<PAGE>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 1993
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-8567-2
MAXUS ENERGY CORPORATION
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 75-1891531
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
717 NORTH HARWOOD STREET 75201-6594
DALLAS, TEXAS (Zip Code)
(Address of principal executive
offices)
Registrant's telephone number, including area code: (214) 953-2000
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------
<S> <C>
Common Stock, $1.00 Par Value New York Stock Exchange
Pacific Stock Exchange
Rights to Purchase Junior Preferred Stock, Series A, New York Stock Exchange
of Maxus Energy Corporation Pacific Stock Exchange
$4.00 Cumulative Convertible Preferred Stock, $1.00 New York Stock Exchange
Par Value
$2.50 Cumulative Preferred Stock, $1.00 Par Value New York Stock Exchange
8 1/2% Sinking Fund Debentures Due April 1, 2008 New York Stock Exchange
</TABLE>
Securities registered pursuant to Section 12(g) of the Act: None
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEDING 12 MONTHS, AND (2) HAS BEEN SUBJECT TO SUCH FILING
REQUIREMENTS FOR THE PAST 90 DAYS. YES [X] NO [_]
INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM
405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED, TO
THE BEST OF REGISTRANT'S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION
STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY
AMENDMENT TO THIS FORM 10-K. [X]
The aggregate market value of the voting stock held by non-affiliates of the
registrant as of February 28, 1994 was approximately $638,269,000.
Shares of Common Stock outstanding at February 28, 1994--134,372,471.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the following documents are incorporated by reference into the
indicated parts of this report:
(a) 1993 Annual Report to Stockholders of the Company--Parts I, II and IV
(b) Definitive proxy statement of the Company relating to the 1994 Annual
Meeting of Stockholders, filed with the Commission pursuant to Regulation
14A--Part III.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES.
Maxus Energy Corporation (the "Company") was incorporated in Delaware in 1983
as a company to hold the stock of various corporations, the oldest of which was
founded in 1910. The Company, together with its subsidiaries, is an independent
oil and gas exploration and production company. Its principal executive offices
are located at 717 North Harwood Street, Dallas, Texas 75201-6594, and its
telephone number is (214) 953-2000. In this report, the term "Company" means
Maxus Energy Corporation, its subsidiaries and their predecessors unless the
context otherwise indicates.
The Company is one of the largest independent oil and gas exploration and
production companies in the United States, with ongoing international activity
in Indonesia and a number of other countries, and domestic activity primarily
in the Mid-Continent and Gulf Coast regions of the United States. Information
concerning outside sales and operating profit by geographic area for the three
years ended December 31, 1993 and identifiable assets by geographic area as of
December 31, 1993, 1992 and 1991 is presented on page 39 of the Company's 1993
Annual Report to Stockholders, which information is incorporated herein by
reference.
The Company's sales or transfers between geographic areas were not
significant in each of the three years ended December 31, 1993. Operating
revenues from export sales to unaffiliated customers located outside the United
States were less than 10% of the Company's consolidated sales and operating
revenues in each of the three years ended December 31, 1993.
Exploration and Production
International. The Company has interests in production sharing contracts with
Pertamina, Indonesia's state oil company, for the exploration, development and
production of oil and gas in two primary areas in the Java Sea--Southeast
Sumatra and Northwest Java. These areas accounted for 93% of the Company's
total net production of oil during 1993. The Company's working interest in the
Southeast Sumatra production sharing contract under which it acts as operator
is 55.7% and in the Northwest Java production sharing contract is 24.3%.
The Indonesian production sharing contracts allow the Company to recover,
subject to available production, tangible and intangible costs of exploration,
intangible costs of production and operating costs on a current basis and
tangible costs of production generally over a seven-year period. After recovery
of those costs and fulfillment of a domestic market obligation for oil, the
contractors currently receive 34% of the oil produced and 79.5% of the gas
produced, before Indonesian taxes, the statutory rate for which is 56%. The
Southeast Sumatra and Northwest Java production sharing contracts extend to
2018 and 2017, respectively.
Gas projects are progressing in both the Northwest Java and Southeast Sumatra
contract areas. In 1992, ARCO, the operator under the Northwest Java production
sharing contract, began developing gas reserves. Production from this project
began delivery to Jakarta in September 1993 and the objective of the project is
to attain a production level of 260 Mmcf per day (gross) in 1994. In Southeast
Sumatra by year-end 1993, the Company had certified 290 Bcf of gross gas
reserves. The Company is negotiating with Pertamina for a gas sales contract to
supply the Jakarta market by 1996.
In May 1993, the Company announced its intention to seek buyers for its
interest in the Northwest Java contract area. In September 1993, the Company
announced that it had rejected as inadequate bids received for such sale. The
Company is continuing to pursue a sale of all or part of its interest in this
area along with other possible asset sales.
The Company is the operator of and has a 35% working interest in the Block 16
project in eastern Ecuador which is expected to begin production in early 1994.
Average production for 1994 is expected to be
<PAGE>
approximately 30,000 gross barrels per day. The Company plans to spend
approximately $50 million on the Block 16 project in 1994 compared to $108.8
million spent in 1993.
In the Surubi Field of the Mamore-1 Block in Bolivia, production has begun
from three wells. Proven Surubi area gross reserves are estimated at 25 million
barrels out of a potential 50 to 100 million barrels. Current production from
the block is approximately 2,500 barrels of oil per day. The Company is the
operator of the Mamore Block and has a 100% working interest in the concession.
The Company is awaiting final government approval of a transportation and sale
agreement under which it will sell oil to the Bolivian market and/or transport
oil for export and under which it will receive capacity guarantees in the
existing pipeline infrastructure.
During 1993, the Company completed drilling of the Volcanera 1 well located
on the Recetor Block, one of the Company's contract areas in Colombia. Testing
operations ceased in September 1993 and the well was suspended pending further
evaluation. In 1993, the Company began drilling the Liria 1 well, also on the
Recetor Block. Effective November 1, 1993, the Company transferred its 53.33%
interest in the Recetor Block to BP Exploration Company (Colombia) Ltd., one of
its partners in the Block. Under the transfer agreement, the Company retained a
4.50% overriding royalty from total production and received a $10 million
payment. The override is subject to reduction to 2.25% should Ecopetrol, the
Colombian national oil company, elect to participate in the Recetor Association
Contract pursuant to a declaration of commerciality. In August 1993, the
Company farmed out 40% of its 100% interest in the Chimichagua Association
Contract and, in January 1994, the Company relinquished its rights to the
Tierra Negra Association Contract.
In November 1993, the Company announced the signing of a contract in which it
has a 95% interest for the Quiriquire Unit in Venezuela with Lagoven, an
affiliate of Petroleos de Venezuela, S.A. The Quiriquire Unit currently
produces slightly less than 1,000 barrels per day of crude oil. The Company's
three-year plan includes a field reactivation program and the drilling of two
delineation wells. The Company has executed a letter of intent to convey a 45%
interest in the Quiriquire Unit to a third party, subject to government
approval.
During 1993, the Company also conducted geological and geophysical work in
other countries including Tunisia, Ethiopia, Bulgaria, Madagascar and Slovakia.
During 1994, however, the Company plans total domestic and international
program spending in the amount of approximately $212 million, substantially
below the levels of 1990 through 1993. Consequently, during the year, the
Company intends to focus its international efforts primarily on its present
interests in Indonesia, Ecuador, Bolivia and Venezuela, while reducing its
activities outside these areas.
The Company's foreign petroleum exploration, development and production
activities are subject to political and economic uncertainties, expropriation
of property and cancellation or modification of contract rights, foreign
exchange restrictions and other risks arising out of foreign governmental
sovereignty over the areas in which the Company's operations are conducted, as
well as risks of loss in some countries due to civil strife, guerrilla
activities and insurrection.
Domestic. The Company currently focuses its domestic exploration and
production efforts in the Anadarko Basin in the Texas Panhandle and western
Oklahoma and the Texas and Louisiana offshore and onshore Gulf Coast areas. In
addition, the Company has substantial investments in natural gas gathering
systems in the Texas Panhandle and western Oklahoma which are used to aggregate
gas produced and purchased by the Company for processing and resale.
In the Mid-Continent area in 1993, the Company completed construction on and
placed into operation its new gas processing plant in the Texas Panhandle. It
is currently processing at capacity and uses cold-box technology allowing more
efficient recovery of natural gas liquids and recovery of helium.
2
<PAGE>
The Company acts as a general partner and operates in federal waters offshore
Texas and Louisiana through a master limited partnership, Diamond Shamrock
Offshore Partners Limited Partnership (the "Partnership"). The aggregate
ownership interest of the Company in the Partnership, comprised of a 1% general
partnership interest and units of limited partnership interest, was
approximately 87.1% at December 31, 1993. The Company's ownership interest in
the Partnership is reflected in the information regarding the Company's oil and
gas operations included in this report. During 1994, the Partnership's emphasis
in program spending will be on existing fields to maintain production levels.
Oil and Gas Operations
Average sales prices and production costs of crude oil and natural gas
produced by geographic area for the three years ended December 31, 1993 were as
follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1993 1992 1991
------- ------- -------
<S> <C> <C> <C>
UNITED STATES
Average Sales Price
Crude Oil (per barrel)............................. $16.99 $18.28 $19.49
Natural Gas Liquids (per barrel)................... $11.08 $11.51 $12.16
Natural Gas Sold (per Mcf)(a)...................... $ 2.13 $ 1.80 $ 1.66
Natural Gas Produced (per Mcf)(b).................. $ 2.26 $ 2.04 $ 1.90
Average Production Cost (per barrel)(c).............. $ 3.22 $ 2.91 $ 3.04
INDONESIA
Average Sales Price
Crude Oil (per barrel)............................. $17.31 $18.40 $19.59
Natural Gas Liquids (per barrel)................... $10.57 $11.93 $10.36
Natural Gas Sold (per Mcf)(a)...................... $ 1.30 $ 0.20 $ 0.20
Natural Gas Produced (per Mcf)(b).................. $ 2.35 $ 1.50 $ 1.46
Average Production Cost (per barrel)(c).............. $ 6.53 $ 6.10 $ 5.47
</TABLE>
- --------
(a) The average natural gas price for sales volumes is derived from the total
net sales value for all natural gas sold, including residue gas remaining
after the removal of natural gas liquids, divided by the annual natural gas
sales volume.
(b) The average natural gas price for produced volumes is calculated by
dividing the total net value received from the sale of natural gas and
natural gas liquids by the annual natural gas production volume.
(c) Production or lifting cost is exclusive of depreciation and depletion
applicable to capitalized lease acquisition, exploration and development
expenditures. Average production costs are calculated by dividing total
costs by the sum of crude oil and equivalent barrels of oil for natural gas
production. Gas volumes produced were converted to equivalent barrels of
oil by dividing the Mcf volume by six. Six Mcf of gas have approximately
the heating value of one barrel of crude oil.
The Company periodically hedges against the effects of fluctuations in the
prices of natural gas through price swap agreements. A hedging program which
began with June 1993 production covered an average of 50% of United States
production. It has been extended through 1994 but may cover a larger portion of
production during the year.
3
<PAGE>
Information regarding the Company's oil and gas producing activities for
1993, 1992 and 1991 is set forth on pages 52 through 56 of the Company's 1993
Annual Report to Stockholders, which information is incorporated herein by
reference. The Company's estimates of its net interests in proved reserves are
based upon records regularly prepared and maintained by its engineers. In 1993,
the Company and the Partnership each filed estimates of certain of its proved
reserves of crude oil and natural gas in the United States at December 31, 1992
with the United States Department of Energy. The total reserve estimates
included therein do not differ by more than 5% from the total reserve estimates
for the comparable period for the same reserves included in the Company's
filings with the Securities and Exchange Commission.
The following table shows the Company's average daily sales and net
production (after deducting royalty and operating interests of others) by
geographic area for the three years ended December 31, 1993.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1993 1992 1991
------- ------- -------
<S> <C> <C> <C>
UNITED STATES
Average Daily Production
Crude Oil (M barrels)............................... 4.9 5.7 9.9
Natural Gas (Mmcf)(a)............................... 208 227 238
Average Daily Sales
Natural Gas Liquids (M barrels)..................... 7.6 8.9 8.8
Natural Gas (Mmcf)(b)............................... 181 200 207
INDONESIA
Average Daily Production
Crude Oil (M barrels)............................... 62.4 61.9 67.4
Average Daily Sales
Natural Gas Liquids (M barrels)..................... 1.5 1.6 1.4
Natural Gas (Mmcf).................................. 13 8 7
</TABLE>
- --------
(a) Reflects the average amount of daily wellhead production.
(b) Average daily sales volumes for natural gas production, reduced, in those
cases where the gas is processed for extraction of natural gas liquids, by
the shrinkage resulting therefrom.
In addition to gathering and processing a substantial part of the Company's
own natural gas, the Company also purchases natural gas, primarily in the Texas
Panhandle and western Oklahoma, for resale. The majority of this natural gas is
processed through the Company's processing facilities. The table below reflects
the average daily sales and average sales price received for such purchased
natural gas and the natural gas liquids extracted in processing during 1993,
1992 and 1991.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1993 1992 1991
------- ------- -------
<S> <C> <C> <C>
Average Sales Price
Natural Gas Liquids (per barrel)...................... $11.19 $11.13 $12.04
Natural Gas (per Mcf)................................. $ 1.99 $ 1.70 $ 1.51
Average Daily Sales
Natural Gas Liquids (M barrels)....................... 9.8 9.0 7.9
Natural Gas (Mmcf).................................... 184 80 61
</TABLE>
4
<PAGE>
The following tables set forth information regarding the Company's wells and
leasehold acres. "Gross" wells or acres are the total number of wells or acres
in which the Company owns any interest. "Net" wells or acres are the sum of the
fractional working interests the Company owns in gross wells or acres.
"Productive" wells are either producing wells or wells capable of commercial
production although currently shut-in. One or more completions ("multiple
completions") in the same bore hole are counted as one well.
At December 31, 1993, total gross and net productive oil and gas wells,
including multiple completions, by geographic area were as follows:
<TABLE>
<CAPTION>
GROSS NET
----- ------
<S> <C> <C>
Oil Wells Owned
United States..................................................... 652 312.6
Indonesia......................................................... 1000 363.8
South America..................................................... 4 4.0
---- ------
Total.......................................................... 1656 680.4
==== ======
Gas Wells Owned
United States..................................................... 1457 1098.2
Indonesia......................................................... 13 3.7
---- ------
Total.......................................................... 1470 1101.9
==== ======
Multiple Completions
United States..................................................... 71 54.9
Indonesia......................................................... 100 24.3
---- ------
Total.......................................................... 171 79.2
==== ======
</TABLE>
At December 31, 1993, total gross and net developed and undeveloped acreage
by geographic area was as follows:
<TABLE>
<CAPTION>
SOUTH AMERICA
UNITED AND OTHER
STATES INDONESIA FOREIGN
--------- --------- -------------
<S> <C> <C> <C>
GROSS ACRES
Developed Acres............................... 576,417 141,063 3,954
Undeveloped Acres............................. 831,780 8,135,862 48,607,479
--------- --------- ----------
Total..................................... 1,408,197 8,276,925 48,611,433
========= ========= ==========
NET ACRES
Developed Acres............................... 452,134 53,426 3,954
Undeveloped Acres............................. 500,703 2,944,845 47,810,721
--------- --------- ----------
Total..................................... 952,837 2,998,271 47,814,675
========= ========= ==========
</TABLE>
5
<PAGE>
Drilling activities of the Company for the three years ended December 31,
1993 are summarized by geographic area in the following table:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1993 1992 1991
------- ------- -------
<S> <C> <C> <C>
UNITED STATES
Net Exploratory Wells Drilled
Productive............................................ 1.7 0 5.0
Dry................................................... 1.9 1.2 5.9
------- ------- -------
Total............................................... 3.6 1.2 10.9
======= ======= =======
Net Development Wells Drilled
Productive............................................ 20.2 10.3 17.5
Dry................................................... 2.2 1.7 3.9
------- ------- -------
Total............................................... 22.4 12.0 21.4
======= ======= =======
INDONESIA
Net Exploratory Wells Drilled
Productive............................................ 0 0 0
Dry................................................... 0 1.1 .6
------- ------- -------
Total............................................... 0 1.1 .6
======= ======= =======
Net Development Wells Drilled
Productive............................................ 20.9 16.4 26.9
Dry................................................... 9.1 3.5 6.3
------- ------- -------
Total............................................... 30.0 19.9 33.2
======= ======= =======
SOUTH AMERICA AND OTHER FOREIGN
Net Exploratory Wells Drilled
Productive............................................ 2.0 0 0
Dry................................................... 2.1 2.5 1.5
------- ------- -------
Total............................................... 4.1 2.5 1.5
======= ======= =======
Net Development Wells Drilled
Productive............................................ 2.0 0 0
Dry................................................... 0 0 0
------- ------- -------
Total............................................... 2.0 0 0
======= ======= =======
</TABLE>
At December 31, 1993, the Company was participating in the drilling of 10
gross and 4.1 net wells in the United States, 5 gross and 1.8 net wells in
Indonesia and 2 gross and 1.3 net wells in areas outside the United States
other than Indonesia.
Competition and Markets
The primary markets for the Company's Indonesian oil production are the
Pacific Rim countries, including Japan, China and Indonesia. The increasing
environmental consciousness of this region has resulted in premium prices for
low sulfur oil such as that produced from the Southeast Sumatra and Northwest
Java areas. The Company has ongoing business relationships with government oil
companies, utilities, refiners and trading companies which are expected to
continue to facilitate sales in this area. The Company is preparing for the
sales of new production in Ecuador, primarily focusing on customers in the
United States.
The Company believes that the long-term potential for growth in natural gas
demand in North America remains high due to environmental awareness and price
advantages; however, market prices remain extremely
6
<PAGE>
volatile, with weather and regional supply and demand imbalances causing the
potential for large monthly price swings. The Company has concentrated its
domestic natural gas production in two core areas--the Mid-Continent area of
the Texas Panhandle and western Oklahoma and the Texas and Louisiana onshore
and offshore Gulf Coast areas. The Company has been able to realize premium
prices by focusing its marketing efforts in these areas and by aggregating
supply, thereby offering large volumes backed by diverse supply sources.
Approximately 43% of the Company's gas sales in 1993 were made directly to
local gas distribution companies and industrial users.
The Company, as do other independent exploration and production companies,
sells crude oil and natural gas to a wide number of customers, including
refineries and other industrial consumers, gas transmission companies and
utilities. Oil and gas are essentially commodities and the Company's production
represents only a small fraction of the total world markets for oil and natural
gas. As a result, the prices the Company receives depend primarily on the
relative balance between supply and demand in these markets.
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 possibility of renewed 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.
Health, Safety and Environmental Controls
Federal, state and local laws and regulations relating to health and
environmental quality in the United States as well as environmental laws and
regulations of other countries in which the Company operates affect nearly all
of the operations of the Company. These laws and regulations set various
standards regulating certain aspects of health and environmental quality,
provide for penalties and other liabilities for the violation of such standards
and establish in certain circumstances obligations to remediate current and
former facilities and off-site locations. In addition, especially stringent
measures and special provisions may be appropriate or required in
environmentally sensitive foreign areas of operation, such as those in Ecuador.
Many of the Company's United States operations are subject to requirements of
the Oil Pollution Act of 1990, the Safe Drinking Water Act, the Clean Water
Act, the Clean Air Act (as amended in 1990), the Occupational Safety and Health
Act and other federal, as well as state, laws. These laws typically require
compliance with associated regulations and permits and provide for the
imposition of penalties for noncompliance. For example, the federal
Comprehensive Environmental Response, Compensation and Liability Act of 1980,
as amended ("CERCLA"), and certain state laws and regulations thereunder
require and address the cleanup of deposits and spills of hazardous substances
and the monitoring and maintaining of closed hazardous waste disposal sites.
The Clean Air Act Amendments of 1990 may benefit the Company's business by
increasing the demand for natural gas as a clean fuel.
The Company accepts the Environmental Mission and Guiding Environmental
Principles of the American Petroleum Institute and believes that its policies
and procedures in the area of pollution control, product safety and
occupational health are adequate to prevent unreasonable risk of environmental
and other damage, and of resulting financial liability, in connection with its
business. Some risk of environmental and other damage is, however, inherent in
particular operations of the Company and, as discussed below, the Company has
certain potential liabilities associated with former operations. The Company
cannot predict what environmental legislation or regulations will be enacted in
the future or how existing or future laws or regulations will be administered
or enforced. Compliance with more stringent laws or regulations, as well as
more vigorous enforcement policies of the regulatory agencies, could in the
future require material expenditures by the Company for the installation and
operation of systems and equipment for remedial measures and in certain other
respects.
In connection with the sale of the Company's chemical subsidiary, Diamond
Shamrock Chemicals Company ("Chemicals"), to Occidental Petroleum Corporation
("Occidental") in 1986, the Company agreed
7
<PAGE>
to indemnify Chemicals and Occidental from and against certain liabilities
relating to the business or activities of Chemicals prior to the September 4,
1986 closing date (the "Closing Date"), including certain environmental
liabilities relating to certain chemical plants and waste disposal sites used
by Chemicals prior to the Closing Date.
In addition, the Company agreed to indemnify Chemicals and Occidental for 50%
of certain environmental costs incurred by Chemicals for which notice is given
to the Company within 10 years after the Closing Date on projects involving
remedial activities relating to chemical plant sites or other property used in
the conduct of the business of Chemicals as of the Closing Date and for any
period of time following the Closing Date, with the Company's aggregate
exposure for this cost sharing being limited to $75 million. The total expended
by the Company under this sharing arrangement was about $24.7 million as of
December 31, 1993.
In connection with the spin-off of Diamond Shamrock R&M, Inc., now known as
Diamond Shamrock, Inc. ("DSI") in 1987, the Company and DSI agreed to share the
costs of losses (other than product liability) relating to businesses disposed
of prior to the spin-off, including Chemicals. Pursuant to this cost-sharing
agreement, the Company bore the first $75 million of such costs and DSI bore
the next $37.5 million. Under the arrangement, such ongoing costs are now borne
one-third by DSI and two-thirds by the Company. This will continue until DSI
has borne an additional $47.5 million, following which such costs will be borne
solely by the Company. As of January 1, 1994, DSI's remaining responsibility is
approximately $29.4 million.
In 1993, the Company spent $14.9 million in environmental related
expenditures in its oil and gas operations, mainly attributable to the
installation of environmental control equipment for the Sunray gas plant and
the gas project in Northwest Java. Expenditures in 1994 are expected to be
approximately $9 million.
The Company's total expenditures for environmental compliance for disposed of
businesses, including Chemicals, were $36.3 million in 1993, $11.4 of which was
recovered from DSI under the above described cost-sharing agreement. Those
expenditures are projected to be at approximately $21 million in 1994 after
recovery from DSI under such agreement.
The insurance companies that wrote Chemicals' and the Company's primary and
excess insurance during the relevant periods have to date refused to provide
coverage for most of Chemicals' or the Company's cost of the personal injury
and property damage claims related to environmental claims, including remedial
activities at chemical plant sites and disposal sites. In two actions filed in
New Jersey state courts, the Company has been conducting litigation against all
of these insurers for declaratory judgments that it is entitled to coverage for
certain of these claims. In 1989, the trial judge in one of the New Jersey
actions ruled that there is no insurance coverage with respect to the claims
related to the Newark plant (discussed below). The trial court's decision was
upheld on appeal and that action is now ended. The other suit, which is
pending, covers disputes with respect to insurance coverage related to certain
other environmental matters.
Newark, New Jersey. A consent decree, previously agreed upon by the U.S.
Environmental Protection Agency (the "EPA"), the New Jersey Department of
Environmental Protection and Energy (the "DEP") and Occidental, as successor to
Chemicals, was entered in 1990 by the United States District Court of New
Jersey and requires implementation of a remedial action plan at Chemicals'
former Newark, New Jersey agricultural chemicals plant. Engineering, which will
include an engineering estimate of the cost of construction, is progressing.
Construction will follow, which is expected to be completed within four years.
The work is being supervised and paid for by the Company pursuant to its above
described indemnification obligation to Occidental.
