<PAGE> 1
SCHEDULE 14C INFORMATION
Information Statement Pursuant to Section 14(c) of the Securities Exchange Act
of 1934
Check the appropriate box:
/X/ Preliminary Information Statement (Revised)
/ / Definitive Information Statement
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
(Name of Registrant As Specified In Charter)
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
(Name of Person(s) Filing The Information Statement)
Payment of Filing Fee (Check the appropriate box):
/ / $125 per Exchange Act Rule 0-11(c)(i)(ii) or 14c-5(g)
/X/ Fee computed on table below per Exchange Act Rule 14c-5(g)
and 0-11.
1) Title of each class of securities to which transaction applies:
Depositary Units
2) Aggregate number of securities to which transaction applies:
9,597,855 Depositary Units
3) Per unit price or other underlying value of transaction computed
pursuant to Exchange Act Rule 0-11(1):
$43,046,379
4) Proposed maximum aggregate value of transaction:
$43,046,379
CALCULATION OF FILING FEE
Transacton Valuation Amount of filing fee
$43,046,379(1) $8,609
(1) For purposes of calculating fee only. The amount assumes 9,597,855
Depositary Units, representing all Depositary Units other than those
Depositary Units owned by Meridian Offshore Company and its affiliates,
will be converted into the right to receive $4.485 per unit in cash.
/X/ Check box if any part of the fee is offset as provided by Exchange Act
Rule 0-11(a)(2) and identify the filing for which the offsetting fee was
paid previously. Identify the previous filing by registration statement
number, or the Form or Schedule and the date of its filing.
1) Amount Previously Paid:
$8,609
2) Form, Schedule or Registration Statement No.:
Schedule 13E-3
3) Filing Party:
Burlington Resources Inc.
Meridian Offshore Company
4) Date Filed:
May 12, 1994
<PAGE> 2
REVISED PRELIMINARY COPY
DIAMOND SHAMROCK OFFSHORE
PARTNERS LIMITED PARTNERSHIP
5051 WESTHEIMER
SUITE 1400
HOUSTON, TEXAS 77056
------------------------------------------
INFORMATION STATEMENT
------------------------------------------
This Information Statement is being furnished by Diamond Shamrock Offshore
Partners Limited Partnership, a Delaware limited partnership (the
"Partnership"), to holders of record as of the close of business on June 20,
1994 of limited partnership units of the Partnership (the "Units") represented
by depositary receipts (the "Depositary Units"), in connection with an Agreement
and Plan of Merger dated as of April 28, 1994 (the "Merger Agreement"), between
the Partnership and Meridian Offshore Company, a Delaware corporation (the
"Company") which is a direct wholly owned subsidiary of Meridian Oil Inc., a
Delaware corporation ("Meridian"), and an indirect wholly owned subsidiary of
Burlington Resources Inc., a Delaware corporation ("BR"). Pursuant to the Merger
Agreement (i) the Partnership will be merged with and into the Company (the
"Merger") and (ii) holders of record of Depositary Units on the effective date
of the Merger will receive $4.485 in cash for each Unit (the "Merger
Consideration").
The Merger is the second step in a transaction pursuant to which (i) on
April 26, 1994, the Company acquired the managing general partnership interest
of Maxus Offshore Exploration Company ("Maxus Offshore") in the Partnership and
64,163,885 Units held by Maxus Exploration Company ("Maxus Exploration"), and
Meridian Offshore Acquisition Company, a Delaware corporation which is an
affiliate of the Company ("Acquisition"), acquired the special general
partnership interest of Maxus Energy Corporation ("Maxus Energy" and, together
with Maxus Offshore and Maxus Exploration, "Maxus") in the Partnership, for an
aggregate purchase price of $291,088,000 (of which $3,341,230 was attributable
to the general partnership interests in the Partnership) or approximately $4.485
per Unit, and (ii) on April 28, 1994, the Partnership and the Company entered
into the Merger Agreement, pursuant to which holders of Units will receive
$4.485 per Unit in cash, the same price paid to Maxus for its interests in the
Partnership.
The Merger Agreement and the Merger have each been approved by the Board of
Directors of the Company, on behalf of the Company, and by the Company, in its
capacity as managing general partner of the Partnership, on behalf of the
Partnership. The Company, as the holder of the managing general partnership
interest in the Partnership and of 64,163,885 Units, and Meridian Offshore
Acquisition Company, a Delaware corporation which is an affiliate of the Company
("Acquisition"), as the holder of the special general partnership interest in
the Partnership, have each executed a written consent approving the Merger.
Under Delaware law and the Second Amended and Restated Agreement of Limited
Partnership of the Partnership, as amended (the "Partnership Agreement"), the
Merger does not require the vote or consent of any other Unit holder.
NO MEETING OF UNIT HOLDERS WILL BE HELD TO CONSIDER APPROVAL OF THE MERGER
AND NO VOTE OR CONSENT OF UNIT HOLDERS IS BEING SOLICITED.
---------------------
NEITHER THE PARTNERSHIP NOR THE COMPANY IS ASKING YOU FOR A PROXY OR
CONSENT AND YOU ARE REQUESTED NOT TO SEND THE PARTNERSHIP OR THE COMPANY A PROXY
OR CONSENT.
THIS TRANSACTION HAS NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION NOR HAS THE COMMISSION PASSED UPON THE FAIRNESS OR MERITS OF
THIS TRANSACTION OR UPON THE ACCURACY OR ADEQUACY OF THE INFORMATION CONTAINED
IN THIS DOCUMENT. ANY REPRESENTATION TO THE CONTRARY IN UNLAWFUL.
---------------------
THE DATE OF THIS INFORMATION STATEMENT IS , 1994.
<PAGE> 3
AVAILABLE INFORMATION
The Partnership and BR are subject to the informational requirements of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"), and, in
accordance therewith, file reports, proxy statements (in the case of BR only)
and other information with the Securities and Exchange Commission (the
"Commission"). Such reports, proxy statements (in the case of BR) and other
information filed with the Commission can be inspected and copied at the public
reference facility maintained by the Commission at Room 1024, Judiciary Plaza,
450 Fifth Street, N.W., Washington, D.C. 20549, and should also be available for
inspection and copying at the regional offices of the Commission located at 7
World Trade Center, New York, New York 10048 and Northwest Atrium Center, 500
West Madison Street, Suite 1400, Chicago, Illinois 60661. Copies can also be
obtained from the Public Reference Section of the Commission at 450 Fifth
Street, N.W., Washington, D.C. 20549 at prescribed rates.
Although the Company, BR and the Partnership believe that the Merger is not
a "Rule 13e-3 transaction" within the meaning of Rule 13e-3 under the Exchange
Act, the Company, BR and the Partnership have filed with the Commission a Rule
13e-3 Transaction Statement under the Exchange Act in connection with the
Merger. This Information Statement also constitutes a part of such Rule 13e-3
Transaction Statement. The Rule 13e-3 Transaction Statement and any amendments
thereto, including exhibits filed as a part thereof, are available for
inspection and copying as set forth above.
DOCUMENTS INCORPORATED BY REFERENCE
This Information Statement incorporates by reference documents relating to
the Partnership and BR which are not presented herein or delivered herewith.
Documents relating to the Partnership and BR (other than exhibits to such
documents unless such exhibits are specifically incorporated by reference) are
available to any person, including any beneficial owner, to whom this
Information Statement is delivered, on written or oral request, without charge,
from Meridian Offshore Company, 5051 Westheimer, Suite 1400, Houston, Texas
77056, Attention: Wendi L. Shackelford, Corporate Secretary, Telephone: (713)
624-9000. Copies of documents so requested will be sent by first class mail,
postage paid, within one business day of the receipt of such request.
The following Partnership documents are incorporated by reference herein:
1. Annual Report on Form 10-K for the year ended December 31, 1993
(the "1993 Partnership 10-K").
2. Quarterly Report on Form 10-Q for the quarter ended March 31, 1994
(the "1994 Partnership 10-Q").
The following BR documents are incorporated by reference herein:
1. Annual Report on Form 10-K for the year ended December 31, 1993
(the "1993 BR 10-K").
2. Quarterly Report on Form 10-Q for the quarter ended March 31, 1994
(the "1994 BR 10-Q").
All documents filed by the Partnership or BR with the Commission pursuant
to Sections 13(a), 13(c), 14 and 15(d) of the Exchange Act after the date hereof
and prior to the date of the Merger shall be deemed to be incorporated by
reference herein and shall be a part hereof from the date of filing of such
documents. Any statements contained in a document incorporated by reference
herein or contained in this Information Statement shall be deemed to be modified
or superseded for purposes hereof to the extent that a statement contained
herein (or in any other subsequently filed document which also is incorporated
by reference herein) modifies or supersedes such statement. Any statement so
modified or superseded shall not be deemed to constitute a part hereof except as
so modified or superseded.
NO PERSON IS AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY
REPRESENTATION NOT CONTAINED IN THIS INFORMATION STATEMENT AND, IF GIVEN OR
MADE, SUCH INFORMATION OR REPRESENTATION SHOULD NOT BE RELIED UPON AS HAVING
BEEN AUTHORIZED.
ii
<PAGE> 4
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
NO.
---
<S> <C>
AVAILABLE INFORMATION................................................................ ii
DOCUMENTS INCORPORATED BY REFERENCE.................................................. ii
GLOSSARY............................................................................. iv
INTRODUCTION......................................................................... 1
SPECIAL FACTORS...................................................................... 2
Background......................................................................... 2
Purpose and Structure of the Merger................................................ 3
Fairness of the Merger............................................................. 4
Effect of the Merger on the Market for Units; NYSE and PSE Listing and Exchange Act
Registration.................................................................... 6
Financing of the Merger............................................................ 6
Appraisal Rights................................................................... 6
Certain Federal Income Tax Consequences............................................ 7
Accounting Treatment............................................................... 8
Certain Litigation................................................................. 8
THE MERGER........................................................................... 9
Approval of the Merger............................................................. 9
Terms of the Merger................................................................ 9
Effects of the Merger.............................................................. 11
CERTAIN AGREEMENTS BETWEEN THE COMPANY AND ITS AFFILIATES AND MAXUS.................. 11
Unit Purchase Agreement............................................................ 11
Transition Agreement............................................................... 12
Purchase and Sale Agreement........................................................ 12
INFORMATION CONCERNING THE PARTNERSHIP AND THE PROPERTIES............................ 12
Business and Properties............................................................ 12
Oil and Gas Reserves............................................................... 15
Future Net Cash Flows.............................................................. 16
Certain Projections................................................................ 17
Recent Developments................................................................ 19
Selected Financial Data............................................................ 19
PRICE RANGE OF UNITS; CASH DISTRIBUTIONS............................................. 20
INFORMATION CONCERNING THE COMPANY, ACQUISITION, MERIDIAN AND BR..................... 20
Business of BR and its Subsidiaries................................................ 20
Selected Financial Data............................................................ 20
FEES AND EXPENSES.................................................................... 22
REGULATORY APPROVALS................................................................. 22
INDEX TO FINANCIAL INFORMATION....................................................... F-1
SCHEDULE 1 -- DIRECTORS AND EXECUTIVE OFFICERS OF BR AND THE COMPANY................. S-1
APPENDIX A -- AGREEMENT AND PLAN OF MERGER DATED AS OF APRIL 28, 1994 BETWEEN DIAMOND
SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP AND MERIDIAN OFFSHORE COMPANY.......
</TABLE>
iii
<PAGE> 5
GLOSSARY
Certain terms used in this Information Statement have the following
meanings:
"Bbl" means barrel.
"Bcf" means billion cubic feet of gas.
"Bcfe" means billion cubic feet of gas equivalent. Oil is converted
into cubic feet of gas equivalent based on 6 Mcf of gas to one barrel of
oil.
"MB" means thousands of barrels.
"MBO" means thousands of barrels of oil.
"Mcf" means thousand cubic feet of gas.
"Mmcf" means million cubic feet of gas.
"Proved reserves" are those estimated quantities of crude oil, natural
gas and natural gas liquids, which, upon analysis of geological and
engineering data, appear with reasonable certainty to be recoverable in the
future from known oil and gas reservoirs under existing economic and
operating conditions. The categories of proved reserves are as follows:
"Proved developed reserves" are those proved reserves which can be
expected to be recovered through existing wells with existing equipment
and operating methods.
"Proved undeveloped reserves" are those proved reserves which are
expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required.
"Unproved reserves" are potential oil and gas reserves that currently
have a degree of uncertainty that precludes them from being classified as
proved reserves. The classifications of unproved reserves, based upon
increasing degrees of uncertainty, are probable reserves, possible reserves
and speculative reserves. In all cases, the degree of uncertainty relates
to the geological, geophysical and engineering knowledge of the area. The
categories of unproved reserves are as follows:
"Probable reserves" are unproved reserves in an area of known
commercial oil and/or gas production where there is either an absence
of, or insufficient, geological, geophysical and/or engineering data
from which to have adequate certainty that the reserves can be
classified as proved reserves.
"Possible reserves" are unproved reserves in an area where
engineering, geological and geophysical data indicate the existence of
hydrocarbons but further data (particularly drilling) is required to
prove the presence of oil and/or gas.
"Speculative reserves" are unproved reserves in an area which has
characteristics analogous to known hydrocarbon producing environments
but where there is a lack of information to indicate the presence of
hydrocarbons.
iv
<PAGE> 6
INTRODUCTION
This Information Statement is being furnished to Unit holders by the
Partnership in connection with the Merger, pursuant to which (i) the Partnership
will be merged with and into the Company and (ii) each outstanding Unit (other
than Units held by the Company and its affiliates) will be converted into the
right to receive the Merger Consideration in cash, without interest. The Merger
is the second step in a transaction pursuant to which (i) on April 26, 1994, the
Company acquired the managing general partnership interest of Maxus Offshore in
the Partnership (representing a 0.99% economic interest in the Partnership) and
64,163,885 Units held by Maxus Exploration, and Acquisition acquired the special
general partnership interest of Maxus Energy in the Partnership (representing a
0.01% economic interest in the Partnership), for an aggregate purchase price of
$291,088,000 or approximately $4.485 per Unit, and (ii) on April 28, 1994, the
Partnership and the Company entered into the Merger Agreement, pursuant to which
holders of Units will receive $4.485 per Unit, the same price paid to Maxus for
its interests in the Partnership.
The principal executive offices of the Partnership, BR and the Company are
each located at 5051 Westheimer, Suite 1400, Houston, Texas 77056. The telephone
number of each of the Partnership, BR and the Company at such address is (713)
624-9000.
The Partnership is engaged in the exploration for, and the development and
production of, oil and gas on federal offshore leases located off the coast of
Louisiana and Texas. The Company is a direct wholly owned subsidiary of Meridian
and was formed for the purposes of acquiring the .99% managing general
partnership interest of Maxus Offshore in the Partnership and the 64,163,885
Units owned by Maxus Exploration and effecting the Merger. BR is a holding
company whose principal operating subsidiary, Meridian, is engaged in the
exploration, development and production of oil and gas and related marketing
activities.
The Company and the Partnership have entered into the Merger Agreement,
which provides for the consummation of the Merger. The Company, as the holder of
the managing general partnership interest in the Partnership and 64,163,885
Units, and Acquisition, as the holder of the special general partnership
interest in the Partnership, have each executed a written consent approving the
Merger. Under Delaware law and the Partnership Agreement, the Merger does not
require the consent of any other Unit holder.
As of the date of this Information Statement, there are 73,761,740 Units
outstanding held by approximately 14,679 Unit holders of record, of which
64,163,885 Units or approximately 87% are owned by the Company.
---------------------
NO MEETING OF UNIT HOLDERS WILL BE HELD TO CONSIDER APPROVAL OF THE MERGER
AND NO VOTE OR CONSENT OF UNIT HOLDERS IS BEING SOLICITED.
NEITHER THE PARTNERSHIP NOR THE COMPANY IS ASKING YOU FOR A PROXY OR
CONSENT AND YOU ARE REQUESTED NOT TO SEND THE PARTNERSHIP OR THE COMPANY A PROXY
OR CONSENT.
---------------------
<PAGE> 7
SPECIAL FACTORS
BACKGROUND
On March 8, 1994, George E. Howison, President and Chief Executive Officer
of Meridian, was contacted by Charles S. Weiss, Managing Director of Smith
Barney Shearson, who advised Mr. Howison that he understood that Maxus was
interested in selling all of its general and limited partnership interests in
the Partnership (the "Maxus Interests"). Mr. Weiss advised Mr. Howison that
Smith Barney Shearson was not acting on behalf of Maxus. Mr. Howison was told
that Maxus would provide information concerning the Partnership assets to
Meridian and that Maxus would permit access to Maxus employees for discussions
concerning those assets. Mr. Howison indicated to Mr. Weiss that Meridian might
be interested in acquiring the Maxus Interests.
On March 29, 1994, Randolph P. Mundt, Senior Vice President of Meridian,
was contacted by W. H. Bagley, Vice President of Maxus, to discuss Meridian's
potential interest in acquiring the Maxus Interests. Mr. Mundt indicated that
Meridian would be interested in acquiring these interests, and asked for
additional information. Mr. Bagley generally discussed the types of information
that could be made available, such as an inventory of properties and a
production history with respect to the properties.
On March 30, 1994, Maxus and Meridian executed a Confidentiality Agreement
under which Meridian was provided with data relating to the oil and gas
properties owned by the Partnership (the "Properties") and two other oil and gas
properties owned by Maxus and operated by the same Maxus regional staff (the
"Maxus Fee Properties"). This data included a list of the properties and Maxus'
and the Partnership's interest therein. On April 5, 1994, Mr. Bagley and Steven
G. Crowell, Senior Vice President of Maxus, made a presentation to Bobby S.
Shackouls, Executive Vice President and Chief Operating Officer, Mr. Mundt,
James S. Buchanan, Senior Vice President, L. David Hanower, Senior Vice
President, Steven W. Nance, Vice President, and David M. Drummond, Vice
President of Meridian, concerning the operational attributes of the Properties
and the Maxus Fee Properties, marketing arrangements, the Partnership's
structure, and staffing requirements associated with the management of the
Partnership. Matthew Buten, Vice President of Smith Barney Shearson, attended
the April 5 meeting at Meridian's request. Additional data supporting the
presentation on April 5 and other information concerning the assets being sold
were provided to Meridian personnel during the week of April 11, 1994.
On April 15, 1994, Mr. Mundt, accompanied by Mr. Hanower, presented Mr.
Crowell, McCarter Middlebrook, Vice President and General Counsel, and George W.
Pasley, Senior Vice President and Chief Financial Officer of Maxus, with
preliminary indications of interest with respect to the acquisition of the
Properties and the Maxus Fee Properties. On April 18, 1994, Mr. Crowell called
Mr. Mundt and indicated that Maxus was interested in pursuing the negotiation of
definitive agreements that would specify the terms and conditions under which
the Partnership Interests and the Maxus Fee Properties would be purchased.
Between April 19 and April 25, 1994, representatives of the Company,
including Mr. Mundt, Mr. Hanower, Gary P. Cooperstein and Warren de Wied of
Fried, Frank, Harris, Shriver & Jacobson, counsel to Meridian, and
representatives of Maxus, including Mr. Crowell, Mr. Middlebrook and Ed
Notestine, formerly General Counsel and currently a consultant to Maxus,
negotiated with respect to the terms of an acquisition of the Maxus Interests by
the Company and Acquisition, including the structure of the transaction and
representations and warranties and indemnities to be provided by Maxus. In the
course of these negotiations, the Company agreed to make an upward adjustment to
the purchase price to be paid to Maxus of approximately $15 million (an increase
from approximately $4.25 per Unit to approximately $4.485 per Unit) to reflect
Maxus' pro rata share of the cash proceeds of the sale by the Partnership of its
interests in Main Pass blocks 72, 73 and 74 to Pogo Producing Company. During
the same period, the foregoing representatives of the Company and Maxus prepared
drafts of an acquisition agreement for the transaction and negotiated and
prepared drafts of an agreement for certain transition services to be provided
by Maxus to the Partnership. The parties also negotiated the terms of the
purchase of the Maxus Fee Properties during the same period.
On April 25, 1994, Maxus issued a press release disclosing that it was
negotiating with an unidentified third party with respect to a sale of the Maxus
Interests at a price of approximately $4.48 per Unit.
2
<PAGE> 8
On April 26, 1994, the parties executed a unit purchase agreement (the
"Unit Purchase Agreement") with respect to the sale of the managing general
partnership interest of Maxus Offshore and the 64,163,885 Units held by Maxus
Exploration to the Company and the sale of the special general partnership
interest of Maxus Energy to Acquisition, for a total purchase price of
$291,088,000 (of which $3,341,230 was attributable to the 1.0% economic interest
in the Partnership represented by the general partnership interests in the
Partnership), or approximately $4.485 per Unit. The closing of the sale and
purchase took place simultaneously with the execution of the Unit Purchase
Agreement. Immediately following the closing of this transaction, Maxus
Exploration paid to the Partnership $36,849,635 in satisfaction of the amount
estimated to be outstanding under a promissory note of Maxus Exploration to the
Partnership and $253,050 in satisfaction of the Partnership's share of the value
of certain hedging transactions undertaken by Maxus, approximately 35% of which
were allocated for the account of the Partnership.
