<PAGE>
 
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                      SECURITIES AND EXCHANGE COMMISSION
                            WASHINGTON, D.C. 20549
 
                                   FORM 10-K
 
(MARK ONE)
 
   [X]           ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
                    OF THE SECURITIES EXCHANGE ACT OF 1934
                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
 
                                      OR
 
   [_]         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
                    OF THE SECURITIES EXCHANGE ACT OF 1934
 
                        COMMISSION FILE NUMBER 1-8567-2
 
                           MAXUS ENERGY CORPORATION
            (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
 
               DELAWARE                              75-1891531
    (STATE OR OTHER JURISDICTION OF               (I.R.S. EMPLOYER
    INCORPORATION OR ORGANIZATION)               IDENTIFICATION NO.)
 
       717 NORTH HARWOOD STREET                      75201-6594
             DALLAS, TEXAS                           (ZIP CODE)
    (ADDRESS OF PRINCIPAL EXECUTIVE
               OFFICES)
 
      Registrant's telephone number, including area code: (214) 953-2000
 
          Securities registered pursuant to Section 12(b) of the Act:
 
<TABLE>
<CAPTION>
                                                          NAME OF EACH EXCHANGE
       TITLE OF EACH CLASS                                 ON WHICH REGISTERED
       -------------------                                ---------------------
<S>                                                      <C>
$2.50 Cumulative Preferred Stock, $1.00 Par Value....... New York Stock Exchange
8 1/2% Sinking Fund Debentures Due April 1, 2008........ New York Stock Exchange
</TABLE>
 
       Securities registered pursuant to Section 12(g) of the Act: None
 
  Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) has been subject to such filing
requirements for the past 90 days. YES [X]  NO [_]
 
  Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
 
  The aggregate market value of the voting stock held by non-affiliates of the
registrant as of March 1, 1997: Not applicable.
 
  Shares of Common Stock outstanding at March 1, 1997 -- 147,246,135.
 
                      DOCUMENTS INCORPORATED BY REFERENCE
                                     None
 
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<PAGE>
 
                                    PART I
 
ITEMS 1 AND 2. BUSINESS AND PROPERTIES.
 
  Maxus Energy Corporation ("Maxus" or the "Company") was incorporated in
Delaware in 1983 to hold the stock of various corporations, the oldest of
which was founded in 1910. The Company, together with its subsidiaries, is an
oil and gas exploration and production company with ongoing international
activity primarily in Indonesia and Ecuador and domestic activity primarily in
the mid-continent region of the United States. Its principal executive offices
are located at 717 North Harwood Street, Dallas, Texas 75201-6594, and its
telephone number is (214) 953-2000. In this report, the terms "Company" and
"Maxus" mean Maxus Energy Corporation, its subsidiaries and their predecessors
unless the context otherwise indicates.
 
  On June 8, 1995, YPF Sociedad Anonima ("YPF"), an Argentine sociedad
anonima, completed its acquisition of all the shares of common stock ("Common
Stock") of Maxus through a merger (the "Merger") of Maxus with a YPF
subsidiary. The Merger was the consummation of transactions contemplated by a
tender offer which was commenced by YPF on March 6, 1995 for all outstanding
shares of Common Stock of the Company at $5.50 per share. As of the date
hereof, the Common Stock, all of which is owned by a subsidiary of YPF, and
the Company's $2.50 Cumulative Preferred Stock ("$2.50 Preferred Stock")
remain outstanding. On August 13, 1996, the Company redeemed all of its
outstanding $4.00 Cumulative Convertible Preferred Stock ("$4.00 Preferred
Stock"), and on January 31, 1997, the Company redeemed its remaining
outstanding $9.75 Cumulative Convertible Preferred Stock ("$9.75 Preferred
Stock").
 
  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. Due to the application of purchase accounting on April 1, 1995,
financial information post-Merger is not comparable to prior periods.
Therefore, financial information is presented separately for pre-Merger (year
ended December 31, 1994 and the three-month period ended March 31, 1995) and
post-Merger periods (nine months ended December 31, 1995 and year ended
December 31, 1996). The Company's sales or transfers between geographic areas
were not significant for the year ended December 31, 1994, the three months
ended March 31, 1995, the nine months ended December 31, 1995 and year ended
December 31, 1996. Operating revenues from export sales to unaffiliated
customers located outside the United States were less than 10% of the
Company's consolidated sales and operating revenues for the twelve months
ended December 31, 1994, the three months ended March 31, 1995, the nine
months ended December 31, 1995 and the year ended December 31, 1996.
Information concerning outside sales and operating profit by geographic area
for the twelve months ended December 31, 1996 and the nine months ended
December 31, 1995 and identifiable assets by geographic area as of December
31, 1996 and 1995 is presented on pages F-41 and F-42. Information concerning
outside sales and operating profit by geographic area for the twelve months
ended December 31, 1994, and the three months ended March 31, 1995 and
identifiable assets by geographic area as of December 31, 1994 is presented on
pages F-8 and F-9 of this report.
 