Studies have indicated that sediments of the Newark Bay watershed, including
the Passaic River adjacent to the plant, are contaminated with hazardous
chemicals from many sources. Studies performed by the Company and others
suggest that contaminants historically discharged by the Newark plant are
buried under
8
<PAGE>
several feet of more recent sediment deposits and are not moving. The Company
has been negotiating with the EPA to conduct further testing and studies to
characterize contaminated sediment in a six-mile portion of the Passaic River
near the plant site. The Company has been conducting similar studies under its
own auspices for several years. Until these studies are completed and
evaluated, the Company cannot reasonably forecast what regulatory program, if
any, will be proposed for the Newark Bay watershed.
Hudson County, New Jersey. Until 1972, Chemicals operated a chromium ore
processing plant at Kearny, New Jersey. According to the DEP, wastes from these
ore processing operations were used as fill material at sites in Hudson County.
As a result of negotiations between the Company (on behalf of Occidental) and
the DEP, Occidental signed an administrative consent order with the DEP in 1990
for investigation and remediation work at certain chromite ore residue sites in
Kearny and Secaucus, New Jersey. The work is being performed by the Company on
behalf of Occidental, and the Company is funding Occidental's share of the cost
of investigation and remediation of these sites and is currently providing
financial assurance for performance of the work in the form of a $20 million
letter of credit. This financial assurance may be reduced with the approval of
the DEP following any annual cost review. While the Company has participated in
the cost of studies and is implementing interim remedial actions and conducting
remedial investigations and feasibility studies, the ultimate cost of
remediation cannot be estimated at this time.
Painesville, Ohio. From about 1912 until 1977, Chemicals operated
manufacturing facilities in Painesville, Ohio. The operations over the years
involved several discrete but contiguous plant sites over an area of several
hundred acres between Lake Erie, on the north, and the Grand River, on the
south. There was also some waste handling in certain areas just south of the
Grand River. The primary area of concern historically has been Chemicals'
former chromite ore processing plant (the "Chrome Plant"). For many years, the
area of the Chrome Plant has been under the administrative control of the EPA
pursuant to an administrative consent order under which Chemicals is required
to maintain a clay cap over the area and to conduct certain ground water and
surface water monitoring. Many other areas have previously been clay-capped and
one specific area, which was a waste disposal area from the mid-1960s until the
1970s, has been encapsulated and is being controlled and monitored. In spite of
these many remedial, maintenance and monitoring activities, the former
Painesville plant areas have been proposed for listing on the National Priority
List under CERCLA. Discussions are underway among the Company, EPA and Ohio
Environmental Protection Agency ("Ohio EPA") concerning the appropriate scope
and nature of any further investigation or remediation that may be required. No
estimate can be made at this time of the ultimate cost of investigation and any
further remediation.
Other Former Plant Sites. Environmental remediation programs are in place at
all other former plant sites where material remediation is required in the
opinion of the Company. Former plant sites where remediation has been completed
are being maintained and monitored to insure continued compliance with
applicable laws and regulatory programs.
Third Party Sites. Chemicals has also been designated as a potentially
responsible party ("PRP") by the EPA under CERCLA with respect to a number of
third party sites, primarily off of the Company's properties, where hazardous
substances from Chemicals' plant operations allegedly were disposed of or have
come to be located. Numerous PRPs have been named at substantially all of these
sites. At several of these, Chemicals has no known exposure. Although PRPs are
almost always jointly and severally liable for the cost of investigations,
cleanups and other response costs, each has the right of contribution from
other PRPs and, as a practical matter, cost sharing by PRPs is usually effected
by agreement among them. Accordingly, the ultimate cost of these sites and
Chemicals' share of the costs thereof cannot be estimated at this time, but is
not expected to be material except possibly as a result of the matters
described below.
1. Fields Brook; Ashtabula, Ohio. At the time that Chemicals was sold to
Occidental, Chemicals operated a chemical plant at Ashtabula, Ohio which
discharges into Fields Brook. Occidental has continued to operate
9
<PAGE>
the Ashtabula plant. In 1986, Chemicals was formally notified by the EPA that
it was a PRP for the Fields Brook site. The site is defined as Fields Brook,
its tributaries and surrounding areas within the Fields Brook watershed. At
least 15 other companies are presently considered to be financially responsible
PRPs. In 1986, the EPA estimated the cost of sediment remediation at the site
would be $48.4 million. Some of the PRPs, including Occidental, have entered
into an allocation agreement for sharing the costs of a portion of the work
ordered by the EPA. Under the agreement, the costs attributable to Occidental
for Chemicals' ownership of the Ashtabula plant would be less than five percent
of the total, assuming all viable PRPs were to participate.
In 1990, the Ohio EPA, as state trustee for natural resources under CERCLA,
advised previously identified PRPs, including Chemicals, that the Ohio EPA
intended to conduct a Natural Resource Damage Assessment of the Fields Brook
site to calculate a monetary value for injury to surface water, groundwater,
air, biological and geological resources at the site.
Although Fields Brook empties into the Ashtabula River which flows into Lake
Erie, it is not known to what extent, if any, the EPA will propose remedial
action beyond Fields Brook for which the Fields Brook PRPs might be asked to
bear some share of the costs. Until all preliminary studies have been completed
and negotiated or judicial allocations have been made, it is not possible to
estimate what the response costs, response activities or natural resource
damages may be for Fields Brook or related areas, the parties responsible
therefor or their respective shares. It is the Company's position that costs
attributable to the Ashtabula plant fall under the Company's above-described
cost sharing arrangement with Occidental under which the Company bears one-half
of certain costs up to an aggregate dollar cap. Occidental, however, is
contending that it is entitled to full indemnification from the Company for
such costs, and the outcome of this dispute cannot be predicted.
2. French Limited Disposal Site; Crosby, Texas. The PRPs, including Chemicals
represented by the Company, entered into a consent decree and a related trust
agreement with the EPA with respect to this disposal site. The consent decree
has been entered by the federal court as a settlement of the EPA's claim for
remedial action. The estimated cost of future remediation is approximately $20
million, of which Chemicals' share is expected to be approximately five
percent.
3. SCP/Carlstadt Site; Carlstadt, New Jersey. Chemicals' share of remedial
costs at this CERCLA site would be approximately one percent, based on relative
volume of waste shipped to the site. A partial remedial investigation and
feasibility study conducted by the PRPs (including Chemicals represented by the
Company), a draft of which was submitted to the EPA in 1989, recommended a $20
million interim remedial project to address surface and soils cleanup, but did
not address any offsite issues. This interim remedy has now been implemented by
the PRPs but no estimate can be made at this time of ultimate costs of
remediation.
4. Chemical Control Site; Elizabeth, New Jersey. The DEP has demanded of PRPs
(including Chemicals) reimbursement of the DEP's alleged $26 million in past
costs for its partial cleanup of this site. The PRPs and the EPA have settled
the federal claims for cost recovery and site remediation, and remediation is
now complete. Chemicals' share of any money paid to the DEP for its claim will
be approximately two percent based on the previous allocation formula.
Employees
As of December 31, 1993, the Company had approximately 2,572 employees.
ITEM 3. LEGAL PROCEEDINGS.
See the heading "Health, Safety and Environmental Controls" under "Items 1
and 2. Business and Properties." of this report for a description of certain
legal proceedings, which description is incorporated herein by reference.
10
<PAGE>
The Company is involved in various other legal proceedings incidental to its
business, the outcome of any of which should not have a material adverse effect
on its financial position.
ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS.
Inapplicable.
Executive Officers of the Company
The following table sets forth certain information as of March 1, 1994
concerning the executive officers of the Company.
<TABLE>
<CAPTION>
SERVED
AS AN
OFFICER
NAME POSITION WITH THE COMPANY AGE SINCE
---- ------------------------- --- -------
<S> <C> <C> <C>
C. L. Blackburn.............. Chairman, President and Chief 66 1986
Executive Officer
M. C. Forrest................ Vice Chairman and Chief Operating 60 1992
Officer
S. G. Crowell................ Senior Vice President, Operations 46 1987
G. W. Pasley................. Senior Vice President, Operations 43 1989
N. D. Rietman................ Senior Vice President, Production 60 1987
M. A. Schuepbach............. Senior Vice President, Exploration 49 1987
L. E. Ardila................. Vice President, Exploration 53 1993
W. H. Bagley................. Vice President, Drilling and 46 1987
Construction
M. J. Barron................. Vice President, Treasurer and Chief 44 1991
Financial Officer
J. W. Blankenship............ Vice President, Hydrocarbon Marketing 49 1992
G. R. Brown.................. Vice President and Controller 51 1987
M. J. Gentry................. Vice President, Human Resources and 42 1991
General Services
M. Middlebrook............... Vice President and General Counsel 58 1984
E. J. Ritchie................ Vice President, Exploration 49 1993
D. E. Vandenberg............. Vice President, Engineering and 50 1992
Development
</TABLE>
Officers are elected annually by the Board of Directors and may be removed at
any time by the Board. There are no family relationships among the executive
officers listed and there are no arrangements or understandings pursuant to
which any of them were elected as officers. Each of the officers named above
has been employed by the Company during the last five years with
responsibilities of the general nature indicated by his title, except as set
forth below.
Mr. Forrest joined the Company in 1992 as special assistant to the Chairman
and later that year was elected Vice Chairman and Chief Operating Officer.
Prior to 1992, he was with Shell U.S.A. for more than five years, last serving
as President of its subsidiary, Pecten International Company.
Mr. Crowell joined the Company in 1976 as a geophysicist. Since such time, he
has held various positions with the Company, including Senior Vice President,
North American Exploration and Production, and Vice President, Administration.
Mr. Crowell was named Senior Vice President, Operations, in 1992.
Mr. Pasley joined the Company in 1984 as Associate Director of Investor
Relations. Since such time, he has held various positions with the Company,
including Director of Communications, Vice President, Human Resources and
Senior Vice President, International. Mr. Pasley was named Senior Vice
President, Operations, in 1992.
11
<PAGE>
Mr. Ardila was elected Vice President, Exploration, in October 1993. Mr.
Ardila joined the Company in 1979 as a Senior Geologist in Jakarta and has held
various positions with the Company since such time, including Exploration
Manager in Indonesia and Exploration Manager, Latin America and Far East, in
Dallas. His present position pertains to the Company's South American
exploration efforts.
Mr. Barron was elected Vice President, Treasurer and Chief Financial Officer
of the Company in 1991. Mr. Barron joined Natomas Company in 1982 as a Project
Manager. Natomas Company was acquired by the Company in 1983 and Mr. Barron has
held various positions with the Company, including Director of Strategic
Planning and Assistant Treasurer, since such time.
Mr. Blankenship was elected Vice President, Hydrocarbon Marketing, in April
1993. Mr. Blankenship joined Natomas Company in 1983 as Senior Manager of
Research. Natomas Company was acquired by the Company in the same year and Mr.
Blankenship has held various positions with the Company, including Vice
President, Economics and Contracts, since such time.
Mr. Gentry was elected Vice President, Human Resources and General Services,
in 1991. Mr. Gentry joined the Company in 1975 and has held various positions
with the Company, including Associate Director of Management Information
Systems Operations, Assistant Treasurer and General Manager of Human Resources,
since such time.
Mr. Vandenberg joined the Company in 1990 as Production Engineer in Jakarta,
Indonesia. He served as Production and Acquisition Manager for Kilroy Company
of Texas from 1988 to 1990. Mr. Vandenberg was elected Vice President,
Engineering and Development, in 1992.
Mr. Rietman retires in March 1994.
A new organizational structure will become effective March 31, 1994. The
position of Vice Chairman will be eliminated and Mr. Forrest will become Senior
Vice President, Business Development. Mr. Crowell will become Senior Vice
President, Producing Operations and Mr. Pasley will become Senior Vice
President, Finance and Administration and Chief Financial Officer. After the
restructuring becomes effective, Messrs. Barron, Brown, Gentry and Middlebrook
will be the only other Vice Presidents.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The principal United States market on which the Common Stock is traded is the
New York Stock Exchange. The Common Stock is also listed and traded on the
Pacific Stock Exchange, the Basel Stock Exchange (Switzerland), the Geneva
Stock Exchange (Switzerland) and the Zurich Stock Exchange (Switzerland). The
high and low sales prices for the Common Stock for each full quarterly period
during 1993 and 1992 as reported on the New York Stock Exchange Composite Tape
are set forth on page 58 of the Company's 1993 Annual Report to Stockholders,
which information is incorporated herein by reference.
The approximate number of record holders of Common Stock at December 31, 1993
was 35,619.
The Company paid no dividends on its Common Stock during 1993 and 1992. Cash
flows are currently being dedicated to exploration and development projects
rather than to the payment of dividends on Common Stock. The Company intends to
continue paying regular quarterly dividends on its $4.00 Cumulative Convertible
Preferred Stock, $9.75 Cumulative Convertible Preferred Stock and $2.50
Cumulative Preferred Stock.
ITEM 6. SELECTED FINANCIAL DATA.
The information required by this item appears on page 57 of the Company's
1993 Annual Report to Stockholders, which information is incorporated herein by
reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
The information required by this item appears on pages 26 through 32 of the
Company's 1993 Annual Report to Stockholders, which information is incorporated
herein by reference.
12
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The information required by this item appears on pages 33 through 49 and
pages 52 through 59 of the Company's 1993 Annual Report to Stockholders, which
information is incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
Inapplicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
With the exception of the information provided below as to Darrell L. Black,
the information required by this item with respect to the directors of the
Company appears on pages 2 through 6 of the definitive proxy statement of the
Company relating to the Company's 1994 Annual Meeting of Stockholders filed
with the Securities and Exchange Commission pursuant to Regulation 14A, under
the captions "Nominees for Election at Annual Meeting," "Present Directors
Whose Terms Continue After Annual Meeting," and "Director Proposed By
Prudential" which information is incorporated herein by reference. Darrell L.
Black, aged 70, has served as a director of the Company since 1989. His current
term expires on the date of the Company's annual meeting, May 11, 1994, and Mr.
Black will retire as a director of the Company as of such date pursuant to the
Board's retirement policy that a director shall not be nominated or stand for
reelection to the Board after age 70. Information concerning the Company's
executive officers is set forth under the caption "Executive Officers of the
Company" in Part I above.
ITEM 11. EXECUTIVE COMPENSATION.
The information required by this item appears under the captions "Director
Compensation," "Executive Officer Compensation," and "Termination of Employment
and Change In Control Arrangements" in the definitive proxy statement of the
Company relating to the Company's 1994 Annual Meeting of Stockholders filed
with the Securities and Exchange Commission pursuant to Regulation 14A, which
information is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by this item appears under the caption "Beneficial
Ownership of Securities" in the definitive proxy statement of the Company
relating to the Company's 1994 Annual Meeting of Stockholders filed with the
Securities and Exchange Commission pursuant to Regulation 14A, which
information is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information required by this item appears under the caption "Certain
Transactions and Relationships" in the definitive proxy statement of the
Company relating to the Company's 1994 Annual Meeting of Stockholders filed
with the Securities and Exchange Commission pursuant to Regulation 14A, which
information is incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) Documents filed as part of this report:
(1) Financial Statements--The following financial statements have been
incorporated by reference to pages 33 through 49 and pages 52 through 59 of
the Company's 1993 Annual Report to Stockholders:
Consolidated Statement of Operations for the three years ended December
31, 1993.
Consolidated Balance Sheet at December 31, 1993 and 1992.
Consolidated Statement of Cash Flows for the three years ended December
31, 1993.
13
<PAGE>
Notes to Consolidated Financial Statements.
Report of Independent Accountants.
Supplementary Financial Information (unaudited).
Quarterly Data (unaudited).
(2) Financial Statement Schedules.
Schedule V--Consolidated Properties and Equipment.
Schedule VI--Consolidated Accumulated Depreciation and Depletion.
Report of Independent Accountants on Financial Statement Schedules.
All other schedules have been omitted because they are not applicable or the
required information is shown in the Financial Statements or the Financial
Summary.
Condensed parent company financial information has been omitted, since the
amount of restricted net assets of consolidated subsidiaries does not exceed
25% of total consolidated net assets. Also, footnote disclosure regarding
restrictions on the ability of both consolidated and unconsolidated
subsidiaries to transfer funds to the parent company has been omitted since the
amount of such restrictions does not exceed 25% of total consolidated net
assets.
The Company has computed the ratio of earnings to fixed charges and the ratio
of earnings to combined fixed charges and preferred stock dividends for the
year ended December 31, 1993 to be 1.50 and less than one, respectively, on a
consolidated basis. Earnings were inadequate to cover combined fixed charges
and preferred stock dividends for such year by $7.8 million. For the purposes
of these computations, earnings consist of income before income taxes and fixed
charges (excluding interest capitalized, net of amortization). Fixed charges
represent interest incurred, amortization of debt expense and that portion of
rental expense deemed to be the equivalent of interest.
(3) Exhibits.
Each document marked by an asterisk is incorporated herein by reference to
the designated document previously filed with the Securities and Exchange
Commission (the "Commission"). Each of Exhibits Nos. 10.1 through 10.17 is a
management contract or compensatory plan, contract or arrangement required to
be filed as an exhibit hereto by Item 14(c) of Form 10-K.
<TABLE>
<S> <C>
3.(i) --Restated Certificate of Incorporation of the Company (Exhibit
3.(i) to the Company's Current Report on Form 8-K dated January
24, 1994).*
3.(ii) --By-Laws of the Company (Exhibit 3.2 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1992 [the
"1992 Form 10-K"]).*
4.1 --Indenture dated as of April 1, 1978 between Diamond Shamrock
Corporation ("Diamond") and Mellon Bank, N.A. relating to
Diamond's $150,000,000 8 1/2% Sinking Fund Debentures due April 1,
2008 (Exhibit 4.1 to the 1992 Form 10-K).*
4.2 --First Supplemental Indenture dated as of January 26, 1984 among
the Company, Diamond Shamrock Chemicals Company ("Chemicals") and
Mellon Bank, N.A. supplementing the Indenture described in Exhibit
4.1 above (Exhibit 4.2 to the 1992 Form 10-K).*
4.3 --Tri Party Agreement dated January 24, 1993 appointing Chemical
Bank as successor trustee under the Indenture described in Exhibit
4.1 above (Exhibit 4.3 to the Company's Current Report on Form 8-K
dated January 12, 1994 [the "January 12 Form 8-K"]).*
4.4 --Indenture dated as of May 1, 1983 between Diamond and Mellon
Bank, N.A. relating to unspecified Debt Securities of Diamond
(Exhibit 4.4 to the 1992 Form 10-K).*
4.5 --Resolutions of the Board of Directors of Diamond supplementing
the Indenture described in Exhibit 4.4 above and establishing
terms and conditions of Diamond's $150,000,000
11 1/4% Sinking Fund Debentures due May 1, 2013 (Exhibit 4.5 to
the 1992 Form 10-K).*
4.6 --First Supplemental Indenture dated as of January 26, 1984 among
the Company, Chemicals and Mellon Bank, N.A. supplementing the
Indenture and the resolutions described in Exhibits 4.4 and 4.5,
respectively, above (Exhibit 4.6 to the 1992 Form 10-K).*
</TABLE>
14
<PAGE>
<TABLE>
<C> <S>
4.7 --Tri Party Agreement dated January 12, 1994 appointing NationsBank
of Texas, N.A. as successor trustee under the Indenture described in
Exhibit 4.4 above (Exhibit 4.1 to the January 12 Form 8-K).*
4.8 --Indenture dated as of November 1, 1985 between the Company and
Mellon Bank, N.A. relating to unspecified Debt Securities of the
Company (Exhibit 4.8 to the 1992 Form 10-K).*
4.9 --Resolutions of an ad hoc committee of the Board of Directors of
the Company supplementing the Indenture described in Exhibit 4.8
above and establishing terms and conditions of the Company's
$150,000,000 11 1/2% Sinking Fund Debentures due November 15, 2015
(Exhibit 4.9 to the 1992 Form 10-K).*
4.10 --Tri Party Agreement dated January 12, 1994 appointing NationsBank
of Texas, N.A. as successor trustee under the Indenture described in
Exhibit 4.8 above (Exhibit 4.2 to the January 12 Form 8-K).*
4.11 --Indenture dated as of April 1, 1988 between the Company and
Chemical Bank relating to unspecified debt securities of the Company
(Exhibit 4.11 to the 1992 Form 10-K).*
4.12 --Officers' Certificate dated June 1, 1988 establishing a series of
debt securities ($150,000,000 Medium-Term Notes, Series A) to be
issued under the Indenture described in Exhibit 4.11 above (Exhibit
4.12 to the 1992 Form 10-K).*
4.13 --Indenture dated as of November 1, 1990 between the Company and
Chemical Bank relating to unspecified debt securities of the Company
(Exhibit 4.13 to the 1992 Form 10-K).*
4.14 --Officers' Certificate dated February 13, 1991 establishing a
series of debt securities ($150,000,000 Medium-Term Notes, Series B)
to be issued under the Indenture described in Exhibit 4.13 above
(Exhibit 4.14 to the 1992 Form 10-K).*
4.15 --Officers' Certificate dated September 28, 1992 establishing a
series of debt securities ($250,000,000 9 7/8% Notes Due 2002) to be
issued under the Indenture described in Exhibit 4.13 above (Exhibit
4.15 to the 1992 Form 10-K).*
4.16 --Officers' Certificate dated January 26, 1993 establishing a series
of debt securities ($100,000,000 9 1/2% Notes Due 2003) to be issued
under the Indenture described in Exhibit 4.13 above (Exhibit 4.16 to
the 1992 Form 10-K).*
4.17 --Officer's Certificate dated June 30, 1993 establishing a series of
debt securities ($150,000,000 Medium-Term Notes, Series C) to be
issued under the Indenture described in Exhibit 4.13 above (Exhibit
4 to the Company's Current Report on Form 8-K dated June 21, 1993).*
4.18 --Officer's Certificate dated September 9, 1993 establishing a
series of debt securities ($250,000,000 Medium-Term Notes, Series D)
to be issued under the Indenture described in Exhibit 4.13 above
(Exhibit 4 to the Company's Current Report on Form 8-K dated
September 9, 1993).*
4.19 --Officer's Certificate dated October 27, 1993 establishing a series
of debt securities ($200,000,000 9 3/8% Notes due 2003) to be issued
under the Indenture described in Exhibit 4.13 above (Exhibit 4 to
the Company's Annual Report on Form 8-K dated October 20, 1993).*
4.20 --Officer's Certificate dated January 18, 1994 establishing a series
of debt securities ($60,000,000 9 3/8% Notes due 2003) to be issued
under the Indenture described in Exhibit 4.13 (Exhibit 4 to the
Company's Current Report on Form 8-K dated January 10, 1994).*
4.21 --Preferred Stock Purchase Agreement dated February 1, 1987 (the
"Preferred Stock Purchase Agreement") between the Company and The
Prudential Insurance Company of America ("Prudential") (Exhibit 4.17
to the 1992 Form 10-K).*
</TABLE>
15
<PAGE>
<TABLE>
<S> <C>
4.22 --Amendment dated February 8, 1987 to the Preferred Stock Purchase
Agreement (Exhibit 4.18 to the 1992 Form 10-K).*
4.23 --Registration Rights Agreement dated as of February 1, 1987 between
the Company and Prudential (Exhibit 4.19 to the 1992 Form 10-K).*
4.24 --Agreement dated April 12, 1990 amending the Preferred Stock
Purchase Agreement (Exhibit 4.20 to the 1992 Form 10-K).*
4.25 --Waiver of Certain Rights Relating to $9.75 Preferred Stock dated
June 5, 1990 between the Company and Prudential (Exhibit 4.21 to the
1992 Form 10-K).*
4.26 --Waiver of Certain Equity Offering Rights dated April 12, 1990
between the Company and Prudential amending the Preferred Stock
Purchase Agreement (Exhibit 4.22 to the 1992 Form 10-K).*
4.27 --Warrant Certificate No. 1 dated October 10, 1992 issued to Kidder,
Peabody Group Inc. for 8,000,000 warrants each representing the
right to purchase from the Company on or prior to October 10, 1997
one share of common stock, $1.00 par value, of the Company at a
price of $13.00 per share (Exhibit 4.23 to the 1992 Form 10-K).*
4.28 --Registration Rights Agreement dated as of October 10, 1992 between
Kidder, Peabody Group Inc. and the Company (Exhibit 4.24 to the 1992
Form 10-K).*
10.1 --1992 Director Stock Option Plan of the Company (Exhibit 4.1 to the
Company's Form S-8 Registration Statement No. 33-55918).*
10.2 --1992 Long-Term Incentive Plan of the Company (Exhibit 4.1 to the
Company's Form S-8 Registration Statement No. 33-47538).*
10.3 --1980 Long-Term Incentive Plan of the Company, as amended August
31, 1983 (Exhibit 4.19 to Post Effective Amendment on Form S-8,
amending the Company's Form S-14 Registration Statement No. 2-
85403).*
10.4 --1986 Long-Term Incentive Plan of the Company (Exhibit 4.1 to the
Company's Form S-8 Registration Statement No. 33-6693).*
10.5 --Amendment dated April 29, 1987 to the 1986 Long-Term Incentive
Plan of the Company (Exhibit 4.2 to Post Effective Amendment No. 1
to the Company's Form S-8 Registration Statement No. 33-6693).*
10.6 --Performance Incentive Plan of the Company, as amended effective
January 1, 1986 (Exhibit 10.6 to the 1992 Form 10-K).*
10.7 --Specimen copy of Change of Control Agreement between the Company
and its executive officers (Exhibit 10.7 to the 1992 Form 10-K).*
10.8 --Specimen copy of letter agreement between the Company and certain
of its executive officers relating to 10 of the Agreements referred
to in Exhibit 10.7 above (Exhibit 10.8 to the 1992 Form 10-K).*
10.9 --Employee Shareholding and Investment Supplemental Benefits Plan of
the Company, as amended and restated effective January 1, 1991
(Exhibit 10.9 to the 1992 Form 10-K).*
10.10 --Amendment effective as of January 1, 1994 to the plan described in
Exhibit 10.9 above, filed herewith.