In addition, Maxus Exploration and the Company entered into a transition
services agreement (the "Transition Agreement"), which provides that Maxus will
continue, for a period of up to 90 days after April 26, 1994, to provide certain
services to the Partnership.
Also on April 26, 1994, Maxus Exploration and Meridian entered into a
separate purchase and sale agreement (the "Purchase and Sale Agreement")
pursuant to which Meridian agreed to purchase the Maxus Fee Properties for
approximately $58,000,000.
For additional information concerning the foregoing agreements, see
"CERTAIN AGREEMENTS BETWEEN THE COMPANY AND ITS AFFILIATES AND MAXUS."
On April 28, 1994, the Company and the Partnership entered into the Merger
Agreement, and the Company and Acquisition each executed a written consent
approving the Merger.
PURPOSE AND STRUCTURE OF THE MERGER
The purpose of the Merger is to acquire all of the outstanding Units,
thereby acquiring the entire equity interest in the Partnership. Since 1988, BR
has been selling its nonstrategic real estate, minerals and forest product
assets and reinvesting the net proceeds in domestic oil and gas reserves and in
the repurchase of its common stock. BR's current strategy is to increase
reserves principally through capital improvements to its existing properties and
through acquisitions of proved properties. The Company acquired the Maxus
Interests and is effecting the Merger at this time in furtherance of this
strategy. The Company has structured the acquisition of the Partnership
essentially as a unitary transaction involving a negotiated acquisition of the
Maxus Interests to be followed by a merger at the same purchase price per unit
that was negotiated with the holders of 87.1% of the Partnership interests.
The Company believes that the acquisition of the Maxus Interests in
conjunction with the Merger represents an opportunity for BR and the Company to
establish an operating position in a high priority, strategic area. The Company
believes that the Properties (which are primarily gas-producing properties) have
access to premium gas markets in the northeastern United States and that the
acquisition will provide further diversification from BR's existing gas markets
(a significant portion of which includes highly competitive markets in
California). In addition, the Company believes that the Properties have high
growth and exploratory potential. Meridian's staff and management have
considerable operating experience in offshore waters and Meridian believes this
experience increases the potential for further growth through exploration and
exploitation of the Properties. Moreover, the Partnership's proved reserves have
a reserve to production ratio of between five and seven years, which complements
the higher reserve to production ratio of BR's existing asset base.
Because the Company and Acquisition own all of the outstanding general
partnership interests in the Partnership and the Company owns approximately 87%
of the outstanding Units, under the Partnership Agreement and Delaware law the
Company and Acquisition currently have the power to approve a merger without the
consent of any other Unit holder. On April 28, 1994, the Company, as the holder
of a .99% managing general partnership interest in the Partnership and
64,163,885 Units, and Acquisition, as the holder of a .01% special general
partnership interest in the Partnership, each executed a written consent
approving the
3
<PAGE> 9
Merger. Under applicable federal securities laws, the Merger cannot be effected
until at least 20 calendar days after this Information Statement has been sent
or given to Unit holders. Accordingly, the Company expects that the Merger will
be consummated on , 1994 or as promptly as practicable thereafter,
assuming that the conditions to the Merger set forth in the Merger Agreement
have been satisfied. See "THE MERGER -- Terms of the Merger." As a result of the
Merger, the interest of the Company in the net book value and net income of the
Partnership will increase from 87.1% to 100%.
Except as described above, BR, the Company and the Partnership have no
present plans or proposals that would relate to or result in any extraordinary
corporate transaction, such as a merger, reorganization or liquidation involving
the Partnership or its subsidiaries, a sale or transfer of a material amount of
assets of the Partnership or its subsidiaries, any change in the Partnership's
management, any material change in the Partnership's distribution rate or policy
or indebtedness or capitalization, or any other material change in the
Partnership's structure or business.
FAIRNESS OF THE MERGER
The Company believes that the Merger is fair to Unit holders. In reaching
this conclusion, the Company considered the factors discussed below.
(i) The purchase price of $4.485 per Unit pursuant to the Merger is the
same price paid by the Company and Acquisition to acquire the Maxus Interests
from Maxus on April 26, 1994. See "SPECIAL FACTORS -- Background of the Merger."
The Company views the acquisition of the Maxus Interests and the Merger as
essentially a unitary transaction, on terms which were approved by the holders
of 87% of the Units, and in which Unit holders are being treated alike (except
that, as noted in clauses (ii) and (iii) below, certain aspects of the Merger
are more favorable to Unit holders than the terms of the purchase of the Maxus
Interests). The purchase price was negotiated in an arm's length transaction
with Maxus, which the Company believed to be sophisticated and experienced in
purchase and sale transactions involving oil and gas properties. Based upon
statements by Maxus, the Company believed that, prior to selling the Maxus
Interests to the Company and Acquisition, Maxus had solicited offers from other
third parties and that the price paid by the Company and Acquisition to acquire
the Maxus Interests represented the most favorable offer received by Maxus.
(ii) Unit holders of record as of May 13, 1994 would receive the
Partnership distribution of $.13 declared on April 25, 1994, which was paid on
June 7, 1994. Maxus did not and will not receive any such distribution.
(iii) Under the Unit Purchase Agreement, Maxus made certain representations
and warranties to the Company and Acquisition regarding, among other things, the
financial condition, assets, liabilities and operations of the Partnership.
Maxus is obligated to indemnify the Company against all damages incurred by the
Company or Acquisition arising out of a breach of any representation, warranty
or agreement by Maxus in the Unit Purchase Agreement, any filings by the
Partnership with the Commission prior to April 26, 1994, and certain other
matters. Accordingly, the purchase price received by Maxus could be reduced in
the future by indemnification payments to the Company. Unit holders are not
being asked to make any of the foregoing representations or warranties or to
indemnify the Company against any of the foregoing matters, and therefore the
Merger Consideration of $4.485 per Unit to be received by Unit holders will not
be subject to any such potential future reduction. Although as of the date of
this Information Statement the Company has not asserted any claims for
indemnification against Maxus, for the foregoing reasons the Merger
Consideration could be greater than the per Unit consideration retained by
Maxus. See "CERTAIN AGREEMENTS BETWEEN THE COMPANY AND ITS AFFILIATES AND
MAXUS -- Unit Purchase Agreement."
(iv) The Company considered conditions in the oil and gas industry in
general, and the current environment for acquisitions of oil and gas properties
(including offshore oil and gas properties). Meridian believes that it has
significant experience in acquiring oil and gas properties and, based upon its
view of conditions in the oil and gas industry in general, the current
acquisition environment for oil and gas properties and the factors described in
clauses (i) and (vi), the Company believes that the Merger Consideration is
consistent with consideration paid in connection with acquisitions of oil and
gas properties generally and is fair to the Unit holders.
4
<PAGE> 10
(v) The Company considered the current market price of the Units (the
closing sales price of the Units on April 25, 1994, the last trading day prior
to the announcement of the acquisition of the Maxus Interests, was $4.625) and
historical market prices for the Units during the past two years. See "PRICE
RANGE OF UNITS; CASH DISTRIBUTIONS." There is limited liquidity in the market
for the Units and the Merger represents an opportunity for holders to liquidate
their investment which might not otherwise be available to Unit holders. While
the Units had historically traded at prices higher than the Merger Consideration
(the high sales price of the Units for the year ended December 31, 1993 was
$6.875), the Units had also traded at lower prices (the closing price for the
Units on March 31, 1994 was $4.00 per Unit; the average closing price for the
Units for the 30 days prior to the announcement of the acquisition of the Maxus
Interests was $4.494), and the Company believed historical prices to be less
significant given that (i) the same purchase price was paid to Maxus for its
87.1% interest in the Partnership in a negotiated transaction and (ii) Maxus had
had the opportunity to seek other offers and, based upon statements by Maxus,
the Company believed that Maxus had done so.
(vi) The Company also considered information relating to the Properties,
including the historical operations of the Properties, current operations and
potential of the Properties, levels of oil and gas reserves, the ratio of oil
reserves to gas reserves, and programs for development and production
optimization. Meridian believes that it has significant experience in evaluating
oil and gas properties and, based upon its view of the Properties and the
factors described in clauses (i) and (iv), the Company believes that the Merger
Consideration is consistent with consideration paid in connection with
acquisitions of oil and gas properties generally and is fair to the Unit
holders. See "INFORMATION CONCERNING THE PARTNERSHIP AND THE PROPERTIES."
(vii) Unit holders are not entitled to appraisal rights in connection with
the Merger, and the lack of appraisal rights was deemed a negative factor. See
"SPECIAL FACTORS -- Appraisal Rights" and "SPECIAL FACTORS -- Certain
Litigation."
(viii) The Company did not structure the Merger to require approval of a
majority of unaffiliated Unit holders.
(ix) No unaffiliated representative was retained to act solely on behalf of
unaffiliated Unit holders for the purpose of negotiating the terms of the Merger
or preparing a report concerning the fairness of the Merger.
In view of the number and variety of factors considered, the Company did
not find it practicable to, and did not, assign relative weights to the factors
described above. However, the Company believes that the factors described in
(i), (ii), (iii) and (iv) above are favorable to its determination of fairness,
factors (v) and (vi) are neutral, and factors (vii), (viii) and (ix) are
negative.
As stated above, the Merger is not structured to require the approval of a
majority of unaffiliated Unit holders. In addition, neither Meridian, the
Company, the Partnership nor a majority of the non-employee directors of
Meridian or the Company retained or considered retaining an unaffiliated
representative to act solely on behalf of unaffiliated Unit holders for the
purpose of negotiating the terms of the Merger or preparing a report concerning
the fairness of the Merger. While these factors could be viewed as unfavorable
to a determination of fairness, the Company believes, notwithstanding these
factors, that the terms of the Merger are fair to Unit holders (a) because the
purchase price of $4.485 per Unit pursuant to the Merger is the same price paid
by the Company and Acquisition to acquire the Maxus Interests from Maxus on
April 26, 1994; the Company views the acquisition of the Maxus Interests and the
Merger as essentially a unitary transaction, on terms which were approved by the
holder of 87% of the Units, and in which all Unit holders are being treated
alike (except that, as noted in clauses (ii) and (iii) above, certain aspects of
the Merger are more favorable to Unit holders than the terms of the purchase of
the Maxus Interests); the purchase price was negotiated in an arm's length
transaction with Maxus, which the Company believed to be sophisticated and
experienced in purchase and sale transactions involving oil and gas properties;
and, based upon statements by Maxus, the Company believed that, prior to selling
the Maxus Interests to the Company and Acquisition, Maxus had solicited offers
from other third parties and that the price paid by the Company and Acquisition
to acquire the Maxus Interests represented the most favorable offer received by
Maxus, and (b) for the other reasons set forth in clauses (ii), (iii) and (vi)
above.
5
<PAGE> 11
The Company did not believe current net book value per Unit to be relevant
to its determination of fairness because such value (approximately $2.00 per
Unit at March 31, 1994 on a pro forma basis giving effect to the sale of the
Partnership's interests in Main Pass blocks 72, 73 and 74 on April 25, 1994 to
Pogo Producing Company) is substantially less than the Merger Consideration and
historical trading prices for the Units. The Company did not consider
liquidation value to be relevant to its determination of fairness because the
Company intends to continue to operate the business currently conducted by the
Partnership as a going concern and therefore the Company evaluated the
Partnership on a going concern basis, although the Company believed that
estimates of future net revenue, information concerning historical operations,
current operations and potential of the Properties, levels of reserves, the
ratio of oil reserves to gas reserves, programs for development and production
optimization, estimates of future oil and gas prices and general economic and
market conditions, which were considered by it in its determination of fairness,
would also be taken into account in determining liquidation value. A dissolution
of the Partnership, which could lead to liquidation of the Partnership, requires
an election to dissolve by the managing general partner of the Partnership which
is approved by the affirmative vote of the holders of a majority of the Units.
The Company, as the managing general partner and holder of a majority of the
Units, currently has no intention to dissolve or liquidate the Partnership.
Under the Partnership Agreement and the Delaware Revised Uniform Limited
Partnership Act, in the event of a dissolution of the Partnership, the
Partnership is not required to distribute the assets of the Partnership within a
specific time period. Accordingly, the value of the Partnership's assets in a
liquidation would depend upon prevailing conditions at the time of any such
sale. Such value, on a per Unit basis, could be higher or lower than the Merger
Consideration of $4.485 per Unit in cash. However, based upon the factors set
forth in clauses (i), (iv) and (vi) above, the Company has no reason to believe
that the consideration Unit holders would receive in a liquidation would be
greater than the Merger Consideration.
Neither Meridian nor the Company received any report, opinion or appraisal
from an outside party in connection with the acquisition of the Maxus Interests
or the Merger.
For the reasons stated above, BR and the Partnership acting through the
Company also believe that the Merger is fair to Unit holders.
EFFECT OF THE MERGER ON THE MARKET FOR UNITS; NYSE AND PSE LISTING AND EXCHANGE
ACT REGISTRATION
As a result of the Merger, the Units will cease to be outstanding and will
be delisted from the New York Stock Exchange (the "NYSE") and the Pacific Stock
Exchange (the "PSE"), and the registration of the Units under the Exchange Act
will be terminated.
FINANCING OF THE MERGER
The amount of funds needed by the Company to purchase all of the
outstanding Units pursuant to the Merger and to pay related fees and expenses
will be approximately $45 million. See "FEES AND EXPENSES." The Company plans to
obtain all of such funds through capital contributions or advances made by
Meridian. Meridian plans to obtain the funds for such capital contributions or
advances from working capital.
APPRAISAL RIGHTS
Holders of Units do not have appraisal rights in connection with the
Merger. The Partnership is a Delaware limited partnership and the Partnership
Agreement provides that the Partnership Agreement shall be construed in
accordance with and governed by the laws of the State of Delaware. The Company
is not aware of any provisions of Delaware law expressly providing rights to
holders of interests in a Delaware limited partnership in lieu of appraisal
rights. In cases involving corporations, courts applying Delaware law have held
that a controlling stockholder of a corporation involved in a merger has a
fiduciary duty to other stockholders that requires that the merger be fair to
other stockholders. In determining whether a merger is fair to minority
stockholders of a corporation, these courts have considered, among other things,
the type and amount of consideration to be received by stockholders and whether
there was fair dealing among the parties. These
6
<PAGE> 12
courts have held that a damages remedy may be available in a merger which is the
result of procedural unfairness, including fraud, misrepresentation or other
misconduct.
CERTAIN FEDERAL INCOME TAX CONSEQUENCES
The following discussion is a summary of the Federal income tax
consequences of the Merger to Unit holders. This discussion does not address the
particular Federal income tax consequences that may be relevant to certain types
of taxpayers subject to special treatment under the Federal income tax laws
(such as life insurance companies, banks, tax-exempt organizations, foreign
corporations and nonresident aliens). Moreover, because certain of the tax
consequences of the Merger are uncertain (due to the absence of precedental
authority), Unit holders are strongly urged to consult with their own tax
advisors regarding the Federal (as well as state, local and foreign) tax
consequences of the Merger.
Upon the Merger, a Unit holder will generally recognize gain or loss, for
Federal income tax purposes, measured by the difference between the amount
realized by the Unit holder in the Merger (which will include not only the cash
received by the Unit holder, but also the Unit holder's proportionate share of
the liabilities of the Partnership at the time of the Merger) and the Unit
holder's aggregate basis in his Units (which will generally equal the price paid
by the Unit holder for his Units, increased by the amount of income and gain
allocated to the Unit holder through and including the date of the Merger and
the Unit holder's proportionate share of the liabilities of the Partnership at
the time of the Merger, and decreased by the amount of deduction and loss
allocated to the Unit holder through and including the date of the
Merger - including depletion allowances to which the Unit holder was entitled
but, as to any depletable property, not in excess of the Unit holder's
proportionate share of the Partnership's basis in such depletable property - and
the amount of any cash distributions made to the Unit holder prior to the
Merger). Assuming that the Units were held by the Unit holder as a capital
asset, such gain or loss will be capital gain or loss (long term or short term
depending upon whether or not the Unit holder has held his Units for more than a
year at the time of the Merger), except to the extent provided in the following
paragraph.
A Unit holder will recognize ordinary income for Federal income tax
purposes (which may be substantial in amount) to the extent that the amount
realized by the Unit holder in the Merger, determined as set forth above, is
attributable to (1) inventory items which have "appreciated substantially in
value" and (2) unrealized receivables (which includes, generally, the
depreciation and intangible drilling deductions previously allocated to the Unit
holder as well as the depletion deductions to which the Unit holder was entitled
with respect to the depletable properties of the Partnership - but, as to any
depletable property, not in excess of the Unit holder's proportionate share of
the Partnership's basis in such depletable property). In the case of a Unit
holder realizing an overall gain in connection with the Merger, the ordinary
income which the Unit holder must recognize pursuant to the foregoing rule will
reduce the amount of capital gain that the Unit holder would otherwise recognize
(assuming, as stated above, that the Units are held by the Unit holder as a
capital asset). The amount of ordinary income which a Unit holder must recognize
pursuant to the foregoing rule may, however, be in excess of the Unit holder's
overall gain on the Merger, in which event the Unit holder will recognize no
capital gain but, instead, will recognize a capital loss in an amount equal to
the excess. In the case of a Unit holder who realizes an overall loss on the
Merger, any ordinary income which the Unit holder is required to recognize under
the foregoing rule will result in a corresponding increase in the amount of the
Unit holder's capital loss (assuming again that the Units are held by the Unit
holder as a capital asset).
The foregoing rules are complicated by a relatively recently enacted
provision of the Internal Revenue Code of 1986, as amended (the "Code"), under
which no regulations have yet been issued. This provision provides that if a
partner contributes property to a partnership having a value that does not equal
its basis and, within five years of the date of the contribution, the property
is distributed by the partnership (other than to the contributing partner), the
contributing partner must recognize gain or loss for Federal income tax purposes
equal to the difference between the fair market value of the contributed
property and its basis at the time of the contribution (with appropriate
adjustments being made to the contributing partner's basis in the partnership).
For Federal income tax purposes, the sale of the Units which was effected on
April 26, 1994 pursuant to the Unit Purchase Agreement (the "Sale Transaction")
resulted in a termination of the Partnership under Section 708(b)(1)(B) of the
Code, a theoretical distribution of the assets of the
7
<PAGE> 13
Partnership to the partners existing immediately subsequent to the Sale
Transaction, including the Unit holders, and a theoretical recontribution of
these assets to a newly formed partnership. As a result, Unit holders are
treated, for Federal income tax purposes, as having made property contributions
to the Partnership immediately subsequent to the Sale Transaction, and, in most
if not all cases, the value of the assets that the Unit holders are treated as
having contributed to the Partnership will not be equal to the Unit holder's
basis in those assets (which, in the aggregate, will equal the Unit holder's
basis in his Units immediately subsequent to the Sale Transaction). Accordingly,
this new provision of the Code would appear to apply to Unit holders. Arguments
can be made, however, based on the legislative history of the provision, that
the foregoing provision should only apply to property which was not contributed
to the Partnership in connection with the Partnership's formation in 1985 or, if
so contributed, should only apply to the extent of the Unit holder's pro rata
share of any decrease or increase in the value of the property occurring between
the time of the Partnership's formation and the date of the Sale Transaction.
Additionally, arguments can be made that, as a policy matter, the provision
should not apply at all in a situation such as the Merger where,
contemporaneously with the distribution of the property that the Unit holders
are treated as having contributed to the Partnership, the contributing partners
are recognizing the full amount of gain or loss attributable to their Units.
However, in the absence of any controlling precedental authority, no assurance
can be given that the provision will not apply.
