the December 31, 1995
Henry Hub price of $2.26 per MCF. A comparison was made between the Henry Hub
price during 1995 and the price actually received for each lease during the
same time period. A difference between Henry Hub and actual pricing was
determined and this adjustment was applied to the December 31, 1995 Henry Hub
price on a lease basis.
For leases with known contracts or fixed prices, that price was used instead of
the relationship to the Henry Hub price. All prices were held constant
throughout the life of each lease. Adjustments were made for state severance and
ad valorem taxes where applicable.
Operating Expenses
- ------------------
Operating expenses were based upon actual operating costs charged by the
respective operators as supplied by the staff of Coda Energy, Inc., or were
based upon the actual experience of the operators in the respective areas. For
leases operated by Coda Energy, Inc., monthly lease operating expenses do not
include overhead charges. All expenses have been held constant throughout the
life of each lease.
GENERAL
- -------
Information upon which this appraisal has been based was furnished by the staff
of Coda Energy, Inc. or was obtained by us from outside sources. This
information is assumed to be correct. No attempt has been made to verify title
or ownership of the appraised properties.
A-4
<PAGE>
Leases were not inspected by a representative of this firm, nor were the wells
tested under our supervision; however, the performance of the majority of the
wells was discussed with employees of Coda Energy, Inc.
This report has been prepared utilizing methods and procedures regularly used by
petroleum engineers to estimate oil and gas reserves for properties of this type
and character. The recovery of oil and gas reserves and projection of producing
rates are dependent upon many variable factors. These include, among others,
prudent operation, compression of gas when needed, market demand, installation
of lifting equipment and remedial work when required. The reserves included in
this report have been based upon the assumption that the wells will continue to
be operated in a prudent manner under the same conditions existing at the
present time. Actual production results and future well data may yield
additional facts, not presently available to us, which will require an
adjustment to our estimates.
The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered,
and, if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. As in all aspects of oil and
gas evaluation, therefore are uncertainties inherent in the interpretation of
engineering data and, therefore, our conclusions necessarily represent only
informed professional judgments.
You should be aware that state regulatory authorities could, in the future,
change the allocation of reserves allowed to be produced from a particular well
in any reservoir, thereby altering the material premise upon which our reserve
estimate may be based.
The projection of cash flow has been made assuming constant prices. There is
no assurance that prices will not vary. For this reason and those listed in
the previous paragraph, the future net cash from the sale of production from the
appraised properties may vary from the estimates contained in this report.
The information developed during the course of this investigation, basic data,
maps and worksheets showing recovery determinations are available for inspection
in our office.
We appreciate this opportunity to be of service to you.
Very truly yours,
/s/ LEE KEELING AND ASSOCIATES, INC.
LEE KEELING AND ASSOCIATES, INC.
A-5
<PAGE>
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
NO PERSON IS AUTHORIZED IN CONNECTION WITH ANY OFFERING MADE HEREBY TO GIVE
ANY INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN THIS PROSPEC-
TUS, AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RE-
LIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY. THIS PROSPECTUS DOES NOT
CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY ANY SECURI-
TIES OTHER THAN THE SECURITIES DESCRIBED IN THIS PROSPECTUS OR AN OFFER TO
SELL OR THE SOLICITATION OF AN OFFER TO BUY SUCH SECURITIES IN ANY CIRCUM-
STANCES IN WHICH SUCH OFFER OR SOLICITATION IS UNLAWFUL. NEITHER THE DELIVERY
OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES,
CREATE ANY IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE
COMPANY SINCE THE DATE HEREOF OR THAT THE INFORMATION CONTAINED HEREIN OR
THEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO ITS DATE.
-----------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Summary.................................................................. 4
Risk Factors............................................................. 18
The Exchange Offer....................................................... 25
The Merger............................................................... 33
Use of Proceeds.......................................................... 34
Capitalization........................................................... 35
Selected Historical and Pro Forma Financial Data......................... 36
Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................... 38
Business................................................................. 50
Management............................................................... 64
Security Ownership of Certain Beneficial Owners and Management........... 66
Executive Compensation and Other Information............................. 67
Certain Transactions..................................................... 70
Description of Exchange Notes............................................ 74
Description of Other Indebtedness........................................ 104
Description of Capital Stock of Coda..................................... 105
Certain Federal Income Tax Considerations................................ 106
Plan of Distribution..................................................... 106
Legal Matters............................................................ 107
Experts.................................................................. 107
Available Information.................................................... 108
Glossary................................................................. 109
Index to Financial Statements............................................ F-1
Summary Reserve Report................................................... A-1
</TABLE>
UNTIL SEPTEMBER 9, 1996, ALL DEALERS EFFECTING TRANSACTIONS IN THE EXCHANGE
NOTES, WHETHER OR NOT PARTICIPATING IN THIS OFFERING, MAY BE REQUIRED TO DE-
LIVER A PROSPECTUS. THIS IS IN ADDITION TO THE OBLIGATION OF DEALERS TO DE-
LIVER A PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UN-
SOLD ALLOTMENTS OR SUBSCRIPTIONS.
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
$110,000,000
[LOGO OF CODA ENERGY, INC. APPEARS HERE]
OFFER TO EXCHANGE ITS 10 1/2% SERIES B SENIOR SUBORDINATED NOTES DUE 2006
WHICH HAVE BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED, FOR
ANY AND ALL OF ITS OUTSTANDING 10 1/2% SERIES A SENIOR SUBORDINATED NOTES DUE
2006
-----------
PROSPECTUS
-----------
JUNE 11, 1996
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