10.11 --Specimen copy of disability benefit arrangement between the
Company and its executive officers (Exhibit 10.10 to the 1992 Form
10-K).*
10.12 --Supplemental Executive Retirement Plan of the Company, effective
May 1, 1987 (Exhibit 10.11 to the 1992 Form 10-K).*
10.13 --Supplemental Executive Retirement Plan of the Company, effective
March 1, 1990 (Exhibit 10.12 to the 1992 Form 10-K).*
</TABLE>
16
<PAGE>
<TABLE>
<S> <C>
10.14 --Specimen copy of supplemental death benefit arrangement between
the Company and its executive officers (Exhibit 10.13 to the 1992
Form 10-K).*
10.15 --Deferred Compensation Plan for Directors of the Company, revised
as of April 30, 1991 (Exhibit 10.14 to the 1992 Form 10-K).*
10.16 --Trust Agreement dated December 18, 1986 between the Company and
Ameritrust Company National Association (Exhibit 10.15 to the 1992
Form 10-K).*
10.17 --Deferred Compensation Plan for Executives of the Company,
effective September 28, 1993, filed herewith.
10.18 --Distribution Agreement dated as of April 22, 1987 between the
Company and Diamond Shamrock R&M, Inc. (Exhibit 10.23 to the 1992
Form 10-K).*
10.19 --Rights Agreement dated as of September 2, 1988 between the Company
and AmeriTrust Company National Association (Exhibit 10.24 to the
1992 Form 10-K).*
10.20 --Stock Purchase Agreement by and among the Company and Occidental
Petroleum Corporation, et. al. dated September 4, 1986 (Exhibit
10.25 to the 1992 Form 10-K).*
12.1 --Statement re Computation of Ratios, filed herewith.
13.1 --Pages 25 through 59 of the 1993 Annual Report to Stockholders of
the Company, filed herewith. (such pages are incorporated by
reference and are identified by reference to page numbers in the
text of this report on Form 10-K).
21.1 --List of Subsidiaries of the Company, filed herewith.
23.1 --Consent of Independent Accountants, filed herewith.
24.1 --Powers of Attorney of directors and officers of the Company, filed
herewith.
99.1 --Certain portions of the definitive Proxy Statement of the Company
relating to the Company's 1994 Annual Meeting of Stockholders filed
with the Commission pursuant to Regulation 14A. (Such portions are
incorporated by reference and are identified by reference to
captions thereof in the text of this report on Form 10-K.)*
</TABLE>
(b) Reports on Form 8-K.
<TABLE>
<CAPTION>
ITEMS
DATE OF REPORT REPORTED
-------------- -------------
<S> <C>
October 20, 1993 Items 5 and 7
November 18, 1993 Items 5 and 7
</TABLE>
17
<PAGE>
SCHEDULE V
MAXUS ENERGY CORPORATION
CONSOLIDATED PROPERTIES AND EQUIPMENT
THREE YEARS ENDED DECEMBER 31, 1993
(DOLLARS IN MILLIONS)
<TABLE>
<CAPTION>
OIL & GAS
----------------------------
PROVED UNPROVED
PROPERTIES PROPERTIES OTHER CORPORATE TOTAL
---------- ---------- ------ --------- --------
<S> <C> <C> <C> <C> <C>
January 1, 1991............... $2,440.2 $89.7 $126.7 $181.3 $2,837.9
Additions, at cost.......... 231.8 19.3 18.9 2.3 272.3
Disposals and transfers..... (176.9) (38.4) (2.5) (0.2) (218.0)
-------- ----- ------ ------ --------
December 31, 1991............. 2,495.1 70.6 143.1 183.4 2,892.2
Additions, at cost.......... 166.8 34.7 58.2 1.4 261.1
Disposals and transfers..... (33.9) (25.8) 6.6 (13.2) (66.3)
-------- ----- ------ ------ --------
December 31, 1992............. 2,628.0 79.5 207.9 171.6 3,087.0
Additions, at cost.......... 291.3 31.4 16.2 1.1 340.0
Disposals and transfers..... (17.2) (38.6) (3.5) 1.1 (58.2)
-------- ----- ------ ------ --------
December 31, 1993............. $2,902.1 $72.3 $220.6 $173.8 $3,368.8
======== ===== ====== ====== ========
</TABLE>
18
<PAGE>
SCHEDULE VI
MAXUS ENERGY CORPORATION
CONSOLIDATED ACCUMULATED DEPRECIATION AND DEPLETION
THREE YEARS ENDED DECEMBER 31, 1993
(DOLLARS IN MILLIONS)
<TABLE>
<CAPTION>
OIL & GAS
---------------------------
PROVED UNPROVED
PROPERTIES PROPERTIES OTHER CORPORATE TOTAL
---------- ---------- ----- --------- --------
<S> <C> <C> <C> <C> <C>
January 1, 1991............... $1,609.5 $19.0 $73.6 $58.7 $1,760.8
Additions charged against
income..................... 174.5 15.1 8.6 4.1 202.3
Disposals and transfers..... (132.3) (18.6) 3.6 1.2 (146.1)
-------- ----- ----- ----- --------
December 31, 1991............. 1,651.7 15.5 85.8 64.0 1,817.0
Additions charged against
income..................... 148.5 13.1 7.6 3.9 173.1
Disposals and transfers..... (14.6) (14.4) (5.0) (7.4) (41.4)
-------- ----- ----- ----- --------
December 31, 1992............. 1,785.6 14.2 88.4 60.5 1,948.7
Additions charged against
income..................... 129.8 10.0 8.6 3.9 152.3
Disposals and transfers..... (32.4) (3.6) (2.6) 0.8 (37.8)
-------- ----- ----- ----- --------
December 31, 1993............. $1,883.0 $20.6 $94.4 $65.2 $2,063.2
======== ===== ===== ===== ========
</TABLE>
19
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
ON
FINANCIAL STATEMENT SCHEDULES
To the Board of Directors
of Maxus Energy Corporation
Our audits of the consolidated financial statements referred to in our report
dated February 22, 1994 appearing on page 51 of the 1993 Annual Report to
Stockholders of Maxus Energy Corporation (which report and consolidated
financial statements are incorporated by reference in this Annual Report on
Form 10-K) also included an audit of the Financial Statement Schedules listed
in Item 14 (a)(2) of this Form 10-K. In our opinion, these Financial Statement
Schedules present fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial
statements.
PRICE WATERHOUSE
Dallas, Texas
February 22, 1994
20
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
Maxus Energy Corporation
C. L. BLACKBURN
By __________________________________
C. L. Blackburn
Chairman, President and Chief
Executive Officer
March 25, 1994
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
SIGNATURE TITLE
C. L. BLACKBURN* Chairman, President and Chief
_____________________________________ Executive Officer
C. L. Blackburn
M. J. BARRON* Vice President, Treasurer and Chief
_____________________________________ Financial Officer (Principal
M. J. Barron Financial Officer)
G. R. BROWN* Vice President and Controller
_____________________________________ (Principal Accounting Officer)
G. R. Brown
J. DAVID BARNES* Director
_____________________________________
J. David Barnes
DARRELL L. BLACK* Director
_____________________________________
Darrell L. Black
B. CLARK BURCHFIEL* Director
_____________________________________
B. Clark Burchfiel
21
<PAGE>
SIGNATURE TITLE
BRUCE B. DICE* Director
_____________________________________
Bruce B. Dice
M. C. FORREST* Director
_____________________________________
M. C. Forrest
CHARLES W. HALL* Director
_____________________________________
Charles W. Hall
RAYMOND A. HAY* Director
_____________________________________
Raymond A. Hay
GEORGE L. JACKSON* Director
_____________________________________
George L. Jackson
JOHN T. KIMBELL* Director
_____________________________________
John T. Kimbell
RICHARD W. MURPHY* Director
_____________________________________
Richard W. Murphy
W. THOMAS YORK* Director
_____________________________________
W. Thomas York
Lynne P. Ciuba, by signing her name hereto, does hereby sign this report on
Form 10-K on behalf of each of the above-named officers and directors of the
registrant pursuant to a power of attorney executed by each of such officers
and directors.
LYNNE P. CIUBA
*By _________________________________
Lynne P. Ciuba
Attorney-in-fact March 25, 1994
22
<PAGE>
Exhibit Index
(exhibits filed herewith)
10.10 -Amendment effective as of January 1, 1994 to the Employee Shareholding
and Investment Supplemental Benefits Plan of the Company.
10.17 -Deferred Compensation Plan for Executives of the Company, effective
September 28, 1993.
12.1 -Statement re Computation of Ratios.
13.1 -Pages 25 through 59 of the 1993 Annual Report to Stockholders of the
Company (such pages are incorporated by reference and are identified by
reference to page numbers in the text of this report on Form 10-K).
21.1 -List of Subsidiaries of the Company.
23.1 -Consent of Independent Accountants.
24.1 -Powers of Attorney of directors and officers of the Company.
<PAGE>
Exhibit 10.10
AMENDMENT TO
MAXUS ENERGY CORPORATION
EMPLOYEE SHAREHOLDING AND INVESTMENT PLAN
(EFFECTIVE AS OF JANUARY 1, 1994)
THIS Amendment to the Maxus Energy Corporation Employee Shareholding and
Investment Plan (as amended and restated as of November 1, 1990) (the "Plan") is
made effective as of January 1, 1994 (the "Effective Date").
Paragraph 4.10 of the Plan is amended as of the Effective Date to read as
follows:
"4.10 In addition to other applicable limitations which may
be set forth in the Plan and notwithstanding any other
contrary provision in the Plan, annual Earnings taken
into account under the Plan shall not exceed $150,000
(adjusted for changes in the cost of living as provided
in Section 401(a)(17) and Section 415(d) of the Code)
for purposes of determining the level of a Participant's
contributions under the Plan for any Plan Year commencing
after December 31, 1993. This provision shall not serve
to reduce a Participant's accrued benefit under the Plan
calculated as of 12:00 A.M., January 1, 1994."
The Plan as amended herein is ratified, confirmed and approved.
EXECUTED this ____ day of December, 1993.
ATTEST: MAXUS ENERGY CORPORATION
______________________ BY_____________________________
Vice President
<PAGE>
Exhibit 10.17
MAXUS ENERGY CORPORATION
DEFERRED COMPENSATION PLAN
FOR EXECUTIVES
1. Purpose of Plan.
It is the purpose of this Plan to enable Executives of the Corporation to
defer some or all Compensation payable for the future services to be performed
as an employee or officer of the Corporation.
2. Definitions.
"Account" means the account, described in Paragraph 5 below, to which is
---------
credited Compensation deferred in accordance with this Plan.
"Accounting Date" means each March 31, June 30, September 30 and December
-----------------
31.
"Administrator" means the Employee Benefits Committee of the Corporation,
---------------
or such other person as may be designated by the Chief Executive Officer of the
Corporation, with power and authority to construe, interpret and administer this
Plan pursuant to Paragraph 12 below.
"Beneficiary" means the person or persons designated from time to time in
------------
the Notice of Beneficiary Designation, referred to in Paragraph 10 below, by a
Participant to receive payments under this Plan after the Participant's death.
"Board" means the Board of Directors of the Corporation or any committee of
-------
such Board of Directors to the extent that such committee has been delegated
authority to act on behalf of the Board of Directors with respect to this Plan.
"Common Stock" means whole shares of common stock of the Corporation.
--------------
"Compensation" means base salary and payments under or pursuant to the
--------------
Corporation's Performance Incentive Plan, or any successor plan.
1
<PAGE>
"Corporation" means Maxus Energy Corporation, its majority owned
-------------
subsidiaries and affiliates, and their successors.
"Executive" means a regular, full time employee of the Corporation at
-----------
exempt job grade 12, or its equivalent, or above.
"Interest Factor" means interest on the cash denominated portion of a
-----------------
Participant's Account during any quarterly accounting period. The quarterly
rate of interest for this purpose shall be designated from time to time by the
Administrator.
"Notice of Beneficiary Election" means the notice provided for in Paragraph
--------------------------------
10 below.
"Notice of Election" means the notice provided for in Paragraph 4 below.
---------------------
"Participant" means any Executive who participates in this Plan.
------------
"Plan" means the Maxus Energy Corporation Deferred Compensation Plan for
------
Executives.
3. Eligibility.
Any Executive shall be eligible to participate in this Plan.
4. Manner of Election.
(a) Any Executive wishing to participate in this Plan must file with the
Administrator a written notice on the Notice of Election form designated by the
Administrator electing to defer payment of all or a portion of his or her
Compensation. An election shall be effective only as follows:
(i) if filed not later than September 30, 1993 the election shall
be effective with respect to Compensation earned on or after
October 1, 1993 for the balance of calendar year 1993 and, except
to the extent such election is subsequently modified or
terminated as provided below, subsequent calendar quarters; and
(ii) if filed after September 30, 1993, the election shall be
effective with respect to
2
<PAGE>
Compensation earned during the first calendar quarter that
commences after the date of filing of the Notice of Election and,
except to the extent such election is subsequently modified or
terminated as provided below, subsequent calendar quarters.
(b) An election, unless subsequently modified or terminated as provided
below, shall apply to Compensation payable with respect to each subsequent
calendar quarter.
(c) An election may be modified by filing with the Administrator a new
Notice of Election on or before the calendar
3
<PAGE>
quarter for which such modification is to be effective. No modification shall
be effective with respect to Compensation earned prior to the date the new
Notice of Election is received by the Administrator or the effective date of the
new Notice of Election, whichever is later.
(d) An election may be terminated by the filing with the Administrator of
a Notice of Termination on the form designated by the Administrator on or before
the calendar quarter for which such termination is to be effective. No
termination shall be effective with respect to Compensation earned prior to the
date the Notice of Termination is received by the Administrator or the effective
date of the Notice of Termination, whichever is later. An election shall also
terminate on the date a person ceases to be a Executive.
(e) A Participant for whom an election is terminated may thereafter file a
new Notice of Election for future calendar quarters for which such person is
eligible to participate in this Plan.
5. Accounts.
(a) The amount of any Compensation deferred in accordance with an election
shall be credited to an Account maintained by the Corporation on its books in
the name of the Participant.
(b) In the case of a Participant who has elected that amounts credited to
such Participant's Account under this Plan be denominated in Common Stock, all
amounts so credited to the Account of such Participant to the extent prescribed
by the Participant in his or her election, shall be denominated quarterly by the
Corporation in Common Stock.
4
<PAGE>
(c) In lieu of the cash dividends, if any, which would be payable on
Common Stock credited to the Account of a Participant on any dividend record
date if such Common Stock had been owned by the Participant, the Corporation
shall credit the Account of such Participant, on the dividend payment date, with
an amount equivalent to such dividends ("dividend equivalents") to be
denominated in Common Stock. The Common Stock credited to the Account of a
Participant shall be adjusted to reflect any stock dividends or stock splits in
respect to Common Stock. Further, if the Corporation shall issue any other
rights with respect to Common Stock, it shall, on the date of such issuance,
credit to the Account of the Participant the amount of the value of the right
which would have been issued on the Common Stock credited to such Account on the
record date for such distribution if such Common Stock had been issued to and
owned by the Participant.
6. No Trust Lien, Etc.
Solely for convenience in administering this Plan and in describing the
cash and Common Stock credited to the Account of a Participant, the amount of
such cash and the amount of such Common Stock shall be reflected in the Account
of such Participant and shall be respectively referred to in this Plan as cash
and Common Stock "credited" to such Account or as assets "credited" to such
Account. Nevertheless, the purpose of this Plan is merely to describe an
unsecured promise by the Corporation to make the payments described in this Plan
and not to create any trust for the benefit of any Participant or any other
person, including, without limitation, any Beneficiary. All rights, title and
interest in cash and Common Stock credited to the Account of a Participant shall
remain at all times solely the Corporation's unsecured contractual obligation
under this Plan. No cash or Common Stock credited under this Plan to a
Participant's Account on the books of the Corporation shall be held in trust, by
reason of this Plan, for such Participant or any other person, including,
without limitation, any Beneficiary, and neither such Participant nor any other
person, including, without limitation, any Beneficiary shall have any right,
title or interest of any kind, by reason of this Plan, in any such cash or
Common Stock or other assets of the Corporation.
7. Annual Report to Participant.
The Administrator shall cause the Corporation to keep an accurate record of
the cash and Common Stock credited to the
5
<PAGE>
Account of each Participant, and as of the end of each calendar year shall
deliver to each Participant a written statement showing the cash and Common
Stock credited to such Participant's Account.
8. Adjustment of Account.
As of each Accounting Date the Account for each Participant shall be
adjusted for the period elapsed since the last preceding Accounting Date to
reflect the adjustments required by this Plan, including the following:
(a) First, the Account shall be charged with any distribution made during
the period in accordance with Paragraph 9 below.
(b) Then, the Account shall be credited with the amount,
if any, of any Compensation deferred during that period in accordance with an
election under Paragraph 4 above.
(c) Finally, the Account shall be credited with the Interest Factor
(compounded quarterly) for that period with respect to the cash credited to the
Account, and shall be credited with any "dividend equivalents" or the value of
any other rights with respect to Common Stock credited to the Account under
Paragraph 5 above.
9. Payment.
(a) Except in the case of the death or permanent disability of a
Participant, distribution of an Account shall be made in a lump sum as of the
last day of the month following the date the Participant ceases to be an
Executive, unless the Participant, at the time of his or her election to defer
Compensation, specified on the Notice of Election that distribution of his or
her Deferred Compensation Account shall commence as of a specific date, which
date is not after the January 1 following the calendar year in which the
Participant reaches age 70 and either (i) be in the form of a lump sum payment
or (ii) be in the form of installments on an annual or quarterly basis.
Provided, however, in no event other than in the case of death, permanent
disability or ceasing to be an Executive will a Participant or his or her
Beneficiary receive payment for that portion of the Participant's's Account, if
any, which has been denominated as Common Stock until at least six months have
elapsed since such
6
<PAGE>
portion of the Participant's Account was denominated as Common Stock.
(b) In the event of Participant's death or permanent disability prior to
the date specified for distribution of such Participant's Account, or prior to
the full distribution of such Account, whichever may be applicable, the balance
of the Account shall be distributed in a lump sum to the Participant or his or
her Beneficiary designated pursuant to Paragraph 10 below. The lump sum payment
shall be paid as of the last day of the month following the Participant's date
of death or permanent disability.
(c) All cash and Common Stock credited to a Participant's Account will be
paid in cash. Distributions will be made to the Participant or, in the event of
such Participant's death, to the designated Beneficiary, in accordance with the
Participant's election and Paragraph 10 below. Provided, however, in no event
other than in the case of death, permanent disability or ceasing to be a
Executive will a Participant or his or her Beneficiary receive payment for that
portion of the Participant's Account, if any, which has been denominated as
Common Stock until at least six months have elapsed since such portion of the
Participant's Account was denominated as Common Stock.
(d) On each date for an installment distribution, there shall be
distributed to the Participant an amount in cash equal to the sum of the cash
balance and the fair market value of Common Stock then credited to such
Participant's Account multiplied by a fraction, the numerator of which is one
and the denominator of which is the number of remaining installments.
(e) Notwithstanding the provisions of Subparagraphs (a), (b), (c) and (d)
of this Paragraph 9, the Administrator, in its absolute discretion exercised in
good faith, may accelerate the rate of distribution but only in the case of
financial hardship caused by circumstances over which the Participant has no
control, and only to the extent necessary to alleviate such financial hardship.
In no such event, however, will a Participant be entitled to receive payment of
that portion of his Account, if any, which is denominated as Common Stock and
which has not been so denominated for at least six months. No Participant shall
participate in any such decision affecting uniquely such member as a
Participant.
(f) The balance of a Participant's Account shall be appropriately reduced
in accordance with this Paragraph 9 to reflect distributions made hereunder.
7
<PAGE>
(g) Any election with respect to the distribution of Compensation deferred
for a given quarterly period pursuant to this Plan shall be irrevocable.
10. Beneficiary Designation.
A Participant may designate on the Notice of Beneficiary Designation form
designated by the Administrator any person or persons to whom payments are to be
made if the Participant dies before receiving payment of all amounts due under
this Plan and the proportion or proportions in which distributions are to be
made to each such person. A beneficiary designation will be effective only
after the Notice of Beneficiary Designation is filed with and accepted by the
Administrator while the Participant is alive and, to the extent indicated by the
Participant in the Notice of Beneficiary Designation, will cancel all
beneficiary designations signed and filed earlier by such Participant. Any such
designation may be terminated or modified from time to time by the Participant.
If and to the the extent that a Participant fails to designate a Beneficiary or
if all of the Beneficiaries of the Participant die before the death of the
Participant or before complete payment of all the amounts credited to the
Participant's Account under this Plan, the remaining unpaid amounts shall be
paid in one lump sum to the estate of the last to die of the Participant or the
Participant's Beneficiaries.
11. Non-Alienability of Benefits.
Neither any Participant nor any Beneficiary shall have any right to,
directly or indirectly, alienate, assign or encumber any amount that is or may
be payable under this Plan nor shall any such amounts be subject to alienation,
assignment, encumbrance or garnishment, voluntary or involuntary, by process of
law or otherwise.
12. Administration of Plan.
(a) Except as provided in Paragraph 9(e), full power and authority to
construe, interpret and administer this Plan shall be vested in the
Administrator, who may from time to time adopt any rules or regulations the
Administrator determines are necessary or appropriate. If there is no
Administrator, the power and authority of the Administrator shall rest with the
Board; however, no person who is a member of the Administrator or
8
<PAGE>
Board, or who serves as Administrator, shall participate in any decision
affecting uniquely such member as a Participant. Decisions of the Administrator
and the Board made in good faith, shall be final, conclusive and binding upon
all parties.
(b) In the absence of bad faith or gross neglect of duty, neither the
Administrator nor any member of the Board, nor any person who serves as
Administrator, shall have any liability to the Corporation or to any other
person, firm or corporation arising out of or connected with the administration
of this Plan for any decision made respecting this Plan or its administration.
13. Amendment or Discontinuance of Plan.
At the sole discretion of the Board this Plan may be discontinued or
changed at any time. Upon such discontinuance, the cash and Common Stock
theretofore credited to the Account of any Participant shall be distributed in
satisfaction of the obligations of the Corporation under this Plan, in the
manner selected at the option of the Board or at the option of the Administrator
if so directed by the Board, as follows:
(a) The value of the Account may be distributed in a lump sum as of the
date of discontinuance in a manner consistent with Paragraph 9 hereof. The lump
sum payment shall be made on the last day of the month following the date of
discontinuance; or
(b) The value of the Account may be distributed in accordance with the
Notice of Election; or
(c) Commencing on the last day of the month following the date of
discontinuance, an amount equal to the value of the Account as of the date of
discontinuance may be distributed in no more than ten annual installments,
calculated in the same manner as payments under Paragraph 9(d), with interest on
such amounts from the date of discontinuance to the date of such payment at a
rate to be determined in accordance with Paragraph 8(c).