Assuming that the provision does apply, any Unit holder at the time of the
Merger who was also a Unit holder at the time of the Sale Transaction will be
required, for Federal income tax purposes, to recognize gain or loss in the
Merger in a net amount equal to the difference between the Unit holder's basis
in his Units and the fair market value of those Units at the time of the Sale
Transaction. A Unit holder at the time of the Merger who acquired his Units
subsequent to the Sale Transaction will have to recognize gain or loss in an
amount equal to that which the person who held the Units at the time of the Sale
Transaction would have had to recognize pursuant to the foregoing rule,
generally increased or decreased by the amount of any adjustment made to the
Unit holder's share of the Partnership's basis in its assets, under Section 754
of the Code, in connection with the Unit holder's acquisition of his Units
(although, as a practical matter, the subsequent Unit holder will not know the
prior Unit holder's basis in his Units at the time of the Sale Transaction and,
therefore, will not be able to determine the amount of the prior holder's gain
or loss or the amount of the Section 754 adjustment resulting from the
subsequent Unit holder's acquisition of his Units). The character of the
foregoing gain or loss will be determined by reference to each property that the
Unit holder is deemed as having contributed to the Partnership at the time of
the Sale Transaction, with the amount of the gain or loss being computed
separately with respect to each property (but with the aggregate, net amount of
the gain or loss being as set forth above). Any gain or loss recognized under
this provision will result in a corresponding increase or decrease in the Unit
holder's basis in his Units and, therefore, in a corresponding reduction in the
overall gain or a corresponding increase in the overall loss recognized by the
Unit holder in connection with the Merger (pursuant to the rules discussed in
the second and third paragraphs under this heading, "Special Factors -- Certain
Federal Income Tax Consequences"). As a result, application of the foregoing
provision will not alter the net amount of gain or loss that must be recognized
by a Unit holder as a result of the Merger, but may alter the character of all
or a portion of that gain or loss.
ACCOUNTING TREATMENT
The acquisition of the Units pursuant to the Merger will be accounted for
as a purchase of assets whereby the oil and gas reserves underlying the Units
will be consolidated with the Company's reserves.
CERTAIN LITIGATION
On April 27, 1994, a purported class action entitled Susser vs. Burlington
Resources Inc., et al. (C.A. No. 13483) (the "Action") was filed in the Delaware
Chancery Court. The complaint (which names as defendants BR, the Partnership,
Maxus Energy, Maxus Offshore and three officers and directors of Maxus Offshore)
alleges, among other things, (i) that the proposed purchase price to be paid to
Unit holders does not represent the true value of the assets and future
prospects underlying the limited partnership interests in the Partnership, but
is an attempt to benefit BR unfairly at the expense of Unit holders, that the
market value and
8
<PAGE> 14
intrinsic value of the Units was and is materially in excess of $4.48 per Unit
and that the purchase price is not the result of arm's length negotiations, (ii)
that Maxus was under pressure to sell its stake in the Partnership due to
growing financial problems at Maxus, (iii) that defendants' announcement of the
proposed Merger fails to adequately disclose, inter alia, whether defendants
obtained a fairness opinion from an independent investment bank and that
allegedly the Partnership was on the verge of reporting sustained and
significant profits, and (iv) that Maxus and BR have breached and continue to
breach their purported fiduciary duties as past and present controlling security
holders of the Partnership, including that Maxus did not attempt to achieve the
highest possible price for the Partnership. The complaint seeks, among other
things, preliminary and permanent injunctive relief and unspecified damages. BR
and the Company believe that the Action is wholly without merit and intend to
defend it vigorously.
On or about May 27, 1994, a purported class action entitled Sonem Partners,
Ltd. vs. Diamond Shamrock Offshore Partners Limited Partnership, et al. (C.A.
No. 13532) (the "Sonem Action") was filed in the Delaware Chancery Court. The
complaint (which names as defendants the Partnership, Maxus Offshore and Maxus
Energy) claims, among other things, that Maxus Offshore and Maxus Energy owed a
duty, in connection with the sale of their interests in the Partnership, to the
Partnership and its public Unit holders to treat them in a fair and equitable
manner, to refrain from abusing their positions of control and not to favor
their own interests at the expense of the Partnership and its public Unit
holders. The complaint alleges, inter alia, that (1) Maxus Offshore and Maxus
Energy, by engaging in two simultaneous transactions (the sale of their
Partnership interests and the sale of the Maxus Fee Properties to BR), breached
their duties by failing to seek the maximum value for each publicly-held Unit
and, instead, agreed to sell Maxus' control of the Partnership for an amount
below its realizable value and compensated themselves by the sale of the Maxus
Fee Properties at an artificially inflated value; (2) the consideration to be
paid to the Partnership's public Unit holders is grossly unfair, inadequate and
substantially below the fair value of the Partnership; and (3) the transaction
is wrongful, unfair and harmful to the Partnership's public Unit holders. The
complaint seeks, among other things, preliminary and permanent injunctive
relief, rescission, an accounting and unspecified damages. The Company believes
that the Partnership is not an appropriate party to the Sonem Action and that
such action as to the Partnership is wholly without merit, and the Company
intends to defend it vigorously.
THE MERGER
APPROVAL OF THE MERGER
On April 28, 1994, the Board of Directors of the Company approved on behalf
of the Company, and the Company, in its capacity as managing general partner of
the Partnership, approved on behalf of the Partnership, the Merger, upon the
terms and subject to the conditions set forth in the Merger Agreement. Also on
April 28, 1994, the Company, as the holder of a .99% managing general
partnership interest in the Partnership and of 64,163,885 Units, and
Acquisition, as the holder of a .01% special general partnership interest in the
Partnership, executed written consents approving the Merger. Under Delaware law
and the Partnership Agreement, by reason of such consents, no other vote or
consent of Unit holders is required in order to consummate the Merger.
TERMS OF THE MERGER
Merger Consideration
At the Effective Time (as defined below), each partnership interest in the
Partnership held by the Company or any of its affiliates will be cancelled and
each outstanding Unit (other than Units held by the Company or any of its
affiliates) will be converted into the right to receive the Merger Consideration
of $4.485 per Unit in cash, without interest, and all such Units will
automatically cease to be outstanding and will be cancelled and retired and
cease to exist.
Effective Time
The Merger will become effective (the "Effective Time") at the time a
Certificate of Merger is duly filed with the Secretary of State of the State of
Delaware in accordance with the Delaware General Corporation
9
<PAGE> 15
Law and the Delaware Revised Uniform Limited Partnership Act or at such other
time as may be specified in the Certificate of Merger. Provided the conditions
to the Merger have been satisfied or waived, it is anticipated that the Merger
will be consummated on , 1994 or as promptly as practicable
thereafter.
Parties; Surviving Corporation
In the Merger, the Partnership will be merged with and into the Company,
whereupon the separate existence of the Partnership will cease. The Company will
be the surviving corporation in the Merger and will continue its existence under
the laws of the State of Delaware. At the election of the Company, any direct or
indirect wholly owned subsidiary of Meridian Oil Holding Inc. ("MOHI") may be
substituted for the Company as a party in the Merger.
Conditions to the Merger
The obligations of the Company and the Partnership to effect the Merger are
each subject to (i) no statute, rule, regulation, executive order, decree,
injunction or other order having been executed, entered, promulgated or enforced
by any court or governmental authority which is in effect and has the effect of
prohibiting consummation of the Merger, (ii) the waiting period applicable to
the Merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as
amended (the "HSR Act"), having expired or been terminated (which was terminated
effective June 9, 1994), and (iii) a 20 calendar day period having elapsed from
the date of mailing of this Information Statement to Unit holders.
Procedures for Exchange of Units
Prior to the Effective Time, the Company will appoint a bank or trust
company to act as disbursing agent (the "Disbursing Agent") for the payment of
the Merger Consideration upon surrender of certificates representing the Units.
Promptly after the Effective Time, the Company will cause the Disbursing Agent
to mail to each person who was a record holder as of the Effective Time of an
outstanding certificate or certificates which immediately prior to the Effective
Time represented Depositary Units (the "Certificates"), a form of letter of
transmittal (which shall specify that delivery shall be effected, and risk of
loss and title to the Certificates shall pass, only upon proper delivery of the
Certificates to the Disbursing Agent) and instructions for use in effecting the
surrender of the Certificate in exchange for payment of the Merger
Consideration. Upon surrender to the Disbursing Agent of a Certificate, together
with such letter of transmittal duly executed and such other documents as may be
reasonably required by the Disbursing Agent, the holder of such Certificate will
be paid in exchange therefor cash in an amount equal to the product of the
number of Units represented by such Certificate multiplied by the Merger
Consideration, and such Certificate shall forthwith be cancelled. No interest
will be paid or accrued on the cash payable upon the surrender of the
Certificates.
At and after the Effective Time, there will be no registration of transfers
of Units and the Partnership will instruct the depositary for the Depositary
Units not to register transfers of the Depositary Units. From and after the
Effective Time, the holders of Units outstanding immediately prior to the
Effective Time shall cease to have any rights with respect to such Units except
as otherwise provided in the Merger Agreement or by applicable law.
At any time more than one year after the Effective Time, the Company will
be entitled to require the Disbursing Agent to deliver to it any funds made
available to the Disbursing Agent and not disbursed in exchange for
Certificates. Thereafter, holders of Units will be entitled to look only to the
Company (subject to abandoned property, escheat and other similar laws) as
general creditors thereof with respect to any Merger Consideration that may be
payable upon due surrender of the Certificates held by them. Neither the Company
nor the Disbursing Agent will be liable to any holder of a Unit for any Merger
Consideration delivered to a public official pursuant to any abandoned property,
escheat or other similar law.
Distribution
Unit holders of record on May 13, 1994 received the Partnership
distribution of $.13 per Unit declared on April 25, 1994, which was paid on June
7, 1994.
10
<PAGE> 16
The foregoing summary of the Merger Agreement is qualified in its entirety
by reference to the complete text of the Merger Agreement, a copy of which is
attached as Appendix A.
EFFECTS OF THE MERGER
As a result of the Merger, each outstanding Unit (other than Units held by
the Company or any of its affiliates) will be converted into the right to
receive the Merger Consideration of $4.485 per Unit in cash, without interest,
and all such Units will automatically cease to be outstanding and will be
cancelled and retired and cease to exist and will have no further interest in
the net book value, assets, net income, cash flow, distributions or other future
performance of the Partnership, and the current holders of Units (other than the
Company and its affiliates) will have no equity interest in the Partnership and,
therefore, will not be able to participate in the future growth, if any, of the
Partnership. At the same time, the interest of the Company in the net book
value, assets, net income, cash flow, distributions and future performance of
the Partnership will increase from 87.1% to 100%.
CERTAIN AGREEMENTS BETWEEN THE COMPANY AND ITS AFFILIATES AND MAXUS
UNIT PURCHASE AGREEMENT
On April 26, 1994, the Company and Acquisition purchased the Maxus
Interests for an aggregate purchase price of $291,088,000 (of which $3,341,230
was attributable to the 1.0% economic interest in the Partnership represented by
the general partnership interests in the Partnership) or approximately $4.485
per Unit, pursuant to the Unit Purchase Agreement. In accordance with the terms
of the Unit Purchase Agreement, Maxus Exploration used $36,849,635 of the
purchase price to repay the amount estimated to be outstanding under a
promissory note of Maxus in favor of the Partnership and used $253,050 of the
purchase price to pay the Partnership its share of the value of certain hedging
transactions undertaken by Maxus, approximately 35% of which were allocated for
the account of the Partnership.
In the Unit Purchase Agreement, Maxus made certain representations and
warranties to the Company and Acquisition, including representations and
warranties with respect to (i) the organization and qualification of Maxus, the
Partnership and its subsidiary, Diamond Shamrock Offshore Pipeline Company
("Pipeline"), (ii) the power and authority of Maxus to consummate the purchase
and sale of the Maxus Interests, (iii) the absence of any material adverse
change affecting the Partnership since December 31, 1993, (iv) the absence of
pending or threatened litigation affecting the Partnership or Pipeline, (v) the
accuracy of all filings of the Partnership with the Commission since December
31, 1990, including the Partnership's financial statements, (vi) the absence of
consent or approval requirements for consummation of the purchase and sale,
(vii) compliance by the Partnership with applicable laws, (viii) title of Maxus
to the Maxus Interests, (ix) rights of the Partnership under oil and gas leases
and (x) the absence of material liabilities or obligations of the Partnership
other than those reflected in its financial statements at December 31, 1993 or
incurred subsequently in the ordinary course of business.
Under the Unit Purchase Agreement, Maxus agreed to indemnify and hold
harmless the Company and Acquisition from and against all damages incurred by
the Company or Acquisition or any of their affiliates, arising out of, resulting
from or relating to (i) a breach of any representation, warranty or agreement of
Maxus contained in or made pursuant to the Unit Purchase Agreement or any facts
or circumstances constituting such a breach, (ii) the Partnership's Quarterly
Report on Form 10-Q for the quarter ended March 31, 1994 and all other forms,
reports and documents filed by the Partnership with the Commission prior to
April 26, 1994, (iii) any indebtedness of Maxus or any of its affiliates to the
Partnership, or any transaction or arrangement (contractual or otherwise)
involving the Partnership and Maxus or any of its affiliates, other than
transactions or arrangements set forth in the Transition Agreement, and (iv) the
transactions under an agreement of purchase and sale dated as of March 28, 1994,
pursuant to which the Partnership sold certain oil and gas properties to Pogo
Producing Company.
11
<PAGE> 17
TRANSITION AGREEMENT
Concurrently with the execution of the Unit Purchase Agreement, Maxus
Exploration and the Company entered into the Transition Agreement, pursuant to
which Maxus Exploration will continue to provide management, operations,
accounting, tax, marketing, technical and administrative services to the
Partnership of the same type, level and quality provided prior to April 26,
1994, for a period of up to 90 days after April 26, 1994, to the extent Maxus
Exploration is capable of providing such services and such services are not
terminated by the Company. Under the Transition Agreement, Maxus Exploration
will also assist the Company in preparing tax returns of the Partnership
covering periods through December 31, 1994.
The Company agreed (i) to cause the Partnership to reimburse Maxus
Exploration as provided in the Partnership Agreement with respect to service
relating to periods prior to April 26, 1994, (ii) on behalf of the Partnership,
to pay Maxus Exploration a fixed fee of $375,000 for services for each of the
periods ending May 31, 1994 and June 30, 1994, and (iii) on behalf of the
Partnership, to reimburse Maxus Exploration as provided in the Partnership
Agreement for any services thereafter. The Company also agreed to indemnify and
hold harmless Maxus Exploration against damages incurred by it arising out of
the performance of the services, except to the extent arising from its gross
negligence or willful misconduct.
The Transition Agreement also permits the Company to terminate certain
existing marketing arrangements between Maxus and the Partnership pursuant to
which Maxus markets gas produced by the Partnership, at no cost to the
Partnership, and to require Maxus to assign to the Partnership all of its right,
title and interest under certain gas sales and exchange contracts for which
Maxus previously obtained gas supplies under the marketing arrangements referred
to above.
Maxus further agreed that, to the extent the Company incurs damages arising
out of matters for which Maxus could bring a claim under its insurance policies,
Maxus will use its best efforts to bring a claim under such policies and will
remit the net proceeds of any such claim to the Company.
PURCHASE AND SALE AGREEMENT
Also on April 26, 1994, Meridian and Maxus Exploration entered into the
Purchase and Sale Agreement, pursuant to which Meridian agreed to acquire the
interests of Maxus in the Maxus Fee Properties for $58,000,000, subject to
certain adjustments. Maxus' interests in the Maxus Fee Properties consisted of
approximately 1,801 net acres in the McFarlan Field in Wharton County, Texas and
approximately 3,300 net acres in Grand Isle Block 25 located offshore Louisiana
(daily gross production attributable to the Maxus Fee Properties is
approximately 30 Mmcf and approximately 148 Bbls of condensate). The Purchase
and Sale Agreement contains representations and warranties, covenants, closing
conditions and indemnities customary for purchase and sale transactions
involving oil and gas properties. The sale of the Maxus Fee Properties closed on
June 22, 1994.
INFORMATION CONCERNING THE PARTNERSHIP AND THE PROPERTIES
BUSINESS AND PROPERTIES
The following information is excerpted from the 1993 Partnership 10-K,
which was prepared by Maxus Offshore, which at that time was the managing
general partner of the Partnership:
"The Partnership is engaged in oil and gas exploration and production
activities in federal waters offshore Texas and Louisiana. The Partnership
was formed in Delaware in 1985 to succeed to the oil and gas exploration
and production business previously conducted by [Maxus] Exploration, a
wholly owned subsidiary of Maxus [Energy], in federal waters offshore Texas
and Louisiana. . . ."
"The Partnership properties include interests in 82 offshore federal
leases within 45 fields. The Partnership is the operator of 46 of such
leases. Of the leases, 49 are held by either oil or gas production, with
sales being made from all of such leases in 1993. During 1993, the
Partnership properties produced approximately 74 Mmcf of gas per day and
4,100 barrels of oil per day."
12
<PAGE> 18
"The following table sets forth information with respect to certain of
the Partnership properties. The blocks shown in the table are listed in
descending order based upon the present value of estimated future net cash
flows from production at December 31, 1993, before income taxes, discounted
at 10% per annum ("Discounted Present Value"), with the total proved
reserves from such blocks accounting for 55% of the Discounted Present
Value attributable to the Partnership properties as of December 31, 1993.
The two largest blocks, accounting for approximately 28% of the Partnership
properties on a percentage of Discounted Present Value basis, are discussed
in greater detail below.
<TABLE>
<CAPTION>
1993 AVERAGE NET
% OF YEAR DAILY PRODUCTION
WORKING PRODUCTION -----------------
BLOCKS INTEREST(1) COMMENCED(2) BBL MCF
------ ----------- ------------ ----- ------
<S> <C> <C> <C> <C>
Green Canyon 18.......................... 15.00 1987 1,149 1,341
West Cameron 142......................... 100.00 1993 3(3) 102(3)
Ewing Banks 944, 988..................... 15.00 1988 588 633
Main Pass 127 Complex.................... 100.00 1980 8 23,526
Vermilion 225/226........................ 68.16 1983; 1992 119 8,592
</TABLE>
- ---------------
(1) A working interest entitles the owner to explore, develop, operate and
receive the production from a property, subject usually to a royalty and
sometimes to other non-operating interests. The working interest bears the
operating and development costs. If more than one block is shown and
different ownership interests occur in each block, then the working
interest shown is a unitized working interest.
(2) For blocks with platforms that commenced production in different years, the
year production commenced is shown for each platform.
(3) Average is for eight days of production during 1993."
"Green Canyon Block 18 accounts for approximately 15.2% of the Discounted
Present Value of the Partnership properties. The block contains 5,760 acres in
which the Partnership holds a 15% working interest. A total of 14 wells are
currently producing."
"West Cameron Block 142 accounts for approximately 12.9% of the Discounted
Present Value of the Partnership properties. The block was discovered and
developed in 1993. Two wells were drilled on the block and current net
production is approximately 13 Mmcf per day and 340 barrels of oil per day."
"During 1993, the Partnership had gas discoveries at West Cameron 142, Main
Pass 181 and Main Pass 111, blocks where it had a 100% working interest. The
Partnership's reserve additions resulted in replacement of approximately 122% of
the year's production."
Developed and Undeveloped Properties
"The following table sets forth information at December 31, 1993 with
respect to the developed and undeveloped oil and gas properties owned by the
Partnership. As used in this report, "gross" acres are the total number of acres
in which the Partnership owns any interest. "Net" acres are the sum of the
fractional working interests the Partnership owns in gross acres.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
------------------ --------------------
GROSS NET GROSS NET
ACRES ACRES ACRES ACRES
------ ------ ------- -------
<S> <C> <C> <C> <C>
Offshore Louisiana......................... 26,383 9,686 219,005 145,707
Offshore Texas............................. 12,478 2,800 132,761 77,319
------ ------ ------- -------
Total............................ 38,861 12,486 351,766 223,026
</TABLE>
The Managing General Partner believes that the time remaining under the
primary terms of the leases covering undeveloped acreage included in the
Partnership properties is, as a whole, sufficient for their exploration and
development under current conditions."
13
<PAGE> 19
Drilling Activity
"The following table sets forth information regarding exploratory and
development wells drilled for the three years ended December 31, 1993. As used
in this report, "gross" wells are the total number of wells in which the
Partnership owns any interest. "Net" wells are the sum of the fractional
interests the Partnership owns in gross wells. "Productive" wells are either
producing wells or wells capable of commercial production although currently
shut-in. One or more completions in the same bore hole are counted as one well.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER
31,
---------------------
1993 1992 1991
--- --- ---
<S> <C> <C> <C>
Net Exploratory Wells Drilled
Productive............................................ 2.0 0 2.3
Dry................................................... 1.0 1.0 1.6
--- --- ---
Total......................................... 3.0 1.0 3.9
Net Development Wells Drilled
Productive............................................ 1.5 3.2 .4
Dry................................................... .1 .0 2.1
--- --- ---
Total......................................... 1.6 3.2 2.5
</TABLE>
At February 28, 1994, the Partnership had 5 gross wells (.9 net wells) in
progress."
Productive Wells
"The following table sets forth the Partnership's total gross and net
productive oil and gas wells, including multiple completions, at December 31,
1993.
