ITEM 3. LEGAL PROCEEDINGS.
In connection with the tender offer by YPFA Corp. and Merger, a number of holders of Common Stock sued in the Chancery Court of the State of Delaware. In the various complaints, the plaintiffs purported to sue individually and on behalf of classes comprised of the holders of shares of Common Stock, stockholders of the Company or all holders of the Company's securities. The complaints named as defendants the Company, the directors and certain of the officers of the Company, a former director of the Company and, with respect to some of the complaints, YPF, and alleged, among other things, that the defendant directors and officers of the Company breached their fiduciary duties in approving the Offer and the Merger and that YPF aided and abetted the alleged breach of duties. The plaintiffs purported to seek orders enjoining the consummation of the Offer and the Merger (or the rescission of those transactions) or, in the alternative, an accounting for any damages to the alleged classes, together with their attorneys' fees and other relief. These lawsuits were consolidated into one action and, in September 1995, were settled with no payment to the class members. However, as a part of the settlement, the Company was ordered to pay $800,000 in attorneys' fees to the plaintiffs' class counsel.
In November 1995, OxyChem filed suit in Texas state court seeking a declaration of certain of the parties' rights and obligations under the sales agreement pursuant to which the Company sold Chemicals to Occidental. Henkel joined in said lawsuit as a plaintiff in January 1996. Specifically, OxyChem and Henkel are seeking a declaration that the Company is required to indemnify them for 50% of certain environmental costs incurred on projects involving remedial activities relating to chemical plant sites or other property used in connection with the business of Chemicals on the Closing Date which relate to, result from or arise out of conditions, events or circumstances discovered by OxyChem or Henkel and as to which the Company is provided written notice by OxyChem or Henkel prior to the expiration of ten years following the Closing Date, irrespective of when OxyChem or Henkel incurs and gives notice of such costs, subject to an aggregate $75 million cap. The Company believes that this lawsuit is without merit and intends to defend same vigorously.
As of December 31, 1995, the Company had paid OxyChem and Henkel a total of approximately $39 million against said $75 million cap. The Company cannot predict what portion of the approximately $36 million remaining as of that date Occidental and Henkel may actually pay or incur prior to September 4, 1996, the tenth anniversary of the Closing Date, if they accelerate spending with respect to such environmental costs.
See also the heading "Health, Safety and Environmental Controls" under "Items 1 and 2. Business and Properties" of this report for a description of certain other legal proceedings, which description is incorporated herein by reference.
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.

ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS.
Inapplicable.
PART II
ITEM 5.

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
There is no established public trading market for the Common Stock. At March 1, 1996, YPF was the sole holder of record of the Common Stock.
Midgard and Maxus Indonesia, Inc., subsidiaries of the Company, are parties to separate credit agreements which places certain restrictions on the ability of these subsidiaries to make or declare certain payments, advances and loans specified therein, including dividends to the Company. (For a further description of these credit agreements, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations--Significant Events 1995"). While these restrictions could impact the ability of the Company to pay dividends on its Common Stock, the Company has paid no such dividends since 1987, and cash flows are currently being dedicated to exploration and development projects rather than to such payment. The Company intends to continue paying regular quarterly dividends on its $4.00 Preferred Stock, $9.75 Cumulative Convertible Preferred Stock ("$9.75 Preferred Stock") and $2.50 Preferred Stock.
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA.
FIVE-YEAR FINANCIAL SUMMARY (DOLLARS IN MILLIONS, EXCEPT FOR PER SHARE DATA)
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Significant Events 1995
On June 8, 1995, a special meeting of the stockholders of Maxus Energy Corporation (the "Company" or "Maxus") was held to approve the Agreement of Merger ("Merger Agreement") dated February 28, 1995, between the Company, YPF Acquisition Corp. (the "Purchaser" or "YPFA Corp.") and YPF Sociedad Anonima ("YPF"). The holders of the Company's common stock, $1.00 par value per share (the "Shares"), and $4.00 Cumulative Convertible Preferred Stock (the "$4.00 Preferred Stock" and together with the Shares, the "Voting Shares") approved the Merger Agreement, and the Purchaser was merged into the Company (the "Merger") on June 8, 1995 (the "Merger Date").
Pursuant to the Merger Agreement, a tender offer (the "Offer") was commenced on March 6, 1995 by the Purchaser for all the outstanding Shares at $5.50 per Share. Pursuant to the Offer, in April 1995 the Purchaser acquired 120,000,613 Shares representing approximately 88.5% of the then-outstanding Shares of the Company. As a result of the Merger, each outstanding Share (other than Shares held by the Purchaser, YPF or any of their subsidiaries or in the treasury of the Company, all of which were cancelled in the second quarter of 1995, and Shares of holders who perfected their appraisal rights under Section 262 of the Delaware General Corporation Law) was converted into the right to receive $5.50 in cash, and YPF became the sole holder of all outstanding Shares. The Company's preferred stock, consisting of the $4.00 Preferred Stock, $2.50 Cumulative Preferred Stock (the "$2.50 Preferred Stock") and $9.75 Cumulative Convertible Preferred Stock (the "9.75 Preferred Stock"), remain outstanding. YPF currently owns approximately 96.9% of the outstanding Voting Shares.
The total amount of funds required by the Purchaser to acquire the entire common equity interest in the Company, including the purchase of Shares pursuant to the Offer and the payment for Shares converted into the right to receive cash pursuant to the Merger, was approximately $762 million. On April 5, 1995, the Purchaser entered into a credit agreement (the "Credit Agreement") with lenders for which The Chase Manhattan Bank (National Association) ("Chase") acted as agent, pursuant to which the lenders extended to the Purchaser a credit facility for up to $550 million (the "Purchaser Facility"). On April 5, 1995, the Purchaser borrowed $442 million under the Purchaser Facility and received a capital contribution of $250 million from YPF. The Purchaser used borrowings under the Purchaser Facility and the funds contributed to it by YPF to purchase 120,000,613 Shares pursuant to the Offer. Subsequent to the Merger, these Shares and all other outstanding Shares vested in YPF.
Following the Merger, Chase provided two additional credit facilities aggregating $425 million: (i) a credit facility of $250 million extended to Midgard Energy Company ("Midgard"), a wholly owned subsidiary of the Company, and (ii) a credit facility of $175 million extended to Maxus Indonesia, Inc. ("Holdings"), a wholly owned subsidiary of the Company. The proceeds of the loans made pursuant to these facilities were used to repay, in part, the Purchaser Facility, which was assumed by the Company pursuant to the Merger. In addition, the Company applied $8 million of its available cash to repayment of the Purchaser Facility and used approximately $86 million of its available cash to pay holders of Shares converted into the right to receive cash in the Merger.
Effective April 1, 1995, the Company used the purchase method of accounting to record the acquisition of the Company by YPF. In a purchase method combination, the purchase price is allocated to the acquired assets and assumed liabilities based on their fair values at the date of acquisition. As a result, the assets and liabilities of the Company were revalued to reflect the approximate $762 million cash purchase price paid by YPF to acquire the Company. The Company's oil and gas properties were assigned carrying amounts based on their relative fair market values. The Company's pre-Merger Consolidated Balance Sheet as of March 31, 1995, together with the purchase method accounting adjustments, became the Company's opening post-Merger Consolidated Balance Sheet on April 1, 1995. Because of these purchase adjustments, which were effected April 1, 1995, the Company's financial statements for the nine-month period ended December 31, 1995, are not comparable to such statements for prior periods. Accordingly, separate financial statements for periods prior to April 1, 1995 and for the nine-month period ended December 31, 1995 are presented.
Significant Events 1994
Maxus responded to many financial and operational challenges in 1994 which culminated with the Company's agreement to merge with YPF in 1995.
Financially, significant natural gas and crude oil price declines in 1994 contributed to Maxus' decision to streamline operations by decreasing overhead and operating expenses, lowering program spending and redeeming certain preferred stock. During the second quarter of 1994, the Company also sold its interest in Diamond Shamrock Offshore Partners Limited Partnership ("Offshore Partners") and certain producing oil and gas properties in Maxus' U.S. Southern Division for $325 million net ("the Divested Properties"). Additionally, the Company sold its geothermal subsidiary, Thermal Power Company, for approximately $58 million net in cash and a note for $6.5 million. A portion of the proceeds from these sales was used to reduce debt and redeem 625,000 shares of the $9.75 Preferred Stock for $63 million.
Operationally, the Company initiated production from all three of Maxus' South American operations--Ecuador, Bolivia and Venezuela. The Sunray gas plant experienced its first full year of operation and achieved the operating efficiencies and cost savings (approximately $14 million annually) that had been anticipated. Additionally, net production from the Northwest Java gas project averaged approximately 44 million cubic feet per day ("mmcfpd") during 1994, resulting in $30 million of additional revenues.
Results for the Nine Months Ended December 31, 1995
For the nine months ended December 31, 1995, Maxus reported a net loss of $74 million. Comparative information for the nine months ended December 31, 1994, is not presented due to the Merger with YPF which was effective April 1, 1995.
Sales and Operating Revenues. Sales and operating revenues for the nine months ended December 31, 1995, were $464 million composed of $298 million from Maxus' Indonesian operations, $129 million from U.S. operations and $37 million from South American operations.
Maxus' net worldwide crude oil sales volumes were 64 thousand barrels per day ("mbpd") during the nine-month period ended December 31, 1995, which were comprised of 53 mbpd from Maxus' Indonesian operations, 10 mbpd from South American operations and one mbpd from U.S. operations. Maxus' net worldwide crude oil sales volumes increased from 60 mbpd in the third quarter of 1995 to 73 mbpd in the fourth quarter of 1995 due primarily to the recognition of cumulative year-to-date production from the Southern Amo Field in Ecuador in the fourth quarter of 1995, as this production had not previously been approved by the Ecuadorian government, and the sole crude oil sale in Bolivia in October 1995. Despite natural declines in gross crude oil production in Indonesia over the nine months ended December 31, 1995, Indonesian crude oil sales volumes increased slightly due primarily to higher cost recovery. During the nine months ended December 31, 1995, Maxus' average worldwide crude oil price was $16.31 per barrel.
During the nine-month period ended December 31, 1995, U.S. natural gas sales volumes were 172 mmcfpd and U.S. natural gas prices averaged $1.49 per thousand cubic feet ("mcf"). Although U.S. natural gas sales volumes remained relatively flat over the nine months ended December 31, 1995, the success of the 1995 Midgard infill drilling program offset the natural declines from the area. In the future, Maxus expects its Midgard infill drilling program to continue to offset any natural declines. U.S. natural gas prices rose from $1.40 per mcf in the third quarter of 1995 to $1.64 per mcf in the fourth quarter of 1995 which favorably impacted revenues $4 million. During the nine-month period ended December 31, 1995, Northwest Java natural gas sales volumes were 61 mmcfpd and Northwest Java natural gas prices averaged $2.62 per mcf.
Natural gas liquids sales volumes in the U.S. were 18 mbpd and U.S. natural gas liquids prices averaged $10.49 per barrel.
Costs and Expenses. Costs and expenses were $536 million during the nine months ended December 31, 1995. Costs and expenses during this period included operating expenses of $174 million; gas purchase costs of
$41 million; exploration expenses of $51 million; depreciation, depletion and amortization ("DD&A") of $142 million; interest and debt expenses of $105 million and other costs and expenses totaling $23 million.
DD&A of $142 million during the nine-month period ended December 31, 1995, included $43 million of additional DD&A reflecting the impact of the purchase price allocation which increased the book value of the Company's oil and gas properties and equipment. The book value of oil and gas properties and equipment increased approximately $1.3 billion as a result of the purchase price allocation.
In the nine-month period ended December 31, 1995, interest and debt expenses of $105 million included $27 million of interest expense associated with the Purchaser Facility and, Midgard and Holdings credit facilities. Also included in interest and debt expenses during this period was $6 million of interest associated with the accretion of discount on the Company's long-term debt which was outstanding prior to the Merger. These borrowings were recorded at their fair market value in the purchase method of accounting which resulted in a reduction in their carrying value of $115 million. This reduction in carrying value will be amortized to interest expense over the remaining term of the borrowings.
Other Revenues, Net. During the nine months ended December 31, 1995, other revenues, net were $7 million which included $10 million of interest income, a $2 million gain which represented the final settlement of the Company's sole interest rate swap agreement prior to its termination and a $2 million gain recognized on the sale of U.S. Treasury notes partially offset by a $3 million production bonus payment stemming from the Company's Indonesian operations and $5 million of accrued expenses. In the future, the Company anticipates recognizing less interest income as a result of maintaining only minimal balances of cash, cash equivalents and short-term investments to cover working capital fluctuations. Capital contributions from YPF are expected to cover any additional funding needs.
Income Taxes. Income tax expense of $9 million for the nine-month period ended December 31, 1995, included $63 million of current foreign income tax expense primarily from Indonesian operations partially offset by a $49 million deferred tax benefit due primarily to the higher DD&A associated with the increase in book value of the Company's oil and gas properties and equipment as a result of the purchase price allocation. In addition, the Company received $5 million of interest income on U.S. federal income tax refunds. This interest income was not previously accrued in prior periods. In the future, the Company expects to realize additional deferred tax benefits as a result of the higher DD&A.
Comparison of Results
Three Months Ended March 31, 1995 vs. Three Months Ended March 31, 1994
Maxus reported a net loss of $57 million for the first quarter of 1995 compared to a net loss of $11 million for the first quarter of 1994. The first quarter 1995 results reflect $42 million of pre-Merger costs incurred by the Company prior to the Merger. Such costs included expenses associated with financial consulting and legal services, severance payments pursuant to change of control agreements and payments for surrender of stock options and restricted stock.
Sales and Operating Revenues. Sales and operating revenues for the first quarter of 1995 were $143 million, compared to $187 million for the same 1994 period. The loss of production from the Divested Properties which were sold in the second quarter of 1994 and lower volumes of purchased gas accounted for $45 million of the revenue decline. Additionally, U.S. natural gas prices fell, which also unfavorably impacted revenues $12 million for the three months ended March 31, 1995. These declines were partially offset by first quarter 1995 revenue of $8 million from South America. Initial sales from the Company's South American operations were recorded in the third quarter 1994.
Net worldwide crude oil production was 60 mbpd in the first quarter 1995, compared to 69 mbpd in the same quarter a year ago. Domestic crude oil volumes declined four mbpd during the period due to the loss of production from the Divested Properties resulting in lower revenues of $5 million. Crude oil sales from the Company's Indonesian operations were also down 12 mbpd during the period primarily as a result of lower entitlements due to higher crude oil sales prices and lower production. Offsetting these declines, production from South America of seven mbpd provided an additional $8 million of revenues in 1995.
U. S. natural gas sales for the first quarter of 1995 were 167 mmcfpd, a decrease of 208 mmcfpd as compared to the first quarter 1994 resulting in lower revenues of $42 million. The decline was driven by the loss of production from the Divested Properties and lower volumes of gas purchased for resale. The average gas price received in the U. S. was $1.45 per mcf in the first quarter 1995 as compared to $2.24 per mcf in the same 1994 period.
Northwest Java natural gas volumes of 40 mmcfpd in the first quarter 1995 were eight mmcfpd higher than the first quarter 1994. Natural gas sales prices improved to an average of $2.65 per mcf during the first quarter 1995 from $1.81 per mcf during the same period last year due to the change in contract terms which increased the price received for "old" gas production from $0.20 per mcf to $2.65 per mcf effective January 1, 1995. The higher Northwest Java natural gas volumes coupled with the higher average natural gas price resulted in increased revenues of $4 million in the first quarter of 1995.
Natural gas liquids sales in the U. S. for the first quarter 1995 were 18 mbpd, a slight decrease over first quarter last year. The average sales price for U.S. natural gas liquids in the first quarter of 1995 was $10.38 per barrel, an increase of $1.15 per barrel from 1994.
Costs and Expenses. Costs and expenses for the first quarter of 1995 were $190 million which were relatively flat compared to the first quarter of 1994. Costs and expenses for the first quarter of 1995 included Maxus pre-Merger costs of $42 million which were partially offset by lower gas purchase costs of $31 million when compared to the first quarter of 1994.
Gas purchase costs were $31 million lower in the first quarter of 1995 as compared to first quarter 1994 due to the lower volumes of gas purchased to aggregate with the production from the Divested Properties, the reduction in volumes of gas purchased for resale and lower natural gas prices.
DD&A of $30 million for the first quarter 1995 was $8 million lower than the same period of the prior year. Approximately $11 million of this decline represents DD&A from the Divested Properties included in the first quarter of 1994. Partially offsetting this decline was $4 million of DD&A in the first quarter of 1995 associated with South American operations which did not go into production until late 1994.
Income Taxes. Income tax expense was $19 million and $16 million in the first quarters of 1995 and 1994, respectively. The increase in income tax expense was primarily due to higher Indonesian taxes as a result of increased taxable income from the Company's Indonesian operations.
Comparison of Results
Twelve Months Ended December 31, 1994 vs. Twelve Months Ended December 31,
Maxus reported a net loss of $23 million in 1994 compared to a net loss of $49 million in 1993.
Sales and Operating Revenues. Sales and operating revenues dropped 13%, or $105 million, during 1994 when compared to 1993. The loss of production from the Divested Properties and lower volumes of purchased gas which were aggregated and sold with the production from the Divested Properties accounted for $86 million of the revenue decline. Additionally, worldwide oil and gas prices fell, which further compounded the loss of revenues. However, initial production from South America and new gas production from Northwest Java added $54 million to revenues during 1994, partially offsetting the overall negative revenue variances.
The Company's total net crude oil production was 67 mbpd in 1994, essentially flat compared to 1993. Production from South American operations added five mbpd during 1994 and favorably impacted revenues by $24 million. Crude oil volumes in the United States declined three mbpd, resulting in a $15 million negative volume variance, primarily from the loss of production from the Divested Properties. Crude oil sales from the Company's Indonesian operations were also down approximately three mbpd ($20 million negative volume variance), primarily in Northwest Java. A portion of the 1994 decline was the result of temporary production problems, which were corrected. Also, the 1993 volumes in Northwest Java reflected additional barrels received through cost recovery due to the substantial capital outlay for the gas project, which was completed in late 1993. Maxus' 1994 average worldwide crude price hit a five-year low of $15.31 per barrel, negatively impacting income by $39 million.
United States natural gas sales volumes fell from 365 mmcfpd to 275 mmcfpd in 1994 with the decline attributable to the loss of production from the Divested Properties and the decrease in purchased gas volumes which were aggregated and sold with the production from the Divested Properties. The decline was partially offset by increased sales volumes of nine mmcfpd from Midgard. United States natural gas revenues declined approximately $83 million during 1994, with $68 million occurring as a result of the Divested Properties and $14 million attributable to declining prices. Maxus' United States natural gas prices averaged $1.95 per mcf in 1994 and $2.08 per mcf in 1993.
Northwest Java gas volumes increased from 13 mmcfpd in 1993 to 44 mmcfpd during 1994. The Company realized an additional $30 million of revenues during 1994 from the Northwest Java gas project, which came on stream in fourth quarter 1993.