(d) Any provision herein to the contrary notwithstanding, no distribution
of that portion of a Participant's Account which has been denominated as Common
Stock for less than six months shall be made solely by reason of the
discontinuance of this Plan until at least six months have elapsed since such
portion of the Participant's Account was denominated as Common Stock.
14. Governing Law.
9
<PAGE>
The provisions of this Plan shall be interpreted and construed in
accordance with the laws of the State of Texas.
15. Effective Date.
Subject to approval by the Board, this Plan shall become effective on
September 28, 1993, but only with respect to compensation earned for services
rendered on or after October 1, 1993.
10
<PAGE>
MAXUS ENERGY CORPORATION
DEFERRED COMPENSATION PLAN FOR EXECUTIVES
NOTICE OF ELECTION
1. Pursuant to the provisions of the Maxus Energy Corporation Deferred
Compensation Plan for Executives (the "Plan"), I elect to have Compensation
payable to me deferred in the manner specified below. I understand that
this election shall be irrevocable as to Compensation earned by me
following the filing and effectiveness of this election, except to the
extent I file a subsequent Notice of Election or Notice of Termination with
the Administrator applicable to Compensation earned by me in a calendar
quarter subsequent to the calendar quarter as to which this filing is
effective.
I also understand that no modification or termination shall be effective
with respect to Compensation deferred prior to the calendar quarter
following the date any subsequent Notice of Election or Notice of
Termination is received by the Administrator.
2. Percentage of Compensation deferred.
Performance Incentive
Base Salary Plan Bonus
----------- ---------------------
[ ] All [ ] All
[ ] None [ ] None
______ Percent ______ Percent
3. Denomination of amounts deferred.
I further elect that _____ percentage of all Compensation deferred pursuant
to my election shall be denominated (and any dividend equivalents with
respect thereto denominated) in whole shares of Common Stock of the
Corporation, pursuant to the terms of the Plan, and shall be credited to my
account pursuant to the the terms and conditions of the Plan./1/ I
understand that the balance of all Compensation deferred pursuant to my
election shall be credited to my account and denominated as cash and shall
be credited interest at a rate designated from time to time by the
Administrator, as described in the Plan.
- -----------------
/1/Pursuant to the terms of the Plan, any shares of Common Stock credited to my
account will be "phantom" shares, the purpose of which is merely to
describe an unsecured and unfunded promise to pay the amount credited to my
account.
11
<PAGE>
4. Payment.
All payments, whether denominated in shares of Common Stock or cash, will
be made only in cash.
(a) Method of payment (select one):
_______ Lump sum, or
_______ Installments over a period of ______ years (not over
ten).
(b) Frequency of payments:
If election is made to have payments made in installments, identify
the frequency of installments (select one):
_________ Annually
_________ Quarterly
5. Date of commencement of payments.
Select the date on which payment (in either installments or lump sum)
is to commence (which date shall in no event be after the January 1
following the calendar year in which I reach age 70).
___________________,19___
If no date for commencement of payment is specified above, payment (in
either installments or lump sum) shall commence on the last day of the
month following the date on which I cease to be an Executive.
The foregoing notwithstanding, I understand that except in the case of
death, permanent disability or my ceasing to be an Executive neither I
nor my Beneficiary will receive payment for that portion of my
Account, if any, which has been denominated in shares of Common Stock
for less than six months until at least six months have elapsed since
such portion of my Account was denominated as Common Stock.
Date__________________ Signature ______________________
Notice of Election received by the Administrator:
Date__________________ Signature ______________________
12
<PAGE>
MAXUS ENERGY CORPORATION
DEFERRED COMPENSATION PLAN FOR EXECUTIVES
NOTICE OF TERMINATION
Pursuant to the provision of the Maxus Energy Corporation Deferred Compensation
Plan for Executives (the "Plan"), I hereby terminate my participation in the
Plan effective as of ______________, 19__.
Date ______________ Signature_________________________________
Notice of Termination received by Administrator:
Date ______________ Signature_________________________________
13
<PAGE>
MAXUS ENERGY CORPORATION
DEFERRED COMPENSATION PLAN FOR EXECUTIVES
NOTICE OF BENEFICIARY DESIGNATION
Any amounts credited to my Account under the Maxus Energy Corporation Deferred
Compensation Plan for Executives (the "Plan") unpaid at
my death shall be paid to the following beneficiary or beneficiaries, in the
proportions designated:
____________________ __________% ____________________
Name Proportion Relationship
________________________________________________________
Address
____________________ __________% ____________________
Name Proportion Relationship
________________________________________________________
Address
____________________ __________% ____________________
Name Proportion Relationship
________________________________________________________
Address
This designation supersedes any previous beneficiary designation made by me with
respect to the amounts credited to my Account under the Plan. I hereby reserve
the right to terminate or modify any designation made by this Instrument, at any
time or from time to time.
Date______________________ ____________________________________
Signature
Witness:_____________________________
Designation received by Administrator:
Date______________________ Signature___________________________
14
<PAGE>
Exhibit 12.1
MAXUS ENERGY CORPORATION
STATEMENT COMPUTATION OF RATIOS
(in millions, except ratios)
<TABLE>
<CAPTION>
Twelve Months
Ended
Dec. 31,
1993
----------------
<S> <C>
Earnings:
Net loss ......................................................... ($49.4)
Add:
Extraordinary loss on retirement of debt net
of tax benefit of $.1 7.1
Cumulative effect of change in accounting principle 4.4
Provision for income taxes .................................... 84.2
Interest and debt expenses .................................... 88.4
Other fixed charges (a) ....................................... 4.0
Rentals (b) ................................................... 30.5
------
Total earnings ............................................. $169.2
======
Fixed Charges:
Interest and debt expenses ....................................... $88.4
Rentals .......................................................... 30.5
Capitalized interest ............................................. (7.5)
Proportionate share of fixed charges of
unconsolidated associated companies 50% owned.............. 1.4
------
Total fixed charges ........................................ $112.8
------
Preferred stock dividend requirement (c) ....................... 64.2
------
Combined fixed charges and preferred stock dividends ....... $177.0
======
Ratio of earnings to fixed charges (d)............................... 1.50
Ratio of earnings to combined fixed charges and preferred
stock dividends (e) .............................................. (d)
</TABLE>
(a) Other fixed charges include amortization of capitalized
interest and the proportionate share of fixed charges of
unconsolidated associated companies 50% owned.
(b) The amount shown above for rentals represents that portion of
rental expense representative of the interest factor (which
approximates 45%).
(c) The preferred stock dividend requirement was increased by the
amount representing pre-tax earnings which would be required
to cover such dividend requirement. Due to the mix of foreign
and domestic income and losses, use of the Company's effective
tax rate per the consolidated financial statements yielded
meaningless results. Accordingly, the Company chose the U.S.
statutory federal income tax rate to better reflect the pre-tax
earnings necessary to cover the preferred stock dividend
requirement.
(d) Earnings were inadequate to cover combined fixed charges and
preferred stock dividends for the year ended December 31, 1993
by $7.8 million.
(e) Without $6.8 million income from a lawsuit settlement in 1993,
the ratio of earnings to fixed charges would have been 1.44 and
earnings would have been inadequate to cover combined fixed charges
and preferred stock dividends for the year ended December 31, 1993
by $ 14.6 million.
PAGE 1
<PAGE>
EXHIBIT 13.1
Financial Contents
<TABLE>
<S> <C>
Management's Discussion and Analysis 26
Consolidated Financial Statements:
Operations 33
Balance Sheet 34
Cash Flows 35
Notes to Consolidated Financial Statements 36
Report of Management 50
Report of Independent Accountants 51
Supplementary Information:
Oil and Gas Producing Activities 52
Five-Year Financial Summary 57
Quarterly Data 58
Exploration and Production Statistics 59
</TABLE>
25
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Maxus experienced a number of challenges in 1993, including a significant
reduction in worldwide crude oil prices. At the same time, the Company's
spending increased over previous years. The incremental increase in spending was
primarily associated with the Company's two large development projects--the
Northwest Java gas project and Block 16 development in Ecuador. In Northwest
Java, gas came onstream late in the year as planned. In Ecuador, construction
and development has progressed to the point that first production is on schedule
to begin early this year. After a somewhat difficult start-up period, the Sunray
gas plant reached processing capacity and expected recovery efficiencies late in
the year.
The higher level of spending combined with lower crude prices required that
the Company increase debt above the planned level. However, placing these major
projects onstream as early as practicable was important to the achievement of
the Company's longer-range objectives of becoming profitable, reducing leverage
and increasing value to its shareholders.
Reserve replacement in 1993 was 260% of production at a cost of $3.72 per
barrel. While only one measure of success, continued growth in reserves at an
economical cost is important for the long-term growth in value.
RESULTS OF OPERATIONS
Maxus reported a loss of $49 million in 1993, net income of $74 million in 1992
and a loss of $11 million in 1991. Earnings for 1993 and 1992 included the
following special items:
<TABLE>
<CAPTION>
million of dollars 1993 1992
- -----------------------------------------------
<S> <C> <C>
Net income (loss) before
adjusting for special items $(49) $ 74
Less:
Settlement of litigation 7 121
Extraordinary item (7)
Cummulative effect of change
in accounting principle (4)
-------------
Net loss after adjusting
for special items $(45) $(47)
- -----------------------------------------------
</TABLE>
COMPARISON OF RESULTS
1993 VS. 1992
Sales and Operating Revenues
Sales and operating revenues increased 10% from 1992 levels as a result of
rising U.S. natural gas prices and volumes, partially offset by a drop in
worldwide crude prices, which reached a three-year low. The 1993 average U.S.
gas price of $2.08 per thousand cubic feet ("mcf") was at a three-year high,
producing a $42 million favorable revenue variance. Additionally, sales of
purchased gas volumes rose significantly during 1993. Additional sales volumes
contributed an extra $54 million to revenue. Maxus' 1993 average worldwide crude
price, however, hit a three-year low of $17.28 per barrel, negatively impacting
income by $29 million.
The Company's total net crude oil production, over 90% of which came from
Indonesian operations, was 67 thousand barrels per day ("mbpd") in 1993,
essentially flat compared to 1992. Crude oil volumes decreased in both Southeast
Sumatra and the United States. Marketing constraints during the fourth quarter
of 1993 as well as natural declines were contributing factors in Southeast
Sumatra's $17 million unfavorable volume variance for 1993. Crude oil volumes in
the United States declined from 1992 resulting in a $6 million negative volume
variance, primarily from the loss of volumes due to the divestiture of the
remaining Rocky Mountain properties during 1992. Only Northwest Java had
increased volumes during 1993 ($20 million positive volume variance), reflecting
additional barrels received through cost recovery due to the capital outlay for
the gas project during 1993. With the completion of this phase of the gas
project and reduced spending projected in Northwest Java for 1994, the barrels
received from cost recovery will be lower in 1994.
United States natural gas sales volumes rose from 280 million cubic feet per
day ("mmcfpd") in 1992 to 365 mmcfpd in 1993 with the increase attributable to
additional sales of gas purchased for processing and/or resale. Produced
volumes, however, dropped slightly as a result of natural declines. Increased
volumes of purchased gas are helping to keep the new Sunray gas plant near
maximum capacity, thus increasing plant profitability through higher liquids
recovery. Maxus' United States natural gas prices averaged $2.08 per mcf in 1993
and $1.77 per mcf in 1992.
26
<PAGE>
Natural gas liquids sales in the United States for 1993 were essentially
flat with 1992. Average prices received for natural gas liquids declined to
$11.14 per barrel in 1993 from $11.32 per barrel in 1992. By year-end 1993, the
Sunray gas plant was running at capacity, extracting liquids at 86% recovery
rates. With a full year of operation at the Sunray gas plant, liquids volumes
are expected to increase in 1994.
Costs and Expenses
Costs and expenses were $761 million in 1993 as compared to $674 million in
1992. Gas purchase costs and operating expenses rose the most, while
depreciation, depletion and amortization ("DD&A") continued to decrease.
Operating expenses increased $23 million in 1993. Southeast Sumatra incurred
higher production expenses for well workover and repair and contract vessels, as
well as additional costs associated with repairing a pipeline leak in the Intan
field.
Operating expenses also reflect the adoption, effective January 1, 1993, of
Statement of Financial Accounting Standards No. 106 ("SFAS 106"), "Employers'
Accounting for Postretirement Benefits Other Than Pensions," for its retiree
benefit plans. Under SFAS 106, the Company is required to accrue the estimated
costs of retiree benefit payments, other than pensions, during employees' active
service period. The Company previously expensed the costs of these benefits,
principally medical, as claims were incurred. At January 1, 1993, the estimated
accumulated postretirement benefit obligation was $46 million, which the Company
has elected to amortize over a 20-year period. For 1993, the Company's
postretirement benefit cost was $7 million, a $3 million increase over the 1992
expense, which was recorded using the pay-as-you-go method.
Escalating domestic gas prices as well as additional volumes of gas
purchased for processing and/or resale caused gas purchase costs to increase $90
million from 1992. However, the increased cost was recovered through higher
prices upon sale of the processed gas and natural gas liquids.
DD&A declined $21 million from 1992. Maxus has continued to experience a
favorable trend in DD&A rates largely due to success in finding and developing
low-cost reserves. Additionally, decreased production volumes in Indonesia and
the United States contributed to the lower overall DD&A for 1993. The Company's
five-year average finding and development cost is $4.07 per barrel. The DD&A
rate during this same five-year period has declined from $5.38 to $3.32 per
barrel.
Settlement of Litigation
In November 1992, the Company settled a lawsuit with Ivan Boesky arising out of
transactions related to the acquisition of Natomas Company in 1983. In June
1993, the Company received $7 million from Mr. Boesky, which was recorded as
income, net of legal costs.
Other Revenues, Net
Other revenues, net were approximately $2 million higher in 1993 compared to
1992. Maxus recorded higher interest income and gains on the sale of its
investment in U.S. Treasury notes and other securities in 1993, which was offset
by an increase of $12 million in environmental accruals.
Income Taxes
The Company's provision for income taxes in 1993 was comprised almost entirely
of Indonesian taxes.
The provision for income tax decreased $18 million in 1993 compared to 1992,
despite a $3 million increase in operating profit before the non-taxable
litigation settlements. The provision for income taxes decreased primarily due
to lower taxable Indonesian income, partially offset by lower foreign
exploratory expenses, which had no tax effect.
In January 1993, the Company adopted Statement of Financial Accounting
Standards No. 109 ("SFAS 109"), "Accounting for Income Taxes." The adoption,
which was made prospectively, had no impact on current period earnings or cash
flow; however, $21 million of deferred tax liabilities which were considered
current under SFAS 96 were reclassified as noncurrent and $4 million of deferred
tax assets were reported as current assets.
Change in Accounting Principle
In the fourth quarter of 1993, Maxus adopted, retroactive to January 1, 1993,
Statement of Financial Accounting Standards No. 112, "Employers' Accounting for
Postemployment Benefits," which requires an accrual method of recognizing
postemployment benefits. Prior to 1993, postemployment benefit expenses were
recognized on a pay-as-you-go basis. The Company
27
<PAGE>
recognized a one-time charge of $4 million to recognize the cumulative effect of
the change in accounting for post-employment benefits. This liability primarily
represents medical benefits for long-term disability recipients.
Extraordinary Item
During 1993, the Company recorded an extraordinary loss of $7 million after tax,
representing call premium and unamortized issuance costs, for the early
retirement of debt. Approximately $115 million of outstanding 11 1/4% sinking
fund debentures were redeemed at 105.329% of the principal amount.
COMPARISON OF RESULTS
1992 VS. 1991
Sales and Operating Revenues
Sales and operating revenues decreased 9% from the record high sales revenues
recorded in 1991 as a result of the decline in prices and volumes. During 1992,
prices for crude and natural gas liquids dropped while natural gas prices
increased. The impact of the price declines in crude oil and natural gas liquids
($18 million negative price variance) was further compounded by declining crude
oil volumes in Indonesia and the United States, which were only partially offset
by modest increases in United States natural gas and natural gas liquids
volumes. The lower volumes were responsible for $54 million of the revenue
decline from 1991 to 1992.
The Company's net crude oil production, 92% of which came from Indonesian
operations, was 68 mbpd in 1992, a decrease of 12% from 1991. Crude oil volumes
decreased in both Southeast Sumatra and the United States. Crude oil volumes in
the United States declined from 1991 resulting in a $29 million negative volume
variance. Several factors contributed to this decline, primarily the loss of
volumes due to the sale of the Rocky Mountain and Permian Basin properties
during 1991, shut-in production during Hurricane Andrew and natural declines.
Only Northwest Java achieved increased volumes during 1992 ($14 million positive
volume variance), reflecting a full year of operation of the BZZA field, which
commenced production in August 1991. Average worldwide crude oil price was
$18.39 per barrel in 1992, a decrease of $1.19 per barrel from 1991, resulting
in a $29 million negative price variance compared to 1991.
During 1992, United States natural gas sales increased 12 mmcfpd from the
1991 level as a result of additional volumes purchased for resale. Spot market
prices during 1992 averaged $1.77 per mcf, compared to $1.63 per mcf in 1991.
Costs and Expenses
Costs and expenses were $674 million in 1992, a 1% decrease from 1991. Although
total costs and expenses were relatively flat over 1991 levels, the offsetting
variance can be traced to gas purchase costs and DD&A. Gas purchase costs
increased $21 million over the comparable period in 1991. Escalating domestic
gas prices increased the cost of natural gas purchased for processing and resale
($21 million unfavorable variance); however, this cost increase was recovered
through higher prices upon sale of the processed gas and natural gas liquids.
DD&A decreased $29 million from 1991. Similar to the 1992 to 1993 trend,
Maxus experienced decreased DD&A rates through lower finding and development
costs. Additionally, decreased production volumes in Southeast Sumatra and the
United States resulted in lower overall DD&A for 1992.
Settlement of Litigation
In October 1992, Maxus settled its lawsuit against Kidder Peabody arising out of
transactions related to the acquisition of Natomas Company in 1983. Under the
terms of the settlement, the Company received $165 million in cash, a portion of
which represented payment for warrants to acquire eight million shares of Common
Stock of the Company at a price of $13 per share for a period of five years. The
fair market value of the warrants ($10 million) was recorded as an increase to
paid-in capital; the remainder of the settlement ($155 million) was recorded as
income, net of legal costs. The settlement was not taxable for federal income
tax purposes.
In 1992, the Company recorded a $20 million non-cash write-off of a
receivable related to an unfavorable New Jersey appellate court ruling that a
war risk exclusion in certain of the Company's insurance policies precluded
recovery from insurance carriers of an earlier settlement of claims by Vietnam
veterans concerning Agent Orange. The Company had previously recorded the
expected recovery as a receivable.
28
<PAGE>
Income Taxes
The Company's provision for income taxes in 1992 and 1991 was comprised almost
entirely of Indonesian taxes.
Worldwide operating profit before the non-taxable Kidder Peabody settlement
decreased $83 million in 1992 compared to 1991 and the provision for income
taxes decreased $28 million. This was primarily due to lower taxable Indonesian
income. Additionally, foreign exploratory spending was higher in 1992 but
generated no corresponding tax benefit.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity refers to the ability of an enterprise to generate adequate amounts of
cash to satisfy its financial needs. Maxus' primary needs for cash are to fund
its exploration and development program, service debt, pay existing trade
obligations, meet redemption obligations on redeemable preferred stock and pay
dividends to preferred stockholders. The Company's primary sources of liquidity
have been from operating activities, asset sales, debt financing and equity
issuances. In the Company's opinion, adequate cash from operations, asset sales
and project financing will be available to fund a significantly reduced program
spending budget in 1994, service debt and pay dividends and trade obligations.
Existing cash balances will meet the February 1994 preferred stock redemption
requirements.
The Company's current ratio (the relationship between current assets and
current liabilities) for 1993 increased to 1.5 from 1.2 at year-end 1992. Cash
and cash equivalents increased as did the Indonesian underlift receivable, and
the short-term portion of restricted cash. The current portion of deferred tax
was eliminated upon the adoption of SFAS 109. Offsetting these favorable
variances, short-term investments, net of repurchase agreements, declined as the
Company liquidated some of its investment in United States Treasury notes. Also,
the Company reclassified the current portion of certain debt from long-term to
short-term.
Operating Activities
Net cash provided by operating activities totaled $137 million and $297 million
in 1993 and 1992, respectively. Excluding the Boesky and Kidder Peabody
settlements, net cash provided by operating activities would have been $130
million in 1993 and $151 million in 1992. Net cash provided by operating
activities, before the change in working capital, was relatively flat from year
to year. Falling worldwide crude prices and sales volumes negatively impacted
Maxus during 1993, but the impact was mostly offset by the $.31 per mcf
favorable increase in the price of natural gas. Additionally, working capital
requirements increased $19 million during 1993 mainly due to voluntary
production curtailments in Indonesia during the fourth quarter of 1993. The
Company recorded an underlift receivable compared to an overlift liability in
1992.
Excluding the Kidder Peabody settlement, net cash provided by operating
activities in 1992 would have been $151 million, significantly less than the
$238 million provided in 1991. The $87 million decline resulted in part from
lower worldwide oil sales volumes and prices. Additionally, net cash provided by
operating activities was negatively impacted ($33 million) by working capital
requirements. The decrease was largely attributable to the payment of Indonesian
crude oil obligations in 1992.
Investing Activities
The Company concentrated its 1993 spending efforts on international operations,
with almost 80% of the capital spending budget being associated with non-United
States operations. Two large development projects, Northwest Java gas project
and Block 16 in Ecuador, alone accounted for an additional $117 million of
spending in 1993. The Northwest Java gas project was completed on time and
within budget in the fourth quarter of 1993. First production from Ecuador will
begin in early 1994. Maxus also continued to develop its reserves in Bolivia.
Additionally, construction of the Sunray gas plant in the Texas Panhandle, which
was started in mid-1991, was completed during first quarter 1993. After a
longer-than-expected start-up period, the Sunray gas plant achieved full
operating efficiency in late 1993.
29
<PAGE>
The development of the gas reserves in Northwest Java combined with the
assumption of operatorship and additional interest in the development of the
Ecuador reserves accounted for much of the Company's international capital
spending during 1992. Domestically, the Company focused its spending on the
Sunray gas plant, while continuing limited spending for property acquisition,
exploration and development.
During 1991, Maxus realigned its United States property base and increased
its property concentration in Texas, Oklahoma and Louisiana through property
acquisitions totaling $96 million. Partially funding the purchases was $69
million of proceeds from the sale of the Rocky Mountain and Permian Basin
properties.
The Company received approximately $111 million of cash during 1991, 1992
and 1993 from the sale of non-strategic United States oil and gas properties.
Maxus substantially increased its short-term investments during 1992, with
the purchase of approximately $121 million in United States Treasury notes,
which were to be held to partially fund the capital program budget and cover
working capital fluctuations during 1993. In 1993, the Company purchased an
additional $52 million of United States Treasury notes and subsequently sold
$142 million of the total balance realizing a gain of $8 million. Additionally,
during 1993, Maxus received stock and other securities from LTV in settlement of
its bankruptcy claims against LTV. The Company sold these securities for
approximately $22 million, realizing a $2 million gain during fourth quarter
1993.
Effective October 1992, Maxus terminated its $150 million bank revolving
credit agreement ("Credit Agreement"), which historically had been used to
provide backing for letters of credit. Upon termination of the Credit Agreement,
the Company restricted $94 million as cash collateral for outstanding letters of
credit. During 1993, the Company restricted an additional $36 million as cash
collateral for its spending commitment in Venezuela. The Company has signed a
letter of intent with a partner to reduce our interest to 50% subject to
Venezuelan government approval. When finalized, the $36 million in restricted
cash backing the letters of credit in Venezuela is anticipated to be released.
The restricted cash balance will also be reduced an additional $36 million
during 1994 primarily from the release of letters of credit supporting the
Ecuadorian development project. This release is based on 1993 spending levels.
Financing Activities
Over the three-year period from 1991 to 1993, Maxus has taken steps to
restructure its debt and equity position. The overall intent was to provide
immediate funding for its major development and construction projects (the
Sunray gas plant, the Northwest Java gas project and the development of Block 16
in Ecuador) and to match the repayment schedules of the debt with the future
cash flow expected from the projects while maintaining necessary working capital
balances required for flexibility. The Company was able to take advantage of
lower interest rates and, at the same time, the average debt maturities were
extended.
