-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, r3qk6xTTPOSKPGg2rV+f5rDk+lRK7jABBa6yac20OcOHAObB0x4PhJGciP02+d8k nfSQ4VLAO8IGkusHbp7nAw== 0000950131-94-000391.txt : 19940328 0000950131-94-000391.hdr.sgml : 19940328 ACCESSION NUMBER: 0000950131-94-000391 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940325 FILER: COMPANY DATA: COMPANY CONFORMED NAME: MAXUS ENERGY CORP /DE/ CENTRAL INDEX KEY: 0000724176 STANDARD INDUSTRIAL CLASSIFICATION: 1311 IRS NUMBER: 751891531 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-08567 FILM NUMBER: 94517851 BUSINESS ADDRESS: STREET 1: 717 N HARWOOD ST- RM 3147 CITY: DALLAS STATE: TX ZIP: 75201-6594 BUSINESS PHONE: 2149532000 FORMER COMPANY: FORMER CONFORMED NAME: DIAMOND SHAMROCK CORP /DE/ DATE OF NAME CHANGE: 19870518 FORMER COMPANY: FORMER CONFORMED NAME: NEW DIAMOND CORP DATE OF NAME CHANGE: 19830908 10-K 1 10K - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 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:
NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- --------------------- 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
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. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 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 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 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:
YEAR ENDED DECEMBER 31, ----------------------- 1993 1992 1991 ------- ------- ------- 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
- -------- (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 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.
YEAR ENDED DECEMBER 31, ----------------------- 1993 1992 1991 ------- ------- ------- 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
- -------- (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.
YEAR ENDED DECEMBER 31, ----------------------- 1993 1992 1991 ------- ------- ------- 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
4 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:
GROSS NET ----- ------ 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 ==== ======
At December 31, 1993, total gross and net developed and undeveloped acreage by geographic area was as follows:
SOUTH AMERICA UNITED AND OTHER STATES INDONESIA FOREIGN --------- --------- ------------- 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 ========= ========= ==========
5 Drilling activities of the Company for the three years ended December 31, 1993 are summarized by geographic area in the following table:
YEAR ENDED DECEMBER 31, ----------------------- 1993 1992 1991 ------- ------- ------- 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 ======= ======= =======
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 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 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 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 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 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.
SERVED AS AN OFFICER NAME POSITION WITH THE COMPANY AGE SINCE ---- ------------------------- --- ------- 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
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 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 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 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. 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).*
14 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).*
15 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).*
16 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.)*
(b) Reports on Form 8-K.
ITEMS DATE OF REPORT REPORTED -------------- ------------- October 20, 1993 Items 5 and 7 November 18, 1993 Items 5 and 7
17 SCHEDULE V MAXUS ENERGY CORPORATION CONSOLIDATED PROPERTIES AND EQUIPMENT THREE YEARS ENDED DECEMBER 31, 1993 (DOLLARS IN MILLIONS)
OIL & GAS ---------------------------- PROVED UNPROVED PROPERTIES PROPERTIES OTHER CORPORATE TOTAL ---------- ---------- ------ --------- -------- 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 ======== ===== ====== ====== ========
18 SCHEDULE VI MAXUS ENERGY CORPORATION CONSOLIDATED ACCUMULATED DEPRECIATION AND DEPLETION THREE YEARS ENDED DECEMBER 31, 1993 (DOLLARS IN MILLIONS)
OIL & GAS --------------------------- PROVED UNPROVED PROPERTIES PROPERTIES OTHER CORPORATE TOTAL ---------- ---------- ----- --------- -------- 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 ======== ===== ===== ===== ========
19 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 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 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 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. EX-10.10 2 AMEND. EMPLOYEE SHAR. INVS. 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 EX-10.17 3 DEFER. COMP PLAN FOR EXEC 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 "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 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 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 (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 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 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 (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 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 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 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 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 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 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 EX-12.1 4 STATE. COMP. RATIOS Exhibit 12.1 MAXUS ENERGY CORPORATION STATEMENT COMPUTATION OF RATIOS (in millions, except ratios)
Twelve Months Ended Dec. 31, 1993 ---------------- 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)
(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 EX-13.1 5 ANNUAL REP. FINANCIALS EXHIBIT 13.1 Financial Contents 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
25 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:
million of dollars 1993 1992 - ----------------------------------------------- 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) - -----------------------------------------------
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 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 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 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 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 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 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
Year Ended December 31, 1993 1992 1991 - -------------------------------------------------------------------------------------- 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
See Notes to Consolidated Financial Statements. 33 CONSOLIDATED BALANCE SHEET (in millions)
December 31, 1993 1992 - ------------------------------------------------------------------------------- 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 ======================
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 CONSOLIDATED STATEMENT OF CASH FLOWS (in millions)
Year Ended December 31, 1993 1992 1991 - --------------------------------------------------------------------------------------------------- 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 ===============================