Natural gas liquids sales in the United States increased slightly from 17.4 mbpd to 17.9 mbpd in 1994 but average prices received declined from $11.14 per barrel in 1993 to $10.07 per barrel. Overall, liquids revenues were down $5 million compared to 1993 due to the price declines.
Costs and Expenses. Costs and expenses, excluding restructuring, were $728 million in 1994 compared to $781 million in 1993. The decline was primarily due to the elimination of expenses related to the Divested Properties.
Overall, operating expenses were down $21 million, of which approximately $15 million related to the Divested Properties. Operating expenses declined in Indonesia as well as in the United States, but were partially offset by the additional operating expenses incurred in South America due to the start-up of production in Ecuador, Bolivia and Venezuela.
Gas purchase costs were $39 million lower than 1993 primarily as a result of lower purchased gas prices and the reduction in volumes of purchased gas which were previously aggregated and sold with the production from the Divested Properties.
Exploration expenses were $24 million lower than 1993 due to management's decision to curtail exploratory spending in new frontiers during 1994. The Company had previously announced its decision to concentrate spending in its core areas of the United States and Indonesia and its emerging areas in South America.
DD&A declined $13 million in 1994. The Divested Properties created a $32 million favorable variance. Partially offsetting this favorable variance was a $7 million increase in DD&A in South America due to the start-up of production in Ecuador, Bolivia and Venezuela. DD&A in Indonesia was also up $13 million as a result of higher DD&A rates and additional depreciation from the Northwest Java gas project, which came on-stream in fourth quarter 1993.
The Company increased its reserve for environmental liabilities in 1994 by $60 million, primarily in response to the EPA's recently proposed chromium clean-up standards and for additional costs expected to be incurred at the Company's former Newark, New Jersey plant site. The 1993 environmental accrual of $18 million related to expected costs of engineering studies for the Passaic River in New Jersey and the Newark plant site.
Restructuring. The 1994 results reflect a $101 million pre-tax net benefit from the Company's restructuring activities, which included a pre-tax gain of $202 million from the Divested Properties. This gain was partially offset by restructuring costs, including a non-cash, pre-tax $70 million write-off associated with the Company's undeveloped Alaska coal leases. The restructuring also included costs associated with staff reductions and the write-off of non-producing assets outside the Company's core areas.
Other Revenues, Net. Other revenues, net were approximately $31 million lower in 1994 compared to 1993. This decline was due primarily to a loss of $13 million stemming from the sale of the Company's geothermal subsidiary in the third quarter of 1994 and to gains recorded on the sale of investments in U.S. Treasury notes and other securities of $12 million during 1993.
Income Taxes. The Company's provision for income taxes in 1994 was comprised primarily of Indonesian income tax. The 1994 Indonesian tax was $12 million less than that of 1993 as a result of lower operating profit. United States federal and state taxes increased $9 million in 1994 compared to 1993. This increase was the result of tax on asset sales, which was offset by tax benefit from the write-off of undeveloped Alaska coal leases and the favorable resolution of a federal tax refund suit.
Change in Accounting Principle. In 1993, Maxus adopted Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits," which requires an accrual method of recognizing postemployment benefits. The Company recognized a one-time charge of $4 million to recognize the cumulative effect of the change in accounting for postemployment benefits.
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.
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.
Pursuant to the Merger Agreement, in the event that the Company is unable to meet its obligations as they come due, whether at maturity or otherwise, including, solely for the purposes of this undertaking, dividend and redemption payments with respect to the $9.75 Preferred Stock, the $4.00 Preferred Stock and the $2.50 Preferred Stock, YPF has agreed to capitalize the Company in an amount necessary to permit the Company to meet such obligations; provided that YPF's aggregate obligation will be: (i) limited to the amount of debt service obligations under the Purchaser Facility, the Midgard credit facility and the Holdings credit facility and (ii) reduced by the amount, if any, of capital contributions by YPF to the Company after the Merger Date and by the amount of the net proceeds of any sale by the Company of common stock or non-redeemable preferred stock after the Merger Date. The foregoing obligations of YPF (the "Keepwell Covenant") will survive until June 8, 2004. In addition, YPF has guaranteed the Company's outstanding debt as of the Merger Date, the principal amount of which was approximately $976 million. The debt covered by the YPF guarantee includes the Company's outstanding 11 1/4%, 11 1/2% and 8 1/2% Sinking Fund Debentures, its outstanding 9 7/8%, 9 1/2% and 9 3/8% Notes, and its outstanding medium-term notes. YPF has also guaranteed the payment and performance of the Company's obligations to the holders of its $9.75 Preferred Stock.
Each of the Midgard facility and the Holdings facility contains restrictive covenants including limitations upon the sale of assets, mergers and consolidations, the creation of liens and additional indebtedness, investments, dividends, the purchase or repayment of subordinated indebtedness, transactions with affiliates and modifications to certain material contracts. The obligors under the Midgard facility and the Holdings facility may not permit (a) consolidated tangible net worth to be less than $200 million, in the case of the Midgard facility, or $350 million, in the case of the Holdings facility, plus (or minus), in the case of Midgard, the amount of any adjustment in the book value of assets or, in the case of Holdings, 70% of the amount of any adjustment to net worth, resulting from the merger of YPFA Corp. into the Company, (b) the ratio of consolidated cash flow to consolidated debt service to be less than 1.1 to 1.0 at the end of any fiscal quarter and (c) the ratio of consolidated cash flow to consolidated interest expense to be less than 1.25 to 1.0 at the end of any fiscal quarter. In addition, mandatory prepayments of the loans under the Midgard facility and the Holdings facility may be required in connection with certain asset sales and casualty losses, upon the issuance of subordinated indebtedness and in 1996 and in each year thereafter if, after semi-annual review, the agent and the lenders determine that a borrowing base deficiency exists. No borrowing base deficiencies existed at December 31, 1995.
Maxus has guaranteed the obligation under the Midgard facility (the "Midgard Guaranty") and under the Holdings facility (the "Subsidiaries Guaranty"). The Midgard Guaranty and the Subsidiaries Guaranty contain restrictions upon mergers and consolidations, the creation of liens and the business activities in which Maxus and its subsidiaries may engage. In addition, Midgard, in the case of the Midgard Guaranty, and Holdings and its subsidiaries, in the case of the Subsidiaries Guaranty, are required to be wholly owned subsidiaries of Maxus, except to the extent YPF or a subsidiary of YPF (other than Maxus or a subsidiary of Maxus) makes capital contributions to Midgard or Holdings or one of Holdings subsidiaries, as the case may be.
In management's opinion, cash on hand and cash from operations will be inadequate to fund the 1996 program spending budget, service debt, meet redemption obligations on redeemable preferred stock and pay preferred stock dividends and trade obligations. During 1996 through the date of this report, YPF has made capital contributions to the Company in the aggregate amount of $64 million pursuant to the terms of the Keepwell Covenant. It is anticipated that YPF could be required to make capital contributions in 1996 totaling approximately $200 million to $250 million to fund the Company's obligations. Actual capital contributions made by YPF could vary significantly depending on, among other circumstances, oil and gas prices and program spending commitments. Such capital contributions will be credited to YPF's obligations under the Keepwell Covenant and will entitle YPF to shares of Common Stock.
Operating Activities. During the nine months ended December 31, 1995, net cash provided by operating activities was $57 million. Excluding the change in working capital requirements, net cash from operating activities was $44 million during this period. Working capital requirements provided an additional $13 million primarily as a result of U.S. federal income tax refunds of approximately $60 million. These tax refunds were partially offset by lower accrued liabilities of $32 million due primarily to payment of Maxus pre-Merger costs coupled with higher inventories of $13 million.
Net cash provided by operating activities during the three months ended March 31, 1995, was $62 million of which $18 million was provided by operating activities and $44 million was from working capital. Working capital was favorably impacted by higher accrued liabilities of $26 million of which $11 million was due to higher accrued interest, lower oil and gas receivables of $24 million and a U.S. federal income tax refund of $9 million partially offset by lower accounts payable of $15 million.
Net cash provided by operating activities totaled $70 million and $137 million in 1994 and 1993, respectively. Excluding the change in working capital requirements, net cash from operating activities was $58 million lower in 1994 than in 1993. Cash flow from operations was negatively impacted by lower crude oil and natural gas prices, the loss of production from the Divested Properties and costs associated with staff reductions, but was partially offset by additional gas volumes from Northwest Java ($30 million). Net working capital requirements of $42 million for 1994 were $9 million higher than 1993 due to lower accounts payable primarily as a result of timing of expenditures in Ecuador.
Investing Activities. During 1995, the Company continued to concentrate its capital spending in core areas of the United States, Indonesia and Ecuador plus development of the emerging areas: the Mamore Block in Bolivia and the Quiriquire Block in Venezuela. Spending in 1995 increased modestly compared to 1994, with the largest increase occurring in the U.S. due to the implementation of an aggressive program of infill drilling designed to increase production and cash flow. Only Ecuador experienced lower capital spending in 1995 as spending for major infrastructure and facilities was completed in 1994. Approximately 45% of the 1994 capital spending was for development of oil reserves in South America. Initial production began in the third quarter of 1994 in Ecuador, Bolivia and Venezuela. Spending in Ecuador in 1994 was $31 million below 1993 as spending for major infrastructure and facilities was being completed. In 1993, the development of gas reserves in Northwest Java and development of Block 16 in Ecuador alone accounted for $167 million of spending. The Northwest Java gas project was completed on time and within budget in the fourth quarter of 1993. Additionally, construction of the Sunray gas plant in the Texas Panhandle, which was started in mid-1991, was completed during the first quarter of 1993.
In December 1995, the Company sold its overriding royalty interest in the Recetor Block in Colombia for $25 million. There was no gain or loss recognized on this transaction.
On April 25, 1994, Offshore Partners sold its interests in Main Pass Blocks 72, 73 and 74. On April 26, 1994, Maxus and its subsidiaries sold all of their partnership interests in Offshore Partners. In the second quarter of 1994, Maxus also sold the McFarlan Field and Grand Isle Block 25, both producing oil and gas properties. In total, the Company received $325 million of proceeds and recorded a pre-tax gain of $202 million from these transactions. A portion of the proceeds from these sales was used to reduce senior debt by $70 million net and to redeem $63 million of the $9.75 Preferred Stock due in February 1995.
During the second quarter of 1994, Maxus Bolivia, Inc., a subsidiary of Maxus, signed an agreement to take BHP Petroleum as a partner in its Bolivian oil development project. The Company received $10 million from BHP in exchange for a 50% interest in the project. Also during the second quarter of 1994, Maxus Venezuela (C.I.) Ltd. ("Maxus Venezuela"), a subsidiary of Maxus, signed an agreement with BP Exploracion de Venezuela S.A., granting BP a 45% interest in the Quiriquire Unit in eastern Venezuela. Maxus Venezuela remains the operator with a 50% interest and Corporacion Energetica S. 21, C.A., a Venezuelan company, holds the remaining 5%.
The Company sold its geothermal subsidiary, Thermal Power Company, in September 1994. The sale was for $58 million net in cash and a $7 million promissory note due from the purchaser in 1997. The Company recorded a loss of $13 million on the transaction.
In 1993, the Company purchased $52 million of U.S. Treasury notes. To partially fund the 1993 capital program budget and cover working capital fluctuations, the Company subsequently sold $142 million of U.S. Treasury notes realizing a gain of $8 million. Additionally, during 1993, Maxus received stock and other securities from The LTV Corporation ("LTV") in settlement of its bankruptcy claims against LTV. The Company sold these securities for approximately $22 million, realizing a $2 million gain. During 1994, the Company purchased an additional $112 million of short-term investments with the proceeds from the sales of assets. To partially fund the capital program budget and pay Merger-related costs in 1995, the Company liquidated all its short-term investments. Additionally, the Company sold its remaining long-term investment in U.S. Treasury notes for $31 million realizing a gain on the sale of $2 million. In the future, the Company anticipates maintaining only minimal balances of cash, cash equivalents and short-term investments to cover working capital fluctuations.
During 1995, the Company was able to release a significant portion of its restricted cash, of which $48 million supporting letters of credit were released and $17 million of assets held in trust as required by certain insurance policies were released due to YPF's guarantees. Additionally, in 1995, the Company restricted $8 million as required by the Holdings credit agreement. During 1993, the Company restricted $36 million backing its spending commitment in Venezuela. The $36 million in restricted cash backing the letters of credit in Venezuela were released in 1994 when the Company took on a partner and reduced its interest to 50%.
Financing Activities. During 1995, most of Maxus' financing activity was impacted by the Merger. The Company received $851 million from the issuance of debt under the Purchaser Facility and the Midgard and Holdings credit facilities and a $250 million capital infusion from YPF to partially fund the Merger. In connection with the Merger, the Company also paid $14 million to redeem rights attached to Shares, repaid the Purchaser Facility, and, pursuant to the Merger, either assumed or paid $746 million of purchase consideration for the Shares outstanding plus transaction costs. Of the approximate $762 million purchase price paid by YPF to acquire the Company, as of December 31, 1995, $16 million remained to be paid in respect of Shares and Merger costs. This liability was recorded in accrued liabilities.
At December 31, 1995, the Company had $7 million of advances outstanding from YPF. The Company and YPF intend to enter into a loan agreement during 1996 to facilitate short-term loans by YPF to the Company and short-term loans by the Company to YPF of excess cash balances. It is expected that loans will be made by the parties under the loan agreement during 1996; however, the number and amounts thereof are not presently known.
The Company's only derivative financial instruments are an interest rate swap agreement, natural gas price swap agreements and natural gas and crude oil futures contracts, which are not used for trading purposes. During the third quarter of 1995 the Company recorded a $2 million gain which represented the final
settlement of the Company's sole interest rate swap agreement prior to its termination. This gain was recorded in other revenues, net. The Company also received a $5 million termination payment, which has been deferred.
Over the two-year period from January 1, 1993, to December 31, 1994, Maxus took 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 these 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, to extend the average debt maturities.
Debt rose significantly in 1993 due to the completion of two of the Company's major projects and the near completion of the initial phase of the Ecuador project. These projects contributed to substantial capital spending in 1993. To cover the shortfall between cash from operations and the cash used in investing activities, incremental new debt was issued. Of the $412 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 spending program.
During 1994, the Company issued $101 million of additional long-term debt. Debt issuances, along with a portion of the proceeds from asset sales, were used to repay approximately $170 million of debt obligations due 1994 and beyond and to prepay $63 million of $9.75 Preferred Stock due in February 1995.
In 1993, Maxus issued a new class of preferred stock, the $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 $9.75 Preferred Stock as required in February 1994.
Accounting Standards
Effective April 1, 1995, the Company used the purchase method of accounting to record the acquisition of the Company by YPF. In a purchase method combination, the purchase price is allocated to the assets acquired and liabilities assumed based on their fair values at the date of acquisition. In connection with the purchase price allocation, the Company adopted Statement of Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," which requires a review of long-lived assets for impairment whenever events or changes in circumstance indicate that the carrying amount of the asset may not be recoverable. Under SFAS 121, if the expected future cash flow of a long-lived asset is less than the carrying amount of the asset, an impairment loss shall be recognized to value the asset at its fair value. Maxus revalued its assets and liabilities to fair value in the purchase price allocation effective April 1, 1995. There was no impact on the Company's results of operations resulting from the adoption of SFAS 121 during the nine months ended December 31, 1995.
Environmental Matters
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 remedial obligations. 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 Safe Drinking Water Act, the Clean Water Act, the Clean Air Act (as amended in 1990), the Occupational Safety and Health Act, the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended ("CERCLA"), and other federal, as well as state, laws. Such laws address, among other things, limits on the discharge of wastes associated with oil and gas operations, investigation and clean-up of hazardous substances,
and workplace safety and health. In addition, these laws typically require compliance with associated regulations and permits and provide for the imposition of penalties for noncompliance. 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 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. Such potential expenditures cannot be reasonably estimated.
In connection with the sale of the Company's former chemical subsidiary, Diamond Shamrock Chemicals Company ("Chemicals"), to Occidental Petroleum Corporation ("Occidental") in 1986, the Company agreed 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 cost sharing arrangement was about $39 million as of December 31, 1995. Occidental Chemical Corporation ("OxyChem"), a subsidiary of Occidental, and Henkel Corporation ("Henkel"), an assignee of certain of Occidental's rights and obligations, have filed a declaratory judgment action in Texas state court with respect to the Company's agreement in this regard (see "Legal Proceedings").
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 arrangement will continue until DSI has borne an additional $47.5 million, following which such costs will be borne solely by the Company. As of December 31, 1995, DSI's remaining responsibility is approximately $8 million and is included in accounts receivable in the accompanying balance sheet.
For the year ended December 31, 1995, the Company spent $6 million in environmental related expenditures in its oil and gas operations. Expenditures in 1996 are expected to be approximately $8 million.
The Company's total expenditures for environmental compliance for disposed of businesses, including Chemicals, were approximately $38 million in 1995, $12 million of which were recovered from DSI under the above described cost-sharing agreement. Those expenditures are projected to be approximately $23 million in 1996 after recovery from DSI under such agreement.
At December 31, 1995, reserves for the environmental contingencies discussed herein totaled $119 million. Management believes it has adequately reserved for all environmental contingencies which are probable and can be reasonably estimated; however, changes in circumstances could result in changes, including additions, to such reserves in the future.
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 court, 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 for such plan, which will include an engineering estimate of the cost of construction, is progressing. Construction is expected to begin in 1997, cost approximately $22 million and take three to four years to complete. The work is being supervised and paid for by the Company pursuant to its above described indemnification obligation to Occidental. The Company has fully reserved the estimated costs of performing the remedial action plan and required ongoing maintenance costs.
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 several feet of more recent sediment deposits and are not moving. The Company, on behalf of Occidental, negotiated an agreement with the EPA under which the Company is conducting further testing and studies to characterize contaminated sediment in a six-mile portion of the Passaic River near the plant site. The Company currently expects such testing and studies to be completed in 1999 and cost from $4 million to $6 million after December 31, 1995. The Company has reserved its estimate of the remaining costs to be incurred in performing these studies as of December 31, 1995. 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 Passaic River or the Newark Bay watershed and therefore cannot estimate what additional costs, if any, will be required to be incurred.
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 a number of 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 self-guarantee in the amount of $20 million subject to the Company's continuing ability to satisfy certain financial tests specified by the State. 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 is uncertain. The Company anticipates submitting its investigation and feasibility reports to the DEP in late 1996 or 1997. The results of the DEP's review of these reports could impact the cost of any further remediation that may be required. The Company has reserved its best estimate of the remaining cost to perform the investigations and remedial work as being $50 million at December 31, 1995. In addition, the DEP has indicated that it expects Occidental and the Company to participate with the other chromium manufacturers in the funding of certain remedial activities with respect to a number of so-called "orphan" chrome sites located in Hudson County, New Jersey. Occidental and the Company have declined participation as to those sites for which there is no evidence of the presence of residue generated by Chemicals. The Governor of New Jersey issued an Executive Order requiring state agencies to provide specific justification for
any state requirements more stringent than federal requirements. The DEP has indicated that it may be revising its soil action level upwards towards the higher soil screening levels proposed by the EPA in 1994.