The 1991 financing activities resulted in minimal debt increases with cash
from operations virtually covering the Company's investing activities. While net
debt (after consideration of all cash and cash equivalents plus short-term
investments, net of securities sold under repurchase agreements and restricted
cash) declined in 1992, the gross debt went up slightly. Since the Company's
election to terminate its Credit Agreement in 1992, net sources of cash from
financing have been required to fund certain letters of credit (recorded as
Restricted Cash) and to maintain minimum working capital levels which were held
in short-term investments. The 1992 financing activity also included a Common
Stock offering which netted Maxus $179 million.
Unlike 1991 and 1992, debt rose significantly in 1993. The completion of two
of the major projects and the near completion of the initial phase of the
Ecuador project contributed to the substantial increase in the Company's 1993
capital expenditures as compared to 1991 and 1992 levels. To cover the shortfall
between cash from operations and the cash used in investing activities,
incremental new debt was issued. Of the $413 million proceeds received in 1993
from the issuance of long-term debt, $204 million was used to refinance
currently maturing debt and to fund the early retirement of a portion of the
Company's 11 1/4% sinking fund debentures, with the remainder partially funding
the 1993 capital program.
30
<PAGE>
In addition to the 1993 debt activity, Maxus issued a new class of $2.50
Preferred Stock. Of the $85 million in net proceeds received from the offering,
$63 million was used to redeem 625,000 shares of Maxus' $9.75 Preferred Stock as
required in February of 1994. The details of the various debt and equity
offerings over the three-year period are outlined in the Notes to the
Consolidated Financial Statements.
In 1994, the Company intends to continue refinancing its maturing debt with
longer-term debt instruments without adding new incremental debt except for that
which may be obtained through specific project financing. Specifically, in
January 1994, Maxus issued $60 million of 9 3/8% notes due in 2013, the
proceeds of which will be used to redeem medium-term notes with maturities as
short as nine months.
The Company's target for the ratio of net debt to total market
capitalization is still 30% after consideration of all cash and cash equivalents
plus short-term investments, net of securities sold under repurchase agreements
and restricted cash. This ratio was 40% in 1991, 30% in 1992 and 37% in 1993.
The increase in 1993 was necessary to provide funding for major development
projects which are expected to provide future additional cash flow. With these
projects on stream, Maxus expects to fund 1994 activities with cash from
operations and asset sales, supplemented by project financing for certain
international projects.
ENVIRONMENTAL MATTERS
Like other energy companies, Maxus' operations are subject to various laws
related to the handling and disposal of hazardous substances which require the
cleanup of deposits and spills. Compliance with the laws and protection of the
environment worldwide is of the highest priority to Maxus management. In
1993, the Company spent $15 million for the installation of environmental-
control equipment for its oil and gas operations (mainly attributable to the
Sunray gas plant and to the development phase of Block 16 in Ecuador).
Expenditures in 1994 are expected to be approximately $9 million.
In addition, the Company is implementing certain environmental projects
related to its former chemicals business ("Chemicals") sold to Occidental
Petroleum Corporation in 1986 and certain other disposed of businesses.
The Company will be implementing remediation at the former agricultural
chemical plant in Newark, New Jersey as required by a consent decree entered
into in November 1990 with the United States Environmental Protection Agency
(the "EPA") and the New Jersey Department of Environmental Protection and Energy
(the "DEP"). The Company has recently agreed with the EPA to conduct further
testing and studies to characterize contaminated sediment in a six-mile portion
of the Passaic River near the plant site. The Company has been conducting
similar studies under its own auspices for several years.
Under an Administrative Consent Order issued by the DEP in April 1990
covering sites in Kearny and Secaucus, New Jersey, the Company will continue to
implement interim remedial actions and to perform remedial investigations and
feasibility studies and, if necessary, implement additional remedial actions at
various locations where chromite ore residue, allegedly from the former Kearny
plant, was utilized, as well as at the plant site.
Until 1976, Chemicals operated manufacturing facilities in Painesville,
Ohio. The Company has heretofore conducted many remedial, maintenance and
monitoring activities at this site. The former Painesville plant area has been
proposed for listing on the national priority list of Superfund sites. The scope
and nature of further investigation or remediation which may be required cannot
be determined at this time.
In the opinion of the Company, environmental remediation has been
substantially completed at all other former plant sites where material
remediation is required.
The Company also has responsibility for Chemicals' share of the remediation
cost for a number of other non-plant sites where wastes from plant operations by
Chemicals were allegedly disposed of or have come to be located including
several commercial waste disposal sites.
31
<PAGE>
At the time of the spin-off, by the Company of Diamond Shamrock, Inc.
("DSI") in 1987, the Company executed a cost-sharing agreement for the partial
reimbursement by DSI of environmental expenses related to the Company's disposed
of businesses, including Chemicals.
The Company's total expenditures for environmental compliance for disposed
of businesses, including Chemicals, was $36 million in 1993, $11 million of
which was recovered from DSI under the cost-sharing agreement. Those
expenditures are projected to be approximately $21 million in 1994 after
recovery from DSI.
Reserves, net of cost-sharing by DSI, have been established for
environmental liabilities where they are material and probable and can be
reasonably estimated. At December 31, 1993 and 1992, the reserve balance was $38
million and $28 million, respectively.
FUTURE OUTLOOK
While 1993 was difficult, it was also rewarding as Maxus is now positioned to
realize the cash flow benefits from some of its past successes. Fluctuations in
prices, including crude prices, which are currently at a four-year low, will
impact those cash flows.
The Company has reassessed its business plan for 1994 in response to the
current industry conditions. As a result, Maxus' 1994 program spending
requirements have been greatly reduced. The 1994 program provides for
concentration in core areas of the United States and Indonesia through
development, exploration or acquisition plus evaluation and development of the
emerging areas: Block 16 in Ecuador, the Mamore Block in Bolivia and the
Quiriquire Block in Venezuela. The Company is committed to reducing expenditures
for activities outside these areas.
Total program spending (capital expenditures plus exploration expenses) for
1994 has been lowered to $212 million as compared to the $391 million in 1993.
The spending is almost evenly distributed between the United States, Southeast
Sumatra, Northwest Java and South America with only a small remainder for
exploration in other areas.
Substantially all funding for the 1994 spending program is expected to be
provided through cash and cash equivalents on hand at the beginning of the year
and expected cash from operations. Any shortfall in cash will be supplemented by
selected sales of assets, project financing or from reduced spending
requirements on certain international concessions by taking a partner.
In addition to the 1994 program, Maxus has financial and/or performance
commitments for exploration and development activities in 1995 and beyond which
are not material.
As with all international energy companies, Maxus is subject to political
and economic uncertainties as well as the risk inherent in the exploration for
oil and gas reserves. The current business environment requires that a company
must be able to adapt and continually reassess its position. To that end, Maxus
is undertaking an in-depth analysis of its cost and organizational structure to
assure financial success in the future.
32
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31, 1993 1992 1991
- --------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues
Sales and operating revenues $786.7 $718.4 $790.8
Settlement of litigation 6.8 120.8
Other revenues, net 13.5 11.9 12.2
- ---------------------------------------------------------------------------------------
807.0 851.1 803.0
Costs and Expenses
Operating expenses 255.6 232.4 230.1
Gas purchase costs 155.6 65.5 44.3
Exploration, including exploratory dry holes 56.8 64.6 66.5
Depreciation, depletion and amortization 153.6 174.4 203.6
General and administrative expenses 34.8 34.7 34.1
Taxes other than income taxes 15.9 15.9 17.1
Interest and debt expenses 88.4 86.9 88.4
--------------------------
760.7 674.4 684.1
--------------------------
Income Before Income Taxes, Extraordinary Item
and Cumulative Effect of Change in Accounting Principle 46.3 176.7 118.9
Income Taxes 84.2 102.5 130.1
--------------------------
Net Income (Loss) Before Extraordinary Item
and Cumulative Effect of Change in Accounting Principle (37.9) 74.2 (11.2)
Extraordinary item, net of tax benefit of $.1 (7.1)
Cumulative effect of change in accounting principle (4.4)
--------------------------
Net Income (Loss) (49.4) 74.2 (11.2)
Dividend requirement on Preferred Stock (41.7) (41.7) (41.7)
--------------------------
Income (Loss) Applicable to Common Shares $(91.1) $ 32.5 $(52.9)
==========================
Net Income (Loss) per Common Share
Before Extraordinary Item and
Cumulative Effect of Change in Accounting Principle $ (.60) $ .27 $ (.52)
Extraordinary item (.05)
Cumulative effect of change in accounting principle (.03)
--------------------------
Net Income (Loss) Per Common Share (.68) $ .27 $ (.52)
============================
Average Common Shares Outstanding 133.9 119.6 100.8
</TABLE>
See Notes to Consolidated Financial Statements.
33
<PAGE>
CONSOLIDATED BALANCE SHEET (in millions)
<TABLE>
<CAPTION>
December 31, 1993 1992
- -------------------------------------------------------------------------------
<S> <C> <C>
Assets
Current Assets
Cash and cash equivalents $ 128.7 $ 6.8
Short-term investments 33.6 210.7
Receivables, less doubtful receivables 156.8 135.0
Restricted cash 38.4
Inventories 24.1 22.5
Deferred income taxes 2.1
Prepaids and other current assets 21.0 16.2
----------------------
Total Current Assets 404.7 391.2
Properties and Equipment, less accumulated depreciation
and depletion 1,305.6 1,138.3
Investments and Long-Term Receivables 94.2 87.5
Restricted Cash 121.8 124.7
Intangible Assets, less accumulated amortization 37.1 38.3
Deferred Charges 24.0 31.6
----------------------
$1,987.4 $1,811.6
======================
- -------------------------------------------------------------------------------
Liabilities and Stockholders' Equity
Current Liabilities
Long-term debt $ 39.7 $ .1
Securities sold under repurchase agreements 88.0
Accounts payable 99.9 90.3
Accrued liabilities 107.7 103.6
Taxes payable 16.1 24.9
Deferred income taxes 21.0
----------------------
Total Current Liabilities 263.4 327.9
Long-Term Debt 1,015.4 829.3
Deferred Income Taxes 198.3 152.9
Other Liabilities and Deferred Credits 112.4 79.9
Redeemable Preferred Stock, $1.00 par value
Authorized and issued shares-2,500,000 250.0 250.0
Stockholders' Equity (Deficit)
$2.50 Preferred Stock, $1.00 par value
Authorized shares-5,000,000
Issued shares-3,500,000 3.5
$4.00 Preferred Stock, $1.00 par value
Authorized shares-5,915,017 and 4,565,017
Issued shares-4,358,658 and 4,334,858 4.4 4.3
Common Stock, $1.00 par value
Authorized shares-300,000,000
Issued shares-134,373,523 and 133,567,300 134.4 133.6
Paid-in capital 1,026.2 980.1
Accumulated deficit (993.7) (944.3)
Minimum pension liability (24.4)
Common Treasury Stock, at cost-173,963 and 135,751
shares (2.5) (2.1)
----------------------
Total Stockholders' Equity 147.9 171.6
----------------------
$1,987.4 $1,811.6
======================
</TABLE>
See "Commitments and Contingencies."
See Notes to Consolidated Financial Statements.
The Company uses the successful efforts method to account for its oil and gas
producing activities.
34
<PAGE>
CONSOLIDATED STATEMENT OF CASH FLOWS (in millions)
<TABLE>
<CAPTION>
Year Ended December 31, 1993 1992 1991
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Flows From Operating Activities:
Net income (loss) $ (49.4) $ 74.2 $ (11.2)
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
Extraordinary item 7.1
Cumulative effect of change in accounting principle 4.4
Depreciation, depletion and amortization 153.6 174.4 203.6
Dry hole costs 5.7 12.9 17.5
Write-off of insurance receivable 19.6
Income taxes 22.3 3.6 (7.6)
Interest expense on zero-coupon convertible notes 8.4
Net gain on sales of assets (13.8) (3.7) (9.0)
Postretirement benefits 6.6
Other 33.0 29.8 16.7
Changes in components of working capital:
Receivables (21.5) (12.8) 23.3
Inventories, prepaids and other current assets (6.4) (2.2) 4.9
Accounts payable 9.0 (2.1) (12.4)
Accrued liabilities (5.2) 30.5 (15.4)
Taxes payable (8.8) (5.4) (2.9)
Deferred revenue (21.7) 21.7
-------------------------------
Net cash provided by operating activities 136.6 297.1 237.6
- ----------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities:
Expenditures for properties and equipment-including dry hole costs (340.0) (261.1) (272.3)
Expenditures for investments (20.4) (21.4) (17.4)
Proceeds from sales of assets 20.4 14.1 76.6
Proceeds from sale/maturity of short-term investments 171.3 32.7 20.2
Purchases of short-term investments (53.1) (146.7) (22.2)
Restricted cash (35.5) (104.5) (4.2)
Other (20.4) (6.9) (14.0)
-------------------------------
Net cash used in investing activities (277.7) (493.8) (233.3)
- ----------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities:
Net borrowings from joint venture partners 4.4
Proceeds from issuance of short-term debt 38.5
Repayment of short-term debt (32.7) (.1) (.2)
Proceeds from issuance of long-term debt 412.5 332.0 210.2
Repayment of long-term debt (203.7) (291.9) (196.4)
Proceeds from issuance of Common Stock 178.9 17.0
Proceeds from issuance of Preferred Stock 85.7
Proceeds from issuance of Stock Warrants 10.0
Dividends paid (41.7) (41.7) (41.7)
-------------------------------
Net cash provided by (used in) financing activities 263.0 187.2 (11.1)
-------------------------------
Net increase (decrease) in cash and cash equivalents 121.9 (9.5) (6.8)
Cash and cash equivalents at beginning of year 6.8 16.3 23.1
-------------------------------
Cash and cash equivalents at end of year $ 128.7 $ 6.8 $ 16.3
===============================
</TABLE>
See Notes to Consolidated Financial Statements.
35
<PAGE>
Notes to Consolidated Financial Statements
Data is as of December 31 of each year or for the year then ended and dollar
amounts in tables are in millions, except per share. Certain data for 1992 and
1991 has been reclassified to conform with the 1993 presentation.
NOTE ONE
SIGNIFICANT ACCOUNTING POLICIES
The Consolidated Financial Statements have been prepared in conformity with
generally accepted accounting principles, the most significant of which are
described below.
Consolidation and Equity Accounting
The Consolidated Financial Statements include the accounts of Maxus Energy
Corporation and all domestic and foreign subsidiaries (the "Company"). The
Company uses the equity method to account for its less than 50% owned
investments in affiliates and joint ventures ("Associated Companies") and the
proportionate consolidation method to account for its investment in Diamond
Shamrock Offshore Partners Limited Partnership ("Offshore Partners"). Under the
equity method, the Company recognizes its proportionate share of the net income
or loss of Associated Companies currently, rather than when realized through
dividends or disposal. All significant intercompany accounts and transactions
have been eliminated.
Statement of Cash Flows
Investments with maturities of three months or less at the time of acquisition
are considered cash equivalents for purposes of the accompanying Consolidated
Statement of Cash Flows. Short-term investments include U.S. Treasury notes and
investments with maturities over three months but less than one year. The
Company also enters into agreements to sell and repurchase U.S. Treasury
notes. The liabilities to repurchase securities sold under these agreements are
reported as current liabilities and the investments acquired with the funds
received from the securities sold are included in short-term investments.
Net cash provided by operating activities reflects cash receipts for
interest income and cash payments for interest expense and income taxes as
follows:
<TABLE>
<CAPTION>
1993 1992 1991
- --------------------------------------------------------
<S> <C> <C> <C>
Interest income $11.3 $ 6.4 $ 1.7
Interest expense 82.0 80.9 78.0
Income taxes 73.4 104.1 143.1
- --------------------------------------------------------
</TABLE>
Inventory Valuation
Inventories, consisting primarily of oil and gas tubular goods and supplies, are
valued at the lower of cost or market, cost being determined primarily by the
weighted average cost method.
Properties and Equipment
Properties and equipment are carried at cost. Major additions are capitalized;
expenditures for repairs and maintenance are charged against earnings.
The Company uses the successful efforts method to account for costs incurred
in the acquisition, exploration, development and production of oil and gas
reserves. Under this method, all geological and geophysical costs are expensed;
all development costs, whether or not successful, are capitalized as costs of
proved properties; exploratory drilling costs are initially capitalized, but if
the effort is determined to be unsuccessful, the costs are then charged against
earnings; depletion is computed based on an aggregation of properties with
common geologic structural features or stratigraphic conditions, such as
reservoirs or fields; and for unproved properties, both onshore and offshore, a
valuation allowance (included as an element of depletion) is provided by a
charge against earnings to reflect the impairment of unproven acreage.
Depreciation and depletion related to the costs of all development drilling,
successful exploratory drilling and related production equipment is calculated
using the unit of production method based upon estimated proved recoverable
reserves. Other properties and equipment are depreciated generally on the
straight-line method over their estimated useful lives. Intangible assets are
amortized on the straight-line method over their legal or estimated useful
lives, not to exceed 40 years.
The Company capitalizes the interest cost associated with major property
additions and mineral development projects while in progress, such amounts being
amortized over the useful lives of the related assets.
36
<PAGE>
Pensions
The Company has a number of trusteed noncontributory pension plans covering
substantially all full-time employees. The Company's funding policy is to
contribute amounts to the plans sufficient to meet the minimum funding
requirements under governmental regulations, plus such additional amounts as
management may determine to be appropriate. The benefits related to the plans
are based on years of service and compensation earned during years of
employment. The Company also has a noncontributory supplemental retirement plan
for executive officers.
Other Postretirement
and Postemployment Benefits
The Company provides certain health care and life insurance benefits for retired
employees and certain insurance and other postemployment benefits for
individuals whose employment is terminated by the Company prior to their normal
retirement. Effective January 1, 1993, the Company adopted Statement of
Financial Accounting Standards No. 106 ("SFAS 106"), "Employers Accounting for
Postretirement Benefits Other Than Pensions," to account for its retiree
benefits plan. Under SFAS 106, the Company is required to accrue the estimated
cost of retiree benefit payments, other than pensions, during employees' active
service period. Employees become eligible for these benefits if they meet
minimum age and service requirements. Also in 1993, the Company adopted
Statement of Financial Accounting Standards No. 112 ("SFAS 112"), "Employers
Accounting for Postemployment Benefits," to account for benefits provided after
employment but before retirement. Under SFAS 112, the Company is required to
accrue the estimated cost of postemployment benefits when the minimum service
period is met, payment of the benefit is probable and the amount of the benefit
can be reasonably estimated. The Company previously expensed the cost of
postretirement and postemployment benefits as claims were incurred.
Environmental Expenditures
Environmental liabilities are recorded when environmental assessments and/or
remediation are probable and material and such costs to the Company can be
reasonably estimated.
Income Taxes
In January 1993, the Company adopted Statement of Financial Accounting Standards
No. 109 ("SFAS 109"), "Accounting for Income Taxes." SFAS 109 requires the use
of an asset and liability approach to measure deferred tax assets and
liabilities resulting from the expected future tax consequences of events that
have been recognized in the Company's financial statements or tax returns. In
estimating future tax consequences, SFAS 109 generally considers all expected
future events. Previously, the Company reported income taxes under SFAS 96. That
standard required the use of an asset and liability approach which gave no
recognition to future events other than the recovery of assets and settlement of
liabilities at their carrying amounts.
Earnings per Share
Primary earnings per share are based on the weighted average number of shares of
common stock and common stock equivalents outstanding, unless the inclusion of
common stock equivalents has an antidilutive effect on earnings per share. Fully
diluted earnings per share are not presented due to the antidilutive effect of
including all potentially dilutive common stock equivalents.
Financial Instruments with Off-Balance-Sheet
Risk and Concentrations of Credit Risk
The Company's financial instruments that are exposed to concentrations of credit
risk consist primarily of cash equivalents, short-term investments and trade
receivables.
The Company's cash equivalents and short-term investments represent high-
quality securities placed with various high investment grade institutions. This
investment practice limits the Company's exposure to concentrations of credit
risk.
The trade receivables are dispersed among a broad domestic and international
customer base, therefore, concentrations of credit risk are limited. The Company
carefully assesses the financial strength of its customers. Letters of credit
are the primary security obtained to support lines of credit.
37
<PAGE>
Hedging and Futures Contracts
The Company periodically hedges the effects of fluctuations in the price of
natural gas through price swap agreements. Gains and losses on these hedges are
deferred until the related sales are recognized. The Company periodically enters
into interest rate swap agreements to hedge interest on long-term debt. The gain
or loss on interest rate swaps are recognized monthly as an increase or decrease
to interest expense. The Company also enters into futures contracts that are not
specified as hedges. The gains or losses on these contracts are recognized on a
mark-to-market basis.
NOTE TWO
MASTER LIMITED PARTNERSHIP
Offshore Partners is a master limited partnership which explores for and
produces natural gas and crude oil on federal offshore leases in the Gulf of
Mexico off Texas and Louisiana. Maxus Offshore Exploration Company, a wholly
owned subsidiary of the Company, and the Company have a combined 1% general
partner's interest in Offshore Partners and are the managing general partner and
special general partner, respectively. The Company had an aggregate interest in
Offshore Partners of approximately 87.1% at December 31, 1993 and 1992.
NOTE THREE
Settlement of Litigation
In October 1992, the Company settled its lawsuit against Kidder, Peabody & Co.
Incorporated ("Kidder Peabody") arising out of transactions related to the
acquisition of Natomas Company in 1983. Under the terms of the settlement, the
Company received $165.0 million in cash, a portion of which represented payment
for warrants to acquire eight million shares of common stock of the Company at a
price of $13.00 per share for a period of five years. The fair market value of
the warrants ($10.0 million) was recorded as additional paid-in capital; the
remainder of the settlement ($155.0 million) was recorded as income, net of
legal costs. None of the settlement proceeds were taxable for federal income tax
purposes.
In November 1992, the Company settled a lawsuit with Ivan Boesky, also
arising out of transactions related to the acquisition of Natomas Company. In
June 1993, the Company received $7.0 million from Mr. Boesky, which was recorded
as income, net of legal costs.
On April 6, 1992, a New Jersey appellate court ruled that a war risk
exclusion in certain of the Company's insurance policies precluded recovery from
insurance carriers of an earlier settlement of claims by Vietnam veterans
concerning Agent Orange. The Company had previously recorded the expected
recovery as a $19.6 million receivable. Included in "Settlement of litigation"
for 1992 is the non-cash write-off of this receivable.
NOTE FOUR
ASSET ACQUISITIONS AND DIVESTITURES
In November of 1993, the Company transferred its working interest in the Recetor
Block in Colombia to its partner for partial recoupment of its investment. Maxus
received $10.0 million and retained an overriding royalty interest. There was no
gain or loss recognized on this transaction.
In October 1993, the Company and its Venezuelan partner, Otepi Consultores,
S.A., were awarded an operating service agreement to reactivate Venezuelan oil
fields with Lagoven, S.A., an affiliate of the national oil company, Petroleos
de Venezuela, S.A. Under the terms of the operating service agreement, Maxus
will be a contractor for Lagoven and will be responsible for overall operations
of the Quiriquire Unit, including all necessary investments to reactivate the
fields comprising the unit. Maxus will receive a fixed fee in U.S. dollars for
each barrel of crude oil produced and will be reimbursed in U.S. dollars for its
capital expenditures, provided that such fee and expense reimbursement cannot
exceed the maximum dollar amount per barrel set forth in the agreement. The
Venezuelan government will retain full ownership of all hydrocarbons in the
field.
Effective March 1, 1992, the Company sold its remaining producing oil and
gas interests in the Rocky Mountain area of the United States for $8.4 million,
realizing a gain on the sale of $4.9 million.
Effective July 1, 1991, the Company sold oil and gas interests in non-
strategic United States properties for $69.1 million, realizing a gain on the
sale of $7.5 million.
In May 1991, the Company purchased various oil and gas properties located in
the Texas and Oklahoma Panhandles for $52.4 million. In July 1991, Offshore
Partners acquired interests in producing oil and gas leases offshore Louisiana
for $29.0 million funded in part by the Company's $21.0 million acquisition of
units of limited partnership interest in Offshore Partners.
38
<PAGE>
NOTE FIVE
GEOGRAPHIC DATA
The Company is engaged primarily in the exploration for and the production and
sale of crude oil and natural gas.