<TABLE>
<CAPTION>
GROSS NET
----- ----
<S> <C> <C>
Productive oil wells.......................................... 101 20.4
Productive gas wells.......................................... 103 36.2
Multiple completions.......................................... 11 3.7
</TABLE>
Production and Sales of Oil and Gas
"The following table sets forth the average sales prices and production
costs of crude oil and natural gas produced for the three years ended December
31, 1993.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1993 1992 1991
------ ------ ------
<S> <C> <C> <C>
Average Sales Price
Crude Oil (per barrel)....................... $17.12 $18.61 $20.16
Natural Gas (per Mcf)........................ $ 2.21 $ 2.01 $ 1.88
Average Production Cost (per barrel)*.......... $ 2.72 $ 2.33 $ 2.49
</TABLE>
- ---------------
* Production or lifting cost is exclusive of depreciation and depletion
applicable to capitalized lease acquisition, exploration and development
expenditures. The gas production was converted to equivalent barrels of crude
oil by dividing the Mcf volume by six. Six Mcf of gas have approximately the
heating value of one barrel of crude oil."
Regulation of Crude Oil and Natural Gas Production
"Domestic exploration for and production and sale of oil and gas are
extensively regulated at both the national and local levels. The heavy
regulatory burden on the oil and gas industry increases its costs of doing
business and consequently affects its profitability."
14
<PAGE> 20
Environmental Regulation
"Various federal, state and local laws and regulations covering the
discharge of materials into the environment or otherwise relating to the
protection of the environment may affect the Partnership's operations and costs.
Environmental protection laws to date have not required the Partnership to make
any significant additional capital outlays. It is not anticipated that the
Partnership will be required in the near future to expend amounts that are
material in relation to its total capital expenditure program by reason of
environmental laws and regulations, but inasmuch as such laws and regulations
are constantly being revised and changed, the Managing Partner is unable to
predict the ultimate cost of complying with present and future environmental
laws and regulations."
Competition and Marketing
"The Partnership's production represents only a small fraction of the total
world markets for oil and natural gas. As a result, the prices the Partnership
receives depend primarily on the relative balance between supply and demand in
these markets."
"The Managing General Partner believes that the longer term potential for
growth in natural gas demand remains high due to the abundance of the fuel,
environmental awareness and price advantages; however, market prices remain
extremely volatile with weather and regional supply and demand imbalances
causing the potential for large monthly price swings. To counteract the
potential for pricing swings, the Managing General Partner entered into a
hedging program that essentially fixed prices beginning with June 1993
production for approximately 40% of the Partnership's gas production. The
program has been extended through 1994 and may cover a larger portion of the
Partnership's gas production. Overall, the Partnership has been able to realize
premium gas prices resulting from focused marketing efforts and the addition of
aggregated supply, which enables the marketing staff to offer large volumes
backed by diversified supply sources."
"The Partnership's natural gas volumes are combined with aggregated, third
party supplies for ultimate sale to several different types of customers under
various sales arrangements, all of which are classified as either spot or term
sales. Spot sales are made on a day-to-day basis, generally under contracts
having terms of approximately one calendar month or less. Term sales are firm
commitments that are made on a multi-month basis. Pricing is predominately set
as a function of market clearing prices (index prices) which will fluctuate with
the market, or fixed prices which will remain steady with the market. Index
prices may be converted to a fixed price via the hedging program described
above. Of the Partnership's total natural gas sales volumes and gas sales
revenue in 1993, approximately 41% was ultimately sold directly to local
distribution companies and end-users with the remaining 58% ultimately being
sold to pipelines and gas marketing companies."
"The world oil market continues to be subject to uncertainty. Iraq has not
yet resumed oil sales due to its failure to agree to United Nations imposed
conditions on such sales, but the threat of increased Iraqi production continues
to overhang the market. Oil prices have recently decreased primarily due to
additional availabilities from non-OPEC countries and excessive OPEC production
coupled with limited demand growth in developed countries."
OIL AND GAS RESERVES
The following information is excerpted from the 1993 Partnership 10-K:
"Net proved developed and undeveloped reserves are the estimated quantities
of crude oil and natural gas 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 developed
reserves are proved reserve volumes that can be expected to be recovered through
existing wells with existing equipment and operating methods. Proved undeveloped
reserves are proved reserve volumes that are expected to be recovered from new
wells on undrilled acreage or from existing wells where a significant
expenditure is required for recompletion."
15
<PAGE> 21
"The following table represents the Partnership's net interests in
estimated quantities of proved developed and undeveloped reserves of crude oil,
including condensate (in thousands of barrels), and natural gas (in millions of
cubic feet) at December 31, 1993, 1992 and 1991, and changes in such estimated
quantities for the years then ended:
<TABLE>
<CAPTION>
OIL GAS
(MB) (MMCF)
------ -------
<S> <C> <C>
NET PROVED DEVELOPED AND UNDEVELOPED RESERVES
January 1, 1991................................................. 11,354 186,846
Revisions of previous estimates................................. 760 (5,257)
Extensions, discoveries and other additions..................... 122 2,945
Production...................................................... (2,061) (32,778)
Purchase of reserves in place................................... 207 26,752
------ -------
December 31, 1991............................................... 10,382 178,508
Revisions of previous estimates................................. 953 (192)
Extensions, discoveries and other additions..................... 307 10,852
Production...................................................... (1,583) (31,559)
------ -------
December 31, 1992............................................... 10,059 157,609
Revisions of previous estimates................................. 487 (9,692)
Extensions, discoveries and other additions..................... 660 47,223
Production...................................................... (1,517) (27,181)
------ -------
December 31, 1993............................................... 9,689 167,959
====== =======
NET PROVED DEVELOPED RESERVES
January 1, 1991................................................. 10,805 137,731
December 31, 1991............................................... 9,806 141,641
December 31, 1992............................................... 9,287 120,328
December 31, 1993............................................... 9,046 118,567
</TABLE>
FUTURE NET CASH FLOWS
The following information is excerpted from the 1993 Partnership 10-K:
"The standardized measure of discounted future net cash flows
("standardized measure") relating to proved oil and gas reserves is calculated
and presented in accordance with Statement of Financial Accounting Standards No.
69. The standardized measure has been prepared assuming year-end selling prices
(adjusted for future fixed and determinable contractual price changes) for the
Partnership's estimated share of future production from proved oil and gas
reserves. Future production and development costs were computed by applying
year-end costs to future years. A prescribed 10% discount factor was applied to
future net cash flows. Because prices fluctuate, a calculation of the
standardized measure utilizing current prices would result in different
discounted future net cash flows for 1993 than is presented."
16
<PAGE> 22
"The Partnership cautions that this standardized measure is not
representative of fair market value, and the standardized measure presented for
the Partnership's proved oil and gas reserves is not representative of the
reserve value. The standardized measure is intended only to assist financial
statement users in making comparisons between companies."
<TABLE>
<CAPTION>
1993 1992 1991
--------- -------- ---------
<S> <C> <C> <C>
Future cash inflows............................ $ 522,176 $546,581 $ 580,780
Future production and development costs........ (179,006) (87,974) (200,596)
--------- -------- ---------
Future net cash flows.......................... 343,170 358,607 380,184
Annual discount at 10% rate.................... (96,820) (79,706) (77,528)
--------- -------- ---------
Standardized measure of discounted future net
cash flows................................... $ 246,350 $278,901 $ 302,656
========= ======== =========
</TABLE>
"The following are the principal sources of change in the standardized
measure:
<TABLE>
<CAPTION>
1993 1992 1991
-------- -------- --------
<S> <C> <C> <C>
January 1,..................................... $278,901 $302,656 $417,655
Sales and transfers of oil and gas produced,
net of production costs................... (71,482) (79,701) (85,962)
Net changes in prices and production costs... (6,474) (9,504) (119,686)
Extensions, discoveries and improved
recovery, less related costs.............. 48,483 15,152 6,051
Previously estimated development costs
incurred during the year.................. 6,099 (2,966) 5,719
Revisions of previous quantity estimates..... (12,710) 28,433 17,855
Purchase of reserves in place................ 3,509 -- 20,682
Accretion of discount........................ 27,890 30,266 41,766
Other........................................ (27,866) (5,435) (1,424)
-------- -------- --------
December 31,................................... $246,350 $278,901 $302,656
======== ======== ========
</TABLE>
CERTAIN PROJECTIONS
In connection with its evaluation of the acquisition of the Maxus Interests
and the Merger, the Company prepared for internal use certain estimates of
future oil and gas production and net cash flows from the Properties. The
Company and BR do not as a matter of course make public forecasts or estimates
of future sales, production, capital expenditures, earnings or cash flows. The
projections and estimates set forth below were not prepared with a view to
public disclosure and are based upon numerous assumptions with respect to future
prices of oil and gas, future production levels, results of development
programs, timing of production and of development programs, future development
costs and economic and other factors which are subject to significant
uncertainties and conditions, many of which are beyond the control of the
Company and BR. Neither the Company nor BR assumes any responsibility for the
accuracy of the projections or estimates set forth below and there can be no
assurance that such projections or estimates will be realized and actual results
may be higher or lower than those shown. Such projections or estimates were not
prepared with a view to complying with published guidelines of the Commission
regarding projections and forecasts and were not prepared in accordance with
guidelines published by the American Institute of Certified Public Accountants.
Oil and Gas Production from Proved Reserves
Approximately 42% of the proved reserves attributable to the Properties as
of December 31, 1993 consisted of proved developed reserves which were currently
producing and approximately 58% of the proved reserves attributable to the
Properties as of December 31, 1993 were either proved developed reserves which
were not currently producing or proved undeveloped reserves. The Company
currently estimates that capital expenditures for the development of such
non-producing reserves will aggregate approximately $11 million in
17
<PAGE> 23
1994, $17.5 million in 1995, $2.5 million in 1996, $2 million in 1997 and $2
million in 1998. The Company believes that these capital expenditure programs
should result in increases in oil and gas production. Based upon numerous
assumptions, including the capital expenditures program described above, future
oil and gas prices, rates of development of proved undeveloped reserves and a
variety of other assumptions, the Company prepared estimates of oil and gas
production of the Properties from proved reserves. The Company estimated oil
production from proved reserves of 1,405 MBO, 1,446 MBO, 1,149 MBO, 803 MBO and
924 MBO for the years 1994, 1995, 1996, 1997 and 1998, respectively (of which 39
MBO, 139 MBO, 111 MBO, 76 MBO and 97 MBO were estimated to be attributable to
production from proved undeveloped reserves), compared with historical oil
production of the Partnership of 1,583 MBO and 1,517 MBO for the years 1992 and
1993, respectively. The Company estimated gas production from proved reserves of
27,156 Mmcf, 31,642 Mmcf, 27,896 Mmcf, 19,785 Mmcf and 14,263 Mmcf for the years
1994, 1995, 1996, 1997 and 1998, respectively (of which 3,836 Mmcf, 10,529 Mmcf,
10,490 Mmcf, 7,498 Mmcf and 5,634 Mmcf were estimated to be attributable to
production from proved undeveloped reserves), compared with historical gas
production of the Partnership of 31,559 Mmcf and 27,181 Mmcf for the years 1992
and 1993, respectively.
Cash Flows from Proved Reserves
In connection with the Company's evaluation of the acquisition of the Maxus
Interests and the Merger, the Company prepared for internal use projections of
net cash flow of the Properties (cash flow from operations of the Properties
less capital expenditures for proved reserves) from proved reserves for the
years 1994 through 1998. The assumptions underlying these projections were as
follows: (a) the levels of production described above would be achieved; (b)
capital expenditures would be equal to the amounts set forth above; (c) the
Company used for this purpose estimates of future gas and oil prices based upon
the actual average oil and gas prices received by the Partnership for 1993, with
escalators, which were gas prices of $2.28, $2.40, $2.55, $2.71 and $2.82 per
Mcf and oil prices of $15.39, $16.07, $16.58, $17.00 and $17.53 per Bbl for the
years 1994, 1995, 1996, 1997 and 1998, respectively (for the quarter ended March
31, 1994, the Partnership reported that it had received average gas and oil
prices of $2.37 per Mcf and $12.71 per Bbl, respectively; for the month of May
1994, the average gas and oil prices received by the Partnership were
approximately $2.15 per Mcf and $14.44 per Bbl, respectively (the Partnership's
proved reserves consist primarily of gas reserves; information concerning
production from proved reserves is set forth in the preceding paragraph)); (d)
royalty payments would remain a constant percentage of revenue; and (e) lease
operating expenses would be equal to those incurred in 1993 and increase by 4%
annually. These projections do not include any capital expenditures for the
exploration, exploitation and development of probable, possible and speculative
reserves or cash flows attributable to production from probable, possible or
speculative reserves. Forecasts of future oil and gas prices are subject to
numerous uncertainties. Actual future prices may be higher or lower than the
prices set forth above and none of the Company, BR or the Partnership assumes
any responsibility for the accuracy of such price estimates. Based upon the
foregoing, the Company projected that net cash flow of the Properties (after
capital expenditures for proved reserves) from proved reserves would be $56
million, $64 million, $70 million, $49 million and $41 million for the years
1994, 1995, 1996, 1997 and 1998, respectively, compared with historical net cash
flow of the Partnership of $48 million and $38 million for the years 1992 and
1993, respectively.
Unproved Reserves
A substantial portion of the Properties consists of undeveloped acreage
(approximately 225,000 net undeveloped acres at December 31, 1993), and the
Company currently anticipates additional exploration and exploitation of the
Properties in the future. In connection with the Company's evaluation of the
acquisition of the Maxus Interests, the Company identified several major areas
which it believes, based upon two dimensional and three dimensional seismic
data, merit exploitation activity. Based upon the Company's review of such data,
the Company estimates that these areas contain approximately 115 Bcfe of
probable reserves (in addition to the 224 Bcfe of proved reserves attributable
to the Properties as of December 31, 1993). The Company currently intends to
drill wells in these areas commencing in 1994 or 1995. Such wells would involve
capital expenditures not reflected in the projections set forth above and,
depending upon the outcome of such activities, significant additional capital
expenditures to develop these properties could be made in the future.
18
<PAGE> 24
The Company believes that, if these activities are successful, these properties
would generate significant increases in proved reserves, production, cash flow
and operating income in the future, which are not reflected in the projections
described above. In addition, other activities could result in material future
increases in proved reserves, production, cash flow and operating income from
the Properties. In the course of discussions between the parties, Maxus provided
the Company with certain estimates prepared by Maxus of possible reserves and
speculative reserves associated with the Properties, which indicated that Maxus
believed that the Properties included possible reserves of approximately 500
Bcfe and speculative reserves of approximately 1,325 Bcfe. However, the Company
has not independently verified this data. Estimates of probable reserves,
possible reserves and speculative reserves are highly uncertain and there can be
no assurance as to the level of reserves which may ultimately be recovered from
the Properties. Future development and production of reserves is subject to
numerous uncertainties, and will be substantially affected by changes in market
prices for oil and gas and advances in drilling, completion and production
technologies. Given the high level of uncertainty associated with possible and
speculative reserves, the Company believes that information concerning such
reserves is substantially less significant than information with respect to
proved reserves.
RECENT DEVELOPMENTS
On March 30, 1994, the Partnership learned that it was the high bidder in a
federal lease auction for two offshore blocks, Eugene Island 395 and West
Cameron 54. The acquisitions of these blocks by the Partnership were approved on
April 11 and June 1, 1994, respectively, and the leases are effective as of May
1 and July 1, 1994, respectively.
SELECTED FINANCIAL DATA
The following selected financial data relating to the Partnership
(including pro forma data to reflect the sale by the Partnership on April 25,
1994 of its interests in Main Pass Blocks 72, 73 and 74 to Pogo Producing
Company for approximately $18.2 million) has been taken from the 1993
Partnership 10-K for the five years ended December 31, 1993 as contained in
reports filed with the Commission or as contained in the 1994 Partnership 10-Q.
More comprehensive information is included in such reports and other documents
filed by the Partnership with the Commission, and the financial data set forth
below is qualified in its entirety by reference to such reports and other
documents, including the financial statements and related notes contained
therein. The selected financial data set forth below should be read in
conjunction with the financial statements and the notes thereto as listed in the
Index to Financial Information on Page F-1.
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
SELECTED FINANCIAL DATA
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
SELECTED BALANCE SHEET DATA
<TABLE>
<CAPTION>
MARCH 31, DECEMBER 31,
1994 MARCH 31, MARCH 31, -------------------------------------------------------------
PRO FORMA 1994 1993 1993 1992 1991 1990 1989
--------- --------- --------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total Assets................. $171,975 $167,941 $184,780 $ 164,861 $ 193,692 $ 222,084 $ 222,357 $ 217,149
Net Assets................... 147,885 143,851 158,315 139,081 164,557 192,121 190,009 183,979
Book Value per Unit.......... 2.00 1.95 2.15 1.89 2.23 2.70 2.78 3.11
</TABLE>
SELECTED INCOME STATEMENT DATA
<TABLE>
<CAPTION>
THREE
MONTHS THREE THREE
ENDED MONTHS MONTHS YEAR ENDED
MARCH 31, ENDED ENDED DECEMBER 31, FOR THE YEAR ENDED DECEMBER 31,
1994 MARCH 31, MARCH 31, 1993 ------------------------------------------------------------
PRO FORMA 1994 1993 PRO FORMA 1993 1992 1991 1990
--------- --------- --------- ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Sales and Operating
Revenues......... $19,180 $20,694 $24,377 $ 78,620 $ 87,069 $ 95,871 $ 104,696 $ 111,767
Net Income......... 4,023 4,770 5,679 8,744 12,522 20,865 11,420 26,766
Net Income per
Unit............. .05 .06 .08 .12 .17 .28 .16 .39
Cash Distributions
per Unit......... -- -- .16 .51 .51 .65 .44 .30
<CAPTION>
1989
------------
<S> <C>
Sales and Operating
Revenues......... $ 115,752
Net Income......... 2,931
Net Income per
Unit............. .05
Cash Distributions
per Unit......... 2.80
</TABLE>
19
<PAGE> 25
PRICE RANGE OF UNITS; CASH DISTRIBUTIONS
The Units are listed and traded on the NYSE and the PSE under the symbol
DSP. The following table sets forth, for the periods indicated, the reported
high and low sales prices for the Units as reported in the Partnership 1993 10-K
with respect to the years 1992 and 1993, and thereafter the high and low closing
sale prices for the Units on the NYSE as reported in published financial
sources.
<TABLE>
<CAPTION>
DISTRIBUTIONS
HIGH LOW PAID
---- ---- ----
<S> <C> <C> <C>
1992
First quarter.............................................. $ 4 $ 2 3/8 $ .14
Second quarter............................................. 3 5/8 2 3/4 .17
Third quarter.............................................. 4 3/4 3 1/8 .15
Fourth quarter............................................. 5 5/8 4 1/2 .19
1993
First quarter.............................................. $ 6 7/8 $ 4 5/8 $ .16
Second quarter............................................. 6 7/8 6 .10
Third quarter.............................................. 6 3/4 5 5/8 .12
Fourth quarter............................................. 6 3/8 5 .13
1994
First quarter.............................................. $ 6 $ 4 --
Second quarter (through , 1994).................. 5 4 $ .13
</TABLE>
On April 25, 1994, the last full trading day prior to the announcement of
the sale and purchase of the Maxus Interests and the proposed Merger, the high
and low sales prices for the Units on the NYSE were $4 5/8 and $4 1/2,
respectively. On , 1994, the last full trading day prior to the date
of this Information Statement, the high and low sales prices for the Units on
NYSE were $ and . UNIT HOLDERS ARE URGED TO OBTAIN A CURRENT
MARKET QUOTATION FOR THE UNITS.
INFORMATION CONCERNING THE COMPANY,
ACQUISITION, MERIDIAN AND BR
BUSINESS OF BR AND ITS SUBSIDIARIES
The Company is a Delaware corporation which was formed for the purposes of
acquiring the .99% managing general partnership interest of Maxus Offshore in
the Partnership and the 64,163,885 Units held by Maxus Exploration, and
effecting the Merger. Acquisition is a Delaware corporation which was formed for
the purpose of acquiring the .01% special general partnership interest of Maxus
Energy in the Partnership. It is anticipated that prior to the Merger,
Acquisition will be merged with and into the Company, as a result of which the
Company will be the sole general partner of the Partnership. Each of the Company
and Acquisition is a direct wholly owned subsidiary of Meridian, which in turn
is a direct wholly owned subsidiary of MOHI. MOHI is a direct wholly owned
subsidiary of BR. Each of such corporations is a Delaware corporation with its
principal executive offices at 5051 Westheimer, Suite 1400, Houston, Texas
77056.
BR is a holding company whose principal operating subsidiary is Meridian.
Meridian is engaged in (i) the exploration, development and production of oil
and gas, and (ii) related marketing activities which include aggregation and
resale of third-party oil and gas, operating intrastate natural gas pipelines
and holding interests in crude oil pipelines. MOHI is the largest independent
(nonintegrated) oil and gas company in the United States with total domestic
proved equivalent reserves of approximately 6 trillion cubic feet of gas
equivalent.