See Notes to Consolidated Financial Statements. 35 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:
1993 1992 1991 - -------------------------------------------------------- Interest income $11.3 $ 6.4 $ 1.7 Interest expense 82.0 80.9 78.0 Income taxes 73.4 104.1 143.1 - --------------------------------------------------------
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 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 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 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:
Sales and Operating Revenues 1993 1992 1991 - ------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------
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:
1993 1992 1991 - -------------------------------------------------------------------------------- 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 - --------------------------------------------------------------------------------
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:
1993 1992 1991 - -------------------------------------------------------------------------------- United States $ (89.4) $ 31.5 $(101.4) Foreign 135.7 145.2 220.3 -------------------------------- $ 46.3 $ 176.7 $ 118.9 - --------------------------------------------------------------------------------
The Company's provision for income taxes was comprised of the following:
1993 1992 1991 - -------------------------------------------------------------------------------- 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 - --------------------------------------------------------------------------------
39 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:
1993 1992 1991 - ------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------
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:
December 31 January 1 - ------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------
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:
1992 1991 - ------------------------------------------------------------------------- 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) - -------------------------------------------------------------------------
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:
1993 1992 1991 - ------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------
NOTE SEVEN POSTEMPLOYMENT BENEFITS Pensions
1993 1992 1991 - ------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------
40 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:
1993 1992 - -------------------------------------------------------------------------------- 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% - --------------------------------------------------------------------------------
The funded status of the plans at December 31, 1993 and 1992 is as follows:
Accumulated Assets Accumulated Benefits Exceeding Benefits Exceeding Accumulated Exceeding Assets Benefits Assets 1993 1992 1992 - -------------------------------------------------------------------------------- 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) - --------------------------------------------------------------------------------
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:
1993 - -------------------------------------------------------------------------------- Service cost-benefits earned during period $ .4 Interest cost on accumulated postretirement benefit obligation 3.9 Amortization of transition obligation 2.3 --------- $ 6.6 - --------------------------------------------------------------------------------
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: - ------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------
41 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:
1993 Carrying Fair Amount Value - -------------------------------------------------------- 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 - -------------------------------------------------------- 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 - -------------------------------------------------------- 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 - --------------------------------------------------------
42
NOTE TEN PROPERTIES AND EQUIPMENT 1993 1992 - ----------------------------------------------------------- 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 - -----------------------------------------------------------
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.
NOTE ELEVEN INVESTMENTS AND LONG-TERM RECEIVABLES 1993 1992 - ----------------------------------------------------------- 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 - -----------------------------------------------------------
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:
1993 1992 1991 - ----------------------------------------------------------- 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 - -----------------------------------------------------------
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
NOTE FOURTEEN ACCRUED LIABILITIES 1993 1992 - ------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------
NOTE FIFTEEN LONG-TERM DEBT AND CREDIT ARRANGEMENTS
1993 1992 - ------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------
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:
1993 1992 1991 - ------------------------------------------------------------------------- Interest and debt expenses $ 88.4 $ 86.9 $ 88.4 Capitalized interest 7.5 4.6 2.0 --------------------------------------- $ 95.9 $ 91.5 $ 90.4 - -------------------------------------------------------------------------
44 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 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
Shares Amount - ------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------
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 NOTE EIGHTEEN PAID-IN CAPITAL AND ACCUMULATED DEFICIT
Paid-In Accumulated Capital Deficit - -------------------------------------------------------------------------------- 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) - --------------------------------------------------------------------------------
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
Shares Amount - -------------------------------------------------------------------------------- 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) - --------------------------------------------------------------------------------
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 Stock option activity was as follows:
1993 1992 1991 - --------------------------------------------------------------------------- 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 - ---------------------------------------------------------------------------
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:
1994 $ 39.3 1995 23.2 1996 10.3 1997 9.3 1998 5.7 1999 and thereafter 35.4 - ------------------------------------------------------- $123.2
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:
1993 1992 1991 - ------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------
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 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 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 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 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.