Painesville, Ohio. From about 1912 through 1976, Chemicals operated manufacturing facilities in Painesville, Ohio. The operations over the years involved several discrete but contiguous plant sites over an area of about 1,300 acres. The primary area of concern historically has been Chemicals' former chromite ore processing plant (the "Chrome Plant"). For many years, the site 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 site and to conduct certain ground water and surface water monitoring. Many other sites have previously been clay-capped and one specific site, which was a waste disposal site from the mid-1960s until the 1970s, has been encapsulated and is being controlled and monitored. In September 1995, the Ohio Environmental Protection Agency (the "OEPA") issued its Directors' Final Findings and Order (the "Director's Order") by consent ordering that a remedial investigation and feasibility study (the "RIFS") be conducted at the former Painesville plant area. The Company has agreed to participate in the RIFS as required by the Director's Order. It is estimated that the total cost of performing the RIFS will be $3 million to $5 million over the next three years. In spite of the many remedial, maintenance and monitoring activities performed, the former Painesville plant site has been proposed for listing on the National Priority List under CERCLA; however, the EPA has stated that the site will not be listed so long as it is satisfactorily addressed pursuant to the Director's Order and OEPA's programs. The Company has accrued the estimate of its share of the cost to perform the RIFS. The scope and nature of any further investigation or remediation that may be required cannot be determined at this time; however, as the RIFS progresses, the Company will continuously assess the condition of the Painesville plant site and make any changes, including additions, to its reserve as may be required.
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. The Company has reserved $6 million at December 31, 1995, related to these sites, none of which are individually material.
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 Chemicals' 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 are 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 is adjacent to Fields Brook. Occidental has continued to operate 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 parties are presently considered to be financially responsible PRPs. In 1986, the EPA estimated the cost of sediment remediation at the site would be $48 million. The PRPs, including Occidental, have developed an allocation agreement for sharing the costs of the work in Fields Brook ordered by the EPA. Under the allocation, the Occidental share for Chemicals' ownership of the Ashtabula plant would be about five percent of the total, assuming all viable PRPs were to participate.
In 1990, the OEPA, as state trustee for natural resources under CERCLA, advised previously identified PRPs, including Chemicals, that the OEPA 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, and biological and geological resources at the site. Also, 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 and necessary governmental actions have been completed and negotiated or judicial allocations have been made, it is not possible for the Company to estimate what the response costs, response activities or natural resource damages, if any, may be for Fields Brook or related areas, the parties responsible therefore 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, has contended that it is entitled to full indemnification from the Company for such costs, and the outcome of this dispute cannot be predicted. The Company has reserved its estimate of its share of potential cleanup costs based on the assumption that this site falls under the Occidental cost sharing arrangement.
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 was entered by the federal court as a settlement of the EPA's claim for remedial action. Chemical's share of the cost to complete remediation at this site at December 31, 1995 is expected to be approximately $500,000 and such amount is fully accrued.
3. SCP/Carlstadt Site; Carlstadt, New Jersey. Chemicals' share of remediation costs at this CERCLA site would be approximately one percent, based on relative volume of waste shipped to the site. An interim remedy has now been implemented at the site by the PRPs but no estimate can be made at this time of ultimate costs of remediation which may extend to certain off-site locations.
4. Chemical Control Site; Elizabeth, New Jersey. The DEP has demanded of PRPs (including Chemicals) reimbursement of the DEP's alleged $34 million (including interest through December 31, 1995) 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. Based on the previous allocation formula, it is expected that Chemicals' share of any money paid to the DEP for its claim would be approximately two percent. The Company has fully reserved its estimated liability for this site.
Legal Proceedings
In November 1995, OxyChem filed suit in Texas state court seeking a declaration of certain of the parties' rights and obligations under the sales agreement pursuant to which the Company sold Chemicals to Occidental. Henkel joined in said lawsuit as a plaintiff in January 1996. Specifically, OxyChem and Henkel are seeking a declaration that the Company is required to indemnify them for 50% of certain environmental costs incurred on projects involving remedial activities relating to chemical plant sites or other property used in connection with the business of Chemicals on the Closing Date which relate to, result from or arise out of conditions, events or circumstances discovered by OxyChem or Henkel and as to which the Company is provided written notice by OxyChem or Henkel prior to the expiration of ten years following the Closing Date, irrespective of when OxyChem or Henkel incurs and gives notice of such costs, subject to an aggregate $75 million cap. The Company believes that this lawsuit is without merit and intends to defend same vigorously. The Company has established reserves based on its 50% share of costs expected to be paid or incurred by OxyChem and Henkel prior to September 1996.
As of December 31, 1995, the Company had paid OxyChem and Henkel a total of approximately $39 million against said $75 million cap. The Company cannot predict what portion of the approximately $36 million remaining as of that date Occidental and Henkel may actually pay or incur prior to September 4, 1996, the tenth anniversary of the Closing Date if they accelerate spending with regard to such environmental costs; however, the Company has approximately $7 million reserved at December 31, 1995, based on 50% of OxyChem's and Henkel's historical annual expenditures. In the event OxyChem and Henkel prevail in this lawsuit, the Company could be required to provide up to approximately $29 million in additional reserves related to this indemnification.
The Company has established reserves for legal contingencies in situations where a loss is probable and can be reasonably estimated.
Future Outlook
In addition to maintaining and developing its core and emerging areas, it is expected that, beginning in 1996, the Company will acquire or assume responsibility for certain YPF exploration interests in South America (outside Argentina) and the United States Gulf of Mexico. The Company will continue to focus on maximizing the value of its core producing assets and seek new investment opportunities in associated ventures.
Maxus currently projects total program spending (capital expenditures plus exploration expenses) for 1996 to be approximately $249 million, compared to $231 million in 1995. Indonesia will receive nearly $79 million, Midgard (U.S.) $72 million, South America $62 million and exploration interests outside Argentina acquired or assumed from YPF $25 million. The remaining $11 million will be allocated to domestic and overseas new ventures. Funding for the 1996 spending program is expected to be provided through cash and cash equivalents on hand at the beginning of the year, expected cash from operations and capital contributions from YPF as necessary. In addition to the 1996 program, Maxus has financial and/or performance commitments for exploration and development activities in 1997 and beyond none of which are material except for the recently acquired Guarapiche block in Venezuela discussed below.
In January 1996, the Company and its partners were successful in acquiring the highly prospective Guarapiche block in Venezuela's first auction awards for equity production in over 20 years. Guarapiche is located on the same trend as the five billion barrel El Furrial field in northeastern Venezuela. The Company, together with its partners, paid $109 million (approximately $27 million net to the Company) to the Venezuelan government for rights to explore the Guarapiche block. BP Exploration Orinoco Limited is the operator with a 37.5% working interest while Amoco Production Company and the Company hold 37.5% and 25% working interests, respectively. The Company's net exploration commitment is anticipated to total approximately $15 million over the next five years.
The Company has begun discussions with other companies concerning the establishment of a joint venture or other alliance with regard to Midgard's business and assets. The objectives of such a joint venture or alliance would be lowering unit costs, creating economies of scale and improving marketing leverage. No joint venture or other partner has been selected and no assurances can be given that the attempts to establish a joint venture or other alliance will be successful. In addition, Maxus is considering a number of possible capital and business restructuring alternatives; however, no decisions have been made to take any specific action nor can there be any assurance that any specific action will be taken.
By the end of 1995, management had streamlined the Maxus organizational structure, reduced Maxus' overhead costs and improved communications and decision making. In addition, a "management by objectives" program was introduced to make each business unit and staff group directly responsible for their accomplishments. These actions are expected to result in significant cost savings.
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.
In Ecuador, pipeline capacity available to the Company is sufficient to transport only about 60% of the oil the Company expected to be able to produce daily, and none of the various projects to increase transportation capacity that have been considered has been approved by the government of Ecuador. In addition, the Company is involved in a number of contract, auditing and certification disputes with various government entities. Together, the lack of pipeline capacity and the various disputes with government entities are retarding the Company's ability to proceed with the economic development of Block 16. Although the Company can
give no assurances concerning the outcome of these discussions, progress has recently been made on several important issues. The Company intends to reduce program spending in Ecuador in 1996 to $19 million from $32 million in 1995.
ITEM 8.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The information required by this item appears on pages to of this report.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
Inapplicable.
PART III
ITEM 10.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Executive Officers of the Company
The following table sets forth certain information as of March 1, 1996 concerning the executive officers of the Company.
Officers are elected annually by the Board of Directors (sometimes referred to as the "Board") 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 with third parties pursuant to which any of them were elected as officers, except that Mr. Monti received $120,000 from YPF in respect of the period from August 21, 1995, when he was elected President, Chief Executive Officer and a director of the Company, until October 9, 1995, when he became an employee of the Company. Certain information regarding the principal occupations and employment of each of the officers named above during the prior five years is set forth below.
Mr. Monti was elected President and Chief Executive Officer and a director of the Company effective August 21, 1995 and became an employee of the Company on October 9, 1995. Prior to joining Maxus, Mr. Monti served as the President of Dowell, a division of Schlumberger Limited. Since joining the oilfield services company in 1963, Mr. Monti has held various positions with Schlumberger, including president and vice president of various divisions or subsidiaries.
Mr. Miller was elected Executive Vice President and Treasurer of the Company in November 1995. Mr. Miller joined a former subsidiary of Maxus in 1981 as Manager, Taxes and has held various positions with the Company since such time, including Director, Exploration and Production Taxes; Director, Operations Auditing; General Manager, Indonesia; and Vice President of the Company.
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. Forrest was named Senior Vice President, Business Development of the Company in 1994. Mr. Forrest has been a Senior Vice President of the Company since 1994.
Mr. Wadsworth was elected Vice President, Legal of the Company in June 1995. Mr. Wadsworth joined Natomas Company, a former subsidiary of Maxus, in 1979. He has served in various positions with the Company, including Associate General Counsel and Corporate Secretary, since such time.
Mrs. Engelbrecht was elected Controller of the Company in November 1995. She joined a former subsidiary of the Company in 1978 as a financial associate and has held various positions with the Company, including Director of Financial Reporting and Assistant Controller, since such time.
Directors of the Company
Certain information regarding each director, including his age, is set forth below. Each director is elected at the annual meeting of stockholders for a term of one year.
CHARLES L. BLACKBURN: 68, a director of the Company since 1986. For more than five years prior to his retirement in April 1995, he was also the Chairman, President and Chief Executive Officer of Maxus. He is currently an international consultant for the Company. Mr. Blackburn also serves as a director of Lone Star Technologies, Inc. and Landmark Graphics Corporation.
CEDRIC BRIDGER: 60, a director of the Company since April 1995. Mr. Bridger has been Vice President, Finance and Corporate Development of YPF since 1992. From 1989 to 1992, he was employed by CBV Industrias Mecanicas in Brazil, last serving as Marketing Manager. Previously, he was associated with Hughes Tool Company from 1964 to 1989.
GEORGE L. JACKSON: 67, a director of the Company since 1987. Mr. Jackson has been an oil field service consultant for more than five years.
NELLS LEON: 69, a director of the Company since June 1995. Mr. Leon has been a director of YPF since 1991, and was elected President of YPF in May 1995. Mr. Leon held various positions with YPF from 1956 to 1977 and from 1983 to 1987. Since 1990, he has served as Executive Vice President. He was Vice President of Operations of Sol Petroleo S.A. from 1987 to 1990.
JAMES R. LESCH: 74, a director of the Company since April 1995. Mr. Lesch has been a director of YPF since 1993. He is currently retired, having retired from Hughes Tool Company in 1986. He was Chief Executive Officer (1979-1986) and Chairman of the Board (1981-1986) of Hughes Tool Company and also served as Commissioner, State of Texas Department of Commerce (1988-1992). Previously, he served as Director of the American Petroleum Institute. Mr. Lesch also serves as a director of TransTexas Gas Corporation.
ROBERTO MONTI: 57, a director, President and Chief Executive Officer of the Company since August 1995. Prior to such time, Mr. Monti had been employed since 1963 by Schlumberger Limited, an oil field services company, in various capacities. He most recently served as President of Dowell, a division of Schlumberger Limited.
P. DEXTER PEACOCK: 54, a director of the Company since April 1995. Mr. Peacock has been a partner of the law firm of Andrews & Kurth L.L.P. since 1975. He is a member of the firm's Management Committee. He currently serves as a director of Texas Commerce Bank National Association and as an alternate director of YPF.
R. A. WALKER: 39, a director of the Company since 1994. He is a Managing Director of Prudential Capital Group and a Vice President of The Prudential Insurance Company of America ("Prudential"). Mr. Walker has held similar positions with Prudential Capital Group for the past five years. He was elected to the Board of Directors of Maxus by Prudential pursuant to the terms of the $9.75 Preferred Stock.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION.
DIRECTOR COMPENSATION
The Company pays each director who is not an employee of the Company or YPF (other than Mr. Blackburn) an annual retainer of $20,000 and a fee of $1,000 for each meeting of the Board attended and for each committee meeting attended. For so long as Mr. Blackburn is an international consultant to the Company, he will not be entitled to such compensation paid to other non-employee Directors. See--"Employment Contracts and Termination of Employment and Change in Control Agreements."
EXECUTIVE OFFICER COMPENSATION
The following tables set forth compensation awarded to, earned by or paid to the executive officers named below in 1993, 1994 and 1995.
SUMMARY COMPENSATION TABLE
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(1) Mr. Monti became a consultant, officer and director of the Company on August 21, 1995, and an employee of the Company on October 9, 1995. He received $120,000 of this amount from YPF in respect of his serving as President and Chief Executive Officer of the Company prior to the date on which he became an employee. (2) Mr. Monti was paid this amount as a signing bonus upon commencement of his employment with the Company. (3) These payments represent the Company's matching contributions to this individual's qualified and non-qualified savings plans' accounts. (4) $76,592 of this amount represents a payment made in accordance with Mr. Miller's employment agreement (see--"Employment Contracts, Termination of Employment and Change in Control Agreements"), and $10,494 of such amount represents the Company's matching contributions to Mr. Miller's qualified and non-qualified savings plan accounts. (5) $1,075,383 of this amount represents a payment made in accordance with Mr. Forrest's change in control agreement (see--"Employment Contracts, Termination of Employment and Change in Control Agreements"); $199,988 represents payment in respect of the surrender pursuant to the terms of the Merger Agreement of options and stock appreciation rights ("SARs") held by Mr. Forrest (see table below entitled "Aggregated Option/SAR Exercises in the Last Fiscal Year and FY-End Option/SAR Values"); and $15,661 of such amount represents the Company's matching contributions to Mr. Forrest's qualified and non-qualified savings plan accounts. (6) $120,000 of this amount represents payments in connection with Mr. Blackburn's consulting agreement with the Company (see--"Employment Contracts and Termination of Employment and Change in Control Agreements"), $2,662,070 of such amount represents a severance payment made in accordance with Mr. Blackburn's change in control agreement (see "-- Employment Contracts, Termination of Employment and Change in Control Agreements"); $1,943,632 of such amount represents a lump sum payment to Mr. Blackburn in respect of the Company's retirement plans, including the Supplemental Executive Retirement Plan; $298,396 represents a distribution from Mr. Blackburn's savings plan accounts; $104,588 represents payment in respect of restricted shares of Common Stock, the restrictions on which lapsed on May 1, 1995 in accordance with their terms; and $10,400 of such amount represents the Company's matching contributions to Mr. Blackburn's qualified and non-qualified savings plan accounts. (7) Mr. Gaffney became a consultant and an officer of the Company on April 21, 1995 and an employee of the Company on June 6, 1995. Pursuant to an agreement between Mr. Gaffney and the Company, he received a total of $300,000, $195,721 of which was paid with respect of the period during which he was an employee of the Company. (8) $835,893 of this amount represents a severance payment made in accordance with Mr. Pasley's change in control agreement (see--"Employment Contracts, Termination of Employment and Change in Control Agreements"); $162,774 represents a distribution or rights to a distribution from Mr. Pasley's savings plan accounts; and $8,578 of such amount represents the Company's matching contributions to Mr. Pasley's qualified and non-qualified savings plan accounts. (9) $619,877 of this amount represents a severance payment made in accordance with Mr. Brown's change in control agreement (see--"Employment Contracts, Termination of Employment and Change in Control Agreements"); $84,999 represents payment in respect of the surrender pursuant to the terms of the Merger Agreement of options and SARs held by Mr. Brown (see table below entitled "Aggregated Option/SAR Exercises in the Last Fiscal Year and FY-End Option/SAR Values"); $13,772 represents payment in respect of restricted shares of Common Stock, the restrictions on which lapsed on May 1, 1995 in accordance with their terms; $213,560 represents a distribution or rights to a distribution from Mr. Brown's savings plan accounts; and $10,226 represents the Company's matching contributions to Mr. Brown's qualified and non-qualified savings plan accounts.
AGGREGATED OPTION/SAR EXERCISES IN THE LAST FISCAL YEAR AND FY-END OPTION/SAR VALUES
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(1) These payments were made in respect of the surrender of options and any SARs held by the named executive officers as contemplated by the terms of the Merger Agreement. No shares of stock were acquired in these transactions.
(2) Although each of these named executive officers surrendered all of his options and SARs in 1995, payment was not made in 1995 by the Company in respect of a certain number of such options and SARs due to then pending tax and other questions. Such questions have been resolved and these named officers received the following amounts in 1996 for their surrendered options and SARs: Mr. Monti--0; Mr. Miller--0; Mr. Forrest--$182,102; Mr. Wadsworth--0; Mrs. Engelbrecht--0; Mr. Blackburn--$939,256; Mr. Gaffney--0; Mr. Pasley--$307,173; and Mr. Brown--$87,502.
EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND CHANGE IN CONTROL AGREEMENTS
Employment Contracts. On April 5, 1995, the Company entered into an agreement with Mr. Gaffney, a director and the President and Chief Executive Officer of the Company from April 21, 1995 to August 21, 1995, whereby Mr. Gaffney served in the capacity of chief executive officer of the Company in consideration of payment of $50,000 a month from the date of such agreement through September 30, 1995. A total of $300,000 was paid to Mr. Gaffney under this agreement, $195,721 during the period he was an employee. In addition, Gaffney, Cline, an oil and gas technical and management consulting firm of which Mr. Gaffney is a Senior Partner, entered into an agreement with the Company obligating the Company to pay Gaffney, Cline $500,000 in consideration of Gaffney, Cline granting Mr. Gaffney a leave of absence to enable him to serve as the Company's chief executive officer.
The Company entered into an agreement effective July 1, 1995 in replacement of a change in control agreement dated November 1, 1991 with Mr. Miller, Executive Vice President and Treasurer of the Company, under which Mr. Miller is to be employed for a term of four years at not less than his then current salary, plus an annual bonus not less than the amount of the largest bonus paid to Mr. Miller in respect of the years 1992, 1993 or 1994, and a "sign-on" bonus in the amount of $76,592. In addition, a "stay on" bonus in the amount of $76,592 is payable under this agreement on each of July 1, 1996, 1997 and 1998 provided, as to each such "stay on" bonus, that Mr. Miller continues to be an employee of the Company on the respective payment date. Under the agreement, in the event that Mr. Miller's employment is terminated under certain circumstances, severance compensation will be paid to Mr. Miller as specified therein.