SELECTED FINANCIAL DATA
The following selected consolidated financial data relating to BR has been
taken from the 1993 BR 10-K for the five years ended December 31, 1993 as
contained in reports filed with the Commission or as contained
20
<PAGE> 26
in the 1994 BR 10-Q. More comprehensive information is included in such reports
and other documents filed by BR with the Commission, and the financial data set
forth below is qualified in its entirety by reference to such reports and other
documents, including the financial statements and related notes contained
therein.
BURLINGTON RESOURCES INC.
SELECTED FINANCIAL DATA
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
SELECTED CONSOLIDATED BALANCE SHEET DATA
<TABLE>
<CAPTION>
MARCH MARCH DECEMBER 31,
31, 31, ----------------------------------------------
1994 1993 1993 1992 1991 1990 1989
------- ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Total Assets..................... $ 4,469 $4,405 $4,448 $4,470 $5,480 $5,250 $4,625
Long-Term Debt(a)................ 817 935 819 1,003 1,298 529 87
Stockholders' Equity(b).......... 2,639 2,455 2,608 2,406 2,907 3,024 3,223
Book Value per Common Share...... 20.35 18.94 20.11 18.67 22.11 21.92 22.08
</TABLE>
SELECTED CONSOLIDATED INCOME STATEMENT DATA -- CONTINUING OPERATIONS
<TABLE>
<CAPTION>
THREE THREE
MONTHS MONTHS
ENDED ENDED
MARCH MARCH FOR THE YEAR ENDED DECEMBER 31,
31, 31, --------------------------------------------------
1994 1993 1993 1992 1991 1990 1989
------- ------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues................ $ 320 $ 316 $1,249 $1,141 $1,036 $1,025 $ 797
Operating Income........ 69 66 256 240 177 216 90
Income from Continuing
Operations............ 48 45 255 190 100 124 77
Earnings per Common
Share(c).............. 0.37 0.35 1.95 1.44 0.75 0.87 0.52
Ratio of Earnings to
Fixed Charges(d)...... 3.48x 3.11x 4.79x 3.49x 1.95x 2.97x 3.27x
Cash Dividends Declared
per Common Share(e)... 0.1375 0.1375 0.55 0.60 0.70 0.70 0.61
</TABLE>
- ---------------
(a) Excludes current maturities.
(b) On June 30, 1992 BR distributed its El Paso Natural Gas Company ("EPNG")
common stock to BR's stockholders of record as of June 15, 1992. The
distribution was accounted for as a $575 million non-cash dividend.
(c) Excluding non-recurring items totaling $0.45, $0.24, and $0.08 per share,
earnings per common share from continuing operations would have been $1.50,
$1.20 and $0.67 for the years ended 1993, 1992 and 1991, respectively.
(d) Earnings represent pretax income from continuing operations available for
fixed charges, less equity in undistributed earnings of 20-50% owned
companies, together with a portion of rent under long-term operating leases
representative of an interest factor. Fixed charges represent interest
expense, capitalized interest and a portion of rent under long-term
operating leases representative of an interest factor.
(e) On April 7, 1994 BR's Board of Directors declared dividends of $0.1375 per
common share, payable on July 1, 1994. In July 1992, the quarterly dividend
rate was reduced to $0.125 per share to reflect the June 30, 1992 spin-off
of EPNG to BR's stockholders.
21
<PAGE> 27
FEES AND EXPENSES
As described above, Smith Barney Shearson informed Meridian of Maxus'
potential interest in selling the Maxus Interests. In connection with the
acquisition of the Maxus Interests and the Merger, Meridian has agreed to pay
Smith Barney Shearson a fee of $500,000. Smith Barney Shearson was not asked to,
and did not, provide any report, opinion or appraisal in connection with the
purchase of the Maxus Interests or the Merger.
The Company has retained Georgeson & Company Inc. to act as the Information
Agent and The First National Bank of Boston to act as the Disbursing Agent in
connection with the Merger. Each of the Information Agent and the Disbursing
Agent will receive reasonable and customary compensation for its services, will
be reimbursed for certain reasonable out-of-pocket expenses and will be
indemnified against certain liabilities and expenses in connection therewith.
It is estimated that the expenses incurred in connection with the purchase
of the Maxus Units and the Merger will be approximately as set forth below.
<TABLE>
<S> <C>
Filing Fees.............................................................. $
Financial Advisory Fees and Expenses.....................................
Information Agent Fees and Expenses......................................
Disbursing Agent Fees and Expenses.......................................
Legal Fees...............................................................
Printing and Mailing Costs...............................................
Miscellaneous............................................................
--------
Total..........................................................
========
</TABLE>
Meridian and the Company will be responsible for all of the foregoing fees
and expenses.
Brokers, dealers, commercial banks and trust companies will, upon request
only, be reimbursed by the Company for customary mailing and handling expenses
incurred by them in forwarding material to their customers.
REGULATORY APPROVALS
Under the HSR Act and the rules promulgated thereunder by the Federal Trade
Commission (the "FTC"), the Merger may not be consummated until notifications
have been given and certain information has been furnished to the FTC and the
Antitrust Division of the Department of Justice (the "Antitrust Division") and
specified waiting period requirements have been satisfied. The Company and the
Partnership filed notification and report forms under the HSR Act with the FTC
and the Antitrust Division on May 27, 1994. Early termination of the waiting
period under the HSR Act was granted effective June 9, 1994. The Company and the
Partnership are not aware of any other regulatory approvals required in
connection with the Merger. If any other regulatory approvals are required, the
Company and the Partnership intend to seek such approvals as promptly as
practicable.
22
<PAGE> 28
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
INDEX TO FINANCIAL INFORMATION
FINANCIAL INFORMATION FROM ANNUAL REPORT ON
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 1993
<TABLE>
<CAPTION>
PAGES
----
<S> <C>
SELECTED FINANCIAL DATA.............................................................. F-2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.......................................................... F-3
FINANCIAL STATEMENTS:
Report of Independent Accountants.................................................. F-6
Statement of Income for the three years ended December 31, 1993.................... F-7
Balance Sheet at December 31, 1993 and 1992........................................ F-8
Statement of Cash Flows for the three years ended December 31, 1993................ F-9
Statement of Changes in Partners' Capital for the three years ended December 31,
1993............................................................................ F-10
Notes to Financial Statements...................................................... F-11
Supplementary Financial Information................................................ F-15
Financial Statement Schedules:
For the three years ended December 31, 1993
II. Related Party Receivables................................................ F-19
V. Oil and Gas Properties and Equipment..................................... F-20
VI. Accumulated Depreciation and Depletion -- Oil and Gas Properties and
Equipment................................................................ F-21
</TABLE>
All other schedules have been omitted because they are not applicable or
the required information is shown in the Financial Statements or the Notes
to Financial Statements.
FINANCIAL INFORMATION FROM QUARTERLY REPORT ON
FORM 10-Q FOR THE UNAUDITED QUARTERLY PERIOD ENDED MARCH 31, 1994
INTERIM FINANCIAL STATEMENTS:
<TABLE>
<S> <C>
Statement of Income............................................................. F-23
Balance Sheet................................................................... F-24
Statement of Cash Flows......................................................... F-25
Statement of Changes in Partners' Capital....................................... F-26
Notes to Interim Financial Statements........................................... F-27
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS FIRST QUARTER 1994....................................... F-28
PRO FORMA INFORMATION................................................................ F-29
UNAUDITED PRO FORMA BALANCE SHEET AS OF MARCH 31, 1994............................... F-30
UNAUDITED PRO FORMA STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 1993......... F-31
UNAUDITED PRO FORMA STATEMENT OF INCOME FOR THE QUARTER ENDED MARCH 31, 1994......... F-32
</TABLE>
F-1
<PAGE> 29
PRELIMINARY NOTE
The information on pages F-2 through F-32 of this Information Statement has
been taken directly from historical Securities and Exchange Commission (the
"Commission") filings of Diamond Shamrock Offshore Partners Limited Partnership
(the "Partnership"), which were prepared by Maxus Offshore Exploration Company
("Maxus Offshore"), the predecessor managing general partner of the Partnership,
and relate to periods prior to the date on which Meridian Offshore Company
became the managing general partner of the Partnership. Certain textual
information, including information with respect to the distribution policy of
the Partnership, future capital expenditures plans of the Partnership, the
future outlook of the Partnership and arrangements between the Partnership and
Maxus Offshore and its affiliates, is included solely because such information
was contained in the Partnership's historical filings with the Commission for
the relevant periods and does not take into account the transfer to Meridian
Offshore Company of the managing general partnership interest in the Partnership
or the proposed merger of the Partnership into Meridian Offshore Company. For
additional information, see "SPECIAL FACTORS -- Purpose and Structure of the
Merger" and "INFORMATION CONCERNING THE PARTNERSHIP AND THE PROPERTIES" in this
Information Statement.
FINANCIAL INFORMATION FROM ANNUAL REPORT ON
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 1993
The information on pages F-2 through F-21 is from the Diamond Shamrock
Offshore Partners Limited Partnership's Annual Report on Form 10-K for the year
ended December 31, 1993, as filed with the Securities and Exchange Commission by
Maxus Offshore Exploration Company, which at that time was the managing general
partner of Diamond Shamrock Offshore Partners Limited Partnership.
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
SELECTED FINANCIAL DATA
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT)
<TABLE>
<CAPTION>
1993 1992 1991 1990 1989
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Sales and operating revenues (including
$49,081 to related parties in 1993)..... $ 87,069 $ 95,871 $104,696 $111,767 $115,752
Net income................................ 12,522 20,865 11,420 26,766 2,931
Net income per Unit....................... .17 .28 .16 .39 .05
Cash distributions per Unit............... .51 .65 .44 .30 2.80
Total assets.............................. 164,861 193,692 222,084 222,357 217,149
Net assets................................ 139,081 164,557 192,121 190,009 183,979
</TABLE>
F-2
<PAGE> 30
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Diamond Shamrock Offshore Partners Limited Partnership ("Partnership")
reported net income of $12.5 million for the year ended December 31, 1993, $8.3
million less than 1992, primarily due to lower sales and operating revenues of
$8.8 million, resulting chiefly from lower oil prices and lower gas volumes.
Loss on the sales of assets, an exploratory dry hole in the fourth quarter and
higher geological and geophysical costs also contributed to the lower reported
net income. Net income for 1992 was $9.4 million higher than 1991 due to lower
production costs, lower exploration costs and a decline in depreciation and
depletion.
Lower natural gas sales volumes accounted for $10.7 million of the sales
and operating revenue decline in 1993; however, the Partnership benefited from
$5.4 million of higher gas prices. Average production was 74 million cubic feet
per day ("mmcfpd"), 14% lower than 1992. Natural declines in production at
Vermilion 226/237, Main Pass 116, Main Pass 73, High Island 365/376 and Brazos
412 were partially offset by new volumes at Vermilion 225. The 1992 gas volumes
of 86 mmcfpd were 4 mmcfpd below the 1991 level primarily due to natural
declines, along with sanding problems at West Cameron 648. This drop was
partially offset by new production from Main Pass 181 and the Vermilion blocks
acquired in 1991. The 1993 average gas price was $2.21 per thousand cubic feet
("mcf"), up $.20 per mcf from $2.01 per mcf in 1992. Gas prices averaged $1.88
per mcf in 1991.
Crude oil and condensate sales revenues were down in 1993 due to both lower
prices ($2.3 million) and volumes ($1.2 million). Crude oil and condensate sales
volumes averaged 4,157 barrels per day ("bpd") in 1993, compared to 4,325 bpd in
1992 and 5,647 bpd in 1991. Green Canyon 18 and Ewing Bank 944/988 accounted for
almost 700 BPD of the decline from 1991 to 1992 due to casing pressure problems.
During 1993, new development wells at Green Canyon 18 replaced production lost
in 1992. However, natural declines on this and other blocks still resulted in a
slight decrease during 1993. Prices for 1993 averaged $17.12 per barrel, down
from an average realized price of $18.61 per barrel in 1992 and $20.16 per
barrel in 1991.
In 1993, other revenues, net included a loss of $3.3 million from the sale
of the Partnership's interest in East Cameron Block 220. Other revenues, net in
1991 reflected a $2.2 million adverse pricing adjustment.
The Partnership reported production and operating costs in 1993 of $17.6
million, compared to $18.3 million and $20.1 million in 1992 and 1991,
respectively. The higher 1991 costs, relative to 1993 and 1992, were due
primarily to workovers performed in 1991 at Green Canyon 18 and Main Pass
72/73/74.
Exploration costs totaled $8.5 million in 1993, up slightly from 1992, due
to higher geological and geophysical costs. In 1992, exploration costs were $7.8
million compared to $16.9 million in 1991 resulting from less drilling activity
and lower geological and geophysical costs.
General and administrative costs were $5.6 million and $6.8 million during
1993 and 1992, respectively, compared to 1991 general and administrative costs
of $7.2 million, resulting from lower direct and allocated administrative
charges.
The decline in depreciation and depletion expense of $3.3 million during
1993 to $39.6 million was primarily due to lower gas production. A $4.7 million
decrease in depreciation and depletion expense during 1992 as compared to 1991
was also due to lower production, offset somewhat by a rise in impairments for
unproven acreage.
The Partnership is not required to pay federal income taxes on its income
and, therefore, no tax provision or benefit is reflected in the Statement of
Income.
FINANCIAL CONDITION
Net cash provided by operating activities for the Partnership during 1993
decreased 10% to $61.8 million compared to $68.7 million in 1992 and $62.8
million in 1991. Compared to 1992, lower 1993 sales and
F-3
<PAGE> 31
operating revenues were offset in part by lower general and administrative costs
and working capital requirements. For 1992, lower exploration costs and lower
working capital requirements more than offset sales declines resulting in an
increase in net cash provided by operating activities from 1991.
The ratio of current assets to current liabilities (current ratio) was 1.2
at December 31, 1993 versus 2.1 at December 31, 1992. Most of the change
resulted from a reduction in the note receivable with Maxus Energy Corporation
("Maxus") due to an increase in capital expenditures. The 1992 current ratio
remained essentially unchanged from 1991.
Expenditures for oil and gas properties and equipment, including dry hole
costs, in 1993 were $36.1 million compared to $18.4 million in 1992 and $63.0
million in 1991. Higher expenditures for exploratory and development drilling,
production equipment and property and lease acquisitions contributed to the
increase over 1992 spending levels. During 1993, the Partnership was the
successful bidder for seven offshore federal blocks at a cost of $4.3 million.
The Partnership also drilled successful exploratory wells on West Cameron Block
142, Main Pass 111 and Main Pass 181. The reduction in 1992 from 1991 was
largely due to lower property acquisition costs as the 1991 expenditures
included the purchase of Freeport-McMoRan Inc.'s interest in producing oil and
gas leases on Blocks 225 and 226, Vermilion area, offshore Louisiana, for $29.0
million. In addition, lower exploratory and development drilling expenditures
also contributed to the decline in 1992 from 1991.
The 1991 acquisition of the interests in the Vermilion area was funded by
cash from operations and by proceeds from the issuance to Maxus Exploration
Company ("Exploration") of newly issued units of the limited partnership
("Units") in the amount of $21.0 million. No additional Units were issued in
1992 or 1993 and, at December 31, 1993, Exploration owned approximately 87.0% of
the Units outstanding.
The Partnership distributed $38.0 million in cash ($.51 per Unit) to its
partners during 1993, compared to total distributions of $48.4 million ($.65 per
Unit) and $30.5 million ($.44 per Unit) in 1992 and 1991, respectively.
The Partnership presently intends to continue its distribution policy,
which commenced in January 1990, of distributing on a quarterly basis
substantially all distributable cash. For this purpose, distributable cash means
net cash provided by operating activities and proceeds from the sale of assets,
less (i) expenditures for oil and gas properties and equipment, including dry
hole costs, (ii) reserves for future operating and capital requirements and
contingencies and (iii) other Partnership obligations.
Because of the uncertainties of future oil and gas prices, production
levels, future expenditures for properties and equipment and other factors, the
amount of cash distributions for 1994 cannot be predicted but, as in 1993, is
expected to vary quarterly based upon the levels of distributable cash available
to the Partnership and changes, if any, in the Partnership's distribution
policy. No cash distribution will be made for the first quarter 1994 due to the
Partnership's lack of distributable cash for such quarter.
The Partnership has an agreement with Maxus providing for the Partnership
to invest its surplus funds with Maxus at an interest rate not less than the
rate (including points or other financing charges or fees) that Maxus would be
charged by unrelated lenders on comparable loans. At December 31, 1993, the
aggregate principal amount of such investment, evidenced by a note receivable,
was $7.4 million and, at December 31, 1992, such amount was $21.5 million. Since
its formation, the Partnership has incurred no debt.
During 1993, the Partnership entered into a hedging program with respect to
natural gas based on an average of approximately 35 billion British thermal
units per day. The program began with June production and has been extended
through December 1994. Throughout 1993, this program enhanced net cash provided
from operating activities by $.8 million.
F-4
<PAGE> 32
FUTURE OUTLOOK
Natural gas prices continue to be somewhat volatile, primarily due to
weather and regional supply and demand imbalances. Maxus Offshore Exploration
Company ("Managing Partner") believes the desirability of natural gas as a fuel
alternative will result in continued stability in demand with prices as strong
or stronger than in recent years, but subject to seasonal and other periodic
fluctuations.
Oil prices decreased substantially during the second half of 1993 and have
remained at reduced levels. Although oil markets remain unstable, general price
levels will likely continue to be negatively impacted by excess production,
especially from non-OPEC countries, limited worldwide demand growth and the
overhang from potential Iraqi oil exports in the future.
For 1994, gas production is expected to equal 1993 while oil production is
anticipated to increase slightly. Normal declines are expected to be offset by
new oil volumes at Green Canyon 18 and new gas volumes from West Cameron 142,
which was placed into production in the fourth quarter of 1993.
The Managing Partner has planned an exploratory and development program of
approximately $22.5 million for 1994, about half the 1993 actual program
spending of $41.6 million. Emphasis in 1994 will be placed on maximizing the
value of existing assets while maintaining the flexibility to respond to changes
which would make further exploratory activity economical. Currently, the
Partnership anticipates expenditures for platforms at High Island 376, Main Pass
181 and Main Pass 111. In addition, development drilling activity is planned for
Main Pass 111, High Island 376 and Main Pass 288.
With current market expectations for 1994, the Managing Partner is of the
opinion that the Partnership has the financial resources to meet anticipated
needs for future operations. Net cash provided by operating activities is
expected to be adequate to fund the Partnership's planned program for 1994.
F-5
<PAGE> 33
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of
Diamond Shamrock Offshore Partners
Limited Partnership
In our opinion, the financial statements listed in the index appearing on
page F-1 present fairly, in all material respects, the financial position of
Diamond Shamrock Offshore Partners Limited Partnership at December 31, 1993 and
1992, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 1993, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Partnership's management; our responsibility is to express
an opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PRICE WATERHOUSE
Dallas, Texas
February 22, 1994
F-6
<PAGE> 34
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
STATEMENT OF INCOME
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1993 1992 1991
------- ------- --------
<S> <C> <C> <C>
REVENUES
Sales and operating revenues (including $49,081 to
related parties in 1993).............................. $87,069 $95,871 $104,696
Other revenues, net...................................... (3,395) 720 (1,523)
------- ------- --------
83,674 96,591 103,173
------- ------- --------
COSTS AND EXPENSES
Production and operating costs........................... 17,551 18,291 20,121
Exploration, including exploratory dry holes............. 8,484 7,846 16,926
Depreciation and depletion............................... 39,564 42,824 47,494
General and administrative expenses...................... 5,553 6,765 7,212
------- ------- --------
71,152 75,726 91,753
------- ------- --------
NET INCOME................................................. 12,522 20,865 11,420
General Partners' Interest............................... 125 209 114
------- ------- --------
NET INCOME APPLICABLE TO LIMITED PARTNERS.................. $12,397 $20,656 $ 11,306
======= ======= ========
PER UNIT
Net income............................................... $ .17 $ .28 $ .16
Cash distributions....................................... $ .51 $ .65 $ .44
AVERAGE UNITS OUTSTANDING.................................. 73,761,740 73,761,740 71,116,911
</TABLE>
See Notes to Financial Statements.
F-7
<PAGE> 35
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
BALANCE SHEET
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1993 1992
-------- --------
<S> <C> <C>
ASSETS
Current Assets
Note receivable -- Maxus Energy Corporation.......................... $ 7,428 $ 21,487
Accounts receivable -- oil & gas..................................... 9,335 14,849
Accounts receivable -- joint interest................................ 1,817 1,242
Other................................................................ 1,105 1,780
-------- --------
Total Current Assets......................................... 19,685 39,358
-------- --------
Oil and Gas Properties and Equipment................................... 698,798 697,333
Less -- Accumulated depreciation and depletion......................... 553,622 542,999
-------- --------
145,176 154,334
-------- --------
$164,861 $193,692
======== ========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable..................................................... $ 15,081 $ 17,586
Take-or-pay liability................................................ 1,600 934
-------- --------
Total Current Liabilities.................................... 16,681 18,520
Other Liabilities and Deferred Credits................................. 3,766 3,549
Take-or-pay Liability.................................................. 5,333 7,066
Partners' Capital...................................................... 139,081 164,557
-------- --------
$164,861 $193,692
======== ========
</TABLE>
See "Commitments and Contingencies."