Sales, operating profit and identifiable assets by geographic area were as
follows:
<TABLE>
<CAPTION>
Sales and Operating Revenues
1993 1992 1991
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
United States $ 380.7 $ 294.2 $ 303.4
Indonesia 406.0 424.2 487.4
-------------------------------------------
Sales and operating revenues $ 786.7 $ 718.4 $ 790.8
- -------------------------------------------------------------------------------
Operating Profits
1993 1992 1991
- -------------------------------------------------------------------------------
United States $ 39.3 $ 52.7 $ 42.0
Indonesia 169.1 188.4 244.0
South America (13.0) (11.4) (5.6)
Other Foriegn (20.4) (31.8) (18.1)
-------------------------------------------
175.0 197.9 262.3
Equity earnings 10.2 8.7 1.0
General corporate income and
expenses (50.5) 57.0 (56.0)
Interest and debt expenses (88.4) (86.9) (88.4)
-------------------------------------------
Operating profit $ 46.3 $ 176.7 $ 118.9
- -------------------------------------------------------------------------------
Identifiable Assets
1993 1992 1991
- -------------------------------------------------------------------------------
United States $ 521.1 $ 535.6 $ 546.3
Indonesia 665.5 597.2 565.7
South America 218.9 74.8 15.2
Other Foreign 3.9 6.1 11.3
-------------------------------------------
1,409.4 1,213.7 1,138.5
Corporate assets 489.7 521.9 251.2
Investments in Associated
Companies 88.3 76.0 61.8
-------------------------------------------
Identifiable assets $1,987.4 $1,811.6 $1,451.5
- -------------------------------------------------------------------------------
</TABLE>
Net foreign assets were $673.5 million at December 31, 1993, $507.9 million at
December 31, 1992 and $409.1 million at December 31, 1991.
Results of foreign operations, after applicable local taxes, amounted to net
income of $77.8 million in 1993, $78.1 million in 1992 and $112.4 million in
1991.
The Company's foreign petroleum exploration, development and production
activities are subject to political and economic uncertainties, expropriation of
property and cancellation or modification of contract rights, foreign exchange
restrictions and other risks arising out of foreign governmental sovereignty
over the areas in which the Company's operations are conducted.
Sales to three customers in 1993, 1992 and 1991 each represented 10% or more
of consolidated sales:
<TABLE>
<CAPTION>
1993 1992 1991
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Diamond Shamrock, Inc. $ 38.4 $ 79.9 $ 81.6
Mitsubishi Corporation 83.3 95.0 118.1
Indonesian Government 148.0 141.1 99.9
- --------------------------------------------------------------------------------
</TABLE>
NOTE SIX
TAXES
In January 1993, the Company adopted SFAS 109. The adoption, which was made
prospectively, had no impact on current period earnings or cash flow; however,
$21.0 million of deferred tax liabilities, which were considered current under
SFAS 96, were reclassified as noncurrent and $4.1 million of deferred tax assets
were reclassified as current assets.
On August 10, 1993, the Omnibus Budget Reconciliation Act of 1993 was signed
into law increasing the top corporate tax rate from 34% to 35% effective January
1, 1993. The increase in the tax rate had no effect on the Company during 1993.
Income before income taxes, extraordinary item and cumulative effect of the
change in accounting principle was comprised of income (loss) from:
<TABLE>
<CAPTION>
1993 1992 1991
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
United States $ (89.4) $ 31.5 $(101.4)
Foreign 135.7 145.2 220.3
--------------------------------
$ 46.3 $ 176.7 $ 118.9
- --------------------------------------------------------------------------------
</TABLE>
The Company's provision for income taxes was comprised of the following:
<TABLE>
<CAPTION>
1993 1992 1991
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Current
Federal $ .4 $ .9 $ (1.4)
Foreign 60.9 97.4 134.1
State and local .6 .6 1.0
--------------------------------
61.9 98.9 133.7
Deferred
Federal .4 (2.0)
Foreign 22.3 3.2 (1.6)
--------------------------------
22.3 3.6 (3.6)
--------------------------------
Provision for income taxes $ 84.2 $102.5 $130.1
- --------------------------------------------------------------------------------
</TABLE>
39
<PAGE>
The extension of production sharing contracts resulted in the reduction of
deferred tax expense applicable to temporary differences on foreign assets and
liabilities of $16.3 million and $2.1 million in 1992 and 1991, respectively.
The principal reasons for the difference between tax expense at the
statutory federal income tax rate and the Company's provision for income taxes
were:
<TABLE>
<CAPTION>
1993 1992 1991
- -------------------------------------------------------------------------
<S> <C> <C> <C>
Tax expense at statutory federal
rate $ 16.2 $ 60.1 $ 40.4
Increase (reduction) resulting from:
Taxes on foreign income 53.7 69.5 86.4
Excess statutory depletion (1.0) (1.0) (1.0)
Alternative minimum tax .3 .9 .4
Settlement of claims relating to
Natomas acquisition (2.4) (47.7)
Utilization of operating loss
carryforward 19.9 6.4
Valuation allowance 30.0
Items not related to current year
earnings (13.7) (4.0)
Other, net 1.1 .8 1.5
-------------------------------
Provision for income taxes $ 84.2 $102.5 $130.1
- -------------------------------------------------------------------------
</TABLE>
Additionally, the Company recorded a $.1 million tax benefit from the
extraordinary loss on early retirement of debt (see Note Fifteen).
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities for 1993 were
as follows:
<TABLE>
<CAPTION>
December 31 January 1
- -------------------------------------------------------------------------
<S> <C> <C>
U.S. deferred tax liabilities
Properties and equipment $ 45.4 $ 55.8
Other .6 1.6
---------------------------------
Deferred U.S. tax liabilities 46.0 57.4
---------------------------------
U.S. deferred tax assets
Foreign deferred taxes (68.7) (59.1)
Loss carryforwards (55.9) (47.8)
Book accruals (14.3) (12.4)
Credit carryforwards (26.5) (26.5)
Other (7.2) (4.2)
---------------------------------
Gross deferred U.S. tax assets (172.6) (150.0)
---------------------------------
Valuation allowance 126.6 92.6
---------------------------------
Net deferred U.S. tax assets (46.0) (57.4)
---------------------------------
Net deferred U.S. taxes -- --
---------------------------------
Foreign deferred tax liabilities
Properties and equipment 196.2 173.9
---------------------------------
Net deferred foreign taxes 196.2 173.9
---------------------------------
Net deferred taxes $196.2 $173.9
- -------------------------------------------------------------------------
</TABLE>
The valuation allowance was increased $34.0 million during 1993, $30.0 million
of which was attributed to income before the extraordinary item and the
cumulative effect of the change in accounting principle.
For years reported prior to the adoption of SFAS 109, the provision
(benefit) for deferred income taxes was comprised of the tax effects of
temporary differences as follows:
<TABLE>
<CAPTION>
1992 1991
- -------------------------------------------------------------------------
<S> <C> <C>
Intangible drilling costs $ (1.4) $ .7
Accelerated depreciation 4.0 (3.9)
Development wells and related items (.3) .4
Contingencies and asset write-offs .8 (.6)
Other, net .5 (.2)
-----------------------------
$ 3.6 $ (3.6)
- -------------------------------------------------------------------------
</TABLE>
At December 31, 1993, the Company had $21.3 million of general business credit
carryforwards that expire between 1995 and 2006; $159.9 million of U.S. net
operating loss carryforwards that expire in 2002, 2003 and 2005; and $5.2
million of minimum tax credit that can be carried forward indefinitely.
There are accumulated undistributed earnings after applicable local taxes of
foreign subsidiaries of $9.4 million for which no provision was necessary for
foreign withholding or other income taxes because that amount had been
reinvested in properties and equipment and working capital.
Taxes other than income taxes were comprised of the following:
<TABLE>
<CAPTION>
1993 1992 1991
- -------------------------------------------------------------------------
<S> <C> <C> <C>
Gross production $ 8.0 $ 7.9 $ 8.6
Real and personal property 7.4 7.0 7.3
Other .5 1.0 1.2
---------------------------------------
$15.9 $15.9 $17.1
- -------------------------------------------------------------------------
</TABLE>
NOTE SEVEN
POSTEMPLOYMENT BENEFITS
Pensions
<TABLE>
<CAPTION>
1993 1992 1991
- -------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost for benefits
earned during the year $ 2.1 $ 2.1 $ 2.2
Interest cost on projected
benefit obligation 9.3 9.0 9.8
Actual return on plan assets (10.4) (7.5) (15.7)
Net amortization and deferrals .6 (2.4) 6.1
---------------------------------------
$ 1.6 $ 1.2 $ 2.4
- -------------------------------------------------------------------------
</TABLE>
40
<PAGE>
Due to an early retirment program offered to former employees, the Company
recognized a partial curtailment and settlement of one of its plans, which
resulted in a loss of $2.4 million.
Plan assets are primarily invested in short-term investments, stocks and
bonds. The principal assumptions used to estimate the benefit obligations of the
plans on the measurement date, October 1, were as follows:
<TABLE>
<CAPTION>
1993 1992
- --------------------------------------------------------------------------------
<S> <C> <C>
Discount rate 7.25% 8.75%
Expected long-term rate of return on assets 9.50% 9.50%
Rate of increase in compensation levels 5.50% 5.50%
- --------------------------------------------------------------------------------
</TABLE>
The funded status of the plans at December 31, 1993 and 1992 is as follows:
<TABLE>
<CAPTION>
Accumulated Assets Accumulated
Benefits Exceeding Benefits
Exceeding Accumulated Exceeding
Assets Benefits Assets
1993 1992 1992
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Actuarial present value of:
Vested benefit obligation $ 111.6 $ 94.2 $ 5.8
======================================
Accumulated benefit obligation $ 120.5 $ 99.0 $ 7.8
======================================
Projected benefit obligation $ 125.5 $ 101.7 $ 8.3
Plan assets at fair value 102.2 100.5 4.3
--------------------------------------
Plan assets less than projected
benefit obligation (23.3) (1.2) (4.0)
Unrecognized net loss (gain) 36.0 21.2 (.9)
Unrecognized net transition
obligation (asset) (4.5) (7.7) 1.9
Unrecognized prior service cost (1.4) (.5) (1.0)
Adjustment required to recognize
minimum liability (24.4)
--------------------------------------
Prepaid (accrued) pension cost $ (17.6) $ 11.8 $ (4.0)
- --------------------------------------------------------------------------------
</TABLE>
In 1993, the Company's accumulated postretirement benefit obligation ("APBO")
exceeded the plan assets. In accordance with Statement of Financial Accounting
Standards No. 87 "Employers Accounting for Pensions," the Company recorded a
minimum pension liability of $18.3 million and a charge to equity of $24.4
million.
In addition to the defined benefit plans, the Company has a defined
contribution plan which covers Indonesian nationals. Employee contributions of
2% of each covered employee's compensation are matched 6% of compensation by the
Company. Contributions to the plan were $.4 million in 1992 and 1993.
Other Postretirement Benefits
Effective January 1, 1993, the Company adopted SFAS 106, for its retiree
benefits plan. Under SFAS 106, the Company is required to accrue the estimated
cost of retiree benefit payments, other than pensions, during employees' active
service period. The Company previously expensed the cost of these benefits,
which are principally medical benefits, as claims were incurred. The Company
currently administers several unfunded postretirement medical and life insurance
plans covering primarily United States employees which are, depending on the
type of plan, either contributory or noncontributory. Employees become eligible
for these benefits if they meet minimum age and service requirements. At January
1, 1993, the estimated APBO was $46.1 million, which the Company has elected to
amortize over a 20-year period.
The components of net periodic postretirement cost are as follows for the
year ended December 31, 1993:
<TABLE>
<CAPTION>
1993
- --------------------------------------------------------------------------------
<S> <C>
Service cost-benefits earned during period $ .4
Interest cost on accumulated postretirement benefit obligation 3.9
Amortization of transition obligation 2.3
---------
$ 6.6
- --------------------------------------------------------------------------------
</TABLE>
For 1993, the Company's postretirement benefit cost increased $2.8 million as a
result of adopting the new standard. The Company's current policy is to fund
postretirement health care benefits on a "pay-as-you-go" basis as in prior
years.
The APBO as of December 31, 1993 was $50.4 million. The amount recognized in
the Company's statement of financial position at December 31, 1993, was as
follows:
<TABLE>
- -------------------------------------------------------------------------------
<S> <C>
Retirees $ 43.7
Fully eligible active employees 2.5
Other active employees 4.2
-------
Total 50.4
Unrecognized transition obligation (43.8)
Unrecognized net gain (loss) (3.6)
-------
Accrued liability recognized in the balance sheet $ 3.0
- -------------------------------------------------------------------------------
</TABLE>
41
<PAGE>
A discount rate of 7.25% was used in determining the APBO at December 31, 1993.
The year-end 1993 APBO was based on an 11% increase in the medical cost trend
rate, with the rate trending downward .6% per year to 5% in 2003 and remaining
at 5% thereafter. This assumption has a significant effect on annual expense, as
it is estimated that a 1% increase in the medical trend rate would increase the
APBO at December 31, 1993 by $4.3 million and increase the net periodic
postretirement benefit cost by $.7 million per year.
Other Postemployment Benefits
In the fourth quarter of 1993, the Company adopted, retroactive to January 1,
1993, SFAS 112, which requires an accrual method of recognizing postemployment
benefits. Prior to 1993, postemployment benefit expenses were recognized on a
pay-as-you-go basis. The Company recognized the cumulative effect of the change
in accounting for postemployment benefits, which resulted in a charge of $4.4
million. The effect of this change on 1993 operating results was an increase in
postemployment benefits expense of $3.7 million. This liability primarily
represents medical benefits for long-term disability recipients.
NOTE EIGHT
VALUE OF FINANCIAL INSTRUMENTS
The fair value of financial instruments is determined by reference to various
market data and other valuation techniques as appropriate. Unless otherwise
disclosed, the fair value of financial instruments approximates their recorded
values.
Short-Term Investments
The Company's short-term investments are comprised of securities purchased under
repurchase agreements, U.S. Treasury notes and short-term, highly-liquid
investments, with maturities greater than ninety days, but not exceeding one
year. With the exception of the U.S. Treasury notes, the carrying amount
approximates fair value because of the short maturity of these instruments. The
fair value of the U.S. Treasury notes is based on year-end quoted market prices.
Long-Term Debt
The fair value of the Company's long-term debt is estimated based on the quoted
market prices for the same or similar issues or on the current rates offered to
the Company for debt of the same remaining maturities.
Redeemable Preferred Stock
The fair value of the Redeemable Preferred Stock is based on the comparable
yield to the Company's publicly-traded $4.00 Preferred Stock.
Interest Rate Swaps
The fair value of the interest rate swaps is based on the present value of
expected future cash flows from the interest rate swap agreement.
Natural Gas Hedging Program
The fair value of the Company's natural gas price swap agreements is the
estimated amount the Company would receive to terminate the swap agreements at
the reporting date.
The estimated fair value of the Company's financial instruments are as
follows:
<TABLE>
<CAPTION>
1993
Carrying Fair
Amount Value
- --------------------------------------------------------
<S> <C> <C>
Assets
U.S. Treasury notes $ 30.7 $ 32.2
Liabilities
Long-term debt,
including current portion 1,055.1 1,079.1
Redeemable Preferred Stock 250.0 261.9
Unrecognized Financial
Instruments
Interest rate swaps in a net
receivable position 6.3
Natural gas hedging program 6.0
- --------------------------------------------------------
<CAPTION>
1992
Carrying Fair
Amount Value
- --------------------------------------------------------
Assets
U.S. Treasury notes $ 121.2 $ 121.5
Liabilities
Long-term debt,
including current portion 829.4 849.2
Redeemable Preferred Stock 250.0 263.1
- --------------------------------------------------------
<CAPTION>
Note Nine
Receivables
1993 1992
- --------------------------------------------------------
Trade receivables $ 89.2 $ 90.2
Underlift receivables 18.5
Notes and other receivables 50.4 46.0
Less--Allowance for
doubtful receivables 1.3 1.2
---------------
$156.8 $135.0
- --------------------------------------------------------
</TABLE>
42
<PAGE>
<TABLE>
<CAPTION>
NOTE TEN
PROPERTIES AND EQUIPMENT
1993 1992
- -----------------------------------------------------------
<S> <C> <C>
Proved properties $2,902.1 $2,628.0
Unproved properties 72.3 79.5
Other 220.6 207.9
-------------------
Total Oil and Gas 3,195.0 2,915.4
Corporate 173.8 171.6
-------------------
3,368.8 3,087.0
Less--Accumulated depreciation
and depletion 2,063.2 1,948.7
-------------------
$1,305.6 $1,138.3
- -----------------------------------------------------------
</TABLE>
The charge against earnings for depreciation and depletion was $152.3 million in
1993, $173.1 million in 1992 and $202.3 million in 1991. The charge against
earnings for maintenance and repairs was $35.0 million in 1993, $23.6 million in
1992 and $23.2 million in 1991.
<TABLE>
<CAPTION>
NOTE ELEVEN
INVESTMENTS AND
LONG-TERM RECEIVABLES
1993 1992
- -----------------------------------------------------------
<S> <C> <C>
Investments and advances, at equity
Union-Magma-Thermal Tax
Partnership ("UMT")(25%) $88.3 $76.0
Investments, at cost, and
long-term receivables 5.9 11.5
-------------------
$94.2 $87.5
- -----------------------------------------------------------
</TABLE>
The Company has indemnified Union Oil Company of California, its co-venturer in
the Magma-Thermal Power Project ("MTPP"), a California joint venture, and in
UMT, relative to a note payable by MTPP which is a non-recourse loan secured
only by the Company's interest in the Geysers, the site of production of
electric power from geothermal steam in northern California. At December 31,
1993, the note payable had an outstanding principal balance of $20.0 million.
The following schedule presents certain summarized financial information of UMT:
<TABLE>
<CAPTION>
1993 1992 1991
- -----------------------------------------------------------
<S> <C> <C> <C>
Summarized Balance Sheet:
Current Assets $ 14.2 $ 12.4 $ 12.4
Non-Current Assets 408.7 429.0 446.3
Current Liabilities 44.9 34.6 22.7
Non-Current Liabilities 20.0 47.5
Summarized Statement
of Income:
Sales $ 93.1 $ 91.6 $ 68.1
Gross Profit 50.3 47.8 23.6
Net Income 50.3 47.8 23.6
- -----------------------------------------------------------
</TABLE>
Equity earnings are principally from geothermal operations and were $10.2
million in 1993, $8.7 million in 1992 and $1.0 million in 1991.
NOTE TWELVE
RESTRICTED CASH
At December 31, 1993 and 1992, the Company had $160.2 million and $124.7
million, respectively, in restricted cash, of which $103.4 million in 1993 and
$94.2 million in 1992 represented collateral for outstanding letters of credit.
Assets held in trust as required by certain insurance policies were $56.8
million in 1993 and $30.5 million in 1992. Approximately $38.4 million of
collateral for outstanding letters of credit at December 31, 1993, was
classified as a current asset.
NOTE THIRTEEN
INTANGIBLE ASSETS
Intangibles, primarily the excess of cost over fair market value of net assets
acquired, were $50.0 million at December 31, 1993 and 1992. Accumulated
amortization at December 31, 1993 and 1992 was $12.9 million and $11.7 million,
respectively. The charge against earnings for amortization of intangible assets
was $1.3 million in 1993, 1992 and 1991.
43
<PAGE>
<TABLE>
<CAPTION>
NOTE FOURTEEN
ACCRUED LIABILITIES
1993 1992
- -------------------------------------------------------------------------
<S> <C> <C>
Accrued interest payable $ 27.0 $ 23.8
Joint interest billings for
international operations 37.8 37.4
Environmental reserve 12.9 10.6
Overlift payable .8 11.9
Postretirement and
postemployment benefits 3.3
Accrued compensation,
benefits and withholdings 8.3 8.5
Other 17.6 11.4
------------------------
$107.7 $103.6
- -------------------------------------------------------------------------
</TABLE>
NOTE FIFTEEN
LONG-TERM DEBT AND CREDIT
ARRANGEMENTS
<TABLE>
<CAPTION>
1993 1992
- -------------------------------------------------------------------------
<S> <C> <C>
Senior Indebtedness
Sinking Fund Debentures
11 1/4% due 1994-2013 $ 16.9 $134.7
11 1/2% due 1996-2015 108.9 108.9
8 1/2% due 1997-2008 97.8 97.8
Notes
9 7/8% due 2002 249.5 249.4
9 1/2% due 2003 100.0
9 3/8% due 2003 200.0
Medium-tern notes 272.7 237.1
Bank and other loans 9.3 1.5
------------------------
Total senior indebtedness 1,055.1 829.4
Less--current portion 39.7 .1
------------------------
$1,015.4 $829.3
- -------------------------------------------------------------------------
</TABLE>
The aggregate maturities of long-term debt outstanding at December 31, 1993, for
the next five years were as follows: 1994-$89.4 million (of which $60.0 million
has been refinanced through a debt offering consummated by the Company in
January 1994); 1995 - $13.6 million; 1996 - $44.1 million; 1997 - $23.0 million;
1998 - $63.6 million.
At December 31, 1993 the Company had $172.6 million of medium-term notes
outstanding, which were issued in prior years, with maturities from 1994 to 2004
and annual interest rates from 10.0% to 11.08%. During 1993, the Company issued
an additional $100.1 million of medium-term notes. These notes have maturities
from 1994 to 2003 and annual interest rates from 4.64% to 9.0%. The proceeds
from these notes were used for general corporate purposes, including the
repayment of $64.5 million of outstanding medium-term notes which matured in
1993.
During 1993, the Company issued $100.0 million of 9 1/2% notes maturing in
2003 and $200.0 million of 9 3/8% notes due in 2003. The proceeds from these two
debt issuances were used for general corporate purposes, including the repayment
of $117.8 million of the Company's 11 1/4% sinking fund debentures due 2013, of
which $114.5 million were repaid at 105.329% of the principal amount. The 5.329%
call premium and unamortized issuance costs associated with this early
retirement were recorded as an extraordinary loss of $7.1 million, net of $.1
million of tax benefit. In January 1994, the Company issued an additional $60.0
million of 9 3/8% notes due 2013. The proceeds will be used to repay 1994
maturities of long-term debt.
The Company has entered into a $25.0 million uncommitted credit facility
(the "credit facility") to be used for the issuance of documentary or standby
letters of credit and/or the payment of shipping documents. The credit facility
terminates on December 31, 1994 and is secured by the accounts receivable which
have been financed through the letters of credit. At December 31, 1993, there
were $4.4 million of letters of credit outstanding under this credit facility.
Effective January 27, 1993, the Company entered into an interest rate swap
agreement under which it pays to the counterparty interest at a variable rate
based on the London Interbank Offering Rate (LIBOR) and the counterparty pays
the Company interest at 6.73% on the notional principal of $100.0 million. This
agreement is effective through January 27, 2003. The Company is not required to
collateralize its obligation under this agreement unless it is in an unfavorable
position. At December 31, 1993, the Company had $5.8 million of borrowings
against its favorable position in this interest rate swap agreement. At December
31, 1993, the Company had no exposure to credit loss on the interest rate swap.
Total interest and debt expenses incurred, including capitalized interest,
were as follows:
<TABLE>
<CAPTION>
1993 1992 1991
- -------------------------------------------------------------------------
<S> <C> <C> <C>
Interest and debt expenses $ 88.4 $ 86.9 $ 88.4
Capitalized interest 7.5 4.6 2.0
---------------------------------------
$ 95.9 $ 91.5 $ 90.4
- -------------------------------------------------------------------------
</TABLE>
44
<PAGE>
NOTE SIXTEEN
PREFERRED STOCK
The Company has the authority to issue 100,000,000 shares of Preferred Stock,
$1.00 par value. The rights and preferences of shares of authorized but unissued
Preferred Stock are to be established by the Company's Board of Directors at the
time of issuance.
$9.75 Cumulative Convertible
Preferred Stock
In June 1990, the Company used $69.0 million of the net proceeds from a Common
Stock offering (see "Common Stock") to fund its obligations under an agreement,
dated April 12, 1990 between the Company and the holder of the 3,000,000 shares
of $9.75 Cumulative Convertible Preferred Stock (the "$9.75 Preferred Stock").