United States Indonesia -------------------------- -------------------------- 1993 1992 1991 1993 1992 1991 - ----------------------------------------------------------------------------------- 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 - -----------------------------------------------------------------------------------
South America Other Foreign Worldwide -------------------------- -------------------------- -------------------------- 1993 1992 1991 1993 1992 1991 1993 1992 1991 - ------------------------------------------------------------------------------------------------------------------ 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
(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 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:
United States Indonesia ---------------------------- ---------------------------- 1993 1992 1991 1993 1992 1991 - ------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------
South America Other Foreign Worldwide ---------------------------- ---------------------------- ---------------------------- 1993 1992 1991 1993 1992 1991 1993 1992 1991 - ------------------------------------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------------------------------------
COSTS INCURRED Costs incurred by the Company in its oil and gas producing activities (whether capitalized or charged against earnings) were as follows:
United States Indonesia ---------------------------- ---------------------------- 1993 1992 1991 1993 1992 1991 - ------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------
South America Other Foreign Worldwide ---------------------------- ---------------------------- ---------------------------- 1993 1992 1991 1993 1992 1991 1993 1992 1991 - ------------------------------------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------------------------------------
53 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.
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 - --------------------------------------------------------------------------------------------------------------------------- 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 - ---------------------------------------------------------------------------------------------------------------------------
1993 1992 1991 -------------------------- -------------------------- -------------------------- Natural Gas(b) United United United (billions of cubicfeet) States Indonesia Total States Indonesia Total States Indonesia Total - --------------------------------------------------------------------------------------------------------------------------- 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 - ---------------------------------------------------------------------------------------------------------------------------
54
1993 1992 1991 ---------------------------- ---------------------------- ---------------------------- Natural Gas Liquids United United United (millions of barrels) States Indonesia Total States Indonesia Total States Indonesia Total - ----------------------------------------------------------------------------------------------------------------------------------- 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 - -----------------------------------------------------------------------------------------------------------------------------------
(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 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.
United States Indonesia South America Worldwide ---------------------------- ---------------------------- ---------------------------- ---------------------------- 1993 1992 1991 1993 1992 1991 1993 1992 1991 1993 1992 1991 - ----------------------------------------------------------------------------------------------------------------------------------- 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 - -----------------------------------------------------------------------------------------------------------------------------------
The following are the principal sources for change in the standardized measure:
1993 1992 1991 - ----------------------------------------------------------------------------------------------------- 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 - -----------------------------------------------------------------------------------------------------
56 FIVE-YEAR FINANCIAL SUMMARY
1993 1992 1991 1990 1989 - ------------------------------------------------------------------------------------------------------------------------ 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) - ------------------------------------------------------------------------------------------------------------------------
(a) Whether capitalized or expensed. (b) See "Preferred Stock" on page 45 for discussion of dividend restrictions. 57 QUARTERLY DATA
1993 ------------------------------------------------------------------------- March 31, June 30, September 30, December 31, For the Year - -------------------------------------------------------------------------------------------------------------------------- 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 - --------------------------------------------------------------------------------------------------------------------------
1992 ------------------------------------------------------------------------- March 31, June 30, September 30, December 31, For the Year - -------------------------------------------------------------------------------------------------------------------------- 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 - --------------------------------------------------------------------------------------------------------------------------
(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 EXPLORATION AND PRODUCTION STATISTICS (historic)
1993 1992 1991 1990 1989 - --------------------------------------------------------------------------------------------------------------------- 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 - ---------------------------------------------------------------------------------------------------------------------
59 EX-21.1 6 LIST OF SUBSIDIARIES 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 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 EX-23.1 7 CONSENT INDEP. ACCOUNTANT 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 EX-24.1 8 POWER OF ATTORNEY 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 -----END PRIVACY-ENHANCED MESSAGE-----