The Partnership uses the successful efforts method to account for its oil and
gas producing activities.
See Notes to Financial Statements.
F-8
<PAGE> 36
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
STATEMENT OF CASH FLOWS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1993 1992 1991
-------- -------- --------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................. $ 12,522 $ 20,865 $ 11,420
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and depletion........................... 39,564 42,824 47,494
Dry hole costs....................................... 3,050 4,136 7,660
Other, including net (gain) loss on sales of
assets............................................ 3,522 -- (514)
Changes in components of working capital:
Accounts receivable............................... 4,939 2,282 290
Other current assets.............................. 675 (801) (608)
Accounts payable.................................. (2,505) (626) (2,909)
-------- -------- --------
Net cash provided by operating activities............ 61,767 68,680 62,833
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and gas properties and equipment,
including dry hole costs................................ (36,135) (18,375) (63,010)
Proceeds from sales of assets.............................. -- 72 1,050
(Increase) decrease in current note receivable............. 14,059 (1,634) 8,630
Other...................................................... (1,693) (314) (195)
-------- -------- --------
Net cash used in investing activities................... (23,769) (20,251) (53,525)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash distributions paid.................................... (37,998) (48,429) (30,520)
Proceeds from sale of Units and reinvestments.............. -- -- 21,000
Proceeds from capital contributions by general partners.... -- -- 212
-------- -------- --------
Net cash used in financing activities................... (37,998) (48,429) (9,308)
Net change in cash........................................... -- -- --
Cash at beginning of year.................................... -- -- --
-------- -------- --------
Cash at end of year.......................................... $ -- $ -- $ --
======== ======== ========
</TABLE>
See Notes to Financial Statements.
F-9
<PAGE> 37
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
STATEMENT OF CHANGES IN PARTNERS' CAPITAL
THREE YEARS ENDED DECEMBER 31, 1993
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
LIMITED PARTNERS
--------------------------
MAXUS
GENERAL EXPLORATION
PARTNERS COMPANY UNITHOLDERS TOTAL
-------- ----------- ----------- --------
<S> <C> <C> <C> <C>
January 1, 1991.................................... $4,699 $ 124,303 $61,007 $190,009
Net income....................................... 114 9,772 1,534 11,420
Distributions.................................... (305) (25,959) (4,256) (30,520)
Repurchase of Units.............................. -- 656 (656) --
Reinvestments.................................... 212 21,000 -- 21,212
-------- ----------- ----------- --------
December 31, 1991.................................. 4,720 129,772 57,629 192,121
Net income....................................... 209 17,969 2,687 20,865
Distributions.................................... (484) (41,706) (6,239) (48,429)
-------- ----------- ----------- --------
December 31, 1992.................................. 4,445 106,035 54,077 164,557
Net income....................................... 125 10,784 1,613 12,522
Distributions.................................... (380) (32,724) (4,894) (37,998)
-------- ----------- ----------- --------
December 31, 1993.................................. $4,190 $ 84,095 $50,796 $139,081
====== ======== ======== ========
</TABLE>
See Notes to Financial Statements.
F-10
<PAGE> 38
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS
Data is as of December 31 of each year or for the year then ended and dollar
amounts in tables are in thousands. Certain balance sheet amounts have been
reclassified to conform to the 1993 presentation.
(1) ORGANIZATION AND CONTROL
Diamond Shamrock Offshore Partners Limited Partnership ("Partnership") is a
Delaware limited partnership formed to succeed to substantially all of the oil
and gas exploration and production business previously conducted by Maxus
Exploration Company ("Exploration") in federal waters offshore Texas and
Louisiana. Exploration is a wholly owned subsidiary of Maxus Energy Corporation
("Maxus") through which Maxus conducts all of its North American oil and gas
exploration and production operations.
The Partnership was formed in 1985 when it sold to the public five million
units of limited partnership interest ("Units") and issued 37.5 million Units to
Exploration in exchange for its transfer of oil and gas properties.
Maxus Offshore Exploration Company ("Managing Partner"), a wholly owned
subsidiary of Maxus, and Maxus have a combined 1% general partners' interest in
the Partnership and are the managing general partner and special general
partner, respectively. Maxus' aggregate interest in the Partnership was
approximately 87.1% at December 31, 1993, 1992 and 1991.
The Partnership has no officers, directors or employees. Certain employees
of Exploration are engaged principally in the conduct of the Partnership's oil
and gas exploration and production business and certain officers of Maxus
perform all management functions required for the Partnership.
Neither Maxus nor the Managing Partner receive, as general partners of the
Partnership, any carried interests, promotions, back-ins or other compensation.
The Partnership reimburses Maxus for all direct costs incurred in managing the
Partnership and all indirect costs (principally salaries and other general and
administrative costs) allocable to the Partnership. The allocation between the
Partnership and Maxus of direct and indirect costs incurred by Maxus and its
subsidiaries is made by Maxus. Maxus believes that the method of allocation is
reasonable.
(2) SIGNIFICANT ACCOUNTING POLICIES
Exploration and Development Costs
Oil and gas exploration and development activities are accounted for at
cost under the successful efforts method of accounting. Costs of acquiring
unproved oil and gas leasehold acreage are capitalized. Lease rentals and
geological and geophysical costs are charged to expense as incurred. If, and
when, exploratory wells are determined to be nonproductive, the related costs
are charged to expense.
Costs incurred to drill and equip development wells, including production
facilities, are capitalized.
Depreciation and Depletion
Depreciation and depletion related to the capitalized costs of all
development drilling, successful exploratory drilling and related production
equipment, and estimated future abandonment and dismantlement costs for offshore
production platforms are provided by the unit of production method based upon
estimated proved recoverable reserves. A valuation allowance is provided by a
charge against earnings to reflect the impairment of unproved acreage.
F-11
<PAGE> 39
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Retirements and Property Dispositions
Gains or losses on sales or retirements are reflected in earnings when
related to complete production units for which individual depreciation and
depletion allowances are accumulated. Gains or losses from other sales or
retirements are charged to accumulated depreciation and depletion.
Income Taxes
The Partnership is not subject to federal or state income taxes;
accordingly, no recognition has been given to income taxes in the accompanying
financial statements. The income or loss of the Partnership is to be included in
the tax returns of the individual partners. The tax returns of the Partnership
are subject to examination by federal and state taxing authorities. If such
examinations result in adjustments to distributive shares of taxable income or
loss, the tax liability of the partners could be adjusted accordingly.
The partners will have different investment bases depending upon the timing
and prices of Units acquired, and each partner's tax accounting, which is
partially dependent upon their individual tax situation, may differ from the
accounting methods followed in the financial statements. Accordingly, there
could be significant differences between the partners' tax bases and their
proportionate shares of the net assets reported in the financial statements.
In 1993, the Partnership adopted the provisions of Statement of Financial
Accounting Standards No. 109 ("SFAS 109"), "Accounting for Income Taxes." SFAS
109 requires disclosure by a publicly held partnership of the aggregate
difference in the bases of its net assets for financial and tax reporting
purposes. Because the aggregate tax bases of the partners cannot be readily
determined, the difference in the financial and tax bases of the partnership's
net assets cannot be disclosed. Further, since taxes relating to the partners'
distributive shares of the partnership income or loss are determined at the
partners' level, rather than at the partnership level, the adoption of SFAS 109
had no effect on the Partnership's financial statements.
Revenue Recognition
Oil and natural gas revenues are accounted for using the sales method.
Under this method, sales are recorded on all production sold by the Partnership
regardless of the Partnership's ownership interest in the respective property.
Imbalances result when sales differ from the seller's net revenue interest in
the particular property's gas reserves and are recorded to reflect the
Partnership's balancing position. At year-end 1993 and 1992, the volumetric
imbalance and related values were immaterial.
Take-or-Pay Liability
In 1988, the Partnership received cash under provisions of a take-or-pay
contract and recognized a liability to provide gas. The contract stipulated that
the liability would be repaid if it was not eliminated by gas deliveries. During
1993, a portion of the take-or-pay liability was repaid at the option of the
natural gas purchaser. Such payments will continue during 1994 and into 1997.
Hedging
The Partnership periodically hedges against the effects of fluctuations in
the price of natural gas through price swap agreements. Gains or losses on these
hedges are deferred until the related sales are recognized. The Partnership's
hedging program began with June 1993 production based on approximately 35
billion British Thermal Units ("BTUs") per day. The program has been extended
through December 1994 and may cover a larger portion of the Partnership's
production.
F-12
<PAGE> 40
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(3) DISTRIBUTION POLICY
The Partnership presently intends to continue its current distribution
policy, which commenced in January 1990, of distributing on a quarterly basis
substantially all distributable cash. For this purpose, distributable cash means
net cash provided by operating activities and proceeds from the sale of assets,
less (i) expenditures for oil and gas properties and equipment, including dry
hole costs, (ii) reserves for future operating and capital requirements and
contingencies and (iii) other Partnership obligations.
During 1993, 1992 and 1991, the Partnership made per Unit distributions of
cash in the aggregate of $.51, $.65 and $.44, respectively. Because of the
uncertainties of future oil and gas prices, production levels, future
expenditures for properties and equipment and other factors, the amount of cash
distributions for 1994 cannot be predicted but is expected to vary quarterly
based upon the levels of distributable cash available to the Partnership and
changes, if any, in the Partnership's distribution policy. On January 25, 1994,
the Managing Partner of the Partnership announced that no cash distribution
would be paid to any partner or unitholder of the Partnership for the first
quarter of 1994 due to the Partnership's lack of distributable cash for such
quarter.
(4) RELATED PARTY TRANSACTIONS
The Partnership is charged for all direct costs and expenses associated
with its operations. Additionally, general and administrative costs are
allocated to the Partnership by Maxus. Allocation percentages are generally
determined from studies of time devoted to specific services and utilization of
jointly shared facilities as determined on an annual basis. Such direct and
allocated administrative charges amounted to $5,553,000, $6,765,000 and
$7,212,000 in 1993, 1992 and 1991, respectively.
During 1993, the Partnership entered into an agreement with Maxus Gas
Marketing Company ("MGMC"), a wholly owned subsidiary of Maxus, to sell
substantially all of the Partnership's gas production to MGMC at prices
comparable to those received for like sales at similar properties. For the year
1993, such sales amounted to $45,944,000. An additional $3,137,000 of oil was
sold during 1993 to Maxus.
The Partnership has invested its excess funds with Maxus (See Note 6: "Note
Receivable -- Maxus Energy Corporation").
(5) SALES TO MAJOR CUSTOMERS
Sales of oil and gas to major customers (over 10% of sales) are summarized
below:
<TABLE>
<S> <C> <C>
1993
Maxus Gas Marketing Company.................................. $45,944 53%
1992
Amoco Production Company..................................... $12,917 13%
Arkla Energy Resources....................................... $ 9,533 10%
1991
Shell Oil Company............................................ $12,736 12%
</TABLE>
F-13
<PAGE> 41
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(6) NOTE RECEIVABLE -- MAXUS ENERGY CORPORATION
The Partnership has an agreement to invest its surplus funds with Maxus.
This investment is evidenced by a promissory note, including amendments or
extensions. The note bears interest at a rate adjusted monthly not less than the
rate (including points or other financing charges or fees) that Maxus would be
charged by unrelated lenders on comparable loans. Interest earned on this note,
which is included in "Other revenues, net," was $930,000, $1,262,000 and
$1,210,000 in 1993, 1992 and 1991, respectively.
(7) VALUE OF FINANCIAL INSTRUMENTS
The fair value of the Partnership's natural gas price swap agreements is
the estimated amount the Partnership would receive to terminate the swap
agreements at the reporting date. At December 31, 1993, the estimated fair value
was $2.2 million. The fair value of all other financial instruments approximate
their recorded value.
(8) ACCOUNTS RECEIVABLE
The Partnership's accounts receivable relate primarily to sales of oil and
gas and amounts due from joint interest partners for expenditures made by the
Partnership on their behalf. In addition to sales made to MGMC, sales are made
to several major oil and gas and gas pipeline companies. The Partnership reviews
the financial condition of potential purchasers and partners prior to signing
sales or joint interest agreements. Payment terms are on a short term basis and
in accordance with industry standards.
(9) PROPERTY AND EQUIPMENT
Summarized below is detail of the Partnership's property and equipment
holdings:
<TABLE>
<CAPTION>
1993 1992
-------- --------
<S> <C> <C>
Proved properties....................................... $661,252 $665,222
Unproved properties..................................... 37,546 32,111
-------- --------
698,798 697,333
Less -- Accumulated depreciation and depletion.......... 553,622 542,999
-------- --------
$145,176 $154,334
======== ========
</TABLE>
(10) PROPERTY SALES AND ACQUISITIONS
During fourth quarter 1993, the Partnership recorded in "Other revenues,
net," the $3.3 million loss on the sale of its entire interest in East Cameron
220, offshore Louisiana. Although a loss was recorded on the sale of the
property, the disposition did not have a material effect on the ongoing results
of operations or financial position of the Partnership for the year 1993. In
July 1991, the Partnership purchased an interest in producing oil and gas leases
on Blocks 225 and 226, Vermilion area, offshore Louisiana, for $29.0 million. On
a pro forma basis, the acquisition did not have a material impact on 1991
operations.
(11) COMMITMENTS AND CONTINGENCIES
In instances where the Partnership owns less than a 100% of the working
interest in a particular property, it is subject to joint operating agreements,
area of mutual interest agreements, bidding agreements, and similar agreements
which commit the Partnership for its share of any options, benefits or
contingencies as covered by the terms and conditions of any such agreements.
F-14
<PAGE> 42
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
SUPPLEMENTARY FINANCIAL INFORMATION
(UNAUDITED)
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT)
QUARTERLY DATA
<TABLE>
<CAPTION>
1993
--------------------------------------------------------------
FOR THE
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, YEAR
--------- -------- ------------- ------------ --------
<S> <C> <C> <C> <C> <C>
Sales and operating revenues (a).......... $24,377 $ 23,551 $19,344 $ 19,797 $ 87,069
Gross profit (b).......................... 8,079 9,526 5,929 6,420 29,954
Net income (loss)......................... 5,679 6,095 4,335 (3,587) 12,522
Per Unit
Net income (loss)....................... .08 .08 .06 (.05) .17
Distributions........................... .16 .10 .12 .13 .51
Market price per Unit
High.................................... 6 7/8 6 7/8 6 3/4 6 3/8 6 7/8
Low..................................... 4 5/8 6 5 5/8 5 4 5/8
</TABLE>
<TABLE>
<CAPTION>
1992
--------------------------------------------------------------
FOR THE
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, YEAR
--------- -------- ------------- ------------ --------
<S> <C> <C> <C> <C> <C>
Sales and operating revenues.............. $25,051 $ 22,701 $23,383 $ 24,736 $ 95,871
Gross profit (b).......................... 7,359 8,071 8,697 10,629 34,756
Net income................................ 833 6,272 6,475 7,285 20,865
Per Unit
Net income (c).......................... .01 .09 .09 .10 .28
Distributions........................... .14 .17 .15 .19 .65
Market price per Unit
High.................................... 4 3 5/8 4 3/4 5 5/8 5 5/8
Low..................................... 2 3/8 2 3/4 3 1/8 4 1/2 2 3/8
</TABLE>
- ---------------
(a) Includes related party sales of $7,189, $15,211, $12,192 and $14,489 for
quarters ended March 31, June 30, September 30 and December 31,
respectively.
(b) Gross profit is sales and operating revenues less production costs and
depreciation and depletion.
(c) As net income per unit is rounded, the sum of net income per unit does not
equal the annual per unit amount.
F-15
<PAGE> 43
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
SUPPLEMENTARY FINANCIAL INFORMATION -- (CONTINUED)
OIL AND GAS PRODUCING ACTIVITIES
The following are disclosures about the oil and gas producing activities of
the Partnership as required by Statement of Financial Accounting Standards No.
69:
RESULTS OF OPERATIONS
Results of operations relating to all of the Partnership's oil and gas
activity are shown below. These results exclude revenues and expenses related to
the purchase and resale of natural gas, administrative overhead and interest
income.
<TABLE>
<CAPTION>
1993 1992 1991
------- ------- --------
<S> <C> <C> <C>
Sales (including $49,081 to related parties in 1993)... $85,984 $93,399 $103,329
Production costs....................................... 16,466 15,819 18,754
Exploration costs...................................... 8,484 7,846 16,926
Depreciation and depletion............................. 39,564 42,824 47,494
(Gain)/loss on sales of assets......................... 3,522 -- (514)
Other.................................................. 802 542 3,247
------- ------- --------
Results of operations.................................. $17,146 $26,368 $ 17,422
======= ======= ========
</TABLE>
CAPITALIZED COSTS
Capitalized costs applicable to the Partnership's oil and gas producing
activities, all of which are conducted in the United States, include the cost of
mineral interests in properties, completed and incomplete wells and related
support equipment as follows:
<TABLE>
<CAPTION>
1993 1992 1991
-------- -------- --------
<S> <C> <C> <C>
Proved properties.................................... $661,252 $665,222 $650,527
Unproved properties.................................. 37,546 32,111 38,880
-------- -------- --------
698,798 697,333 689,407
Less -- Accumulated depreciation and depletion....... 553,622 542,999 506,528
-------- -------- --------
$145,176 $154,334 $182,879
======== ======== ========
</TABLE>
COSTS INCURRED
Costs incurred by the Partnership in its oil and gas producing activities
(whether capitalized or charged against earnings) were as follows:
<TABLE>
<CAPTION>
1993 1992 1991
------- ------- -------
<S> <C> <C> <C>
Property acquisition costs.............................. $ 5,111 $ 637 $36,629
Exploration costs....................................... 17,048 6,942 20,449
Development costs....................................... 19,410 14,506 15,198
------- ------- -------
$41,569 $22,085 $72,276
======= ======= =======
</TABLE>
F-16
<PAGE> 44
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
SUPPLEMENTARY FINANCIAL INFORMATION -- (CONTINUED)
OIL AND GAS RESERVES
Net proved developed and undeveloped reserves are the estimated quantities
of crude oil and natural gas 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 developed
reserves are proved reserve volumes that can be expected to be recovered through
existing wells with existing equipment and operating methods. Proved undeveloped
reserves are proved reserve volumes that are expected to be recovered from new
wells on undrilled acreage or from existing wells where a significant
expenditure is required for recompletion.
The following table represents the Partnership's net interests in estimated
quantities of proved developed and undeveloped reserves of crude oil, including
condensate (in thousands of barrels), and natural gas (in millions of cubic
feet) at December 31, 1993, 1992 and 1991, and changes in such estimated
quantities for the years then ended:
<TABLE>
<CAPTION>
OIL GAS
(MB) (MMCF)
------ -------
<S> <C> <C>
NET PROVED DEVELOPED AND UNDEVELOPED RESERVES
January 1, 1991.................................................. 11,354 186,846
Revisions of previous estimates.................................. 760 (5,257)
Extensions, discoveries and other additions...................... 122 2,945
Production....................................................... (2,061) (32,778)
Purchase of reserves in place.................................... 207 26,752
------ -------
December 31, 1991................................................ 10,382 178,508
Revisions of previous estimates.................................. 953 (192)
Extensions, discoveries and other additions...................... 307 10,852
Production....................................................... (1,583) (31,559)
------ -------
December 31, 1992................................................ 10,059 157,609
Revisions of previous estimates.................................. 487 (9,692)
Extensions, discoveries and other additions...................... 660 47,223
Production....................................................... (1,517) (27,181)
------ -------
December 31, 1993................................................ 9,689 167,959
====== =======
NET PROVED DEVELOPED RESERVES
January 1, 1991.................................................. 10,805 137,731
December 31, 1991................................................ 9,806 141,641
December 31, 1992................................................ 9,287 120,328
December 31, 1993................................................ 9,046 118,567
</TABLE>
F-17
<PAGE> 45
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
SUPPLEMENTARY FINANCIAL INFORMATION -- (CONTINUED)
FUTURE NET CASH FLOWS
The standardized measure of discounted future net cash flows ("standardized
measure") relating to proved oil and gas reserves is calculated and presented in
accordance with Statement of Financial Accounting Standards No. 69. The
standardized measure has been prepared assuming year-end selling prices
(adjusted for future fixed and determinable contractual price changes) for the
Partnership's estimated share of future production from proved oil and gas
reserves. Future production and development costs were computed by applying
year-end costs to future years. A prescribed 10% discount factor was applied to
future net cash flows. Because prices fluctuate, a calculation of the
standardized measure utilizing current prices would result in different
discounted future net cash flows for 1993 than is presented.