On December 27, 1995, the Company entered an agreement with Mr. Monti, a director and the President and Chief Executive Officer of the Company, pursuant to which his Foreign Service Pay, as defined in such agreement, payable with respect to services rendered from and after January 1, 1996 will be credited by the Company to a deferral account which will bear interest at a specified rate and the balance of which will be paid to Mr. Monti under certain circumstances, including termination of his employment with the Company.
Mr. Blackburn, a director and formerly the Chairman, President and Chief Executive Officer of the Company, became an international consultant during 1995 to YPF pursuant to a consulting agreement which was subsequently assigned to Maxus. Under the two-year contract, Mr. Blackburn will be available to render consulting services for a minimum of 60 days per year and be paid a retainer of $180,000 per year. Mr. Blackburn will be paid $3,000 per day for each day of consulting provided in excess of 60 days per year. Office space is made available to him in Dallas and Buenos Aires. During 1995, Mr. Blackburn was paid a total of $120,000 under the terms of this contract.
Termination of Employment Agreements. On August 3, 1995, the Company entered into an agreement with Mr. Monti under which he will receive a severance payment from the Company in the amount of $3 million in the event that his employment with the Company is terminated (i) by Mr. Monti or the Company for reason of death or disability; (ii) by the Company other than for cause; (iii) by Mr. Monti for any reason within six months following a take-over (other than to accept employment with YPF); and (iv) by Mr. Monti for any reason after reaching age 65.
Separation Pay Plan. Under the Separation Pay Plan, most employees (other than non-resident aliens), excluding Mr. Monti (who has waived any rights thereunder) but including the other named executive
officers, are eligible for separation pay if their employment is terminated for any reason other than death, voluntary termination of employment, voluntary retirement or discharge for reasons of criminal activity, willful misconduct, gross negligence in the performance of duties or violation of Company policy. The payment to be received under the plan by a particular employee depends on his job classification and length of service and whether termination occurs after the elimination of the employee's position or a change in control of the Company (as defined in the plan). In the case of the named executive officers, the plan provides in most cases for separation pay in an amount equal to two-weeks' base pay for each year of service with the Company, plus three months' base pay, not to exceed a maximum of 12 months' base pay; and, in the case of a change in control of the Company, separation pay in an amount equal to one month's base pay for each year of service with the Company, but not less than 12 months' base pay nor more than 24 months' base pay. The plan requires that employees sign releases as a condition of receiving separation pay. Executive officers are not entitled to separation pay under the plan to the extent they receive severance payments under the change in control agreements discussed below or employment contracts discussed above. The acquisition of the Company by YPF constitutes a change in control under the Separation Pay Plan, thereby triggering the post-change in control separation formula until April 5, 1997.
Change in Control Agreements. In 1987 or thereafter, the Company entered into agreements with certain executives including Messrs. Blackburn, Forrest, Brown, Pasley and Miller which were binding upon execution but were to become operative on a change of control of the Company. Pursuant to the terms of said agreements, they became operative when YPF acquired control of the Company.
Under these agreements, the executive officer is entitled to continue in the employ of the Company until the earlier of the expiration of the third anniversary of the occurrence of a "change in control" or the executive's death at an annual base salary of not less than the rate in effect upon the occurrence of a change in control plus an incentive award of not less than the highest such award received by the executive for any year in the three calendar years immediately preceding the change in control. Under the agreements, a "change of control" includes the following: (i) the merger, consolidation or reorganization of the Company after which a majority of voting power of the Company is held by persons other than the holders thereof prior to such event; (ii) the sale of all or substantially all of the assets of the Company to an entity, the majority of the voting power of which is not held by holders of the voting power of the Company before such sale; (iii) a report is filed on Schedule 13D or Schedule 14D-1 showing that a person is the beneficial owner of 25% or more of the voting power of the Company; (iv) the Company files a Form 8-K or proxy statement disclosing that a change in control has or may occur; or (v) a change in the composition of the majority of the Board under certain circumstances occurs during any period of two consecutive years. In the event the Company terminates the executive's employment during such term without cause, the executive will be entitled to receive as severance compensation a lump-sum payment equal to the present value of the cash compensation payable under the agreement in the absence of such termination, not to exceed 299% of his "base amount" as defined in the Internal Revenue Code of 1986, as amended (the "Code"), without any reduction for subsequent earnings.
Under these agreements, continuation of benefits under employee benefit plans of the Company is provided after termination during the remainder of the original term of employment. The agreements include provisions which limit the amounts payable under them in certain circumstances in which the net after-tax amount received by the officer would be reduced as a result of the applicability of the 20% excise tax imposed in respect of certain change in control payments under the Code. The Company has assumed the obligation to pay certain fees and expenses of counsel incurred by the executive officers if legal action is required to enforce their rights under the agreements and has secured such obligation by obtaining a letter of credit issued by a commercial bank.
On April 7, 1995, all of the Company's then executive officers, including Messrs. Blackburn, Forrest, Pasley and Brown, gave notice of their intent to resign under circumstances in which they had the right to receive severance payments under the change in control agreements. In order to facilitate the transition following the acquisition by YPF, the Company and the eight executive officers who were parties to such agreements (Messrs. Blackburn, Forrest, Pasley, Brown, S. G. Crowell, M. J. Barron, M. J. Gentry and M. Middlebrook) agreed that such executive officers would continue to work for the Company in their then present positions at their then current levels of compensation until June 30, 1995 or such date as otherwise
mutually agreed. The Company also agreed to pay such executive officers' said severance payments no later than April 15, 1995. Mr. Blackburn resigned as Chairman, Chief Executive Officer and President of the Company on April 21, 1995 and retired as an employee of the Company on April 30, 1995. Messrs. Brown and Pasley resigned effective December 15, 1995 and August 31, 1995, respectively. All of such other executive officers resigned on June 30, 1995, except Mr. Forrest who agreed to continue in the employment of the Company at a reduced salary and as an "at will" employee. Pursuant to said agreements and the change in control agreements, the named executive officers and all of the executive officers as a group (including said former executive officers) received "severance" payments in the following amounts: Mr. Monti--$0; Mr. Miller--$0; Mr. Forrest--$1.0 million; Mr. Wadsworth--$0; Mrs. Engelbrecht--$0; Mr. Blackburn--$2.7 million; Mr. Gaffney--$0; Mr. Pasley--$0.9 million; and Mr. Brown--$0.6 million and the executive officers (including said former executive officers) as a group, $7.9 million.
RETIREMENT PROGRAM
Effective February 1, 1987, the Company adopted a new retirement income plan (the "New Retirement Income Plan") applicable to most of its employees to replace the Company's former retirement income plans under which such employees ceased to accrue benefits on January 31, 1987. Under the New Retirement Income Plan, a covered employee acquires a right upon retirement to a yearly amount equal to 2% of the employee's earnings during each year from February 1, 1987 forward (rather than on final compensation or average final compensation) without offset for social security benefits. Benefits under the New Retirement Income Plan become vested after five years of service. Benefits may be paid in equal monthly installments, starting on the date of retirement and continuing until death, or employees may select one of a number of optional forms of payment having equal actuarial value as provided in the plan. The benefits payable under the New Retirement Income Plan are subject to maximum limitations under the Employee Retirement Income Security Act of 1974, as amended ("ERISA"), and the Code. In the case of the named executives, if benefits at the time of retirement exceed the then permissible limits of such statutes, the excess would be paid by the Company from the "SERP" described below.
The Company has an unfunded Supplemental Executive Retirement Plan that provides additional benefits to the Company's highest ranking officer, the other named executives and to certain executive employees designated by the highest ranking officer. Under the SERP, a participant acquires the right to a lump sum amount upon retirement which is the actuarial equivalent of a straight life or, if married, a 50% joint and survivor annuity payable monthly in an amount equal to (a) the sum of (i) 1.6% of the participant's average monthly compensation in 1986 times the years of service through January 31, 1987, plus (ii) 2% of the participant's average monthly compensation after January 31, 1987 times the years of service after January 31, 1987 plus an additional five years less (b) the amount of the benefits calculated for such participant under the Company's other retirement plans. The maximum benefit payable is 60% of the participant's high three-year average pay. The amounts calculated under the SERP are not subject to any reduction for Social Security and are not determined primarily by final compensation or average final compensation and years of service. If a participant dies while still employed by the Company and is survived by an eligible spouse, the surviving spouse will receive a lump-sum payment equal to the present value of one-half of the benefit which would have been payable to the participant at his normal retirement age under the SERP assuming the participant had terminated employment with the Company at the time of death with a vested interest under the SERP and that the participant survived to the normal retirement age. In the case of retirement after age 55 but before age 60, the supplemental retirement benefits generally will be reduced by 5% for each year that the employee's actual retirement date precedes age 60. The benefits provided under the plan will vest upon completion of five years of service or attainment of age 55.
The estimated annual benefits payable upon retirement at normal retirement age (or January 1, 1996 in those cases where the participant's age on that date was greater than normal retirement age) under the Company's retirement plans as supplemented by the SERP based on service and compensation through December 31, 1995 for the executive officers named in the compensation table are as follows: Mr. Monti-- $82,668, Mr. Miller--$46,751, Mr. Forrest--$64,502, Mr. Wadsworth--$52,900, Mrs. Engelbrecht--$33,863 and Mr. Gaffney--$0. The annual benefits payable under the Company's retirement plans as supplemented by
the SERP to Mr. Blackburn who retired on April 30, 1995 (and received a lump sum distribution of his retirement benefits) were $193,006. The annual benefits payable at normal retirement age to Mr. Brown who resigned from the Company effective December 15, 1995 are $61,207 and to Mr. Pasley who resigned from the Company effective August 31, 1995 are $58,002.
Whether any amounts actually become payable in whole or in part depends on the contingencies and conditions governing the applicable retirement plan.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
From January 1, 1995 to April 21, 1995, the Compensation Committee of the Board of Directors consisted of J. David Barnes, B. Clark Burchfiel, Charles W. Hall, George L. Jackson and Richard W. Murphy. From April 21, 1995 to June 7, 1995, the Compensation Committee consisted of Jose Estenssoro, Cedric Bridger and James R. Lesch. On June 7, 1995, Nells Leon replaced Mr. Estenssoro.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Except as provided in the next succeeding sentence, the following table sets forth the beneficial ownership (as defined in the rules of the Securities and Exchange Commission) as of February 1, 1996 of the equity securities of the Company and YPF by the directors, the named executive officers and all directors and executive officers as a group. At such date, none of the directors or executive officers beneficially owned any $4.00 Preferred Stock, $9.75 Preferred Stock or $2.50 Preferred Stock.
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(1) Does not include Common Stock owned by YPF, as to which each of Messrs. Bridger, Leon, Lesch and Peacock disclaim any beneficial ownership.
(2) Does not include 347 YPF Class "D" shares owned by Mr. Leon's wife, as to which Mr. Leon disclaims any beneficial ownership.
(3) Does not include equity securities owned by Prudential, as to which Mr. Walker disclaims beneficial ownership.
(4) Directors and executive officers individually and as a group did not own more than 1% of the Common Stock or YPF Class D shares.
To the knowledge of the Company, as of February 1, 1996, no person beneficially owned more than 5% of any class of the Company's voting securities except as set forth below:
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(1) Prudential reported on Amendment No. 7 to Schedule 13G, dated February 12, 1996, in connection with beneficial ownership at December 31, 1995, that it had sole voting and dispositive power with respect to all 7,910,000 shares of Common Stock indicated above as beneficially owned by it. The information herein regarding such shares assumes that Prudential's ownership had not changed as of February 1, 1996 and is included in reliance on such Amendment No. 7, except that the percent of class is based upon the Company's calculations made in reliance upon the information regarding such shares contained in such Amendment No. 7.
(2) On February 28, 1995, the Company and Prudential entered into an agreement pursuant to which Prudential waived certain rights, including conversion rights and registration rights. See "Item 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The Company has business transactions and relationships in the ordinary course of business with unaffiliated corporations and institutions with which certain of its directors, executive officers and substantial stockholders are affiliated, including the transactions discussed below. All such transactions are conducted on an arm's-length basis.
Gaffney, Cline, an oil and gas technical and management consulting firm of which Mr. Gaffney, the President and Chief Executive Officer and a director of the Company from April 21, 1995 to August 21, 1995, is a Senior Partner, has provided oil and gas technical and management consulting services to the Company for which the Company paid Gaffney, Cline approximately $490,000 during 1995. The Company and Gaffney, Cline have agreed that Gaffney, Cline will continue to provide such services in 1996 and it is anticipated that the fees for such services will be lower.
During 1996 through the date of this report, YPF has made capital contributions to the Company in the aggregate amount of $64 million pursuant to the terms of the Keepwell Covenant (see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources"). It is anticipated that YPF could be required to make capital contributions in 1996 totaling approximately $200 million to $250 million to fund the Company's obligations. Actual capital contributions made by YPF could vary significantly depending on, among other circumstances, oil and gas prices and program spending commitments. Such capital contributions will be credited to YPF's obligations under the Keepwell Covenant and will entitle YPF to shares of Common Stock.
During 1995, YPF made an advance to the Company in the amount of $7 million. The Company and YPF intend to enter into a loan agreement during 1996 to facilitate short-term loans by YPF to the Company and short-term loans by the Company to YPF of excess cash balances. It is expected that loans will be made by the parties under the loan agreement during 1996, and while the number and amounts thereof are not presently known, it is expected that they will aggregate in excess of $60,000.
Mr. Peacock, a director of the Company, is a partner in the law firm of Andrews & Kurth L.L.P. Andrews & Kurth provided certain legal services to the Company (including services rendered to YPFA Corp. in connection with the Merger), the fees for which the Company paid Andrews & Kurth approximately $3,180,000 in 1995. It is anticipated that Andrews & Kurth will continue to provide legal services to the Company during 1996 and that the fees for such services will be significantly lower.
The Company and YPF intend to enter into a services agreement whereby the Company would render or arrange for services to be rendered to or for the benefit of YPF and YPF would render or arrange for services to be rendered to or for the benefit of the Company, and each party would be compensated on the basis of the cost to them of such services. It is not presently known what the cost of these services will be to either party but it is expected that it will exceed $60,000.
During 1995, Prudential was the record or beneficial owner of more than 5% of one or more of the classes of the Company's voting securities. Mr. Walker, an officer of Prudential, was elected as a director of the Company by Prudential as holder of all of the $9.75 Preferred Stock and pursuant to the terms thereof. The Company offers its employees the opportunity to participate in medical programs administered by Prudential. In addition, Prudential provides services and coverages relating to pension and life insurance programs for retired employees of Gateway Coal Company, a partnership owned by the Company. During 1995, the Company paid Prudential approximately $238,000 for these services. The Company and Prudential have agreed that Prudential will continue to perform such services during 1996 and anticipate that the fees for the year will be somewhat higher.
Also during 1995, Prudential and the Company entered into an agreement to induce Prudential, as the holder of the $9.75 Preferred Stock, to consent to the Merger as required by the terms of the Company's Restated Certificate of Incorporation. Under the agreement, the Company and Prudential agreed to waive certain rights and covenants with respect to the $9.75 Preferred Stock and the Company paid Prudential a restructuring fee of $250,000.
COMPLIANCE WITH SECTION 16(A) OF THE SECURITIES EXCHANGE ACT OF 1934
During 1995, a former director of the Company, Raymond A. Hay, filed a Form 4 reporting a sale of Common Stock in the month following the date upon which such filing was due.
PART IV
ITEM 14.

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 appear on pages through and through of this report.
Consolidated Statement of Operations for the years ended December 31, 1994 and 1993, the three months ended March 31, 1995 and nine months ended December 31, 1995.
Consolidated Balance Sheet at December 31, 1995 and 1994.
Consolidated Statement of Cash Flows for the years ended December 31, 1994 and 1993, the three months ended March 31, 1995 and nine months ended December 31, 1995.
Notes to Consolidated Financial Statements.
Report of Independent Public Accountants.
Supplementary Financial Information (unaudited).
Quarterly Data (unaudited).
(2) Financial Statement Schedules.
None
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.
(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 10.10 and 10.15 through 10.25 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.
(b) Reports on Form 8-K.
None.
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
By ROBERTO MONTI* Roberto Monti President and Chief Executive Officer
March 21, 1996
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.
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.
MAXUS ENERGY CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
See Notes to Consolidated Financial Statements.
MAXUS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEET
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.
MAXUS ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
See Notes to Consolidated Financial Statements.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PRESENTATION
On June 8, 1995, a special meeting of the stockholders of Maxus Energy Corporation (together with its foreign and domestic subsidiaries, the "Company" or "Maxus") was held to approve the Agreement of Merger ("Merger Agreement") dated February 28, 1995, between the Company, YPF Acquisition Corp. (the "Purchaser") and YPF Sociedad Anonima ("YPF"). The holders of the Company's common stock, $1.00 par value per share, and $4.00 Cumulative Convertible Preferred Stock approved the Merger Agreement, and the Purchaser was merged into the Company (the "Merger") on June 8, 1995.
Effective April 1, 1995, the Company used the purchase method of accounting to record the acquisition of the Company by YPF. In a purchase method combination, the purchase price is allocated to acquired assets and assumed liabilities based on their fair values at the date of acquisition. As a result, the Company's assets and liabilities were revalued to reflect the approximate $762 million cash purchase price paid by YPF to acquire the Company. The Company's pre-Merger Consolidated Balance Sheet as of March 31, 1995, together with the purchase method accounting adjustments became the Company's opening post-Merger Consolidated Balance Sheet on April 1, 1995.
The following pre-Merger data is for the three months ended March 31, 1995, and the years ended December 31, 1994 and 1993 and dollar amounts in tables are in millions, except per share amounts. The financial statements for the three-month period ended March 31, 1995, and the years ended December 31, 1994 and 1993 are presented separately as pre-Merger and post-Merger financial information are not comparable. Certain data for 1994 and 1993 has been reclassified to conform with the 1995 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 used the equity method to account for its less than majority owned investments in affiliates and joint ventures ("Associated Companies"). 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. The Company used the proportionate consolidation method to account for its investment in Diamond Shamrock Offshore Partners Limited Partnership ("Offshore Partners"). The Company sold its investment in Offshore Partners in the second quarter of 1994 (See Note Four). All significant intercompany accounts and transactions have been eliminated.
Statement of Cash Flows
Investments with original maturities of three months or less at the time of original purchase are considered cash equivalents for purposes of the accompanying Consolidated Statement of Cash Flows. Short-term investments include investments with maturities over three months but less than one year.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Net cash provided by operating activities reflects cash receipts for interest income and cash payments for interest expense and income taxes as follows:
Inventory Valuation
Inventories are valued at the lower of historical cost or market value and are primarily comprised of well equipment and supplies. Historical cost is determined primarily by using 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.
For investment in unproved properties in the United States, a valuation allowance (included as an element of depletion) is provided by a charge against earnings to reflect the impairment of unproven acreage. Investment in international non-producing leasehold costs are reviewed periodically by management to insure the carrying value is recoverable based upon the geological and engineering estimates of total possible and probable reserves expected to be added over the remaining life of each concession. Based upon increases to proved reserves determined by reserve reports, a portion of the investment in international non-producing leasehold costs will be periodically transferred to investment in proved properties.