 General Reorganization
 
  On June 18, 1996, the Company announced a reorganization which included the
sale of three of its subsidiaries holding certain Bolivian and Venezuelan
assets to YPF, the redemption of the outstanding shares of $4.00 Preferred
Stock and the transfer to a YPF subsidiary of a Maxus subsidiary that assumed
certain liabilities related to environmental matters.
 
  Effective July 1, 1996, Maxus International Energy Company ("Seller"), a
wholly owned subsidiary of Maxus, sold all of the issued and outstanding
shares of capital stock of its wholly owned subsidiary, YPF International Ltd.
("International"), to YPF pursuant to a Stock Purchase and Sale Agreement by
and between YPF and Seller. The sole assets of International at the time of
the transaction were all of
 
                                       2
<PAGE>
 
the issued and outstanding shares of capital stock of Maxus Bolivia, Inc.
("Maxus Bolivia"), Maxus Venezuela (C.I.) Ltd. ("Venezuela C.I.") and Maxus
Venezuela S.A. ("Venezuela S.A."). The assets of Maxus Bolivia consisted of
all of the former assets and operations of Maxus in Bolivia, including the
interests of Maxus in the Surubi Field and Secure and Caipipendi Blocks. The
assets of Venezuela C.I. and Venezuela S.A. consisted of all of the former
assets and operations of Maxus in Venezuela, except those held through Maxus
Guarapiche Ltd. ("Maxus Guarapiche"), including the interests of Maxus in the
Quiriquire Unit.
 
  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.
In July 1996, 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. While not a part of the above-
described sale transaction, effective September 1, 1996, Seller sold all of
the capital stock of Maxus Guarapiche to International for $26 million which
represented the carrying amount of Maxus Guarapiche on the financial reporting
books of Seller as of August 31, 1996. Maxus Guarapiche had a 25% interest in
the Guarapiche Block.
 
  Also as part of the general reorganization, on August 13, 1996, Maxus
redeemed all of its outstanding shares of $4.00 Preferred Stock at a price of
$50 per share plus accrued and unpaid dividends (approximately $221 million in
the aggregate). The excess of the redemption price over the carrying value of
the $4.00 Preferred Stock resulted in an increase in the Company's accumulated
deficit of $214 million. The Company used a portion of the proceeds from the
sale of all the issued and outstanding shares of capital stock of
International as well as an advance from YPF of approximately $56 million to
redeem the $4.00 Preferred Stock.
 
  As a further part of the reorganization, the Company transferred certain
liabilities related to environmental matters to Chemical Land Holdings, Inc.
("CLH"), an indirect subsidiary of YPF, effective as of August 1, 1996. In
connection with this transfer, CLH assumed (the "Assumption") the liabilities
so transferred and YPF committed to contribute to the capital of CLH up to
$108 million, which amount will enable CLH to satisfy its obligations under
the Assumption based on the Company's reserves established in respect of the
assumed liabilities as of July 31, 1996, plus provide funding for certain
operating expenses budgeted by CLH from time to time.
 
 Exploration and Production--International
 
  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 changes in governments, civil
strife, acts of war, guerrilla activities and insurrection.
 
 Indonesia
 
  The Company has interests in production sharing contracts with Pertamina,
Indonesia's state oil company, for the exploration, development and production
of oil and gas in two primary areas in the Java Sea--Southeast Sumatra and
Northwest Java. These areas accounted for 77% of the Company's total net
production of oil during 1996. The Company's working interest in the Southeast
Sumatra production sharing contract is 55.7% and in the Northwest Java
production sharing contract is 24.3%. The Company is the operator of the
Southeast Sumatra block, and Atlantic Richfield Company ("ARCO") is the
operator of the Northwest Java block.
 
  The Indonesian production sharing contracts allow the Company to recover,
subject to available production, tangible and intangible costs of exploration,
intangible costs of production and operating costs on a current basis and
tangible costs of production generally over a seven-year period. After
recovery of those costs and fulfillment of a domestic market obligation for
oil, in 1996 the contractors received 34% of the oil produced and 79.5% of the
gas produced before Indonesian taxes, the statutory rate for which is
approximately 56%. The Southeast Sumatra and Northwest Java production sharing
contracts extend to 2018 and 2017, respectively.
 