The Partnership cautions that this standardized measure is not
representative of fair market value, and the standardized measure presented for
the Partnership's proved oil and gas reserves is not representative of the
reserve value. The standardized measure is intended only to assist financial
statement users in making comparisons between companies.
<TABLE>
<CAPTION>
1993 1992 1991
-------- -------- --------
<S> <C> <C> <C>
Future cash inflows.................................. $522,176 $546,581 $580,780
Future production and development costs.............. (179,006) (87,974) (200,596)
-------- -------- --------
Future net cash flows................................ 343,170 358,607 380,184
Annual discount at 10% rate.......................... (96,820) (79,706) (77,528)
-------- -------- --------
Standardized measure of discounted future net cash
flows.............................................. $246,350 $278,901 $302,656
======== ======== ========
</TABLE>
The following are the principal sources of change in the standardized
measure:
<TABLE>
<CAPTION>
1993 1992 1991
-------- -------- --------
<S> <C> <C> <C>
January 1,........................................... $278,901 $302,656 $417,655
Sales and transfers of oil and gas produced, net of
production costs................................ (71,482) (79,701) (85,962)
Net changes in prices and production costs......... (6,474) (9,504) (119,686)
Extensions, discoveries and improved recovery, less
related costs................................... 48,483 15,152 6,051
Previously estimated development costs incurred
during the year................................. 6,099 (2,966) 5,719
Revisions of previous quantity estimates........... (12,710) 28,433 17,855
Purchase of reserves in place...................... 3,509 -- 20,682
Accretion of discount.............................. 27,890 30,266 41,766
Other.............................................. (27,866) (5,435) (1,424)
-------- -------- --------
December 31,......................................... $246,350 $278,901 $302,656
======== ======== ========
</TABLE>
F-18
<PAGE> 46
SCHEDULE II
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
RELATED PARTY RECEIVABLES
FOR THREE YEARS ENDED DECEMBER 31, 1993
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
DEDUCTIONS BALANCE AT
BALANCE AT ---------- END OF PERIOD
YEAR BEGINNING OF AMOUNTS -------------
ENDED NAME OF DEBTOR PERIOD ADDITIONS COLLECTED CURRENT
----- ------------------ ------------ --------- ---------- -------------
<S> <C> <C> <C> <C> <C>
December 31, 1991.......... Maxus Energy Corp. $ 28,483 -- $ 8,630 $19,853
December 31, 1992.......... Maxus Energy Corp. $ 19,853 $ 1,634 -- $21,487
December 31, 1993.......... Maxus Energy Corp. $ 21,487 -- $ 14,059 $ 7,428
</TABLE>
- ---------------
Refer to Note 6 to the Financial Statements, "Note Receivable -- Maxus Energy
Corporation."
F-19
<PAGE> 47
SCHEDULE V
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
OIL AND GAS PROPERTIES AND EQUIPMENT
FOR THREE YEARS ENDED DECEMBER 31, 1993
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
BALANCE AT BALANCE AT
BEGINNING ADDITIONS DISPOSALS END OF
OF PERIOD AT COST AND TRANSFERS PERIOD
---------- --------- ------------- ----------
<S> <C> <C> <C> <C>
Year ended December 31, 1991...................... $ 682,135 $63,010 $ (55,738) $ 689,407
Year ended December 31, 1992...................... $ 689,407 $18,375 $ (10,449) $ 697,333
Year ended December 31, 1993...................... $ 697,333 $36,135 $ (34,670) $ 698,798
</TABLE>
F-20
<PAGE> 48
SCHEDULE VI
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
ACCUMULATED DEPRECIATION AND DEPLETION
OIL AND GAS PROPERTIES AND EQUIPMENT
FOR THREE YEARS ENDED DECEMBER 31, 1993
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
BALANCE AT DISPOSALS BALANCE AT
BEGINNING ADDITIONS AND END OF
OF PERIOD AT COST TRANSACTIONS PERIOD
---------- --------- ------------- ----------
<S> <C> <C> <C> <C>
Year ended December 31, 1991...................... $ 507,100 $47,494 $ (48,066) $ 506,528
Year ended December 31, 1992...................... $ 506,528 $42,824 $ (6,353) $ 542,999
Year ended December 31, 1993...................... $ 542,999 $39,564 $ (28,941) $ 553,622
</TABLE>
F-21
<PAGE> 49
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
FINANCIAL INFORMATION FROM QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 1994
The information on pages F-22 through F-32 is from the Diamond Shamrock
Offshore Partners Limited Partnership's Quarterly Report on Form 10-Q for the
quarter ended March 31, 1994.
The accompanying financial statements have not been examined by independent
accountants, but in the opinion of Diamond Shamrock Offshore Partners Limited
Partnership's management all adjustments (consisting only of normal accruals)
necessary for a fair presentation of results of operations, changes in partners'
capital, financial position and cash flows at the date and for the periods
indicated have been included.
F-22
<PAGE> 50
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
STATEMENT OF INCOME -- (UNAUDITED)
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
---------------------
1994 1993
------- -------
<S> <C> <C>
REVENUES
Sales and operating revenues -- trade.............................. $ 3,476 $17,188
Sales and operating revenues -- associated companies............... 17,218 7,189
Other revenues, net................................................ 443 144
------- -------
21,137 24,521
COSTS AND EXPENSES
Production and operating costs..................................... 3,943 5,514
Exploration, including exploratory dry holes....................... 794 506
Depreciation and depletion......................................... 10,334 10,784
General and administrative expenses (b)............................ 1,296 2,038
------- -------
16,367 18,842
NET INCOME........................................................... 4,770 5,679
General Partners' Interest......................................... 48 57
------- -------
NET INCOME APPLICABLE TO LIMITED PARTNERS............................ $ 4,722 $ 5,622
======= =======
NET INCOME PER UNIT (c).............................................. $ .06 $ .08
AVERAGE UNITS OUTSTANDING............................................ 73,761,740 73,761,740
</TABLE>
See Notes to Interim Financial Statements (Unaudited).
F-23
<PAGE> 51
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
BALANCE SHEET
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
MARCH 31,
1994 DECEMBER 31,
(UNAUDITED) 1993
------------ ------------
<S> <C> <C>
ASSETS
Current Assets
Note receivable -- Maxus Energy Corporation........................ $ 17,328 $ 7,428
Accounts receivable -- oil and gas sales........................... 8,819 9,335
Accounts receivable -- joint interest.............................. 1,519 1,817
Other.............................................................. 454 1,105
------- --------
Total Current Assets....................................... 28,120 19,685
------- --------
Oil and Gas Properties and Equipment -- held for sale, net........... 14,116 --
------- --------
Oil and Gas Properties and Equipment................................. 598,496 698,798
Less -- Accumulated depreciation and depletion..................... 472,791 553,622
------- --------
125,705 145,176
------- --------
$167,941 $164,861
======== ========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable................................................... $ 13,660 $ 15,081
Take-or-pay liability.............................................. 1,600 1,600
------- --------
Total Current Liabilities.................................. 15,260 16,681
Other Liabilities and Deferred Credits............................... 3,763 3,766
Take-or-Pay Liability................................................ 5,067 5,333
Partners' Capital.................................................... 143,851 139,081
------- --------
$167,941 $164,861
======== ========
</TABLE>
The Partnership uses the successful efforts method to account for its oil and
gas producing activities.
See Notes to Interim Financial Statements (Unaudited).
F-24
<PAGE> 52
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
STATEMENT OF CASH FLOWS -- (UNAUDITED)
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
---------------------
1994 1993
-------- --------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income........................................................... $ 4,770 $ 5,679
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation and depletion...................................... 10,334 10,784
Dry hole costs.................................................. (9) (332)
(Gain)/Loss on sale of assets................................... (42) --
Changes in components of working capital:
Accounts receivable.......................................... 814 1,596
Other current assets......................................... 651 237
Accounts payable............................................. (1,421) (2,710)
-------- --------
Net cash provided by operating activities....................... 15,097 15,254
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for oil and gas properties and equipment, including dry
hole costs........................................................ (4,951) (8,029)
(Increase) decrease in current note receivable....................... (9,900) 4,654
Other................................................................ (246) 42
-------- --------
Net cash used in investing activities............................. (15,097) (3,333)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash distributions paid.............................................. -- (11,921)
-------- --------
Net cash used in financing activities............................. -- (11,921)
-------- --------
Net change in cash..................................................... -- --
Cash at beginning of period............................................ -- --
-------- --------
Cash at end of period.................................................. $ -- $ --
======== ========
</TABLE>
See Notes to Interim Financial Statements (Unaudited).
F-25
<PAGE> 53
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
STATEMENT OF CHANGES IN PARTNERS' CAPITAL -- (UNAUDITED)(A)
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
LIMITED PARTNERS
--------------------------
MAXUS
GENERAL EXPLORATION
PARTNERS COMPANY UNITHOLDERS TOTAL
-------- ----------- ----------- --------
<S> <C> <C> <C> <C>
December 31, 1993.................................. $4,190 $84,095 $50,796 $139,081
Net income....................................... 48 4,108 614 4,770
------ ------- ------- --------
March 31, 1994..................................... $4,238 $88,203 $51,410 $143,851
====== ======= ======= ========
</TABLE>
See Notes to Interim Financial Statements (Unaudited).
F-26
<PAGE> 54
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
NOTES TO INTERIM FINANCIAL STATEMENTS (UNAUDITED)
(A) ORGANIZATION
Diamond Shamrock Offshore Partners Limited Partnership ("Partnership") is a
Delaware limited partnership formed in 1985 to succeed to substantially all of
the oil and gas exploration and production business previously conducted by
Maxus Exploration Company ("Exploration"), a wholly owned subsidiary of Maxus
Energy Corporation ("Maxus"), in federal waters offshore Texas and Louisiana. In
exchange for its contribution of properties to the Partnership, Exploration
received units of limited partnership interest ("Units") in the Partnership. As
of March 31, 1994, Maxus Offshore Exploration Company ("MOEC"), a wholly owned
subsidiary of Maxus, was the managing general partner of the Partnership and
Maxus was the special general partner.
On April 26, 1994, Maxus, MOEC and Exploration sold all their partnership
interests consisting of general partners' interests and Units to affiliates of
Burlington Resources Inc. for an aggregate $291.1 million. Maxus' aggregate
ownership interest in the Partnership was approximately 87.1%. As a result of
the sale, Meridian Offshore Company, a Burlington Resources Inc. affiliate,
became the managing general partner of the Partnership and Meridian Offshore
Acquisition Company became the special general partner.
(B) GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses represent allocations from Maxus. Maxus
believes that the method of allocation is reasonable.
(C) INCOME PER UNIT
Net Income per Unit is calculated for financial reporting purposes only.
Income or loss for federal income tax purposes will be calculated and
communicated separately for each Unitholder subsequent to December 31, 1994.
(D) FINANCIAL INSTRUMENTS
As discussed in the Partnership's Annual Report on Form 10-K for year ended
December 31, 1993, the Partnership hedged against the effects of fluctuations in
the price of natural gas through price swap agreements. As of April 26, 1994,
the Partnership settled all then-outstanding hedged positions for a $253,050
gain.
(E) DISPOSITION OF ASSETS
On April 25, 1994, the Partnership sold its interests in Main Pass Blocks
72, 73 and 74, offshore Louisiana, to Pogo Producing Company for approximately
$18.2 million. The net book value of the properties was $14.1 million. The
unaudited pro forma financial statements are presented on pages F-30 through
F-32.
F-27
<PAGE> 55
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRST QUARTER, 1994
RESULTS OF OPERATIONS
Diamond Shamrock Offshore Partners Limited Partnership ("Partnership")
reported net income of $4.8 million for the first three months of 1994, a $.9
million decline over the same period in 1993. This decrease was a result of
lower sales and operating revenues, despite lower production costs and lower
administrative expenses. Sales and operating revenues for the first three months
of 1994 were $20.7 million, down from $24.4 million recorded for the same period
of 1993.
Average gas production in the first three months of 1994 was down 18% to 73
million cubic feet ("mmcf") per day compared to 89 mmcf per day in the same
period of 1993. Contributing to the volume decline were watering and sanding at
Main Pass 116/126 (7 mmcf per day) and watering at Vermilion 226/237 (3 mmcf per
day) and Main Pass 181 (5 mmcf per day) partially offset by new production at
West Cameron 142 (8 mmcf per day). The average gas price in the first quarter
1994 was $2.37 per thousand cubic feet ("mcf"), up $.31 per mcf from $2.06 per
mcf in the first quarter last year.
Crude oil and condensate sales revenues were down in the first three months
of 1994 due to lower oil prices which averaged $12.71 per barrel compared to
$18.05 per barrel in the first quarter last year. Production increased to 4,468
barrels ("bbls") per day compared to 4,246 bbls per day in the same period in
1993. New production from West Cameron 142 (252 bbls per day) and Ewing Bank
944/988 (420 bbls per day) were partially offset by watering at Vermilion 226
and field decline at Main Pass 288/289.
Production and operating costs were $3.9 million in the first quarter 1994
as compared to $5.5 million in the first quarter 1993. The decrease resulted
from third-party gas purchase costs of $1.1 million recorded in first quarter
1993.
Depreciation and depletion expense was $10.3 million in the first quarter
of 1994, $.5 million below the same period last year. Lower production was
responsible for the decline, despite higher depletion rates.
FINANCIAL CONDITION
Net cash provided by operating activities for the Partnership during the
first three months of 1994 decreased slightly to $15.1 million from $15.3
million in the same period in 1993. Lower working capital requirements offset
the decline in operating cash income.
Expenditures for oil and gas properties and equipment, including dry hole
costs, in the first three months of 1994 were $5.0 million compared to $8.0
million in 1993. The decrease in 1994 was largely due to lower spending on
exploratory wells. During the first quarter 1994, the Partnership was high
bidder at the Federal lease sale on two blocks offshore Louisiana. One of these,
Eugene Island 395 (100% working interest) has been awarded to the Partnership.
The bid for the other, West Cameron 54 (100% working interest), must be accepted
or rejected by the Minerals Management Service on or before June 29, 1994.
At March 31, 1994, the Partnership's ratio of current assets to current
liabilities (current ratio) equaled 1.8 compared to a ratio of 1.2 at December
31, 1993. Current assets rose primarily due to an increase in the note
receivable with Maxus Energy Corporation ("Maxus") which, at March 31, 1994, was
$17.3 million, an increase of $9.9 million from December 31, 1993. This note was
repaid in full on April 26, 1994 upon sale of Maxus' interest to Meridian
Offshore Company and the proceeds from the repayment have been advanced to
Meridian Offshore Company.
No cash distribution was made for the first quarter 1994 due to the
Partnership's lack of distributable cash for the quarter. A second quarter cash
distribution, payable June 7, 1994, was declared at $.13 per Unit to Unitholders
of record on May 13, 1994.
F-28
<PAGE> 56
OTHER EVENTS
On April 25, 1994 the Partnership sold its interest in Main Pass 72, 73 and
74 to Pogo Producing Company for $18.2 million. The net book value of the
properties was $14.1 million.
On April 26, 1994, Maxus, the special general partner of the Partnership,
Maxus Offshore Exploration Company, the managing general partner, and Maxus
Exploration Company sold all of their interests in the Partnership consisting of
general partners' interests and 64,163,885 Units to affiliates of Burlington
Resources Inc. for an aggregate of $291.1 million. Units were sold at an
equivalent of approximately $4.48 per Unit. Maxus' aggregate ownership interest
in the Partnership was approximately 87.1%. As a result of the sale, Meridian
Offshore Company, a Burlington Resources Inc. affiliate, became the managing
general partner of the Partnership and Meridian Offshore Acquisition Company
became the special general partner.
Also, on April 26, 1994, Burlington Resources Inc. announced that it
intends to acquire the remaining Units through merger for $4.48 per unit.
F-29
<PAGE> 57
PRO FORMA INFORMATION
On April 25, 1994, the Partnership sold its interests in Main Pass Blocks
72, 73 and 74, offshore Louisiana, to Pogo Producing Company for approximately
$18.2 million. The net book value of these properties was $14.1 million. An
unaudited pro forma balance sheet as of March 31, 1994 has been prepared as if
the sale had occurred at that date. The unaudited pro forma statements of income
for the year ended December 31, 1993 and the three months ended March 31, 1994
have been prepared as if the sale had occurred at January 1, 1993 and January 1,
1994, respectively. The pro forma data are not necessarily indicative of the
financial results which would have occurred had the sale been effective on those
dates and should not be viewed as indicative of the Partnership in future
periods. The unaudited pro forma financial statements are presented on pages
F-30 through F-32.
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
UNAUDITED PRO FORMA BALANCE SHEET
AS OF MARCH 31, 1994
<TABLE>
<CAPTION>
PRO-FORMA
HISTORICAL ADJUSTMENTS
D.S. OFFSHORE ------------------
PARTNERS DEBIT CREDIT PRO-FORMA
------------- ------- ------- ---------
<S> <C> <C> <C> <C>
ASSETS
Current Assets
Note Receivable -- Maxus Energy Corporation........ $ 17,328 $18,150 -- $ 35,478
Accounts Receivable -- oil and gas sales........... 8,819 -- -- 8,819
Accounts Receivable -- joint interest.............. 1,519 -- -- 1,519
Other.............................................. 454 -- -- 454
--------- ------- ------- --------
Total Current Assets....................... 28,120 18,150 -- 46,270
--------- ------- ------- --------
Oil and Gas Properties and Equipment --
held for sale, net................................. 14,116 -- $14,116 --
--------- ------- ------- --------
Oil and Gas Properties and Equipment................. 598,496 -- -- 598,496
Less -- Accumulated depreciation and depletion..... 472,791 -- -- 472,791
--------- ------- ------- --------
125,705 -- -- 125,705
--------- ------- ------- --------
$ 167,941 $18,150 $14,116 $171,975
========= ======= ======= ========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts Payable................................... $ 13,660 -- -- $ 13,660
Take-or-pay liability.............................. 1,600 -- -- 1,600
--------- ------- ------- --------
Total Current Liabilities.................. 15,260 -- -- 15,260
Other Liabilities and Deferred Credits............... 3,763 -- -- 3,763
Take-or-Pay Liability................................ 5,067 -- -- 5,067
Partners' Capital.................................... 143,851 -- $ 4,034 147,885
--------- ------- ------- --------
$ 167,941 -- $ 4,034 $171,975
========= ======= ======= ========
</TABLE>
F-30
<PAGE> 58
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
UNAUDITED PRO FORMA STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 1993
<TABLE>
<CAPTION>
PRO-FORMA
HISTORICAL ADJUSTMENTS
D.S. OFFSHORE ---------------
PARTNERS DEBIT CREDIT PRO FORMA
------------- ------ ------ ---------
<S> <C> <C> <C> <C>
REVENUES
Sales and operating revenues -- trade............... $37,988 $6,600 -- $31,388
Sales and operating revenues -- associated
companies........................................ 49,081 1,849 -- 47,232
Other revenues, net................................. (3,395) -- -- (3,395)
------- ------ ------ -------
83,674 8,449 -- 75,225
COSTS AND EXPENSES
Production and operating costs...................... 17,551 -- $1,355 16,196
Exploration, including exploratory dry holes........ 8,484 -- -- 8,484
Depreciation and depletion.......................... 39,564 -- 3,316 36,248
General and administrative expenses................. 5,553 -- -- 5,553
------- ------ ------ -------
71,152 -- 4,671 66,481
NET INCOME............................................ 12,522 8,449 4,671 8,744
General Partner's Interest.......................... 125 85 47 87
------- ------ ------ -------
NET INCOME APPLICABLE TO LIMITED PARTNERS............. $12,397 $8,364 $4,624 $ 8,657
======= ====== ====== =======
NET INCOME PER UNIT................................... $ .17 $ .12
======= =======
AVERAGE UNITS OUTSTANDING............................. 73,761,740 73,761,740
</TABLE>
F-31
<PAGE> 59
DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP
UNAUDITED PRO FORMA STATEMENT OF INCOME
FOR THE QUARTER ENDED MARCH 31, 1994
<TABLE>
<CAPTION>
PRO-FORMA
HISTORICAL ADJUSTMENTS
D.S. OFFSHORE ----------------
PARTNERS DEBIT CREDIT PRO-FORMA
------------- ------ ------ ---------
<S> <C> <C> <C> <C>
REVENUES
Sales and operating revenues -- trade.............. $ 3,476 $1,116 -- $ 2,360
Sales and operating revenues -- associated
companies....................................... 17,218 398 -- 16,820
Other revenues, net................................ 443 -- -- 443
------- ------ ----- -------
21,137 1,514 -- 19,623
COSTS AND EXPENSES
Production and operating costs..................... 3,943 -- $118 3,825
Exploration, including exploratory dry holes....... 794 -- -- 794
Depreciation and depletion......................... 10,334 -- 649 9,685
General and administrative expenses................ 1,296 -- -- 1,296
------- ------ ----- -------
16,367 -- 767 15,600
NET INCOME........................................... 4,770 1,514 767 4,023
General Partner's Interest......................... 48 15 7 40
------- ------ ----- -------
NET INCOME APPLICABLE TO LIMITED
PARTNERS........................................... $ 4,722 $1,499 $760 $ 3,983
======= ====== ===== =======
NET INCOME PER UNIT.................................. $ .06 $ .05
======= =======
AVERAGE UNITS OUTSTANDING............................ 73,761,740 73,761,740
</TABLE>
F-32
<PAGE> 60
SCHEDULE 1
DIRECTORS AND EXECUTIVE OFFICERS OF BR, THE COMPANY AND ACQUISITION
The name, business address and present principal occupation or employment
and five year employment history of each director and executive officer of BR,
the Company and Acquisition are set forth below. The business address of each
director and executive officer, unless otherwise indicated below, is 5051
Westheimer, Houston, Texas 77056. Each of the individuals listed below is a
United States citizen. To the knowledge of BR and the Company, none of such
individuals owns any Units.