Pursuant to the agreement, the Company repurchased 500,000 shares of the $9.75
Preferred Stock. In addition, the holder waived the right to convert 750,000 of
the remaining 2,500,000 shares of $9.75 Preferred Stock and will receive an
additional cash payment of $.25 per share per quarter (subject to increase to
$.50 per share per quarter in certain circumstances) on the 750,000
nonconvertible shares (the "Conversion Waiver Shares"). Further, certain
covenants relating to the $9.75 Preferred Stock were waived or amended. In
October 1990, the number of authorized shares of $9.75 Preferred Stock was
decreased to 2,500,000.
The $9.75 Preferred Stock has a liquidation value of $102.1669
per share for the 12-month period commencing February 1, 1994 ($255.4 million in
the aggregate), reducing progressively as of February 1 of each year to $100 per
share at February 1, 1996, in each case plus accrued dividends. Each outstanding
share of the $9.75 Preferred Stock is convertible (other than the Conversion
Waiver Shares) into 9.04 shares of the Company's Common Stock, is redeemable at
the Company's option after August 1, 1995 and is subject to mandatory redemption
at the rate of 625,000 shares per year beginning February 1, 1994. The Company
redeemed the mandatory number of shares on February 1, 1994, with proceeds from
the November 1993 issuance of $2.50 Preferred Stock.
In addition, the holder of the $9.75 Preferred Stock (other than the
Conversion Waiver Shares) is entitled to elect one individual to the Company's
Board of Directors and vote as a class on any transaction between the Company
and any holder of 5% or more of the outstanding Common Stock that requires
stockholder approval and certain matters separately affecting the holders of the
$9.75 Preferred Stock. The holders of the Conversion Waiver Shares may only vote
on certain matters separately affecting the holders of the $9.75 Preferred
Stock. In connection with the issuance of the $9.75 Preferred Stock, the Company
agreed to certain financial covenants relating to the issuance of debt, capital
expenditures, the payment of dividends, the repurchase of stock and the
disposition of certain assets.
$4.00 Cumulative Convertible
Preferred Stock
Each outstanding share of $4.00 Cumulative Convertible Preferred Stock (the
"$4.00 Preferred Stock") is entitled to one vote, is convertible at any time
into shares of the Company's Common Stock (2.29751 shares at December 31, 1993),
shall receive annual cash dividends of $4.00 per share, is callable at $50.00
per share ($217.9 million in the aggregate at December 31, 1993) and has a
liquidation value of $50.00 per share ($217.9 million in the aggregate at
December 31, 1993) plus accrued but unpaid dividends, if any.
In August 1993, the Company issued 23,800 shares of $4.00 Preferred Stock
with net proceeds of $1.1 million after deducting related fees and expenses.
$2.50 Preferred Stock
In November 1993, the Company issued 3.5 million shares of $2.50 Cumulative
Preferred Stock (the "$2.50 Preferred Stock") in a public offering for $25.00
per share. The net proceeds to the Company, after deducting related fees and
expenses, were approximately $84.6 million, of which $62.5 million was used to
redeem the mandatory portion of the $9.75 Preferred Stock on February 1, 1994.
Each outstanding share of the $2.50 Preferred Stock shall receive annual
cash dividends of $2.50 per share, is callable after December 1, 1998 at $25.00
per share ($87.5 million in the aggregate at December 31, 1993), and has a
liquidation value of $25.00 per share ($87.5 million in the aggregate at
December 31, 1993) plus accrued but unpaid dividends, if any.
45
<PAGE>
The holders of the shares are entitled to limited voting rights under
certain conditions. In the event the Company is in arrears in the payment of six
quarterly dividends, the holders of the $2.50 Preferred Stock have the right to
elect two members to the Board of Directors until such time as the dividends in
arrears are current and a provision is made for the current dividends du e.
NOTE SEVENTEEN
COMMON STOCK
<TABLE>
<CAPTION>
Shares Amount
- -------------------------------------------------------------------------
<S> <C> <C>
January 1, 1991 100,223,348 $100.2
Dividend Reinvestment and Stock
Purchase Plan 2,044,315 2.0
Restricted stock 453,420 .5
Exercise of stock options 57,831 .1
Fractional shares exchanged
for cash (4)
----------------------------------
January 1, 1992 102,778,910 102.8
Issuance of Common Stock 22,000,000 22.0
Dividend Reinvesment and Stock
Purchase Plan 7,955,830 8.0
Employee Shareholding and
Investment Plan 506,002 .5
Restricted stock 322,360 .3
Exercise of stock options 4,200
Fractional shares exchanged
for cash (2)
----------------------------------
January 1, 1993 133,567,300 133.6
Employee Shareholding and
Investment Plan 475,852 .5
Restricted stock 312,690 .3
Exercise of stock options 17,683
Fractional shares exchanged
for cash (2)
----------------------------------
December 31, 1993 134,373,523 $134.4
- -------------------------------------------------------------------------
</TABLE>
In June 1992, the Company issued 22 million shares of Common Stock in a public
offering for $6.00 per share. The net proceeds to the Company, after deducting
related fees and expenses, were approximately $125.9 million.
On July 30, 1991, the Company's Dividend Reinvestment and Stock Purchase
Plan (the "Plan") became effective. The Plan allows holders of Common Stock to
purchase additional shares at a 3% discount from the current market prices
without paying brokerage commissions or other charges. In addition, if the
Company pays a dividend on its Common Stock in the future, common stockholders
may then reinvest the amount of those dividends in additional shares also at a
3% discount from the current market prices. In November 1992, the Company
effectively suspended this share purchase plan by raising the threshold price.
At December 31, 1993 and 1992, respectively, there were 51.1
million and 46.0 million shares of Common Stock reserved for issuance upon
conversion of Preferred Stock, exercises of stock options or issuance under
certain employee benefit plans.
The Company has an Employee Shareholding and Investment Plan ("ESIP") which
allows eligible participating employees to contribute a certain percentage of
their salaries (1%-10%) to a trust for investment in any of five funds, one of
which consists of the Company's Common Stock. The Company matches the
participating employee's contribution to the ESIP (up to 6% of base pay); such
matching contribution is charged against earnings and invested in the ESIP fund
which consists of the Company's Common Stock. The charge against earnings for
the Company's contribution to the ESIP was $2.6 million, $2.5 million and $2.4
million in 1993, 1992 and 1991 respectively.
In 1988, the Company adopted a Preferred Share Purchase Rights Plan. The
plan issued one right for each share of Common Stock and 7.92 rights for each
share of $9.75 Cumulative Convertible Preferred Stock outstanding as of the
close of business on September 12, 1988. The rights, which entitle the holder to
purchase from the Company one one-hundredth of a share of a new series of junior
preferred stock at $23.00 per share, become exercisable if a person becomes the
beneficial owner of 20% or more of the Company's Common Stock or of an amount
that the Board of Directors determines is intended to cause the Company to take
certain actions not in the best long-term interests of the Company and its
stockholders. The rights also become exercisable if a person makes a tender
offer or exchange offer for 30% or more of the Company's outstanding Common
Stock. The rights may be redeemed at $.10 per right under certain circumstances.
The rights will expire on September 12, 1995 unless earlier redeemed.
46
<PAGE>
NOTE EIGHTEEN
PAID-IN CAPITAL AND
ACCUMULATED DEFICIT
<TABLE>
<CAPTION>
Paid-In Accumulated
Capital Deficit
- --------------------------------------------------------------------------------
<S> <C> <C>
January 1, 1991 $ 881.3 $(1,007.3)
Net loss (11.2)
Dividends on Preferred Stock (41.7)
Dividend Reinvestment and Stock Purchase Plan 15.0
Exercise of stock options .2
Restricted stock 2.7
----------------------
January 1, 1992 857.5 (1,018.5)
Net income 74.2
Dividends on Preferred Stock (41.7)
Issuance of Common Stock 103.9
Dividend Reinvestment and Stock Purchase Plan 45.0
Issuance of Stock Warrants 10.0
Employee Shareholding and Investment Plan Purchases 2.8
Restricted stock 2.6
-----------------------
January 1, 1993 980.1 (944.3)
Net loss (49.4)
Dividends on Preferred Stock (41.7)
Issuance of $4.00 Preferred Stock 1.1
Issuance of $2.50 Preferred Stock 81.1
Employee Shareholding and Investment Plan Purchases 3.1
Restricted stock 2.5
----------------------
December 31, 1993 $1,026.2 $(993.7)
- --------------------------------------------------------------------------------
</TABLE>
The $10.0 million addition to paid-in capital in 1992 reflects the market value
of the eight million warrants purchased by Kidder Peabody in partial settlement
of the Company's lawsuit against Kidder Peabody arising out of transactions
related to the 1983 acquisition of Natomas Company. Each warrant represents the
right to purchase one share of the Company's Common Stock at $13.00 per share at
any time prior to the expiration of the warrants on October 10, 1997.
NOTE NINETEEN
COMMON TREASURY STOCK
<TABLE>
<CAPTION>
Shares Amount
- --------------------------------------------------------------------------------
<S> <C> <C>
January 1, 1991 (96,109) $ (1.6)
Restricted Stock (26,700) (.4)
--------- -------
January 1, 1992 (122,809) (2.0)
Restricted Stock (12,942) (.1)
--------- -------
January 1, 1993 (135,751) (2.1)
Restricted Stock (38,212) (0.4)
--------- -------
December 31, 1993 (173,963) $ (2.5)
- --------------------------------------------------------------------------------
</TABLE>
NOTE TWENTY
STOCK OPTIONS
Two plans, a Long-Term Incentive Plan and a Director Stock Option Plan, were
approved by the stockholders in 1992. The Company's 1986 and 1992 Long-Term
Incentive Plans (the "Incentive Plans"), administered by the Compensation
Committee of the Board of Directors, permit the grant to officers and certain
key employees of stock options, stock appreciation rights ("SARs"), performance
units and awards of Common Stock or other securities of the Company on terms and
conditions determined by the Compensation Committee of the Board of Directors.
The Director Stock Option Plan became effective on September 1, 1992. Under
this plan, non-employee directors received an option to purchase shares of
Common Stock on the effective date of the plan. Thereafter, upon initial
election or re-election of a non-employee director at an annual meeting, the
non-employee director shall automatically receive an option to purchase shares
of Common Stock. The plan terminates on September 1, 2002.
The grant or exercise of an option does not result in a charge against the
Company's earnings because all options have been granted at exercise prices
approximating the market value of the stock at the date of grant. However, any
excess of Common Stock market price over the option price of options, which
includes SARs, does result in a charge against the Company's earnings; a
subsequent decline in market price results in a credit to earnings, but only to
a maximum of the earnings charges incurred in prior years on SARs.
47
<PAGE>
Stock option activity was as follows:
<TABLE>
<CAPTION>
1993 1992 1991
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Outstanding at January 1 1,855,695 1,605,673 1,900,776
Granted 20,000 449,700
Exercised (17,683) (4,200) (57,831)
Canceled (163,567) (195,478) (237,272)
-----------------------------------------
Outstanding at December 31 1,694,445 1,855,695 1,605,673
Grant price $8.625 $ 6.25
Exercise price $6.625 $6.625 $6.625
to $8.506 to $7.957
Available for future grants
at December 31 3,492,787 4,330,435 412,484
Restricted Stock held for
vesting at December 31 874,602 930,736 834,280
Performance Units held for
vesting at December 31 653,355
- ---------------------------------------------------------------------------
</TABLE>
Exercise prices of stock options outstanding at December 31, 1993 ranged from
$6.25 to $13.75 per share. There was a credit to earnings for SARs in 1993 and
1992 of $.1 million and $.4 million, respectively. There was no earnings
activity related to SARs in 1991.
Under the 1986 Long-Term Incentive Plan, the Company granted Restricted Stock.
The amount of the grant price is amortized over the vesting period of the grant
as a charge against earnings. The charge against earnings was $2.4 million in
1993, $2.6 million in 1992 and $2.8 million in 1991.
In 1993, the Company implemented a Performance Unit Long-Term Incentive Plan.
The performance unit entitles the grantee to the value of a share of Common
Stock contingent upon the performance of the Company compared to a selected
group of peer companies. The value of the performance unit is amortized over the
vesting period based on a weighted probability of expected payout levels. The
charge against earnings was $.6 million in 1993.
NOTE TWENTY-ONE
LEASES
The Company leases certain machinery and equipment, facilities and office space
under cancelable and noncancelable operating leases, most of which expire within
20 years and may be renewed.
Minimum annual rentals for non-cancelable operating leases at December 31,
1993, were as follows:
<TABLE>
<CAPTION>
<S> <C>
1994 $ 39.3
1995 23.2
1996 10.3
1997 9.3
1998 5.7
1999 and thereafter 35.4
- -------------------------------------------------------
$123.2
</TABLE>
Minimum annual rentals have not been reduced by minimum sublease rentals of
$42.6 million due in the future under noncancelable subleases.
Rental expense for operating leases was as follows:
<TABLE>
<CAPTION>
1993 1992 1991
- -------------------------------------------------------------------------
<S> <C> <C> <C>
Total rentals $67.7 $60.8 $67.7
Less--Sublease rental income 3.4 4.7 5.2
---------------------------------------
Rental expense $64.3 $56.1 $62.5
- -------------------------------------------------------------------------
</TABLE>
NOTE TWENTY-TWO
COMMITMENTS AND CONTINGENCIES
Like other energy companies, Maxus' operations are subject to various laws
related to the handling and disposal of hazardous substances which require the
cleanup of deposits and spills. Compliance with the laws and protection of the
environment worldwide is of the highest priority to Maxus management. In 1993,
the Company spent $14.9 million for the installation of environmental-control
equipment for its oil and gas operations (mainly attributable to the Sunray gas
plant and the gas project in Northwest Java). Expenditures in 1994 are expected
to be approximately $9.0 million.
In addition, the Company is implementing certain environmental projects
related to its former chemicals business ("Chemicals") sold to Occidental
Petroleum Corporation in 1986 and certain other disposed of businesses.
The Company will be implementing remediation at the former agricultural
chemical plant in Newark, New Jersey as required by a consent decree entered
into in November 1990 with the United States Environmental
48
<PAGE>
Protection Agency (the "EPA") and the New Jersey Department of Environmental
Protection and Energy (the "DEP"). The Company has recently agreed with the EPA
to conduct further testing and studies to characterize contaminated sediment in
a six-mile portion of the Passaic River near the plant site. The Company has
been conducting similar studies under its own auspices for several years.
Under an Administrative Consent Order issued by the DEP in April 1990
covering sites in Kearny and Secaucus, New Jersey, the Company will continue to
implement interim remedial investigations and to perform remedial investigations
and feasibility studies and, if necessary, implement additional remedial actions
at various locations where chromite ore residue, allegedly from the former
Kearny plant, was utilized, as well as at the plant site.
Until 1976, Chemicals operated manufacturing facilities in Painesville,
Ohio. The Company has heretofore conducted many remedial, maintenance and
monitoring activities at this site. The former Painesville plant area has been
proposed for listing on the national priority list of Superfund sites. The scope
and nature of further investigation or remediation which may be required cannot
be determined at this time.
In the opinion of the Company, environmental remediation has been
substantially completed at all other former plant sites where material
remediation is required.
The Company also has responsibility for Chemicals' share of the remediation
cost for a number of other non-plant sites where wastes from plant operations by
Chemicals were allegedly disposed of or have come to be located including
several commercial waste disposal sites.
At the time of the spin-off by the Company of Diamond Shamrock, Inc. ("DSI")
in 1987, the Company executed a cost-sharing agreement for the partial
reimbursement by DSI of environmental expenses related to the Company's disposed
of businesses, including Chemicals.
The Company's total expenditures for environmental compliance for disposed
of businesses, including Chemicals, was $36.3 million in 1993, $11.4 million of
which was recovered from DSI under the cost-sharing agreement. Those
expenditures are projected to be approximately $21.0 million in 1994 after
recovery from DSI.
Reserves, net of cost sharing by DSI have been established for environmental
liabilities where they are material and probable and can be reasonably
estimated. At December 31, 1993 and 1992, the reserve balance was $38.4 million
and $28.2 million, respectively.
The Company has received notification from the Social Security
Administration concerning assignment of beneficiaries to one of the Company's
subsidiaries under the terms of the Coal Industry Retiree Health Benefit Act of
1992 (the "Act"). Under the provisions of the Act, the Company is legally
required to make annual premium payments to the UMWA Combined Benefit Fund for
the 674 assigned beneficiaries. However, the Company will be entitled to refunds
of premiums paid with respect to beneficiaries improperly assigned to its
subsidiary. Of the 674 assigned beneficiaries, the Company has acknowledged that
22 beneficiaries (two of which are deceased) could potentially be properly
assigned to Maxus. The Company is currently pursuing legal action to have those
remaining beneficiaries, improperly assigned, reassigned to the proper entities.
While the total liability for health and death benefits for the 674
beneficiaries could reach approximately $12 million, the liability for the
beneficiaries expected to be retained is not material and has been recognized.
The Company enters into various operating agreements and capital commitments
associated with the exploration and development of its oil and gas properties.
Such contractual financial and/or performance commitments are not material.
The Company's foreign petroleum exploration, development and production
activities are subject to political and economic uncertainties, expropriation of
property and cancellation or modification of contract rights, foreign exchange
restrictions and other risks arising out of foreign governmental sovereignty
over the areas in which the Company's operations are conducted, as well as risks
of loss in some countries due to civil strife, guerrilla activities and
insurrection. Areas in which the Company has significant operations include the
United States, Indonesia, Ecuador, Bolivia and Venezuela.
49
<PAGE>
REPORT OF MANAGEMENT
To the Stockholders of
Maxus Energy Corporation
The Consolidated Financial Statements have been prepared in conformity with
generally accepted accounting principles and have been audited by Price
Waterhouse, independent accountants. The Company is responsible for all
information and representations contained in the Consolidated Financial
Statements. In the preparation of this information, it has been necessary to
make estimates and judgments based on data provided by the Company's accounting
and control systems.
In meeting its responsibility for the reliability of the Consolidated
Financial Statements, the Company depends on its accounting and control systems.
These systems are designed to provide reasonable assurance that assets are
safeguarded against loss from unauthorized use and that transactions are
executed in accordance with the Company's authorizations and are recorded
properly. The Company believes that its accounting and control systems provide
reasonable assurance that errors or irregularities that could be material to the
Consolidated Financial Statements are prevented or would be detected within a
timely period. The Company also requires that all officers and other employees
adhere to a written business conduct policy.
The independent accountants provide an objective review as to the Company's
reported operating results and financial position. The Company also has an
active operations auditing program which monitors the functioning of the
Company's accounting and control systems and provides additional assurance that
the Company's operations are conducted in a manner which is consistent with
applicable laws.
The Board of Directors pursues its oversight role for the Consolidated
Financial Statements through the Audit Review Committee which is composed solely
of directors who are not employees of the Company. The Audit Review Committee
meets with the Company's financial management and operations auditors
periodically to review the work of each and to monitor the discharge of their
responsibilities. The Audit Review Committee also meets periodically with the
Company's independent accountants, who have free access to the Audit Review
Committee without representatives of the Company present, to discuss accounting,
control, auditing and financial reporting matters.
M.J. BARRON
M. J. Barron
Vice President, Treasurer and Chief Financial Officer
G.R. BROWN
G. R. Brown
Vice President and Controller
Dallas, Texas
February 22, 1994
50
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors
of Maxus Energy Corporation
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of operations and of cash flows present fairly, in all
material respects, the financial position of Maxus Energy Corporation and its
subsidiaries at December 31, 1993 and 1992, and the results of their operations
and their 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 Company'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.
As discussed in Notes 1, 6, and 7 to the Consolidated Financial Statements, the
Company changed its methods of accounting for income taxes, postretirement
benefits and postemployment benefits in 1993.
PRICE WATERHOUSE
Dallas, Texas
February 22, 1994
51
<PAGE>
SUPPLEMENTARY FINANCIAL INFORMATION (Unaudited)
(Data is as of December 31 of each year or for the year then ended and dollar
amounts in tables are in millions, except per share)
Oil and Gas Producing Activities
The following are disclosures about the oil and gas producing activities of the
Company as required by Statement of Financial Accounting Standards No. 69 ("SFAS
69").
RESULTS OF OPERATIONS
Results of operations from all oil and gas producing activities are shown below.
These results exclude revenues and expenses related to the purchase of natural
gas and the subsequent processing and resale of such natural gas plus the sale
of natural gas liquids extracted therefrom.
<TABLE>
<CAPTION>
United States Indonesia
-------------------------- --------------------------
1993 1992 1991 1993 1992 1991
- -----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Sales $202.0 $207.8 $235.2 $405.9 $424.3 $487.4
-------------------------- --------------------------
Production costs 46.5 46.4 54.9 157.5 143.2 138.1
Exploration costs 14.6 15.2 35.5 16.5 13.7 12.7
Depreciation and
depletion 77.9 83.5 96.7 63.0 79.4 95.8
(Gain) loss on sale
of assets (3.0) (3.3) (8.1)
Other 17.0(a) 8.6(a) 14.9(a) (.2) (.4) (3.2)
-------------------------- --------------------------
153.0 150.4 193.9 236.8 235.9 243.4
-------------------------- --------------------------
Income (loss) before
tax provision 49.0 57.4 41.3 169.1 188.4 244.0
Provision (benefit) for
income taxes 1.0 1.1 .8 86.7 104.4 137.3
-------------------------- --------------------------
Results of operations $ 48.0 $ 56.3 $ 40.5 $ 82.4 $ 84.0 $106.7
- -----------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
South America Other Foreign Worldwide
-------------------------- -------------------------- --------------------------
1993 1992 1991 1993 1992 1991 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Sales $607.9 $632.1 $722.6
-------------------------- -------------------------- --------------------------
Production costs $ 1.7 205.7 189.6 193.0
Exploration costs 10.5 $ 11.1 $ 5.6 $ 15.2 $ 24.6 $ 12.7 56.8 64.6 66.5
Depreciation and
depletion .6 .4 1.7 2.8 2.7 143.2 166.1 195.2
(Gain) loss on sale
of assets (3.0) (3.3) (8.1)
Other .2 (.1) (.1) (.1) (.6) 16.9 8.0 11.1
-------------------------- -------------------------- --------------------------
13.0 11.4 5.6 16.8 27.3 14.8 419.6 425.0 457.7
-------------------------- -------------------------- --------------------------
Income (loss) before
tax provision (13.0) (11.4) (5.6) (16.8) (27.3) (14.8) 188.3 207.1 264.9
Provision (benefit) for
income taxes (.3) (.3) (.1) (.3) (.5) (.3) 87.1 104.7 137.7
-------------------------- -------------------------- --------------------------
Results of operations $(12.7) $(11.1) $ (5.5) $(16.5) $(26.8) $(14.5) $101.2 $102.4 $127.2
</TABLE>
(a) Includes United States gathering and processing costs related to sales.
Such costs were $13.1 million, $12.2 million and $12.8 million for 1993,
1992 and 1991, respectively.