                                       3
<PAGE>
 
  The Company has gas projects in both the Northwest Java and Southeast
Sumatra contract areas. In 1992, ARCO began developing gas reserves in
Northwest Java. Production from this project, which began delivery to Jakarta
in 1993, averaged 322.2 million cubic feet per day ("mmcfpd") (gross) during
1996. In Southeast Sumatra, where the Company has certified (but not included
in its proved reserves because of an absence of a contract of sale) 300
billion cubic feet ("bcf") of gross gas reserves, the Company is negotiating
with Pertamina for domestic gas sales contracts to supply expanding West Java
markets. Although the Company cannot give any assurance that a contract will
ultimately be signed, management currently believes that these negotiations
will lead to a satisfactory gas sales contract and a profitable market for the
Company's Southeast Sumatra natural gas.
 
  During 1996, five exploration and 22 development wells were drilled in the
Northwest Java contract area. During the year, 33.6 million barrels (gross) of
oil and 96.3 bcf (gross) of gas were added to proved reserves. Also during
1996, the Company drilled six exploration and 25 development wells in the
Southeast Sumatra contract area which added 45.3 million barrels (gross) of
proved oil reserves. Southeast Sumatra 1996 gross production remained
essentially unchanged from 1995 production. Natural declines were offset by
new production resulting from the introduction of horizontal well technology
and use of high volume electrical submersible pumps combined with an active
drilling program. Two large 3D seismic surveys were also completed in the
Southeast Sumatra block in 1996.
 
  Reserve additions replaced 90% of the gross production of oil for the
Southeast Sumatra block and 90% of the gross oil and gas produced in the
Northwest Java block in 1996. The Company plans to drill nine exploration
wells in the Southeast Sumatra block and nine exploration wells in the
Northwest Java block in 1997. At the same time, the Company has increased
capital expenditures for development drilling to boost current production.
Major efforts are underway to reduce development and lifting costs and secure
operating conditions to commercialize small oil accumulations discovered in
previous years that were formerly considered uneconomic.
 
 Ecuador
 
  The Company is the operator of and has a 35% working interest in the Block
16 project ("Block 16") in eastern Ecuador from which production began in
1994. A total of 14 wells were drilled on the Block in 1996: eight delineation
wells in the Daimi Field, four delineation wells in the Ginta Field and two
disposal wells in the WIPS1 pad. Additionally, 20 completions and 23 workovers
were performed during 1996.
 
  During 1996, the construction of the Southern Production Facilities
continued, with Phase I of the project being completed. These facilities are
scheduled to begin operations in July 1997 and are expected to allow a
production capacity increase from 45,000 barrels of oil per day to 65,000
barrels of oil per day. During 1996, pipeline capacity available to the
Company was sufficient to transport only about 60% to 80% of the oil which the
Company was capable of producing daily in Ecuador. Due to decreased usage
during the first quarter of 1997 by PetroEcuador, the state oil company,
however, pipeline capacity has been available to transport close to 100% of
the oil which the Company is capable of producing daily. It is not known
whether this availability is temporary and, if permanent, whether it will be
adequate to accommodate the expected increased production in mid-1997.
Additionally, the Ecuadorian Government has announced its intention to solicit
bids in early 1997 for the construction of a new pipeline system and expects
completion of the pipeline within 18 to 24 months from the date of execution
of a contract. The impact, if any, which a recent change in the country's
political leadership will have on these plans to solicit such bids is not
known.
 
  On August 10, 1996, a new administration was inaugurated in Ecuador and on
August 20, 1996, the new Energy Minister announced his intention to cancel the
Company's risk service contract unless the Company and the other members of
its consortium for Block 16 agreed to convert such contract into a production
sharing contract. On December 27, 1996, the Company and the Government entered
into a new contract effective January 1, 1997 governing Block 16. The
principal difference between the two contracts is the manner in which the
consortium's costs in Block 16 are recovered. Under the former contract, the
Company had the right to recover its investment before the Government began to
share in significant proceeds from the sale of production; under
 
                                       4
<PAGE>
 
the new contract, the Government receives a royalty, and the Company's
recovery of its investment is out of the proceeds after deducting such
royalty. Previous administrations had signaled their dissatisfaction with the
former arrangement and in recent years a series of auditing, contract
administration and certification of new field disputes had arisen that made it
increasingly difficult to develop Block 16. The new contract also resolves
certain outstanding disputes and amends the prior agreement in various other
ways, some of which are expected to significantly improve the Company's
current and future operating costs. The Company believes that the new contract
permits the Company to go forward with the development of Block 16 and permits
it to do so on a more cost-effective basis, subject to the eventual permanent
increase of pipeline capacity discussed above.
 