DIRECTORS OF BR
<TABLE>
<CAPTION>
PRESENT PRINCIPAL OCCUPATION OR EMPLOYMENT,
NAME BUSINESS ADDRESS AND FIVE YEAR HISTORY
- ----------------------------------- --------------------------------------------------------
<S> <C>
John V. Byrne...................... President, Oregon State University, Corvallis, Oregon
97331 -- Education. Since November 1984, Dr. Byrne's
principal occupation has been as shown above.
S. Parker Gilbert.................. Retired. Mr. Gilbert's address is c/o Morgan Stanley
Group Inc., 1251 Avenue of the Americas, New York, New
York 10020. Mr. Gilbert has been retired since January
1991. From January 1984 until December 1990, Mr. Gilbert
was Chairman and Managing Director of Morgan Stanley
Group Inc.
James F. McDonald.................. President and Chief Executive Officer,
Scientific-Atlanta, Inc., One Technology Parkway South,
Norcross, Georgia 30092 -- Telecommunications. Since
July 1993, Mr. McDonald's principal occupation has been
as shown above. From July 1991 to July 1993, Mr.
McDonald was a partner with J.H. Whitney & Co. From
January 1991 until July 1991, Mr. McDonald was Vice
Chairman of the Board of Prime Computer Inc. From
January 1990 until January 1991, Mr. McDonald was Vice
Chairman of the Board and Chief Executive Officer of
Prime Computer, Inc. From September 1989 until January
1990, Mr. McDonald was President and Chief Executive
Officer of Prime Computer, Inc. From October 1988 until
August 1989, Mr. McDonald was Chairman of the Board,
President and Chief Executive Officer of Gould/
Computer Systems Inc. and Gould/IGD Inc.
Thomas H. O'Leary.................. Chairman of the Board, President and Chief Executive
Officer of BR. Since February 1993, Mr. O'Leary's
principal occupation has been as shown above. From July
1992 to February 1993, Mr. O'Leary was Chairman of the
Board and Chief Executive Officer of BR. From October
1990 until July 1992, Mr. O'Leary was Chairman of the
Board, President and Chief Executive Officer of BR. From
January 1989 until October 1990, Mr. O'Leary was
President and Chief Executive Officer of BR.
Donald M. Roberts.................. Vice Chairman and Treasurer, United States Trust Company
of New York, 114 West 47th Street, New York, New York
10036. Since February 1990, Mr. Roberts' principal
occupation has been as shown above. From January 1989 to
February 1990, Mr. Roberts was Treasurer of United
States Trust Company of New York.
Walter Scott, Jr................... Chairman and President, Peter Kiewit Sons', Inc., 1000
Kiewit Plaza, Omaha, Nebraska 68131 -- Construction,
Mining and Telecommunications. For over five years, Mr.
Scott's principal occupation has been as shown above.
</TABLE>
S-1
<PAGE> 61
<TABLE>
<CAPTION>
PRESENT PRINCIPAL OCCUPATION OR EMPLOYMENT,
NAME BUSINESS ADDRESS AND FIVE YEAR HISTORY
- ----------------------------------- --------------------------------------------------------
<S> <C>
William E. Wall.................... Of Counsel, Siderius Lonergan, 847 Logan Building, 500
Union Street, Seattle, Washington 98101 -- Law. For more
than 5 years, Mr. Wall's principal occupation has been
as shown above.
EXECUTIVE OFFICERS OF BR;
DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY AND ACQUISITION
John E. Hagale..................... Senior Vice President and Chief Financial Officer of BR
since April 1994. Executive Vice President and Chief
Financial Officer of Meridian since March 1993. Vice
President, Finance, of BR from April 1992 to February
1993. Vice President, Taxes, of BR from November 1990 to
April 1992. Assistant Vice President, Taxes, of BR from
January 1989 to November 1990. Executive Vice President
and Chief Financial Officer and Director of the Company
and Acquisition.
Harold E. Haunschild............... Vice President, Human Resources, of BR since July 1992.
Executive Vice President, Human Resources and
Administration, of Meridian since May 1993. Assistant
Vice President, Com-
pensation and Benefits, of BR from May 1988 to July
1992. Executive Vice President of the Company and
Acquisition.
George E. Howison.................. President and Chief Executive Officer of Meridian since
May 1993. Senior Vice President and Chief Financial
Officer of BR from November 1990 to April 1994. Vice
President, Planning and Treasurer, August 1988 to
October 1990. President of the Company and Acquisition.
L. Edward Parker................... Executive Vice President, Marketing, of Meridian since
February 1993. Senior Vice President, Marketing, of
Meridian from December 1990 to February 1993. Vice
President, Marketing, of Meridian from August 1988 to
November 1990. Executive Vice President of the Company
and Acquisition.
Gerald J. Schissler................ Senior Vice President, Law, of BR since December 1993.
Executive Vice President, Law and Corporate Affairs, of
Meridian since July 1993. Consultant from June 1991 to
July 1993. Senior Vice President, Law, of Meridian
Minerals Company, a subsidiary of BR, from November 1987
to June 1991. Executive Vice President and Director of
the Company and Acquisition.
Bobby S. Shackouls................. Executive Vice President and Chief Operating Officer of
Meridian since June 1993. President and Chief Operating
Officer of Torch Energy Advisors, Inc., an affiliate of
Torchmark Corporation, from September 1988 to May 1993.
Executive Vice President and Director of the Company and
Acquisition.
</TABLE>
S-2
<PAGE> 62
APPENDIX A
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
AGREEMENT AND PLAN OF MERGER
DATED AS OF APRIL 28, 1994
BETWEEN
DIAMOND SHAMROCK OFFSHORE PARTNERS
LIMITED PARTNERSHIP
AND
MERIDIAN OFFSHORE COMPANY
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE> 63
TABLE OF CONTENTS
<TABLE>
<S> <C>
AGREEMENT AND PLAN OF MERGER............................................................. 1
Background............................................................................... 1
ARTICLE I THE MERGER..................................................................... 1
SECTION 1.01 The Merger................................................................ 1
SECTION 1.02 Effective Time............................................................ 2
SECTION 1.03 Effects of the Merger..................................................... 2
SECTION 1.04 Certificate of Incorporation and By-Laws.................................. 2
SECTION 1.05 Directors and Officers.................................................... 2
SECTION 1.06 Conversion of Units....................................................... 2
SECTION 1.07 Closing................................................................... 3
ARTICLE II EXCHANGE OF UNITS............................................................. 3
SECTION 2.01 Exchange of Certificates.................................................. 3
SECTION 2.02 Distribution.............................................................. 4
ARTICLE III CONDITIONS TO CONSUMMATION OF THE MERGER..................................... 4
SECTION 3.01 Conditions to Each Party's Obligation to Effect the Merger................ 5
ARTICLE IV MISCELLANEOUS................................................................. 5
SECTION 4.01 Amendment................................................................. 5
SECTION 4.02 Entire Agreement; Assignment.............................................. 5
SECTION 4.03 Validity.................................................................. 5
SECTION 4.04 Governing Law............................................................. 5
SECTION 4.05 Descriptive Headings...................................................... 6
SECTION 4.06 Parties in Interest....................................................... 6
SECTION 4.07 Counterparts.............................................................. 6
</TABLE>
(i)
<PAGE> 64
AGREEMENT AND PLAN OF MERGER
AGREEMENT AND PLAN OF MERGER dated as of April 28, 1994 (the "Agreement"),
between DIAMOND SHAMROCK OFFSHORE PARTNERS LIMITED PARTNERSHIP, a Delaware
limited partnership (the "Partnership"), and MERIDIAN OFFSHORE COMPANY, a
Delaware corporation (the "Company").
BACKGROUND
The Board of Directors of the Company has approved on behalf of the
Company, and the Company, in its capacity as managing general partner of the
Partnership, has approved on behalf of the Partnership, upon the terms and
subject to the conditions set forth in this Agreement, the merger of the
Partnership into the Company (the "Merger"), whereby each outstanding LP Unit
(as defined in the Second Amended and Restated Agreement of Limited Partnership
of the Partnership, as amended (the "Partnership Agreement")) not owned by the
Company or any of its affiliates will be converted into the right to receive the
Merger Consideration (as hereinafter defined). The Company, as the holder of a
.99% managing general partnership interest in the Partnership and 64,163,885 LP
Units, and Meridian Offshore Acquisition Company, as the holder of a .01%
special general partnership interest in the Partnership, have both executed a
written consent approving the Merger.
Now, therefore, the Partnership and the Company hereby agree as follows:
ARTICLE I
THE MERGER
SECTION 1.01 The Merger. Upon the terms and subject to the conditions
hereof, and in accordance with the relevant provisions of the Delaware General
Corporation Law (the "DGCL") and the Delaware Revised Uniform Limited
Partnership Act (the "DRULPA"), the Partnership shall be merged with and into
the Company as soon as practicable following the satisfaction or waiver, if
permissible, of the conditions set forth in Article III. Following the Merger,
the Company shall continue as the surviving corporation (the "Surviving
Corporation") and shall continue its existence under the laws of the State of
Delaware, and the separate existence of the Partnership shall cease. At the
election of the Company, any direct or indirect wholly-owned subsidiary of
Meridian Oil Holding Inc. ("Parent") may be substituted for the Company as a
constituent party in the Merger.
SECTION 1.02 Effective Time. As soon as practicable following the
satisfaction or waiver of the conditions set forth in Article III, the Merger
shall be consummated by filing with the Secretary of State of the State of
Delaware a certificate of merger or other appropriate documents (in any case,
the "Certificate of Merger") in accordance with the DGCL and the DRULPA. The
Merger shall become effective at such time as the Certificate of Merger is duly
filed, or at such other time as the Partnership and the Company shall specify in
the Certificate of Merger (the time the Merger becomes effective being the
"Effective Time").
SECTION 1.03 Effects of the Merger. The Merger shall have the effects set
forth in Section 259 of the DGCL.
SECTION 1.04 Certificate of Incorporation and By-Laws. The Certificate of
Incorporation and the By-Laws of the Company shall be the certificate of
incorporation and by-laws of the Surviving Corporation until thereafter changed
or amended as provided therein or by applicable law.
SECTION 1.05 Directors and Officers. The directors and officers of the
Company immediately prior to the Effective Time shall be the directors and
officers of the Surviving Corporation until the earlier of their resignation or
removal or until their respective successors are duly elected and qualified.
<PAGE> 65
SECTION 1.06 Conversion of Units. At the Effective Time, by virtue of the
Merger and without any action on the part of the Partnership, the Company or the
holders of any of the following securities:
(a) each partnership interest in the Partnership held by the Company
or any affiliate of the Company shall be cancelled and retired and shall
cease to exist, and no payment or consideration shall be made with respect
thereto;
(b) each issued and outstanding LP Unit, other than LP Units included
in the partnership interests referred to in paragraph (a) above shall be
converted into the right to receive from the Surviving Corporation an
amount in cash, without interest, equal to $4.485 per LP Unit (the "Merger
Consideration"). At the Effective Time, all such LP Units shall cease to be
outstanding and shall automatically be canceled and retired and shall cease
to exist, and each holder of a certificate representing any such LP Unit
shall cease to have any rights with respect thereto, except the right to
receive the Merger Consideration, without interest; and
(c) each issued and outstanding share of capital stock of the Company
shall remain outstanding and shall represent one fully paid and
nonassessable share of common stock, par value $.01, of the Surviving
Corporation.
SECTION 1.07 Closing. The closing of the Merger (the "Closing") will take
place at 10:00 a.m. on a date to be specified by the parties, which shall be no
later than the second business day after satisfaction or waiver of the
conditions set forth in Article III, at the offices of Fried, Frank, Harris,
Shriver & Jacobson, One New York Plaza, New York, NY 10004, unless another date
or place is agreed to in writing by the parties hereto.
ARTICLE II
EXCHANGE OF UNITS
SECTION 2.01 Exchange of Certificates. (a) Prior to the Effective Time, the
Company shall appoint a bank or trust company to act as disbursing agent (the
"Disbursing Agent") for the payment of Merger Consideration upon surrender of
certificates representing the LP Units. Parent will enter into a disbursing
agent agreement with the Disbursing Agent, in form and substance reasonably
acceptable to the Company, and shall deposit or cause to be deposited with the
Disbursing Agent in trust for the benefit of the holders of LP Units cash in an
aggregate amount necessary to make the payments pursuant to Section 1.06 to
holders of LP Units (such amounts being hereinafter referred to as the "Exchange
Fund"). The Disbursing Agent shall, pursuant to irrevocable instructions, make
the payments provided for in the preceding sentence out of the Exchange Fund.
The Disbursing Agent shall invest portions of the Exchange Fund as the Company
directs, provided that such investments shall be in obligations of or guaranteed
by the United States of America, in commercial paper obligations receiving the
highest rating from either Moody's Investors Service, Inc. or Standard & Poor's
Corporation, or in certificates of deposit, bank repurchase agreements or
banker's acceptances of commercial banks with capital exceeding $100 million.
The Exchange Fund shall not be used for any other purpose, except as provided in
this Agreement.
(b) Promptly after the Effective Time, the Surviving Corporation shall
cause the Disbursing Agent to mail to each person who was a record holder as of
the Effective Time of an outstanding certificate or certificates which
immediately prior to the Effective Time represented Depositary Units (as defined
in the Partnership Agreement) representing LP Units (the "Certificates"), and
whose LP Units were converted into the right to receive Merger Consideration
pursuant to Section 1.06, a form of letter of transmittal (which shall specify
that delivery shall be effected, and risk of loss and title to the Certificates
shall pass, only upon proper delivery of the Certificates to the Disbursing
Agent) and instructions for use in effecting the surrender of the Certificate in
exchange for payment of the Merger Consideration. Upon surrender to the
Disbursing Agent of a Certificate, together with such letter of transmittal duly
executed and such other documents as may be reasonably required by the
Disbursing Agent, the holder of such Certificate shall be paid in exchange
therefor cash in an amount equal to the product of the number of LP Units
represented by such Certificate multiplied by the Merger Consideration, and such
Certificate shall forthwith be cancelled. No interest will be paid or accrued on
the cash payable upon the surrender of the Certificates. If payment is to be
made to a person other
-2-
<PAGE> 66
than the person in whose name the Certificate surrendered is registered, it
shall be a condition of payment that the Certificate so surrendered be properly
endorsed or otherwise be in proper form for transfer and that the person
requesting such payment pay any transfer or other taxes required by reason of
the payment to a person other than the registered holder of the Certificate
surrendered or establish to the satisfaction of the Surviving Corporation that
such tax has been paid or is not applicable. Until surrendered in accordance
with the provisions of this Section 2.01, each Certificate (other than
Certificates representing LP Units owned by the Company or any affiliate of the
Company shall represent for all purposes only the right to receive the Merger
Consideration in cash multiplied by the number of LP Units represented by such
Certificate, without any interest thereon.
(c) At and after the Effective Time, there shall be no registration of
transfers of LP Units and the Partnership shall instruct the depositary for the
Depositary Units not to register transfers of the Depositary Units which were
outstanding immediately prior to the Effective Time. From and after the
Effective Time, the holders of LP Units outstanding immediately prior to the
Effective Time shall cease to have any rights with respect to such LP Units
except as otherwise provided in this Agreement or by applicable law. All cash
paid upon the surrender of Certificates in accordance with the terms of this
Article II shall be deemed to have been paid in full satisfaction of all rights
pertaining to the LP Units previously represented by such Certificates. If,
after the Effective Time, Certificates are presented to the Surviving
Corporation for any reason, such Certificates shall be cancelled and exchanged
for cash as provided in this Article II.
(d) At any time more than one year after the Effective Time, the Surviving
Corporation shall be entitled to require the Disbursing Agent to deliver to it
any funds which had been made available to the Disbursing Agent and not
disbursed in exchange for Certificates (including, without limitation, all
interest and other income received by the Disbursing Agent in respect of all
such funds). Thereafter, holders of LP Units shall look only to the Surviving
Corporation (subject to abandoned property, escheat and other similar laws) as
general creditors thereof with respect to any Merger Consideration that may be
payable, without interest, upon due surrender of the Certificates held by them.
Notwithstanding the foregoing, neither the Surviving Corporation nor the
Disbursing Agent shall be liable to any holder of an LP Unit for any Merger
Consideration delivered in respect of such LP Unit to a public official pursuant
to any abandoned property, escheat or other similar law.
SECTION 2.02 Distribution. Nothing in this Agreement shall be construed as
affecting the rights of holders of LP Units to receive the distribution of $.13
per LP Unit to be paid on June 7, 1994 to holders of record of LP Units as of
May 13, 1994.
ARTICLE III
CONDITIONS TO CONSUMMATION OF THE MERGER
SECTION 3.01 Conditions to Each Party's Obligation to Effect the Merger.
The respective obligations of each party to effect the Merger are subject to the
satisfaction or waiver, where permissible, prior to the Effective Time, of the
following conditions:
(a) no statute, rule, regulation, executive order, decree, injunction
or other order (whether temporary, preliminary or permanent), shall have
been enacted, entered, promulgated or enforced by any court or governmental
authority which is in effect and has the effect of prohibiting the
consummation of the Merger; provided that each of the parties shall have
used its best efforts to prevent the entry of any injunction or other order
and to appeal as promptly as possible any injunction or other order that
may be entered; and
(b) the waiting period (and any extension thereof) applicable to the
consummation of the Merger under the Hart-Scott-Rodino Antitrust
Improvements Act of 1976, as amended, if any, shall have expired or been
terminated and a 20-day period shall have elapsed from the date of mailing
to holders of LP Units of an information statement with respect to the
Merger.
-3-
<PAGE> 67
ARTICLE IV
MISCELLANEOUS
SECTION 4.01 Amendment. This Agreement may not be amended except by an
instrument in writing signed on behalf of all the parties.
SECTION 4.02 Entire Agreement; Assignment. This Agreement constitutes the
entire agreement and supersedes all prior agreements and understandings, both
written and oral, among the parties with respect to the subject matter hereof.
Neither this Agreement nor any right, interest or obligation under this
Agreement shall be assigned, in whole or in part, by operation of law or
otherwise without the prior written consent of the other parties.
SECTION 4.03 Validity. In the event any one or more of the provisions
contained in this Agreement should be invalid, illegal or unenforceable in any
respect, the validity, legality and enforceability of the remaining provisions
contained herein and therein shall not in any way be affected or impaired
thereby.
SECTION 4.04 Governing Law. This Agreement shall be governed by and
construed in accordance with the substantive laws of the State of Delaware
regardless of the laws that might otherwise govern under principles of conflicts
of laws applicable thereto.
SECTION 4.05 Descriptive Headings. The descriptive headings herein are
inserted for convenience of reference only and are not intended to be part of or
to affect the meaning or interpretation of this Agreement.
SECTION 4.06 Parties in Interest. Nothing in this Agreement, express or
implied, is intended to confer upon any other person any rights or remedies of
any nature whatsoever under or by reason of this Agreement.
SECTION 4.07 Counterparts. This Agreement may be executed in one or more
counterparts, each of which shall be deemed to be an original, but all of which
shall constitute one and the same agreement, and shall become effective when one
or more counterparts have been signed by each of the parties and delivered to
the other parties.
IN WITNESS WHEREOF, each of the parties has caused this Agreement to be
executed on its behalf by its respective officers thereunto duly authorized, all
as of the day and year first above written.
DIAMOND SHAMROCK OFFSHORE
PARTNERS LIMITED PARTNERSHIP
By Meridian Offshore Company,
its managing general partner
By /s/ RANDOLPH P. MUNDT
----------------------------------
Name: Randolph P. Mundt
Title: Senior Vice President
MERIDIAN OFFSHORE COMPANY
By /s/ GERALD J. SCHISSLER
----------------------------------
Name: Gerald J. Schissler
Title: Executive Vice President
-4-