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 ("UOP") method based upon estimated proved developed reserves. Leasehold costs are amortized using the UOP method based on estimated total proved 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. Estimated future dismantlement, restoration and abandonment costs for major facilities, net of salvage value, are taken into account in determining depreciation, depletion and amortization.
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, and applying the same depreciation method, as that used for the related assets.
When complete units of depreciable property are retired or sold, the asset cost and related accumulated depreciation are eliminated with any gain or loss reflected in other revenues, net. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage or sales value is charged or credited to accumulated depreciation and depletion.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Deferred Charges
Deferred charges are primarily comprised of debt issuance costs and are amortized over the terms of the related debt agreements.
Revenue Recognition
Oil and gas sales are recorded on the entitlements method. Differences between the Company's actual production and entitlements result in a receivable when underproduction occurs and a payable when overproduction occurs. These underproduced or overproduced volumes are valued based on the weighted average sales price for each respective property. The Company's gross underproduced and overproduced values at March 31, 1995, are not material.
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. The Company accrues 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. The Company accounts for benefits provided after employment but before retirement by accruing 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's policy is to fund other postretirement and postemployment benefits as claims are 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. The Company's estimate of environmental assessment and/or remediation costs to be incurred are based on either 1) detailed feasibility studies of remediation approach and cost for individual sites or 2) the Company's estimate of costs to be incurred based on historical experience and publicly available information, based on the stage of assessment and/or remediation of each site. As additional information becomes available regarding each site or as environmental remediation standards change, the Company revises its estimate of costs to be incurred in environmental assessment and/or remediation.
Income Taxes
The Company reports income taxes in accordance with 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 all expected future tax consequences of events that have been recognized in the Company's financial statements or tax returns. Additionally, SFAS 109 requires that annual taxes are to be allocated to interim periods on the basis of the requirements of
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Accounting Principles Board Opinion No. 28 ("APB 28"), Interim Financial Reporting. The reporting requirements of APB 28 are based on the view that each interim period is an integral part of the related annual period.
Because the tax year of the Company did not close in any relevant jurisdiction on March 31, 1995, taxes were not measured on deferred tax liabilities and assets at that time. In accordance with APB 28 and SFAS 109, taxes were allocated to the period based on the estimated annual effective tax rate for the period ended December 31, 1995.
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, restricted cash and trade receivables.
The Company's cash equivalents, short-term investments and restricted cash 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 Company's 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.
The Company has minimal exposure to credit losses in the event of nonperformance by the counterparties to its interest rate swap agreement, natural gas price swap agreements and nonderivative financial assets. The Company does not obtain collateral or other security to support financial instruments subject to credit risk but restricts such arrangements to investment-grade counterparties.
Investments in Marketable Securities
Effective January 1, 1994, the Company adopted Statement of Financial Accounting Standards No. 115, ("SFAS 115") "Accounting for Certain Investments in Debt and Equity Securities." SFAS 115 requires that investments in debt and equity securities be reported at fair value except for those investments in debt securities which management has the intent and the ability to hold to maturity. Investments in debt securities which are held-for-sale are classified based on the stated maturity and management's intent to sell the securities. Unrealized gains and losses on investments in marketable securities, except for debt securities classified as "held-to-maturity", are reported as a separate component of stockholders' equity. The cumulative effect of adopting SFAS 115 of $2.4 million was recorded as a valuation reserve in shareholders' equity. The Company's gross unrealized loss on its involvement in marketable securities which are included in long-term investments at March 31, 1995, was $1.3 million which was entirely comprised of unrealized losses on the Company's investment in U. S. Treasury Notes. Prior to the adoption of SFAS 115, the Company accounted for its investments in debt securities at amortized cost and classified such investments according to the stated maturity of the underlying securities.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Derivatives
The Company periodically hedges the effects of fluctuations in the price of crude oil and natural gas through price swap agreements and futures contracts. The Company historically has hedged no more than 50% of its U. S. gas production. Gains and losses on these hedges are deferred until the related sales are recognized and are recorded as a component of sales and operating revenues. The Company periodically enters into interest rate swap agreements to hedge interest on long-term debt. The gain or loss on interest rate swaps is recognized monthly as a decrease or increase to interest expense.
Take-or-Pay Obligations
The Company records payments received for take-or-pay obligations for unpurchased contract volumes as deferred revenue, which is included in Other Liabilities in the consolidated balance sheet. The deferred revenue is recognized in the income statement as quantities are delivered which fulfill the take-or-pay obligation. At March 31, 1995, the Company had $13.6 million in deferred revenue as a result of a take-or-pay payment received related to its Indonesian operations.
NOTE TWO--MASTER LIMITED PARTNERSHIP
In 1994, the Company sold its interests in Offshore Partners, a master limited partnership, which explored for and produced natural gas and crude oil on federal offshore leases in the Gulf of Mexico (See Note Four). Maxus Offshore Exploration Company, a wholly owned subsidiary of the Company, and the Company had a combined 1% general partner's interest in Offshore Partners and were 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.
NOTE THREE--PRE-MERGER COSTS
In March 1995, the Company recorded $42.4 million of pre-merger costs associated with the Merger. Such costs, which included expenses associated with financial consulting and legal services, severance payments pursuant to change of control agreements and payments for surrender of stock options and restricted stock, were recorded in accrued liabilities in the consolidated balance sheet.
NOTE FOUR--RESTRUCTURING
Asset Sales
On April 25, 1994, Offshore Partners sold its interests in Main Pass Blocks 72, 73 and 74. On April 26, 1994, Maxus and its subsidiaries sold all of their partnership interests in Offshore Partners. On June 22, 1994, Maxus also sold the McFarlan Field and Grand Isle Block 25, both producing oil and gas properties. In total, the Company received $324.6 million of proceeds and recorded a net gain of $201.9 million from these transactions.
Restructuring Costs
In June 1994, the Company recorded a $100.9 million restructuring charge. The charge included a $69.8 million write-off associated with undeveloped Alaska coal leases, the development of which does not fit within the Company's strategy to commit funds only to oil and gas exploration and production. The charge also included costs associated with staff reductions and the write-off of non-producing assets outside the Company's core areas.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE FIVE--ASSET ACQUISITIONS AND DIVESTITURES
In September of 1994, the Company sold its geothermal subsidiary, Thermal Power Company, for approximately $58 million net in cash and a $6.5 million promissory note due from the purchaser in 1997. A $12.6 million loss on the sale of these assets was recognized.
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 million and retained an overriding royalty interest ("ORI"). There was no gain or loss recognized on this transaction. In December 1995, the Company sold its ORI to the same party for $25 million.
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 based on an average international crude oil price. Maxus is 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.
During the second quarter of 1994, Maxus Venezuela (C.I.) Ltd., a subsidiary of Maxus, signed an agreement with BP Exploracion de Venezuela S.A., granting BP a 45% interest in the Quiriquire Unit in eastern Venezuela. Maxus Venezuela remained the operator with a 50% interest and Otepi Consultores, a Venezuelan company, holds the remaining 5%. Also, during the second quarter of 1994, Maxus Bolivia, Inc., a subsidiary of Maxus, signed an agreement to take BHP Petroleum as a partner in its Bolivian oil development project. The Company received $10 million from BHP in exchange for a 50% interest in the project.
NOTE SIX--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:
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Net foreign assets were $685.5 million at March 31, 1995, $701.4 million at December 31, 1994 and $673.5 million at December 31, 1993.
Income from foreign operations, after applicable local income taxes, was $16.7 million for the three months ended March 31, 1995 and $63.9 million and $77.8 million for the years ended December 31, 1994 and 1993, respectively.
Sales to three customers for the three months ended March 31, 1995 and the year ended December 31, 1994 and 1993 each represented 10% or more of consolidated sales:
The Company does not believe that the loss of Mitsubishi Corporation and Phillips Petroleum Company as customers would adversely affect the Company's ability to market its oil and gas production. Sales to the Company's largest customer, the Indonesian Government, are made primarily pursuant to long-term
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
production sharing contracts between the Company's Indonesian operations and the Indonesian Government. The Indonesian Government is required to purchase a specified amount of the Company's oil and gas production throughout the life of its operations in Indonesia based on these contracts.
NOTE SEVEN--TAXES
The Company reports income taxes in accordance with SFAS 109 (See Note One). The standard was adopted in January 1993. Adoption, which was made prospectively, had no impact on 1993 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.
Income before income taxes, extraordinary item and cumulative effect of change in accounting principle was comprised of income (loss) from:
The Company's provision for income taxes was comprised of the following:
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
The principal reasons for the difference between tax expense at the statutory federal income tax rate of 35% and the Company's provision for income taxes were:
"Items not related to current year earnings" in 1994 includes tax benefit from the favorable resolution of a federal tax refund suit.
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities for the three months ended March 31, 1995, December 31, 1994 and 1993 were as follows:
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
The valuation allowance was $92.6 million upon adoption of SFAS 109. The valuation allowance was increased $23.4 million during 1994 and $13.9 million during the first three months of 1995, primarily due to the increase in loss carryforwards.
Because the tax year of the Company did not close on March 31, 1995, tax carryovers are not measured at that date. At December 31, 1994, the Company had $13.1 million of general business credit carryforwards that expire between 1996 and 2002; $103.8 million of U.S. net operating loss carryforwards that expire in 2003, 2005 and 2008; and $10.1 million of minimum tax credit that can be carried forward indefinitely.
As a result of the Merger, effective April 1, 1995, the Company's ability to utilize its existing net operating loss carryforwards will be limited by statute to approximately $92.0 million each year until exhausted. To the extent certain gains are recognized in the future, the annual limitation may be increased to the extent that the gains are built-in gains within the meaning of the U.S. Internal Revenue Code.
There are accumulated undistributed earnings after applicable local taxes of foreign subsidiaries of $6.4 million at March 31, 1995 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 in the foreign jurisdictions.
Taxes other than income taxes were comprised of the following:
NOTE EIGHT--POSTEMPLOYMENT BENEFITS
Pensions
The components of net periodic pension expense are as follows:
Due to an early retirement program offered to former employees, the Company recognized a settlement loss of $1.7 million on one of its plans in 1994.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Plan assets are primarily invested in short-term investments and stocks and bonds. The principal assumptions used to estimate the benefit obligations of the plans on the measurement date, October 1, 1994 were as follows:
The funded status of the plans at March 31, 1995 and December 31, 1994 were as follows:
At March 31, 1995 and December 31, 1994, 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 $19.2 million and a charge to equity of $18.3 million at March 31, 1995 and December 31, 1994.
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 by the Company with a contribution of 6% of compensation by the Company. Contributions to the plan were $.1 million in the first quarter of 1995 and $.4 million in 1994.
Other Postretirement Benefits
Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106 ("SFAS 106"), "Employers' Accounting for Postretirement Benefits Other Than Pensions," for its retiree health and welfare 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 U. S. 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
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
requirements. At January 1, 1993, the estimated APBO was $46.1 million, which the Company elected to amortize over a 20-year period.
During 1994, the Company's postretirement medical and life insurance plans experienced a partial curtailment due to the Company's decision to reduce staff. The effect of the curtailment was a $6.6 million charge to earnings in 1994, which was included as a component of the restructuring costs (See Note Four), primarily due to accelerated recognition of the transition obligation.
The components of net periodic postretirement benefit expense for the three months ended March 31, 1995 and for the years ended December 31, 1994 and 1993 are as follows:
The APBO as of March 31, 1995 was $44.4 million. The amount recognized in the Company's statement of financial position at March 31, 1995 and December 31, 1994 is as follows:
A discount rate of 8.5% was used in determining the APBO for the three months ended March 31, 1995 and the year ended December 31, 1994. The APBO was based on a 10.4% 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 by $4.2 million and increase the net periodic postretirement benefit cost by $.4 million per year.
Other Postemployment Benefits
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. SFAS 112 requires an accrual method of recognizing the cost of providing postemployment benefits. Prior to 1993, postemployment benefit expenses were recognized as paid. The Company recognized the cumulative effect of the change in accounting for postemployment benefits in 1993, which resulted in a charge of $4.4 million. This liability primarily represents medical benefits for long-term disability recipients. Future annual costs are expected to be immaterial. Net periodic postemployment benefit expense
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
was insignificant for the three months ended March 31, 1995 and for the years ended December 31, 1994 and 1993.
NOTE NINE--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.
Restricted Cash
The fair value of the Company's restricted cash, which is invested primarily in U. S. Treasury notes, marketable securities and trust accounts is based on the quoted market prices for the same or similar securities at the reporting date.
Long-Term Investments
The fair value of the Company's long-term investments, which are primarily U. S. Treasury notes and long-term notes receivable, is based on the quoted market prices for the same or similar investments at the reporting date.
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.
The estimated fair value of the Company's financial instruments are as follows:
For information on the Company's derivative financial instruments, see Note Seventeen.
NOTE TEN--RECEIVABLES
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE ELEVEN--PROPERTIES AND EQUIPMENT
The charge against earnings for depreciation, depletion and amortization of property and equipment was $29.9 million for the three months ended March 31, 1995, and $138.9 million and $152.3 million for the years ended December 31, 1994 and 1993, respectively. The charge against earnings for maintenance and repairs was $7.4 million for the three months ended March 31, 1995, and $38.9 million and $35.0 million for the years ended December 31, 1994 and 1993, respectively.
NOTE TWELVE--INVESTMENTS AND LONG-TERM RECEIVABLES
In September 1994, the Company sold its geothermal subsidiary, Thermal Power Company, which owned Union-Magma-Thermal Tax Partnership ("UMT") (See Note Five). The investment in UMT was carried on the equity method prior to the sale of Thermal Power Company. The following schedule presents certain summarized financial information of UMT:
The Company's equity earnings are principally from UMT and were $5.2 million in 1994 and $10.2 million in 1993.
NOTE THIRTEEN--RESTRICTED CASH
At March 31, 1995 and December 31, 1994, the Company had $128.4 million and $140.6 million, respectively, in restricted cash, of which $64.0 million in 1995 and $78.5 million in 1994 represented collateral for outstanding letters of credit. Assets held in trust as required by certain insurance policies were $64.4 million in 1995 and $62.1 million in 1994. Approximately $48.5 million and $46.4 million of collateral for outstanding letters of credit at March 31, 1995 and December 31, 1994, respectively, was classified as a current asset.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE FOURTEEN--INTANGIBLE ASSETS
Intangibles, primarily the excess of cost over fair market value of net assets acquired, were $50.0 million at March 31, 1995 and December 31, 1994. Accumulated amortization at March 31, 1995 and December 31, 1994 was $14.5 million and $14.2 million, respectively. The charge against earnings for amortization of intangible assets was $0.3 million for the three months ended March 31, 1995 and $1.3 million for the years ended December 31, 1994 and 1993.
NOTE FIFTEEN--ACCRUED LIABILITIES
NOTE SIXTEEN--LONG-TERM DEBT AND CREDIT ARRANGEMENTS
The aggregate maturities of long-term debt outstanding at March 31, 1995, for the next five years will be as follows:
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
At March 31, 1995 and December 31, 1994, the Company had $149.3 million of medium-term notes outstanding, which were issued in prior years, with maturities from 1995 to 2004 and annual interest rates ranging from 7.57% to 11.08%.
The Company maintains a $25.0 million uncommitted credit facility (the "credit facility") which is used for the issuance of documentary or standby letters of credit and/or the payment of shipping documents. The credit facility can be secured by cash or the accounts receivable which are financed through the letters of credit. At March 31, 1995, there were $24.5 million of cash collateralized letters of credit outstanding under this credit facility.
Total interest and debt expenses incurred, including capitalized interest, were as follows:
NOTE SEVENTEEN--DERIVATIVE FINANCIAL INSTRUMENTS
The Company's only derivative financial instruments are an interest rate swap agreement with an investment broker, natural gas price swap agreements and crude oil and natural gas futures contracts, which are not used for trading purposes.
Interest Rate Swap Agreement
Effective January 27, 1993, the Company entered into an interest rate swap agreement under which it pays 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 borrowings of $5.8 million against its then favorable position in this interest rate swap agreement. Due to higher interest rates in 1994, the Company's position in the interest rate swap became unfavorable. As a result, the Company was required to collateralize $7.9 million, which was recorded in deferred charges at December 31, 1994. As interest rates declined during the first three months of 1995, the Company reduced its collateralized position by $3.4 million, leaving a balance of $4.5 million recorded in deferred charges at March 31, 1995.
Natural Gas Price Swap Agreements
Under the price swap agreements used to hedge fluctuations in the price of natural gas, the Company receives or makes payments based on the differential between the Company's specified price and the counterparty's specified price of natural gas. Depending on the agreement, the Company pays a fixed or variable price per million British Thermal Units ("Mmbtu") and receives a fixed or variable price per Mmbtu. During the three months ended March 31, 1995, the Company had swap agreements with other companies to exchange payments on 0.8 million Mmbtu of gas. Under these swap agreements, the Company paid fixed or variable prices averaging $1.61 per Mmbtu and received fixed or variable prices averaging $1.58 per Mmbtu. Gross gains and gross losses realized on these swap agreements were immaterial.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Natural Gas and Crude Oil Futures Contracts
Under the natural gas futures contracts used to hedge fluctuations in the price of natural gas, the Company receives or makes payments based on the differential between the selling price and the settlement price per Mmbtu. During the three months ended March 31, 1995, the Company settled futures contracts with other companies on 1.2 million Mmbtu of gas. Under these futures contracts, the Company received selling prices averaging $1.65 per Mmbtu and paid settlement prices averaging $1.46 per Mmbtu. Realized gross gains on these futures contracts were $0.2 million.
Under the crude oil futures contracts used to hedge fluctuations in the price of crude oil, the Company receives or makes payments based on the differential between the selling price and the settlement price per barrel. During the three-month period ended March 31, 1995, crude oil volumes hedged under these futures contracts were insignificant as were gross unrealized gains and losses.
NOTE EIGHTEEN--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 established by the Company's Board of Directors at the time of issuance.
$9.75 Cumulative Convertible Preferred Stock
In 1987, the Company sold 3,000,000 shares of $9.75 Cumulative Convertible Preferred Stock (the "$9.75 Preferred Stock"). Since such time, the Company has entered into various agreements, most recently on June 8, 1995, with the sole holder of the $9.75 Preferred Stock pursuant to which, among other things, the Company has repurchased 500,000 shares and the parties have waived or amended various covenants, agreements and restrictions relating to such stock. Currently, 1,250,000 shares of $9.75 Preferred Stock are outstanding, each receiving an annual cash dividend of $9.75. In addition, 375,000 of such shares (the "Conversion Waiver Shares") each receive an additional quarterly cash payment of $.25 ($.50 in certain circumstances). For the 12-month period commencing February 1, 1995, each share of the $9.75 Preferred Stock has a liquidation value of $101.0836 ($126.4 million in the aggregate) which reduces to $100 at February 1, 1996, in each case plus accrued dividends. Since February 1, 1994, the stock has been subject to mandatory redemption at the rate of 625,000 shares per year. The $9.75 Preferred Stock currently is neither convertible by the holder nor redeemable at the Company's option and has no associated registration rights. The $9.75 Preferred Stock entitles the holder to vote only on certain matters separately affecting such holder, and the $9.75 Preferred Stock other than the Conversion Waiver Shares entitles the holder to elect one individual to the Board of Directors of the Company. In addition, pursuant to the June 8, 1995 agreement, the holder of the $9.75 Preferred Stock waived previously granted rights to approve certain "self-dealing" transactions and certain financial covenants pertaining to the Company, and the Company waived its right of first offer with respect to the transfer of the $9.75 Preferred Stock and certain transfer restrictions on such stock.