52
<PAGE>
CAPITALIZED COSTS
Included in properties and equipment are capitalized amounts applicable to the
Company's oil and gas producing activities. Such capitalized amounts include the
cost of mineral interests in properties, completed and incomplete wells and
related support equipment as follows:
<TABLE>
<CAPTION>
United States Indonesia
---------------------------- ----------------------------
1993 1992 1991 1993 1992 1991
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Proved properties $1,214.6 $1,201.2 $1,207.3 $1,514.3 $1,393.4 $1,277.8
Unproved properties 51.2 46.9 60.4 .8 .8 .7
---------------------------- ----------------------------
1,265.8 1,248.1 1,267.7 1,515.1 1,394.2 1,278.5
Less-Accumulated
depreciation and
depletion 931.9 894.0 839.8 968.1 905.1 825.7
---------------------------- ----------------------------
$ 333.9 $ 354.1 $ 427.9 $ 547.0 $ 489.1 $ 452.8
- -------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
South America Other Foreign Worldwide
---------------------------- ---------------------------- ----------------------------
1993 1992 1991 1993 1992 1991 1993 1992 1991
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Proved properties $173.2 $33.4 $10.0 $2,902.1 $2,628.0 $2,495.1
Unproved properties 14.9 29.1 5.0 $5.4 $2.7 $4.5 72.3 79.5 70.6
---------------------------- ---------------------------- ----------------------------
188.1 62.5 15.0 5.4 2.7 4.5 2,974.4 2,707.5 2,565.7
Less-Accumulated
depreciation and
depletion 1.0 .4 .2 2.6 .3 1.5 1,903.6 1,799.8 1,667.2
---------------------------- ---------------------------- ----------------------------
$187.1 $62.1 $14.8 $2.8 $2.4 $3.0 $1,070.8 $ 907.7 $ 898.5
- -------------------------------------------------------------------------------------------------------------
</TABLE>
COSTS INCURRED
Costs incurred by the Company in its oil and gas producing activities (whether
capitalized or charged against earnings) were as follows:
<TABLE>
<CAPTION>
United States Indonesia
---------------------------- ----------------------------
1993 1992 1991 1993 1992 1991
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Property acquisition
costs $13.5 $ 2.7 $ 96.3 $ 6.6 $ .7
Exploration costs 22.6 14.4 43.4 $ 16.4 13.8 12.7
Development cost 35.6 23.4 30.7 120.8 109.0 89.9
---------------------------- ----------------------------
$71.7 $40.5 $170.4 $137.2 $129.4 $103.3
- -------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
South America Other Foreign Worldwide
---------------------------- ---------------------------- ----------------------------
1993 1992 1991 1993 1992 1991 1993 1992 1991
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Property acquisition
costs $ .5 $ .5 $ 1.4 $ 14.0 $ 9.8 $ 98.4
Exploration cost $ 25.3 $35.5 $ 9.8 15.5 24.4 12.9 79.8 88.1 78.8
Development costs 123.6 23.4 2.2 280.0 155.8 122.8
---------------------------- ---------------------------- ----------------------------
$148.9 $58.9 $12.0 $16.0 $24.9 $14.3 $373.8 $253.7 $300.0
- -------------------------------------------------------------------------------------------------------------
</TABLE>
53
<PAGE>
OIL AND GAS RESERVES
The following table represents the Company's net interest in estimated
quantities of developed and undeveloped reserves of crude oil, condensate,
natural gas liquids and natural gas and changes in such quantities at year-end
1993, 1992 and 1991. Net proved 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.
<TABLE>
<CAPTION>
1993 1992 1991
---------------------------------- ------------------------------ ------------------------------
Crude Oil United South United South United South
(millions of barrels) States Indonesia America(c) Total States Indonesia America Total States Indonesia America Total
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Net Proved Developed and
Undeveloped Reserves
Beginning of year 12.2 155.2 53.1 220.5 14.6 162.8 27.5 204.9 22.3 122.8 20.8 165.9
Revisions of
previous estimates .4 39.6(a) 1.2 41.2 .8 8.0(a) (15.1) (6.3) 1.3 44.2(a) 6.7 52.2
Purchase of reserves
in place .2 .2 36.7 36.7 1.2 1.2
Extensions, discoveries
and other additions 1.3 8.1(a) 17.3 26.7 .4 7.0(a) 4.0 11.4 .3 13.0(a) 13.3
Improved recovery 7.4 7.4
Production (1.8) (22.8) (24.6) (2.1) (22.6) (24.7) (3.6) (24.6) (28.2)
Sales of reserves in
place (1.5) (1.5) (6.9) (6.9)
--------------------------------- ------------------------------- ------------------------------
End of year 12.3 180.1 71.6 264.0 12.2 155.2 53.1 220.5 14.6 162.8 27.5 204.9
--------------------------------- ------------------------------- ------------------------------
Net Proved Developed
Reserves
Beginning of year 11.3 128.9 140.2 13.9 137.9 151.8 20.5 105.9 126.4
End of year 11.0 161.1 14.1 186.2 11.3 128.9 140.2 13.9 137.9 151.8
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
1993 1992 1991
-------------------------- -------------------------- --------------------------
Natural Gas(b) United United United
(billions of cubicfeet) States Indonesia Total States Indonesia Total States Indonesia Total
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Net Proved Developed and
Undeveloped Reserves
Beginning of year 584 245 829 635 37 672 642 52 694
Revisions of
previous estimates 3 (23) (20) 8 (3) 5 (11) (13) (24)
Purchase of reserves
in place 17 17 1 1 113 113
Extensions, discoveries
and other additions 152 45 197 24 216 240 11 2 13
Production (76) (5) (81) (83) (5) (88) (87) (4) (91)
Sales of reserves in place (1) (1) (1) (1) (33) (33)
-------------------------- -------------------------- --------------------------
End of year 679 262 941 584 245 829 635 37 672
-------------------------- -------------------------- --------------------------
Net Proved Developed Reserves
Beginning of year 515 22 537 568 23 591 594 33 627
End of year 507 85 592 515 22 537 568 23 591
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
54
<PAGE>
<TABLE>
<CAPTION>
1993 1992 1991
---------------------------- ---------------------------- ----------------------------
Natural Gas Liquids United United United
(millions of barrels) States Indonesia Total States Indonesia Total States Indonesia Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Net Proved Developed and
Undeveloped Reserves
Beginning of year 30.8 9.3 40.1 31.2 4.9 36.1 31.5 5.1 36.6
Revisions of
previous estimates 1.9 (.3) 1.6 2.5 (.7) 1.8 (4.8) .1 (4.7)
Purchase of reserves
in place .1 .1 7.2 7.2
Extensions, discoveries
and other additions 7.2 1.7 8.9 .3 5.7 6.0 .6 .2 .8
Production (2.8) (.5) (3.3) (3.3) (.6) (3.9) (3.2) (.5) (3.7)
Sales of reserves in place (.1) (.1)
---------------------------- ---------------------------- ----------------------------
End of year 37.1 10.2 47.3 30.8 9.3 40.1 31.2 4.9 36.1
---------------------------- ---------------------------- ----------------------------
Net Proved Developed Reserves
Beginning of year 27.0 5.1 32.1 29.6 3.1 32.7 29.8 3.1 32.9
End of year 29.5 3.3 32.8 27.0 5.1 32.1 29.6 3.1 32.7
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(a) The changes reflect the impact of the change in the price of crude oil on
the barrels to which the Company is entitled under the terms of the
Indonesian production sharing contracts. The Indonesian production sharing
contracts allow the Company to recover tangible and intangible production
and exploration costs, as well as operating costs. As the price of crude oil
fluctuates, the Company is entitled to more or less barrels of cost recovery
oil. Decreasing prices resulted in an increase of 24.3 million barrels in
1993, 4.5 million barrels in 1992 and 25.6 million barrels in 1991.
(b) Natural gas is reported on the basis of actual or calculated volumes which
remain after removal, by lease or field separation facilities, of
liquefiable hydrocarbons and of non-hydrocarbons where they occur in
sufficient quantities to render the gas unmarketable. Natural gas reserve
volumes include liquefiable hydrocarbons approximating 7% of total gas
reserves in the United States and 5% in Indonesia which are recoverable at
natural gas processing plants downstream from the lease or field separation
facilities. Such recoverable liquids also have been included in natural gas
liquids reserve volumes.
(c) Venezuelan reserves attributable to an operating service agreement under
which all hydrocarbons are owned by the Venezuelan government have not been
included. The SFAS 69 Results of Operations and Costs Incurred disclosures
both include $.6 million of exploration costs related to Venezuela.
55
<PAGE>
FUTURE NET CASH FLOWS
The standardized measure of discounted future net cash flows relating to the
Company's proved oil and gas reserves is calculated and presented in accordance
with Statement of Financial Accounting Standards No. 69. Accordingly, future
cash inflows were determined by applying year-end oil and gas prices (adjusted
for future fixed and determinable price changes) to the Company'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.
Future income taxes were derived by applying year-end statutory tax rates to the
estimated net future cash flows. A prescribed 10% discount factor was applied to
the future net cash flows.
In the Company's opinion, this standardized measure is not a representative
measure of fair market value, and the standardized measure presented for the
Company'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>
United States Indonesia South America Worldwide
---------------------------- ---------------------------- ---------------------------- ----------------------------
1993 1992 1991 1993 1992 1991 1993 1992 1991 1993 1992 1991
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Future cash
flows $1,781.2 $1,557.5 $1,582.1 $3,269.8 $3,538.7 $3,293.6 $700.9 $708.8 $365.8 $5,751.9 $5,805.0 $5,241.5
Future
production
and
development
cost (521.6) (457.0) (487.7) (2,258.1) (2,024.1) (1,915.2) (500.9) (423.5) (266.1) (3,280.6) (2,904.6) (2,669.0)
Future
income tax
expenses (152.4) (154.7) (255.7) (438.5) (707.1) (722.0) (81.9) (64.0) (20.5) (672.8) (925.8) (998.2)
---------------------------- ---------------------------- ---------------------------- ----------------------------
Future
net cash
flows 1,107.2 945.8 838.7 573.2 807.5 656.4 118.1 221.3 79.2 1,798.5 1,974.6 1,574.3
Annual
discount
at 10%
rate (414.0) (303.5) (193.6) (238.2) (342.8) (220.6) (85.0) (158.7) (65.9) (737.2) (805.0) (480.1)
---------------------------- ---------------------------- ---------------------------- ----------------------------
Standardized
measure of
discounted
future of
net cash
flows $ 693.2 $ 642.3 $ 645.1 $ 335.0 $ 464.7 $ 435.8 $ 33.1 $ 62.6 $ 13.3 $1,061.3 $1,169.6 $1,094.2
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The following are the principal sources for change in the standardized measure:
<TABLE>
<CAPTION>
1993 1992 1991
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
January 1 $1,169.6 $1,094.2 $1,708.2
Sales and transfers of oil and gas produced, net of production costs (399.6) (437.0) (526.8)
Net changes in prices and production costs (443.6) (29.1) (1,149.8)
Extensions, discoveries and improved recovery, less related costs 229.9 202.3 147.5
Previously estimated development costs incurred during the year 217.4 17.8 (59.8)
Revisions of previous quantity estimates 13.6 82.3 122.3
Purchase of reserves in place 18.8 30.3 84.4
Sale of reserves in place (.9) (10.0) (63.2)
Net change in income taxes 170.5 7.9 530.3
Accretion of discount 172.3 167.7 280.0
Other (86.7) 43.2 21.1
----------------------------
December 31 $1,061.3 $1,169.6 $1,094.2
- -----------------------------------------------------------------------------------------------------
</TABLE>
56
<PAGE>
FIVE-YEAR FINANCIAL SUMMARY
<TABLE>
<CAPTION>
1993 1992 1991 1990 1989
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
OPERATIONS
Sales and operating revenues $ 786.7 $ 718.4 $ 790.8 $ 685.4 $ 600.8
Net income (loss) before extraordinary item and
cumulative effect of change in accounting principle (37.9) 74.2 (11.2) 7.3 (31.0)
Extraordinary item (7.1)
Cumulative effect of change in accounting principle (4.4)
------------------------------------------------
Net income (loss) $ (49.4) $ 74.2 $ (11.2) $ 7.3 $ (31.0)
- ------------------------------------------------------------------------------------------------------------------------
FINANCIAL POSITION
Current assets $ 404.7 $ 391.2 $ 205.7 $ 232.9 $ 315.3
Current liabilities 263.4 327.9 249.3 260.4 276.8
Properties and equipment, less accumulated
depreciation and depletion 1,305.6 1,138.3 1,075.2 1,077.1 1,022.3
Total assets 1,987.4 1,811.6 1,451.5 1,470.2 1,477.8
Long-term debt, including
portion payable within one year 1,055.1 829.4 788.9 766.5 747.6
Deferred income taxes 198.3 152.9 142.9 145.6 125.6
Redeemable preferred stock 250.0 250.0 250.0 250.0 300.0
Stockholders' equity (deficit) 147.9 171.6 (55.9) (23.1) (56.7)
- ------------------------------------------------------------------------------------------------------------------------
OTHER DATA
Expenditures for properties and
equipment--including dry hole costs $ 340.0 $ 261.1 $ 272.3 $ 272.9 $ 165.8
Total exploration and development
expenditures (a) 373.8 253.7 300.0 309.2 184.7
Preferred dividends paid (b) 41.7 41.7 41.7 44.0 46.6
Depreciation, depletion and amortization 153.6 174.4 203.6 190.5 234.0
- ------------------------------------------------------------------------------------------------------------------------
PER COMMON SHARE
Net income (loss) before extraordinary item and
cumulative effect of change in accounting principle $ (.60) $ .27 $ (.52) $ (.38) $ (.86)
Extraordinary item (.05)
Cumulative effect of change in accounting principle (.03)
Net income (loss) $ (.68) $ .27 $ (.52) $ (.38) $ (.86)
- ------------------------------------------------------------------------------------------------------------------------
</TABLE>
(a) Whether capitalized or expensed.
(b) See "Preferred Stock" on page 45 for discussion of dividend restrictions.
57
<PAGE>
QUARTERLY DATA
<TABLE>
<CAPTION>
1993
-------------------------------------------------------------------------
March 31, June 30, September 30, December 31, For the Year
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Sales and operating revenues $ 192.0 $ 204.2 $ 193.1 $ 197.4 $ 786.7
Gross profit (a) 64.8 60.3 51.9 44.9 221.9
Net income (loss) before extraordinary item
and cumulative effect of
change in accounting principle .2 (3.9) (7.4) (26.8) (37.9)
Extraordinary item (3.2) (3.9) (7.1)
Cumulative effect of change in
accounting principle, as restated (4.4) (4.4)
Net income (loss), as reclassified (b) (4.2) (3.9) (10.6) (30.7) (49.4)
Net income (loss), as previously reported .2 (3.9) (10.6)
Per Common Share
Net income (loss) before extraordinary item
and cumulative effect of change in
accounting principle (.07) (.11) (.14) (.28) (.60)
Extraordinary item (.02) (.03) (.05)
Cumulative effect of change in
accounting principle, as restated (.03) (.03)
Net income (loss), as reclassified (b) (.10) (.11) (.16) (.31) (.68)
Net income (loss) as previously reported (.08) (.11) (.16)
Market price per share:
Common
High 9 3/4 10 3/8 9 3/4 7 3/8 10 3/8
Low 6 1/8 8 3/8 7 3/8 4 1/2 4 1/2
$4.00 Preferred
High 49 49 3/8 49 7/8 48 7/8 49 7/8
Low 42 5/8 46 1/4 47 1/8 40 40
$2.50 Preferred
High 25 25
Low 23 1/2 23 1/2
- --------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
1992
-------------------------------------------------------------------------
March 31, June 30, September 30, December 31, For the Year
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Sales and operating revenues $171.7 $170.1 $178.6 $198.0 $718.4
Gross profit (a) 58.3 61.1 66.3 60.4 246.1
Net income (loss) per Common Share (c) (.47) (.13) (.15) .86 .27
Market price per share
Common
High 8 1/4 7 1/4 7 3/8 7 1/2 8 1/4
Low 5 3/4 5 5/8 5 1/2 6 1/4 5 1/2
$4.00 Preferred
High 38 7/8 41 1/4 45 1/4 45 3/8 45 3/8
Low 33 3/4 37 1/4 40 1/2 41 7/8 33 3/4
- --------------------------------------------------------------------------------------------------------------------------
</TABLE>
(a) Gross profit is sales and operating revenues less purchases and operating
expenses, gas purchase costs and depreciation, depletion and amortization.
(b) Restated due to the adoption of SFAS 112, retroactive to first quarter 1993.
(c) Due to the Dividend Reinvestment and Stock Purchase Plan the public offering
of Common Stock in 1992, the weighted average number of Common Shares
outstanding used in calculating net income (loss) per Common Share varied
significantly between the individual quarters and for the year. As a
consequence of this share difference, along with the wide variation in
quarterly earnings, calculated net income (loss) per Common Share for 1992
does not equal the sum of the quarters.
58
<PAGE>
EXPLORATION AND PRODUCTION STATISTICS (historic)
<TABLE>
<CAPTION>
1993 1992 1991 1990 1989
- ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Net Proved Oil Reserves (millions of barrels)
United States 12.3 12.2 14.6 22.3 22.3
Indonesia 180.1 155.2 162.8 122.8 145.2
South America 71.6 53.1 27.5 20.8 20.6
--------------------------------------------------
Worldwide Total 264.0 220.5 204.9 165.9 188.1
Net Proved Natural Gas Reserves (billions of cubic feet)
United States 679 584 635 642 633
Indonesia 262 245 37 52 47
--------------------------------------------------
Worldwide Total 941 829 672 694 680
Net Oil Sales (mbpd)
United States 4.9 5.7 9.9 10.2 10.9
Indonesia 62.4 61.9 67.3 41.9 44.0
--------------------------------------------------
Worldwide Total 67.3 67.6 77.2 52.1 54.9
Average Oil Sales Price (per bbl)
United States $16.99 $18.28 $19.49 $22.26 $17.97
Indonesia 17.31 18.40 19.59 21.32 17.52
Worldwide Average 17.28 18.39 19.58 21.50 17.60
Net Natural Gas Sales (mmcfpd)
United States produced 181 200 207 234 236
United States purchased for processing 86 51 48 61 60
United States purchased for resale 98 29 13
Indonesia 13 8 7 7 10
--------------------------------------------------
Worldwide Total 378 288 275 302 306
Average Natural Gas Sales Price (per mcf)
United States produced $ 2.13 $ 1.80 $ 1.66 $ 1.77 $ 1.70
United States purchased for processing 1.91 1.62 1.49 1.70 1.60
United States purchased for resale 2.06 1.84 1.57
Indonesia 1.30 .20 .20 .20 .20
Worldwide Average 2.03 1.73 1.59 1.72 1.63
United States NGL Sales (mbpd)
Produced 7.6 8.9 8.8 8.5 9.3
Purchased 9.8 9.0 7.9 7.7 8.6
--------------------------------------------------
United States Total 17.4 17.9 16.7 16.2 17.9
United States Average NGL Sales Price (per bbl)
Produced $11.08 $11.51 $12.16 $13.48 $ 9.21
Purchased 11.19 11.13 12.04 13.64 9.34
United States Average 11.14 11.32 12.11 13.56 9.27
Indonesian NGL Sales (mbpd) 1.5 1.6 1.4 1.6 2.2
Indonesian Average NGL Sales Price (per bbl) $10.57 $11.93 $10.36 $10.51 $ 6.58
Net Natural Gas Production (mmcfpd)
United States 208 227 238 261 262
Gross Indonesian Crude Oil Production (mbpd) 270 294 324 212 193
- ---------------------------------------------------------------------------------------------------------------------
</TABLE>
59
<PAGE>
Exhibit 21.1
ORGANIZATIONAL LIST OF SUBSIDIARIES
MAXUS ENERGY CORPORATION
(Subsidiaries are shown as indented under their immediate parent.)
MAXUS ENERGY CORPORATION
Wheeling Gateway Coal Company
MAXUS INTERNATIONAL ENERGY COMPANY
Falcon Seaboard, Inc.
Maxus Angola, Inc.
Maxus Aru Inc.
Maxus Bolivia, Inc.
Maxus Bulgaria, Inc.
Maxus Chile, Inc.
Maxus China (C.I.) Ltd.
Maxus Colombia, Inc.
Diamond Shamrock China Petroleum Limited
Maxus Denmark, Inc.
Maxus Egypt, Inc.
Maxus Energy Co. (U.K.) Limited
Maxus Energy Global B.V.
Maxus Ethiopia, Inc.
Maxus Fifi Zaitun, Inc.
Maxus Gabon Inc.
Maxus International Services Company
Maxus Madagascar, Inc.
Maxus Mahdia East, Inc.
Maxus Morocco, Inc.
Maxus New Zealand Limited
Maxus North Sea, Inc.
Maxus Paraguay, Inc.
Maxus Slovakia, Inc.
Maxus Bratislava Association (50%)
Maxus Southeast Asia New Ventures, Inc.
Maxus Spain, Inc.
Maxus Tasmania, Inc.
Maxus Tunisia Inc.
Maxus Venezuela (C.I.) Ltd.
Natomas Company
Natomas Overseas Finance N.V.
Natomas Energy Company
Maxus Ecuador Inc.
Maxus Energy Trading Company
Maxus Northwest Java, Inc.
Maxus Southeast Sumatra Inc.
Natomas Trading Company
Thermal Power Company
Transworld Petroleum Corporation
1
<PAGE>
MAXUS EXPLORATION COMPANY
Maxus Gas Marketing Company
Maxus Industrial Gas Company
Maxus Offshore Exploration Company
Diamond Shamrock Offshore Partners Limited
Partnership (Partnership)
Diamond Shamrock Offshore Pipeline Company
Natomas North America, Inc.
Trice Properties, Inc.
MAXUS CORPORATE COMPANY
Biospecific Technologies, Inc.
Boja Realty Corp.
Quail Hollow Properties, Inc.
Chemical Land Holdings, Inc.
Crile Road Investments, Inc.
CSBWMD All Terrain Vehicles, Inc.
Delaware City Plastics Corporation
Diamond Alaska Coal Company
Granite Point Coal Port, Inc.
Diamond Gateway Coal Company
Gateway Coal Company (a Penn. Partnership)
Diamond Shamrock Europe Limited
Diamond Shamrock Venezolana, S.A.
Diatecnica Comercio e Participacoes Ltda. (99.99%)
DSC Acquisition, Inc.
DSC Holdings, Inc.
DSC Investment Management Company
DSC Receivables, Inc.
DST Corporation
Duolite International, Inc.
Emerald Mining Company
Gateway Land Company
Greenstone Assurance Ltd.
Insulating Aggregates, Inc.
Leon Properties, Inc. (d/b/a Riverside Farms)
RMC Securities, Inc.
Lone Creek Coal Company
Maxus Agricultural Chemicals, Inc.
DSC Products International, Inc.
Fint Corporation
DS Investments, S.A.
Maxus Aviation Company
Maxus International Corporation
Maxus Realty Company
OCV Corporation
QHRP Investments, Inc.
The Harbor Land Company
Tidewater Services Corporation
V.E.P. Corporation
2
<PAGE>
EXHIBIT 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Prospectuses
constituting parts of the Registration Statements on Form S-3 (Nos. 33-41663,
33-46307 and 33-61350, respectively) and the Registration Statements on Form S-8
(Nos. 2-85403, 33-6693, 33-28353, 33-47538, 33-55938 and 33-55918,
respectively), and any existing amendments thereto, of Maxus Energy Corporation
of our report dated February 22, 1994 appearing on Page 51 of the 1993 Annual
Report to Stockholders which is incorporated in this Annual Report on Form 10-K.
We also consent to the incorporation by reference of our report on the Financial
Statement Schedules, which appears on page 20 of this Form 10-K.
PRICE WATERHOUSE
Dallas, Texas
March 25, 1994
<PAGE>
Exhibit 24.1
POWER OF ATTORNEY
THE STATE OF TEXAS
KNOW ALL MEN BY THESE PRESENTS:
COUNTY OF DALLAS
That each undersigned hereby constitutes and appoints Lynne P. Ciuba, H. R.
Smith and David A. Wadsworth, and each of them, his true and lawful attorney or
attorneys-in-fact with full power of substitution and resubstitution, for him
and in his name, place and stead, to sign on his behalf as a director or
officer, or both, as the case may be, of Maxus Energy Corporation (the
"Corporation") the Corporation's Form 10-K Annual Report pursuant to Section 13
of the Securities Exchange Act of 1934, as amended, for fiscal year ended
December 31, 1993, and to sign any or all amendments to such Form 10-K, and to
file the same, with all exhibits thereto, and other documents in connection
therewith, with the Securities and Exchange Commission, granting unto said
attorney or attorneys-in-fact, and to each of them, full power and authority to
do and perform each and every act and thing requisite and necessary to be done
in and about the premises, as fully to all intents and purposes as he might or
could do in person, hereby ratifying and confirming all that said attorney or
attorneys-in-fact or any of them or their substitute or substitutes may lawfully
do or cause to be done by virtue hereof.
January 25, 1994
J. DAVID BARNES CHARLES W. HALL
- ------------------------- -------------------------
J. David Barnes Charles W. Hall
DARRELL L. BLACK RAYMOND A. HAY
- ------------------------- -------------------------
Darrell L. Black Raymond A. Hay
CHARLES L. BLACKBURN GEORGE L. JACKSON
- ------------------------- -------------------------
Charles L. Blackburn George L. Jackson
B. CLARK BURCHFIEL JOHN T. KIMBELL
- ------------------------- -------------------------
B. Clark Burchfiel John T. Kimbell
BRUCE B. DICE RICHARD W. MURPHY
- ------------------------- -------------------------
Bruce B. Dice Richard W. Murphy
M. C. FORREST W. THOMAS YORK
- ------------------------- -------------------------
M. C. Forrest W. Thomas York
G. R. BROWN M. J. BARRON
- ------------------------- -------------------------
G. R. Brown M. J. Barron