$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 March 31, 1995), is entitled to receive annual cash dividends of $4.00 per share, is callable at and has a liquidation value of $50.00 per share ($217.8 million in the aggregate at March 31, 1995) plus accrued but unpaid dividends, if any.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
$2.50 Cumulative Preferred Stock
Each outstanding share of the $2.50 Preferred is entitled to shall receive annual cash dividends of $2.50 per share, is callable after December 1, 1998 at and has a liquidation value of $25.00 per share ($87.5 million in the aggregate at March 31, 1995) plus accrued but unpaid dividends, if any.
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 due.
NOTE NINETEEN--COMMON STOCK
On July 30, 1991, the Company's Dividend Reinvestment and Stock Purchase Plan (the "Plan") became effective. The Plan allowed 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 paid a dividend on its Common Stock in the future, common stockholders could 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 the Plan by raising the threshold price.
At March 31, 1995 and December 31, 1994, respectively, there were 32.4 million and 35.8 million shares of Common Stock reserved for issuance upon conversion of Preferred Stock, exercises of stock options or issuance under certain employee benefit plans.
In 1992, Kidder, Peabody & Co. Incorporated purchased eight million warrants from the 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.
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 six 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 $0.6 million, $2.8 million and
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
$2.6 million at March 31, 1995, December 31, 1994, and December 31, 1993, respectively. Subsequent to the Merger, contributions can no longer be invested in the Company's Common Stock.
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. In the Merger Agreement, the Company agreed to redeem the rights. On February 28, 1995, the Board of Directors of the Company took action to redeem the rights, effective as of March 22, 1995. Holders of Common Stock on the close of business on that date received the redemption price of $0.10 per right. Under a separate agreement with the sole holder of the $9.75 Preferred Stock, such holder waived its right to receive the redemption price with respect to the rights associated with the $9.75 Preferred Stock, subject to consummation of the Merger.
NOTE TWENTY--PAID-IN CAPITAL AND ACCUMULATED DEFICIT
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE TWENTY-ONE--UNREALIZED LOSS ON INVESTMENT IN MARKETABLE SECURITIES
The amortized cost and estimated fair value of marketable securities at March 31, 1995 are as follows:
At March 31, 1995, securities categorized as held-to-maturity are included in cash equivalents, short-term investments and short- and long-term restricted cash. The securities held-for-sale consist of U. S. Treasury notes which mature in August, 2002 and are classified as long-term investments (See Note Twelve).
The amortized cost and estimated fair value of marketable securities at December 31, 1994 are as follows:
At December 31, 1994, securities categorized as held-to-maturity with maturities of 90 days or less are classified as cash equivalents and those with maturities greater than ninety days are classified as short-term investments. The securities held-for-sale consist of U. S. Treasury notes which mature in August, 2002 and are classified as long-term investments (See Note Twelve).
NOTE TWENTY-TWO--COMMON TREASURY STOCK
NOTE TWENTY-THREE--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.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
The Director Stock Option Plan became effective on September 1, 1992. Under this plan, non-employee directors received options 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 directors automatically receive options to purchase shares of Common Stock. The plan terminated on June 7, 1995.
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.
Stock option activity was as follows:
Exercise prices of stock options outstanding at March 31, 1995 ranged from $5.00 to $13.75 per share. There was a credit to earnings for SARs in 1993 of $.1 million. There was no earnings activity related to SARs in 1994 or for the period ended March 31, 1995. Effective upon the Merger, all stock options and restricted stock outstanding under Company-sponsored incentive plans were surrendered to the Company.
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 $0.5 million for the period ended March 31, 1995, $1.4 million in 1994 and $2.4 million in 1993.
In 1993, the Company issued performance units under the 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 $0.6 million in 1993. There was no earnings activity related to performance units in 1994. For the period ended March 31, 1995, there was a credit to earnings of $0.6 million.
Effective upon the Merger, all stock options and restricted stock outstanding under Company-sponsored incentive plans were surrendered to the Company. In March 1995, the Company recorded a $9.9 million charge to earnings to record the estimated cost to redeem all outstanding options and restricted stock. This charge was included in pre-Merger costs in the Company's consolidated statement of operations (See Note Three).
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE TWENTY-FOUR--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 March 31, 1995, were as follows:
Minimum annual rentals have not been reduced by minimum sublease rentals of $38.7 million due in the future under noncancelable subleases.
Rental expense for operating leases was as follows:
NOTE TWENTY-FIVE--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 the first quarter of 1995, the Company spent $1.4 million in environmental related expenditures for its oil and gas operations.
In addition, the Company is implementing certain environmental projects related to its former chemicals business ("Chemicals") sold to an affiliate of Occidental Petroleum Corporation (collectively, "Occidental") in 1986 and certain other disposed of businesses. The environmental projects discussed below relating to Chemicals' business are being conducted on behalf of Occidental pursuant to the sale agreement.
The Company has agreed to remediate the site of the former agricultural chemical plant in Newark, New Jersey as required by a consent decree entered into in 1990 by Occidental, the United States Environmental Protection Agency (the "EPA") and the New Jersey Department of Environmental Protection and Energy (the "DEP"). Pursuant to an agreement with the EPA, the Company is conducting further testing and studies to characterize contaminated sediment in a 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 1990, covering sites primarily in Kearny and Secaucus, New Jersey, the Company will continue to implement interim remedial measures and to perform remedial investigations and feasibility studies and, if necessary, will 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.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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.
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. DSI is expected to reach its total reimbursement obligation in 1996.
The Company's total expenditures for environmental compliance for disposed of businesses, including Chemicals, were $7.9 million in the first quarter of 1995, $2.6 million of which was recovered from DSI under the cost-sharing agreement.
Reserves have been established for environmental liabilities where they are material and probable and can be reasonably estimated. At March 31, 1995 and December 31, 1994, reserves for the above environmental contingencies totaled $84.7 million and $87.1 million, respectively. During 1994, the Company increased its reserve for future environmental liabilities by $60.5 million, primarily in response to the EPA's proposal of chromium clean-up standards and for additional costs expected to be incurred at Chemicals' former Newark, New Jersey plant site.
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.
The Company has begun discussions with various government entities in Ecuador regarding a number of issues related to Block 16 and the Tivacuno area, including the Company's cost recovery claims, the approval of budgets, contract terms and other operating matters. The Company believes these matters will be satisfactorily resolved.
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 Arthur Andersen LLP, independent accountants, for the three months ended March 31, 1995 and the nine months ended December 31, 1995 and have been audited by Price Waterhouse LLP, independent accountants, for the two years in the period ended December 31, 1994.
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 without representatives of the Company present, to discuss accounting, control, auditing and financial reporting matters.
/s/ W. MARK MILLER W. Mark Miller Executive Vice President and Treasurer (Principal Financial Officer)
/s/ LINDA R. ENGELBRECHT Linda R. Engelbrecht Controller (Principal Accounting Officer)
Dallas, Texas February 2, 1996
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors of Maxus Energy Corporation
We have audited the accompanying consolidated balance sheets of Maxus Energy Corporation (a Delaware corporation) and subsidiaries as of March 31, 1995 and December 31, 1995, and the related consolidated statements of operations and cash flows for the three months ended March 31, 1995 and the nine months ended December 31, 1995. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Maxus Energy Corporation and its subsidiaries as of March 31, 1995 and December 31, 1995, and the results of its operations and its cash flows for the three months ended March 31, 1995 and the nine months ended December 31,1995, in conformity with generally accepted accounting principles.
/s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP
Dallas, Texas February 2, 1996
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, 1994 and the results of their operations and their cash flows for each of the two years in the period ended December 31, 1994, 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, 7 and 8 to the Consolidated Financial Statements, the Company changed its methods of accounting for income taxes, postretirement benefits and postemployment benefits in 1993.
/s/ PRICE WATERHOUSE LLP PRICE WATERHOUSE LLP
Dallas, Texas February 28, 1995
FINANCIAL SUPPLEMENTARY INFORMATION (Unaudited)
(DATA IS AS OF DECEMBER 31 FOR THE YEARS ENDED 1993 AND 1994 AND AS OF MARCH 31 FOR THE FIRST QUARTER THEN ENDED 1995. THE 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.
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(a) Includes United States gathering and processing costs related to sales. Such costs were $3.1 million, $11.8 million and $15.1 million for March 31, 1995, December 31, 1994 and 1993, respectively.
(b) Production costs, Exploration costs and Other have been restated for the years ended December 31, 1994 and 1993 to be consistent with current period presentation.
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:
Costs Incurred
Costs incurred by the Company in its oil and gas producing activities (whether capitalized or charged against earnings) were as follows:
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(a) Exploration costs have been restated for the years ended December 31, 1994 and 1993 to be consistent with current period presentation.
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 quarter-end March 31, 1995 and at year-end 1994 and 1993. 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.
Estimates of reserves were prepared by the Company using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC"). The choice of method or combination of methods employed in the analysis of each reservoir was determined by experience in the area, stage of development, quality and completeness of basic data, and production history. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumption upon which they were based. The reserve estimates were subjected to economic tests to determine economic limits. The estimates may change as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continued reassessment of the viability of production under varying economic conditions.
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(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 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. Increasing prices at the end of 1994 resulted in a decrease of 11.7 million barrels. Decreasing prices resulted in an increase of 24.3 million barrels in 1993.
(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 11% 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) Reserves in Venezuela attributable to an operating service agreement under which all hydrocarbons are owned by the Venezuelan government have not been included. Production reported in Oil and Gas reserves does not include Venezuela production but it is included in net oil sales reported in Exploration and Production Statistics. The SFAS 69 Results of Operations, Capitalized Costs and Costs Incurred disclosures include costs related to Venezuela.
(d) Reserves are estimated at year end only. Reserves at March 31, 1995 are December 31, 1994 reserves adjusted only for the production for the first quarter of 1995 and purchase of properties in the United States.
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 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.
Future net cash flows and changes in the standardized measure are only prepared at year-end, therefore, no data is presented as of March 31, 1995. Information as of December 31, 1995 is included in the Post-merger section.
The following are the principal sources for change in the standardized measure:
MAXUS ENERGY CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
See Notes to Consolidated Financial Statements.
MAXUS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEET
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. The Consolidated Balance Sheet at April 1, 1995 which represents the opening post-merger consolidated balance sheet is unaudited.
MAXUS ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
See Notes to Consolidated Financial Statements.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PRESENTATION
On June 8, 1995, a special meeting of the stockholders of Maxus Energy Corporation (together with its foreign and domestic subsidiaries, the "Company" or "Maxus") was held to approve the Agreement of Merger ("Merger Agreement") dated February 28, 1995, between the Company, YPF Acquisition Corp. (the "Purchaser") and YPF Sociedad Anonima ("YPF"). The holders of the Company's common stock, $1.00 par value per share, and $4.00 Cumulative Convertible Preferred Stock approved the Merger Agreement, and the Purchaser was merged into the Company (the "Merger") on June 8, 1995.
Effective April 1, 1995, the Company used the purchase method of accounting to record the acquisition of the Company by YPF. In a purchase method combination, the purchase price is allocated to acquired assets and assumed liabilities based on their fair values at the date of acquisition. As a result, the Company's assets and liabilities were revalued to reflect the approximate $762 million cash purchase price paid by YPF to acquire the Company. The Company's pre-Merger Consolidated Balance Sheet as of March 31, 1995, together with the purchase method accounting adjustments, became the Company's opening unaudited post-Merger Consolidated Balance Sheet on April 1, 1995, which is included in the accompanying balance sheet.
The following post-Merger data is for the nine months ended December 31, 1995 and dollar amounts in tables are in millions, except per share amounts. Post-Merger financial information is not comparable to prior periods due to the application of purchase accounting effective April 1, 1995.
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 Accounting
The Consolidated Financial Statements include the accounts of Maxus Energy Corporation and all domestic and foreign subsidiaries. All significant intercompany accounts and transactions have been eliminated.
Statement of Cash Flows
Investments with original maturities of three months or less at the time of original purchase are considered cash equivalents for purposes of the accompanying Consolidated Statement of Cash Flows. Short-term investments include investments with maturities over three months but less than one year.
Net cash provided by operating activities reflects cash receipts for interest income and cash payments for interest expense and income taxes as follows:
Inventory Valuation
Inventories are valued at the lower of historical cost or market value and are primarily comprised of well equipment and supplies. Historical cost is determined primarily by using the weighted average cost method.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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.
For investment in unproved properties in the United States, a valuation allowance (included as an element of depletion) is provided by a charge against earnings to reflect the impairment of unproven acreage. Investment in international non-producing leasehold costs are reviewed periodically by management to insure the carrying value is recoverable based upon the geological and engineering estimates of total possible and probable reserves expected to be added over the remaining life of each concession. Based upon increases to proved reserves determined by reserve reports, a portion of the investment in international non-producing leasehold costs will be periodically transferred to investment in proved properties.
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 ("UOP") method based upon estimated proved developed reserves. Leasehold costs are amortized using the UOP method based on estimated total proved reserves. Other properties and equipment are depreciated generally on the straight-line method over their estimated useful lives. Estimated future dismantlement, restoration and abandonment costs for major facilities, net of salvage value, are taken into account in determining depreciation, depletion and amortization.
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, and applying the same depreciation method, as that used for the related assets.
When complete units of depreciable property are retired or sold, the asset cost and related accumulated depreciation are eliminated with any gain or loss reflected in other revenues, net. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage or sales value is charged or credited to accumulated depreciation and depletion.
Deferred Charges
Deferred charges are primarily comprised of debt issuance costs and are amortized over the terms of the related debt agreements.
Revenue Recognition
Oil and gas sales are recorded on the entitlements method. Differences between the Company's actual production and entitlements result in a receivable when underproduction occurs and a payable when overproduction occurs. These underproduced or overproduced volumes are valued based on the weighted average sales price for each respective property. The Company's gross underproduced and overproduced volumes at December 31, 1995, are not material.
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
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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. The Company accrues 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. The Company accounts for benefits provided after employment but before retirement by accruing 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's policy is to fund other postretirement and postemployment benefits as claims are 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. The Company's estimate of environmental assessment and/or remediation costs to be incurred are based on either 1) detailed feasibility studies of remediation approach and cost for individual sites or 2) the Company's estimate of costs to be incurred based on historical experience and publicly available information, based on the stage of assessment and/or remediation of each site. As additional information becomes available regarding each site or as environmental remediation standards change, the Company revises its estimate of costs to be incurred in environmental assessment and/or remediation.
Income Taxes
The Company reports income taxes in accordance with 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 all expected future tax consequences of events that have been recognized in the Company's financial statements or tax returns. Additionally, SFAS 109 requires that annual taxes are to be allocated to interim periods on the basis of the requirements of Accounting Principles Board Opinion No. 28 ("APB 28"), Interim Financial Reporting. The reporting requirements of APB 28 are based on the view that each interim period is an integral part of the annual period.
Because the tax year of the Company did not close in any relevant jurisdiction on March 31, 1995, taxes were not measured on deferred tax liabilities and assets at that time. Thus, taxes were allocated to the nine month period ended December 31, 1995 based on an allocation of taxes for the annual period ended December 31, 1995, in accordance with APB 28 and SFAS 109. Deferred tax assets and liabilities were measured at December 31, 1995.
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.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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, short-term investments and restricted cash 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 Company's 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.
The Company has minimal exposure to credit losses in the event of nonperformance by the counterparties to its interest rate swap agreement, natural gas price swap agreements and nonderivative financial assets. The Company does not obtain collateral or other security to support financial instruments subject to credit risk but restricts such arrangements to investment-grade counterparties.
Investments in Marketable Securities
Investments in debt and equity securities are reported at fair value except for those investments in debt securities which management has the intent and the ability to hold to maturity. Investments in debt securities which are held-for-sale are classified based on the stated maturity and management's intent to sell the securities. Unrealized gains and losses on investments in marketable securities, except for debt securities classified as "held-to-maturity", are reported as a separate component of stockholders' equity.
Derivatives
The Company periodically hedges the effects of fluctuations in the price of crude oil and natural gas through price swap agreements and futures contracts. The Company historically has hedged no more than 50% of its U. S. gas production although the Company anticipates it may hedge up to 90% of its U. S. gas production during 1996. Gains and losses on these hedges are deferred until the related sales are recognized and are recorded as a component of sales and operating revenues. The Company periodically enters into interest rate swap agreements to hedge interest on long-term debt. The gain or loss on interest rate swaps is recognized monthly as a decrease or increase to interest expense.
Take-or-Pay Obligations
The Company records payments received for take-or-pay obligations for unpurchased contract volumes as deferred revenue, which is included in Other Liabilities in the consolidated balance sheet. The deferred revenue is recognized in the income statement as quantities are delivered which fulfill the take-or-pay obligation. At December 31, 1995, the Company had $12.4 million in deferred revenue as a result of a take-or-pay payment received related to its Indonesian operations.
NOTE TWO--MERGER
On June 8, 1995, a special meeting of the stockholders of the Company was held to approve the Agreement of Merger ("Merger Agreement") dated February 28, 1995, between the Company, YPF Acquisition Corp. (the "Purchaser") and YPF Sociedad Anonima ("YPF"). The holders of the Company's common stock, $1.00 par value per share (the "Shares"), and $4.00 Cumulative Convertible Preferred Stock (the "$4.00 Preferred Stock") and together with the Shares, the ("Voting Shares") approved the Merger Agreement, and the Purchaser was merged into the Company (the "Merger") on June 8, 1995 (the "Merger Date").
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
The Merger was the consummation of all transactions contemplated by the Merger Agreement. Pursuant to the Merger Agreement, a tender offer (the "Offer") was commenced on March 6, 1995 by the Purchaser for all the outstanding Shares at $5.50 per Share. Pursuant to the Offer, in April 1995 the Purchaser acquired 120,000,613 Shares representing approximately 88.5% of the then-outstanding Shares of the Company. As a result of the Merger, each outstanding Share (other than Shares held by the Purchaser, YPF or any of their subsidiaries or in the treasury of the Company (all of which were cancelled in the second quarter of 1995) and Shares of holders who perfected their appraisal rights under Section 262 of the Delaware General Corporation Law) was converted into the right to receive $5.50 in cash, and YPF became the sole holder of all outstanding Shares. The Company's preferred stock, consisting of the $4.00 Preferred Stock, $2.50 Cumulative Preferred Stock ("$2.50 Preferred Stock") and $9.75 Cumulative Convertible Preferred Stock (the "$9.75 Preferred Stock") remain outstanding. YPF currently owns approximately 96.9% of the outstanding Voting Shares.
The total amount of funds required by the Purchaser to acquire the entire common equity interest in the Company, including the purchase of Shares pursuant to the Offer and the payment for Shares converted into the right to receive cash pursuant to the Merger, was approximately $762 million. On April 5, 1995 the Purchaser entered into a credit agreement (the "Credit Agreement") with lenders for which The Chase Manhattan Bank (National Association) ("Chase") acted as agent, pursuant to which the lenders extended to the Purchaser a credit facility for up to $550 million (the "Purchaser Facility"). On April 5, 1995, the Purchaser borrowed $442 million under the Purchaser Facility and received a capital contribution of $250 million from YPF. The Purchaser used borrowings under the Purchaser Facility and the funds contributed to it by YPF to purchase 120,000,613 Shares pursuant to the Offer. Subsequent to the Merger, these Shares and all other outstanding Shares vested in YPF.
During the second quarter of 1995, the Company used the purchase method to record the acquisition of the Company by YPF. In a purchase method combination, the purchase price is allocated to the acquired assets and assumed liabilities based on their fair values at the date of acquisition. As a result, the assets and liabilities of the Company were revalued to reflect the approximate $762 million cash purchase price paid by YPF plus all liabilities assumed to acquire the Company. The Company's oil and gas properties were assigned carrying amounts based on their relative fair market values. In connection with the purchase price allocation, the Company adopted Statement of Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," which requires a review of long-lived assets for impairment whenever events or changes in circumstance indicate that the carrying amount of the asset may not be recoverable. Under SFAS 121, if the expected future cash flow of a long-lived asset is less than the carrying amount of the asset, an impairment loss shall be recognized to value the asset at its fair value. Maxus revalued its assets and liabilities on April 1, 1995 following the provisions of SFAS 121. There was no impact on the Company's results of operations due to the adoption of SFAS 121 during the nine months ended December 31, 1995.
Following the Merger, Chase provided two additional credit facilities aggregating $425 million: (i) a credit facility of $250 million extended to Midgard Energy Company ("Midgard"), a wholly owned subsidiary of the Company, and (ii) a credit facility of $175 million extended to Maxus Indonesia, Inc. ("Holdings"), a wholly owned subsidiary of the Company. The proceeds of the loans made pursuant to these facilities were used to repay, in part, the Purchaser Facility, which was assumed by the Company pursuant to the Merger. In addition, the Company applied $8 million of its available cash to repay the Purchaser Facility and used approximately $86 million of its available cash to pay holders of Shares converted into the right to receive cash in the Merger.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE THREE--ASSET DIVESTITURES
In December 1995, the Company sold its overriding royalty interest in the Recetor Block in Colombia for $25 million. There was no gain or loss recognized on this transaction as the sales price approximated the carrying value of the investment in the Recetor Block.
NOTE FOUR--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:
Net foreign assets were $1,296.7 million at December 31, 1995. Income from foreign operations, after applicable local taxes, was $6.9 million for the nine months ended December 31, 1995.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Sales to two customers for the nine months ended December 31, 1995 each represented 10% or more of consolidated sales:
The Company does not believe that the loss of Mitsubishi Corporation as a customer would adversely affect the Company's ability to market its oil and gas production. Sales to the Company's largest customer, the Indonesian Government, are made primarily pursuant to long-term production sharing contracts between the Company's Indonesian operations and the Indonesian Government. The Indonesian Government is required to purchase a specified amount of the Company's oil and gas production throughout the life of its operations in Indonesia based on these contracts.
NOTE FIVE--TAXES
Income before income taxes was comprised of income (loss) from:
The Company's provision for income taxes was comprised of the following:
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
The principal reasons for the difference between tax expense at the statutory federal income tax rate of 35% and the Company's provision for income taxes were:
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of and for the nine months ended December 31, 1995 were as follows:
As a result of an increase in U. S. net operating loss carryforwards, the valuation allowance was increased $11.7 million during the nine months ended December 31, 1995.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
At December 31, 1995, the Company had $14.4 million of general business credit carryforwards that expire between 1996 and 2002; $207.7 million of U.S. net operating loss carryforwards that expire from 2003 to 2010; and $5.5 million of minimum tax credit that can be carried forward indefinitely.
As a result of the Merger, effective April 1, 1995, the Company's ability to utilize its existing net operating loss carryforwards will be limited by statute to approximately $92.0 million each year until exhausted. To the extent certain gains are recognized in the future, the annual limitation may be increased to the extent that the gains are built-in gains within the meaning of the U.S. Internal Revenue Code.
There are accumulated undistributed earnings after applicable local taxes of foreign subsidiaries of $5.7 million at December 31, 1995 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 in the foreign jurisdictions.
Taxes other than income taxes were comprised of the following:
NOTE SIX--POSTEMPLOYMENT BENEFITS
Pensions
The components of net periodic pension expense are as follows:
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, 1995, were as follows:
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
The funded status of the plans at December 31, 1995 were as follows:
As a result of the Merger, the Company was required to fully accrue its obligation for pension benefits in purchase accounting (See Note Two). Therefore, effective April 1, 1995, the Company increased its balance sheet liability to reflect any previously unrecognized gains and losses, transition obligations and prior service costs. Additionally, several of the Company's pension plans experienced a partial curtailment due to workforce reductions following the Merger. The impact of the partial curtailment, which had no impact on the Company's net periodic pension expense, reduced the Company's projected benefit obligation by $1.1 million.
At December 31, 1995, 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 $5.9 million and a charge to equity of $5.9 million.
In addition to the defined benefit plans, the Company has a defined contribution plan which covers the Indonesian nationals. Employee contributions of 2% of each covered employee's compensation are matched by the Company with a contribution of 6% of compensation. Contributions to the plan were $.4 million for the nine months ended December 31, 1995.
Other Postretirement Benefits
As a result of the Merger, the Company was required to fully accrue its obligation for postretirement benefits other than pensions in purchase accounting (See Note Two). Therefore, effective April 1, 1995, the Company increased its balance sheet liability by $31.7 million to reflect any previously unrecognized gains and unrecognized transition obligation at March 31, 1995.
The components of net periodic postretirement benefit expense for the nine months ended December 31, 1995 are as follows:
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
The APBO as of December 31, 1995 was $46.6 million. The amount recognized in the Company's statement of financial position at December 31, 1995 is as follows:
A discount rate of 7.5% was used in determining the APBO at December 31 1995. The APBO was based on a 9% increase in the medical cost trend rate, with the rate trending downward .5% 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, 1995 by $4.6 million and increase the net periodic postretirement benefit cost by $.4 million per year.
NOTE SEVEN--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.
Restricted Cash
The fair value of the Company's restricted cash, which is invested primarily in U. S. Treasury notes, marketable securities and trust accounts, is based on the quoted market prices for the same or similar securities at the reporting date. The Company's gross unrealized gain on its restricted cash was $2.3 million at December 31, 1995.
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.
The estimated fair value of the Company's financial instruments are as follows:
For information on the Company's derivative financial instruments, see Note Thirteen.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE EIGHT--RECEIVABLES
NOTE NINE--PROPERTIES AND EQUIPMENT
The charge against earnings for depreciation, depletion and amortization of property and equipment was $142.1 million for the nine months ended December 31, 1995 and the charge against earnings for maintenance and repairs, which is included in operating expenses, was $25 million.
NOTE TEN--RESTRICTED CASH
At December 31, 1995 the Company had $80.4 million in restricted cash, of which $30.7 million represented collateral for outstanding letters of credit and $7.4 million represented six months of interest on outstanding borrowings as required by the Holdings credit agreement. Assets held in trust as required by certain insurance policies were $42.3 million. Approximately $19.0 million of collateral for outstanding letters of credit at December 31, 1995, was classified as a current asset as these amounts are expected to be released during 1996.
NOTE ELEVEN--ACCRUED LIABILITIES
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE TWELVE--LONG-TERM DEBT AND CREDIT ARRANGEMENTS
As a result of the Merger, the Company was required to revalue its outstanding debt to market value. Consequently, the Company reduced the carrying amount of its debt by recording $115.1 million of unamortized discount on April 1, 1995. Total debt outstanding at April 1, 1995 of $1,295.4 million, as included in the accompanying unaudited balance sheet, reflected the unamortized discount. For the nine months ended December 31, 1995 $5.9 million of discount amortization was included as a component of interest expense.
The aggregate maturities of long-term debt outstanding at December 31, 1995, for the next five years will be as follows:
At December 31, 1995, the Company had $144.8 million of medium-term notes outstanding, which were issued in prior years, with maturities from 1996 to 2004 and annual interest rates ranging from 7.57% to 11.08%.
The Company maintains a $25.0 million uncommitted credit facility (the "credit facility"), which is used for the issuance of documentary or standby letters of credit and/or the payment of shipping documents. The credit facility can be secured by cash or the accounts receivable which are financed through the letters of credit. At December 31, 1995, there were $13.8 million of cash collateralized letters of credit outstanding under this credit facility.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Total interest and debt expenses incurred, including capitalized interest, were as follows:
CREDIT FACILITIES
On April 5, 1995, the Company borrowed $442 million under the Purchaser Facility (See Note Two) and received a capital contribution of $250 million from YPF. The Purchaser used borrowings under the Purchaser Facility and the funds contributed to it by YPF to purchase 120,000,613 Shares pursuant to the Offer.
Pursuant to a commitment letter from Chase, Chase provided two additional credit facilities aggregating $425 million: (i) a credit facility of $250 million extended to Midgard Energy Company ("Midgard"), a wholly owned subsidiary of the Company and (ii) a credit facility of $175 million extended to Maxus Indonesia, Inc. ("Holdings"), a wholly owned subsidiary of the Company. The proceeds of these loans were used to repay in part, the Purchaser Facility, which was assumed by the Company. In addition, the Company applied $8 million of its available cash to repayment of the Purchaser Facility. The Company capitalized $16.8 million of debt issue costs during 1995 in connection with the Midgard and Holdings credit facilities. These costs are recorded as deferred charges and amortized over the terms of the related borrowings. For the nine months ended December 31, 1995 $1.2 million of debt issue costs amortization was included as a component of interest expense.
Midgard Facility. Approximately $250 million of the loans under the Purchaser Facility were repaid on June 8, 1995 with funds provided to the Company by Midgard. Midgard provided these funds from the proceeds of a $250 million loan (the "Midgard Loan") extended to it pursuant to a credit agreement (the "Midgard Facility") entered into on such date. In addition, approximately $8 million of the loans outstanding under the Purchaser Facility, including accrued interest on the Purchaser Facility loans, were repaid on June 8, 1995 utilizing cash held by the Company.
The Midgard Loan, which was made in a single drawing, will mature on December 31, 2003 and will be repaid in up to 28 consecutive equal quarterly installments commencing on March 31, 1997, subject to semi-annual borrowing base redeterminations. At December 31, 1995, the borrowing base for the Midgard Facility was $250 million. The borrowing base is subject to redetermination on April 1, 1996. At Midgard's option, the interest rate applicable to the Midgard Loan will be, until March 31, 1997, either (i) the one-, two- or three-month London Interbank Offered Rate ("LIBOR") plus a margin of 1 3/4% or (ii) the Base Rate (as defined in the Midgard Facility) plus a margin of 3/4% and, thereafter, either (iii) the one-, two- or three-month LIBOR plus a margin of 2 1/4% or (iv) the Base Rate plus a margin of 1 1/4%. At December 31, 1995, the interest rate on the Midgard Facility based on the one-month LIBOR plus 1 3/4% was 7.6875%. The Midgard Loan is not secured but is guaranteed by YPF and the Company. The agreement evidencing the Midgard Loan contains, among other things, a negative pledge on all assets of Midgard, subject to customary exceptions. It is anticipated that the Midgard Loan will be repaid with funds generated by Midgard's business operations.
Holdings Facility. Approximately $175 million of the Purchaser Facility was repaid with funds provided on June 16, 1995 to the Company by Holdings. Holdings provided these funds from the proceeds of a $175 million loan (the "Subsidiaries Loan") extended to it pursuant to a credit agreement (the "Holdings Facility") entered into on such date.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
The Subsidiaries Loan, which was made in a single drawing on June 16, 1995, will mature on December 31, 2002 and will be repaid in up to 24 consecutive equal quarterly installments commencing on March 31, 1997, subject to semi-annual borrowing base redeterminations. At December 31, 1995, the borrowing base for the Holdings Facility was $175 million. The borrowing base is subject to redetermination on April 1, 1996. At the option of Holdings, the interest rates applicable to the Subsidiaries Loan will be, until March 31, 1997, either (i) the one-, two- or three-month LIBOR plus a margin of 2 1/4% or (ii) the Base Rate (as defined in the Holdings Facility) plus a margin of 1 1/4% and, thereafter, either (iii) the one-, two- or three-month LIBOR plus a margin of 2 3/4% or (iv) the Base Rate plus a margin of 1 3/4%. At December 31, 1995, the interest rate on the Holdings Facility based on the one-month LIBOR plus 2 1/4% was 8.125%. The Subsidiaries Loan to Holdings is secured by the stock of Maxus Northwest Java, Inc. ("Java") and Maxus Southeast Sumatra, Inc. ("Sumatra") (collectively, the "Holdings Subsidiaries") and by the interest of Holdings, Java and Sumatra in certain accounts maintained at Chase into which the proceeds of sales of hydrocarbons are to be deposited, and is guaranteed by Java, Sumatra, YPF and the Company. The agreement evidencing the Subsidiaries Loan contains a negative pledge on all of the other assets of Holdings, subject to customary exceptions. It is anticipated that the Subsidiaries Loan will be repaid with funds generated by the Holdings Subsidiaries' business operations.
Each of the Midgard Facility and the Holdings Facility contains restrictive covenants including limitations upon the sale of assets, mergers and consolidations, the creation of liens and additional indebtedness, investments, dividends, the purchase or repayment of subordinated indebtedness, transactions with affiliates and modifications to certain material contracts. The obligors under the Midgard Facility and the Holdings Facility may not permit (a) consolidated tangible net worth to be less than $200 million, in the case of the Midgard Facility, or $350 million, in the case of the Holdings Facility, plus (or minus), in the case of Midgard, the amount of any adjustment in the book value of assets or, in the case of Holdings, 70% of the amount of any adjustment to net worth, resulting from the merger of YPF Acquisition Corp. into the Company, (b) the ratio of consolidated cash flow to consolidated debt service to be less than 1.1 to 1.0 at the end of any fiscal quarter and (c) the ratio of consolidated cash flow to consolidated interest expense to be less than 1.25 to 1.0 at the end of any fiscal quarter. In addition, mandatory prepayments of the loans under the Midgard Facility and the Holdings Facility may be required in connection with certain asset sales and casualty losses, upon the issuance of subordinated indebtedness and in 1996 and in each year thereafter if, after semi-annual review, the agent and the lenders determine that a borrowing base deficiency exists. No borrowing base deficiencies existed at December 31, 1995.
The guaranty by Maxus of the obligation under the Midgard Facility (the "Midgard Guaranty") and under the Holdings Facility (the "Subsidiaries Guaranty") contains restrictions upon mergers and consolidations, the creation of liens and the business activities in which Maxus and its subsidiaries may engage. In addition, Midgard, in the case of the Midgard Guaranty, and Holdings and its subsidiaries, in the case of the Subsidiaries Guaranty, are required to be wholly owned subsidiaries of Maxus, except to the extent YPF or a subsidiary of YPF (other than Maxus or a subsidiary of Maxus) makes capital contributions to Midgard or Holdings or one of Holdings subsidiaries, as the case may be.
Keepwell Covenant
Pursuant to the Merger Agreement, in the event that the Company is unable to meet its obligations as they come due, whether at maturity or otherwise, including, solely for the purposes of this undertaking, dividend and redemption payments with respect to the $9.75 Preferred Stock, the $2.50 Preferred Stock and the $4.00 Preferred Stock, YPF has agreed to capitalize the Company in an amount necessary to permit the Company to meet such obligations; provided that YPF's aggregate obligation will be: (i) limited to the amount of debt service obligations under the Purchaser Facility, the Midgard Facility and the Holdings Facility and (ii) reduced by the amount, if any, of capital contributions by YPF to the Company after the Merger Date and by the amount of the net proceeds of any sale by the Company of common stock or
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
nonredeemable preferred stock after the Merger Date. The foregoing obligations of YPF (the "Keepwell Covenant") will survive until June 8, 2004. YPF has made no capital contributions under the Keepwell Covenant as of December 31, 1995. In addition, YPF has guaranteed the Company's outstanding debt as of the Merger Date, the principal amount of which was approximately $976 million. The debt covered by the YPF guarantee includes the Company's outstanding 11 1/4%, 11 1/2% and 8 1/2% Sinking Fund Debentures, its outstanding 9 7/8%, 9 1/2% and 9 3/8% Notes, and its outstanding medium-term notes. YPF has also guaranteed the payment and performance of the Company's obligations to the holders of its $9.75 Preferred Stock.
Advances from Parent
Based on 1996 projections, the Company anticipates that YPF will make capital contributions of approximately $200 million to $250 million under the Keepwell Covenant during 1996. At December 31, 1995, the Company had $6.6 million outstanding of advances from its parent, YPF, which is included in long- term debt.
The Company and YPF intend to enter into a loan agreement during 1996 to facilitate short-term loans by YPF to the Company and short-term loans by the Company to YPF of excess cash balances. It is expected that loans will be made by the parties under the loan agreement during 1996; however, the number and amounts thereof are not presently known.
NOTE THIRTEEN--DERIVATIVE FINANCIAL INSTRUMENTS
The Company's only derivative financial instruments are natural gas price swap agreements and crude oil and natural gas futures contracts, which are not used for trading purposes. During the nine-month period ended December 31, 1995, the Company unwound its sole interest rate swap agreement and recorded a $2.4 million final settlement gain in other revenues. The Company also received a $4.5 million termination payment, which has been deferred.
Natural Gas Price Swap Agreements
Under the price swap agreements used to hedge fluctuations in the price of natural gas, the Company receives or makes payments based on the differential between the Company's specified price and the counterparty's specified price of natural gas. Depending on the agreement, the Company pays a fixed or variable price per million British Thermal Units ("Mmbtu") and receives a fixed or variable price per Mmbtu. During the nine months ended December 31, 1995, the Company had swap agreements with other companies to exchange payments on 10.7 million Mmbtu of gas. Under these swap agreements, the Company paid fixed or variable prices averaging $1.68 per Mmbtu and received fixed or variable prices averaging $1.53 per Mmbtu. Gross losses realized on these swap agreements of $2.1 million were partially offset by gross gains of $0.5 million resulting in a net loss of $1.6 million during the nine months ended December 31, 1995.
As of December 31, 1995, the Company has outstanding price swap agreements with other companies to exchange payments on 5.5 million Mmbtu of gas during the first quarter of 1996. Under these swap agreements, the Company will pay variable prices averaging $2.00 per Mmbtu and receive fixed prices averaging $1.74 per Mmbtu resulting in gross unrealized losses of $1.4 million based on gas sales prices at period end. Actual gains and losses realized upon settlement of these price swap agreements will depend upon the variable prices received at the time of settlement.
Natural Gas and Crude Oil Futures Contracts
Under the natural gas futures contracts used to hedge fluctuations in the price of natural gas, the Company receives or makes payments based on the differential between the selling price and the settlement price per Mmbtu. During the nine months ended December 31, 1995, the Company settled futures contracts
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
with other companies on 4.9 million Mmbtu of gas. Under these futures contracts, the Company received selling prices averaging $1.71 per Mmbtu and paid settlement prices averaging $1.70 per Mmbtu. Realized gross gains and losses on these futures contracts were immaterial.
As of December 31, 1995, the Company had outstanding futures contracts with other companies to sell 3.6 million Mmbtu of gas. Under these futures contracts, the Company will receive selling prices averaging $2.01 per Mmbtu and pay settlement prices averaging $2.76 per Mmbtu resulting in gross unrealized losses of $2.7 million based on gas prices at period end. Actual gains and losses realized upon expiration of these futures contracts will depend upon the settlement prices.
Under the crude oil futures contracts used to hedge fluctuations in the price of crude oil, the Company receives or makes payments based on the differential between the selling price and the settlement price per barrel. During the nine-month period ended December 31, 1995, crude oil volumes hedged under these futures contracts were insignificant as were gross unrealized gains and losses. The Company had no open crude oil futures contracts at December 31, 1995.
NOTE FOURTEEN--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 established by the Company's Board of Directors at the time of issuance.
$9.75 Cumulative Convertible Preferred Stock
In 1987, the Company sold 3,000,000 shares of $9.75 Preferred Stock. Since such time, the Company has entered into various agreements, most recently on June 8, 1995, with the sole holder of the $9.75 Preferred Stock pursuant to which, among other things, the Company has repurchased 500,000 shares and the parties have waived or amended various covenants, agreements and restrictions relating to such stock. Currently, 1,250,000 shares of $9.75 Preferred Stock are outstanding, each receiving an annual cash dividend of $9.75. In addition, 375,000 of such shares (the "Conversion Waiver Shares") each receive an additional quarterly cash payment of $.25 ($.50 in certain circumstances). For the twelve month period commencing February 1, 1996, each share of the $9.75 Preferred Stock has a liquidation value of $100.00 ($125.0 million in the aggregate) plus accrued dividends. Since February 1, 1994, the stock has been subject to mandatory redemption at the rate of 625,000 shares per year. The $9.75 Preferred Stock currently is neither convertible by the holder nor redeemable at the Company's option and has no associated registration rights. The $9.75 Preferred Stock entitles the holder to vote only on certain matters separately affecting such holder, and the $9.75 Preferred Stock other than the Conversion Waiver Shares entitles the holder to elect one individual to the Board of Directors of the Company. In addition, pursuant to the June 8, 1995 agreement, the holder of the $9.75 Preferred Stock waived previously granted rights to approve certain "self-dealing" transactions and certain financial covenants pertaining to the Company, and the Company waived its right of first offer with respect to the transfer of the $9.75 Preferred Stock and certain transfer restrictions on such stock.
$4.00 Cumulative Convertible Preferred Stock
Each outstanding share of $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, 1995), is entitled to receive annual cash dividends of $4.00 per share, is callable at and has a liquidation value of $50.00 per share ($217.8 million in the aggregate at December 31, 1995) plus accrued but unpaid dividends, if any.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
$2.50 Cumulative Preferred Stock
Each outstanding share of the $2.50 Preferred Stock is entitled to receive annual cash dividends of $2.50 per share, is callable after December 1, 1998 at and has a liquidation value of $25.00 per share ($87.5 million in the aggregate at December 31, 1995) plus accrued but unpaid dividends, if any.
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 due.
NOTE FIFTEEN--COMMON STOCK
Pursuant to the offer in April 1995, YPF acquired 120,000,613 shares of Maxus Common Stock at $5.50 per Share representing 88.5% of the then-outstanding Shares of the Company. As a result of the Merger, each outstanding Share (other than Shares held by YPF or any of their subsidiaries or in the treasury of the Company, all of which were cancelled in the second quarter of 1995, and Shares of holders who perfected their appraisal rights under Section 262 of the Delaware General Corporation Law) was converted into the right to receive $5.50, and accordingly, the Company's common stock ceased to be publicly traded. (See Note Two).
At December 31, 1995, there were 10.0 million shares of Common Stock reserved for issuance upon conversion of Preferred Stock. However, since the Company's Common Stock is not publicly traded, there would be no market for the common shares.
In 1992, Kidder, Peabody & Co. Incorporated purchased eight million warrants from the 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.
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. Prior to the Merger employees could also invest in a fund consisting of the Company's Common Stock. However, the Maxus Energy Stock Fund was eliminated from the ESIP plan effective April 19, 1995. The Company matches the participating employees contributions to the ESIP (up to 6% of base pay). Such matching contribution is charged against earnings and prior to April 19, 1995, was invested in the ESIP fund which consisted of the Company's Common Stock. Subsequent to April 19, 1995, the Company's matching contribution is invested in any of five funds as directed by the employee. For the nine months ended December 31, 1995, the charge against earnings for the Company's contribution was $1.7 million.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE SIXTEEN--PAID-IN CAPITAL AND ACCUMULATED DEFICIT
NOTE SEVENTEEN--UNREALIZED GAIN ON INVESTMENT IN MARKETABLE SECURITIES
The amortized cost and estimated fair value of marketable securities at December 31, 1995 are as follows:
At December 31, 1995, securities categorized as held-to-maturity are included in cash equivalents, short-term investments and short- and long-term restricted cash.
NOTE EIGHTEEN--COMMON TREASURY STOCK
See Note Two.
NOTE NINETEEN--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 options 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 directors automatically received options to purchase shares of Common Stock. The plan terminated on June 7, 1995.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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.
Stock option activity was as follows:
There will be no further grants of stock options, restricted stock or performance units subsequent to April 1, 1995 under the Company's Long-Term Incentive Plans. Effective upon the Merger, all stock options and restricted stock outstanding under Company-sponsored incentive plans were surrendered to the Company. The Company anticipates replacing the Long-Term Incentive Plans in 1996.
In 1993, the Company issued performance units under the 1992 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. There was no earnings activity related to performance units for the nine months period ended December 31, 1995 as outstanding performance units had no value.
NOTE TWENTY--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, 1995, were as follows:
Minimum annual rentals have not been reduced by minimum sublease rentals of $36.9 million due in the future under noncancelable subleases.
MAXUS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Rental expense for operating leases was as follows:
NOTE TWENTY-ONE--RELATED PARTY TRANSACTIONS
A director of the Company, who is also a member of the Audit Committee of the Board of Directors, is a partner in a law firm which provides legal services to the Company. Fees for such services amounted to $3.2 million during 1995. Additionally, the Company has $6.6 million outstanding in advances from its parent, YPF.
NOTE TWENTY-TWO--COMMITMENTS AND CONTINGENCIES
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 remedial obligations. 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 Safe Drinking Water Act, the Clean Water Act, the Clean Air Act (as amended in 1990), the Occupational Safety and Health Act, the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended ("CERCLA"), and other federal, as well as state, laws. Such laws address, among other things, limits on the discharge of wastes associated with oil and gas operations, investigation and clean-up of hazardous substances, and workplace safety and health. In addition, these laws typically require compliance with associated regulations and permits and provide for the imposition of penalties for noncompliance. 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 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. Such potential expenditures cannot be reasonably estimated.
In connection with the sale of the Company's former chemical subsidiary, Diamond Shamrock Chemicals Company ("Chemicals"), to Occidental Petroleum Corporation ("Occidental") in 1986, the Company agreed 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"),
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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 cost sharing arrangement was about $39 million as of December 31, 1995. Occidental Chemical Corporation ("OxyChem"), a subsidiary of Occidental, and Henkel Corporation ("Henkel"), an assignee of certain of Occidental's rights and obligations, have filed a declaratory judgment action in Texas state court with respect to the Company's agreement in this regard (see "Legal Proceedings").
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 onethird by DSI and two-thirds by the Company. This arrangement will continue until DSI has borne an additional $47.5 million, following which such costs will be borne solely by the Company. As of December 31, 1995, DSI's remaining responsibility is approximately $8 million and is included in accounts receivable in the accompanying balance sheet.
During the nine months ended December 31, 1995, the Company spent $5 million in environmental related expenditures in its oil and gas operations. Expenditures for the full year 1996 are expected to be approximately $8 million.
For the nine months ended December 31, 1995, the Company's total expenditures for environmental compliance for disposed of businesses, including Chemicals, were approximately $30 million, $9 million of which was recovered from DSI under the above described cost-sharing agreement. Those expenditures are projected to be approximately $23 million for the full year 1996 after recovery from DSI under such agreement.
At December 31, 1995, reserves for the environmental contingencies discussed herein totaled $119 million. Management believes it has adequately reserved for all environmental contingencies which are probable and can be reasonably estimated; however, changes in circumstances could result in changes, including additions, to such reserves in the future.
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 court, 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 for such plan, which will include an engineering estimate of the cost of construction, is progressing. Construction is expected to begin in 1997, cost approximately $22 million and
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
take three to four years to complete. The work is being supervised and paid for by the Company pursuant to its above described indemnification obligation to Occidental. The Company has fully reserved the estimated costs of performing the remedial action plan and required ongoing maintenance costs.
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 several feet of more recent sediment deposits and are not moving. The Company, on behalf of Occidental, negotiated an agreement with the EPA under which the Company is conducting further testing and studies to characterize contaminated sediment in a six-mile portion of the Passaic River near the plant site. The Company currently expects such testing and studies to be completed in 1999 and cost from $4 million to $6 million after December 31, 1995. The Company has reserved its estimate of the remaining costs to be incurred in performing these studies as of December 31, 1995. 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 Passaic River or the Newark Bay watershed and therefore cannot estimate what additional costs, if any, will be required to be incurred.
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 a number of 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 self-guarantee in the amount of $20 million subject to the Company's continuing ability to satisfy certain financial tests specified by the State. 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 is uncertain. The Company anticipates submitting its investigation and feasibility reports to the DEP in late 1996 or 1997. The results of the DEP's review of these reports could impact the cost of any further remediation that may be required. The Company has reserved its best estimate of the remaining cost to perform the investigations and remedial work as being $50 million at December 31, 1995. In addition, the DEP has indicated that it expects Occidental and the Company to participate with the other chromium manufacturers in the funding of certain remedial activities with respect to a number of so-called "orphan" chrome sites located in Hudson County, New Jersey. Occidental and the Company have declined participation as to those sites for which there is no evidence of the presence of residue generated by Chemicals. The Governor of New Jersey issued an Executive Order requiring state agencies to provide specific justification for any state requirements more stringent than federal requirements. The DEP has indicated that it may be revising its soil action level upwards towards the higher soil screening levels proposed by the EPA in 1994.
Painesville, Ohio. From about 1912 through 1976, Chemicals operated manufacturing facilities in Painesville, Ohio. The operations over the years involved several discrete but contiguous plant sites over an area of about 1,300 acres. The primary area of concern historically has been Chemicals' former chromite ore processing plant (the "Chrome Plant"). For many years, the site 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 site and to conduct certain ground water and surface water monitoring. Many other sites have previously been clay-capped and one specific site, which was a waste disposal site from the mid-1960s until the 1970s, has been encapsulated and is being controlled and monitored.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
In September 1995, the Ohio Environmental Protection Agency (the "OEPA") issued its Directors' Final Findings and Order (the "Director's Order") by consent ordering that a remedial investigation and feasibility study (the "RIFS") be conducted at the former Painesville plant area. The Company has agreed to participate in the RIFS as required by the Director's Order. It is estimated that the total cost of performing the RIFS will be $3 million to $5 million over the next three years. In spite of the many remedial, maintenance and monitoring activities performed, the former Painesville plant site has been proposed for listing on the National Priority List under CERCLA; however, the EPA has stated that the site will not be listed so long as it is satisfactorily addressed pursuant to the Director's Order and OEPA's programs. The Company has accrued the estimate of its share of the cost to perform the RIFS. The scope and nature of any further investigation or remediation that may be required cannot be determined at this time; however, as the RIFS progresses, the Company will continuously assess the condition of the Painesville plant site and make any changes, including additions, to its reserve as may be required.
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. The Company has reserved $6 million at December 31, 1995, related to these sites, none of which are individually material.
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 Chemicals' 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 are 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 is adjacent to Fields Brook. Occidental has continued to operate 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 parties are presently considered to be financially responsible PRPs. In 1986, the EPA estimated the cost of sediment remediation at the site would be $48 million. The PRPs, including Occidental, have developed an allocation agreement for sharing the costs of the work in Fields Brook ordered by the EPA. Under the allocation, the Occidental share for Chemicals' ownership of the Ashtabula plant would be about five percent of the total, assuming all viable PRPs were to participate.
In 1990, the OEPA, as state trustee for natural resources under CERCLA, advised previously identified PRPs, including Chemicals, that the OEPA 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, and biological and geological resources at the site. Also, 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 and necessary governmental actions have been completed and negotiated or judicial allocations have been made, it is not possible for the Company to estimate what the response costs, response activities or natural resource damages, if any, may be for Fields Brook or related areas, the parties responsible therefore 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
certain costs up to an aggregate dollar cap. Occidental, however, has contended that it is entitled to full indemnification from the Company for such costs, and the outcome of this dispute cannot be predicted. The Company has reserved its estimate of its share of potential cleanup costs based on the assumption that this site falls under the Occidental cost sharing arrangement.
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 was entered by the federal court as a settlement of the EPA's claim for remedial action. Chemical's share of the cost to complete remediation at this site at December 31, 1995, is expected to be approximately $500,000 and such amount is fully accrued.
3. SCP/Carlstadt Site; Carlstadt, New Jersey. Chemicals' share of remediation costs at this CERCLA site would be approximately one percent, based on relative volume of waste shipped to the site. An interim remedy has now been implemented at the site by the PRPs but no estimate can be made at this time of ultimate costs of remediation which may extend to certain off-site locations.
4. Chemical Control Site; Elizabeth, New Jersey. The DEP has demanded of PRPs (including Chemicals) reimbursement of the DEP's alleged $34 million (including interest through December 31, 1995) 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. Based on the previous allocation formula, it is expected that Chemicals' share of any money paid to the DEP for its claim would be approximately two percent. The Company has fully reserved its estimated liability for this site.
Legal Proceedings. In November 1995, OxyChem filed suit in Texas state court seeking a declaration of certain of the parties' rights and obligations under the sales agreement pursuant to which the Company sold Chemicals to Occidental. Henkel joined in said lawsuit as a plaintiff in January 1996. Specifically, OxyChem and Henkel are seeking a declaration that the Company is required to indemnify them for 50% of certain environmental costs incurred on projects involving remedial activities relating to chemical plant sites or other property used in connection with the business of Chemicals on the Closing Date which relate to, result from or arise out of conditions, events or circumstances discovered by OxyChem or Henkel and as to which the Company is provided written notice by OxyChem or Henkel prior to the expiration of ten years following the Closing Date, irrespective of when OxyChem or Henkel incurs and gives notice of such costs, subject to an aggregate $75 million cap. The Company believes that this lawsuit is without merit and intends to defend same vigorously. The Company has established reserves based on its 50% share of costs expected to be paid or incurred by OxyChem and Henkel prior to September 1996.
As of December 31, 1995, the Company had paid OxyChem and Henkel a total of approximately $39 million against said $75 million cap. The Company cannot predict what portion of the approximately $36 million remaining as of that date Occidental and Henkel may actually pay or incur prior to September 4, 1996, the tenth anniversary of the Closing Date if they accelerate spending with regard to such environmental costs; however, the Company has approximately $7 million reserved at December 31, 1995, based on 50% of OxyChem's and Henkel's historical annual expenditures. In the event OxyChem and Henkel prevail in this lawsuit, the Company could be required to provide up to approximately $29 million in additional reserves related to this indemnification.
The Company has established reserves for legal contingencies in situations where a loss is probable and can be reasonably estimated.
In Ecuador, pipeline capacity available to the Company is sufficient to transport only about 60% of the oil the Company expects to be able to produce daily, and none of the various projects to increase transportation capacity that have been considered has been approved by the government of Ecuador. In addition, the Company is involved in a number of contract, auditing and certification disputes with various government entities. Together, the lack of pipeline capacity and the various disputes with government entities are retarding
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
the Company's ability to proceed with the economic development of Block 16. Although the Company can give no assurances concerning the outcome of these discussions, progress has recently been made on several important issues. The Company intends to reduce program spending in Ecuador in 1996 to $19 million from $32 million in 1995.
NOTE TWENTY-THREE--SUBSEQUENT EVENTS
In January 1996, the Company and its partners were successful in acquiring the highly prospective Guarapiche block in Venezuela's first auction awards for equity production in over 20 years. Guarapiche is located on the same trend as the five billion barrel El Furrial field in northeastern Venezuela. The Company, together with its partners, paid $109 million ($27 million net to Maxus) to the Venezuelan government for rights to explore the Guarapiche block. BP Exploration Orinoco Limited is the operator with a 37.5% working interest while Amoco Production Company and the Company hold the remaining 37.5% and 25%, respectively. The Company's net exploration commitment for this block is anticipated to total approximately $15 million over the next five years.
FINANCIAL SUPPLEMENTARY INFORMATION (Unaudited)
DATA IS FOR THE NINE MONTHS ENDED DECEMBER 31, 1995. THE 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 for the nine months ended December 31, 1995 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.
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(a) Includes United States gathering and processing costs related to sales. Such costs were $9.1 million for the nine months ended December 31, 1995.
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. In addition, the Company's gas plants that process not only the Company's gas but also third party gas, has been included in capitalized costs. Approximately 52% of the volumes processed through the Company's gas plants is the Company's gas. Only the revenue and cost related to the Company's produced gas is included in results of operations and costs incurred. Capitalized costs at December 31, 1995 were:
COSTS INCURRED
Costs incurred by the Company in its oil and gas producing activities for the nine months ended December 31, 1995 (whether capitalized or charged against earnings) were as follows:
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 for the nine months ended December 31, 1995. 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.
Estimates of reserves for December 31, 1995 were prepared by Gaffney, Cline & Associates, petroleum engineers, using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC"). The choice of method or combination of methods employed in the analysis of each reservoir was determined by experience in the area, stage of development, quality and completeness of basic data, and production history.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumption upon which they were based. The reserve estimates were subjected to economic tests to determine economic limits. The estimates may change as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continued reassessment of the viability of production under varying economic conditions.
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(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 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. Increasing prices resulted in a decrease of 9.9 million barrels in 1995.
(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 11% of total gas reserves in the United States and 4% 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) Reserves in Venezuela are attributable to an operating service agreement under which all hydrocarbons are owned by the Venezuelan government, however, the Company receives payment for production and development services performed based on production.
Future Net Cash Flows
The standardized measure of discounted future net cash flows relating to the Company's proved oil and gas reserves as of December 31, 1995 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 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.
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(a) Future income taxes undiscounted are $161.6 for the United States, $508.2 for Indonesia and $57.1 for South America at December 31, 1995.
The following are the principal sources for change in the standardized measure:
The principle sources for change in the standardized measure are presented for the year-ended December 31, 1995, rather than the nine months period ended December 31, 1995, as reserve reports from which this information is derived are only prepared on an annual basis.
Quarterly Data
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(a) Gross profit is sales and operating revenues less purchases and operating expenses, gas purchase costs and depreciation, depletion and amortization.
(b) Gross profit has been restated to conform to the 1995 presentation.
(c) In the fourth quarter of 1994, the Company increased its reserve for future environmental liabilities by $49.0 million.
EXPLORATION AND PRODUCTION STATISTICS (historic)
INDEX TO EXHIBITS