  The Company's program spending in Ecuador was reduced from $32 million in
1995 to $17 million in 1996. For 1997, the program spending will be increased
to approximately $23 million mainly due to the planned completion of Southern
Production Facilities and use of horizontal drilling in the Tivacuno Field.
 
 Exploration and Production--Domestic
 
  Through its wholly owned subsidiary, Midgard Energy Company ("Midgard"), the
Company currently focuses its domestic exploration and production efforts in
the Texas Panhandle and western Oklahoma where it has substantial investments
in natural gas gathering systems that are used to aggregate gas produced and
purchased by the Company for processing and resale. The Company owns and
operates one gas processing plant in the area: its Sunray plant in Moore
County, Texas. The Sunray plant, which was completed in 1993, incorporates
state-of-the-art technology, including a cold box for extraction of helium. It
can process approximately 200 mmcfpd at peak operation and, as of February 1,
1997, was processing approximately 180 mmcfpd. In December 1996, the Company
shut down its gas processing plant in Roger Mills County, Oklahoma, and gas
previously processed by that plant is currently being processed at a third
party facility. While it has made no decision to reactivate the Roger Mills
plant, the Company is evaluating alternatives to relocate the Roger Mills
plant to a more strategic location in the Texas Panhandle during 1997.
 
  In 1996, Midgard continued an aggressive drilling program on its Mid-
continent properties, drilling and completing 109 wells compared to 81 wells
in 1995. Production for 1996 rose 12% over 1995 rates to an average of 145
mmcfpd and year-end reserves increased 22% from December 31, 1995 to 724 bcf
equivalent. Midgard replaced 330% of production during the year at a cost of
$0.34 per thousand cubic feet ("mcf") equivalent and, as compared to 1995,
reduced unit production costs by 12% and unit gathering costs by 6%.
 
  For 1997, Midgard's development plans include the continuation of its in-
fill drilling program at a level comparable to 1996 and efforts to maximize
processed volumes through gathering systems upgrades. Additionally, Midgard
expects to pursue strategic acquisition opportunities in the gathering,
processing and producing properties sectors, while drilling a portfolio of
higher risk and higher potential exploration wells to complement its lower
risk in-fill and extension drilling program.
 
  Midgard has signed a letter of intent with Amoco Production Company
concerning the establishment of a partnership with regard to its business and
assets. The objective of the partnership is lowering unit costs, creating
economies of scale and improving marketing leverage. Establishment of the
partnership is subject to execution of definitive agreements and efforts in
that regard are currently proceeding.
 
                                       5
<PAGE>
 
 Oil and Gas Operations
 
  Average sales prices and production costs of crude oil and natural gas
produced by geographic area for the three months ended March 31, 1995, the
nine months ended December 31, 1995 and the year ended December 31, 1996 were
as follows:
 
<TABLE>
<CAPTION>
                                         NINE MONTHS  THREE MONTHS
                             YEAR ENDED     ENDED        ENDED      YEAR ENDED
                            DECEMBER 31, DECEMBER 31,  MARCH 31,   DECEMBER 31,
                                1996         1995         1995         1994
                            ------------ ------------ ------------ ------------
<S>                         <C>          <C>          <C>          <C>
United States
 Average Sales Price
  Crude Oil (per barrel)...    $19.23       $16.29       $16.07       $13.89
  Natural Gas Liquids (per
   barrel).................    $11.94       $10.42       $10.27       $10.02
  Natural Gas Sold (per
   mcf)(a).................    $ 1.83       $ 1.54       $ 1.42       $ 1.89
  Natural Gas Produced (per
   mcf)(b).................    $ 2.31       $ 1.97       $ 1.89       $ 2.10
  Average Production Cost
   (per barrel)(c).........    $ 3.46       $ 3.39       $ 3.74       $ 3.37
Indonesia
 Average Sales Price
  Crude Oil (per barrel)...    $20.32       $17.01       $17.54       $15.61
  Natural Gas Liquids (per
   barrel).................    $14.49       $14.33       $19.19       $ 9.42
  Natural Gas Sold (per
   mcf)(a).................    $ 2.65       $ 2.62       $ 2.65       $ 2.24
  Natural Gas Produced (per
   mcf)(b).................    $ 2.65       $ 2.64       $ 2.73       $ 2.53
  Average Production Cost
   (per barrel)(c).........    $ 7.01       $ 6.44       $ 7.42       $ 6.18
South America
 Average Sales Price
  Crude Oil (per barrel)...    $15.81       $12.79       $12.58       $12.58
  Average Production Cost
   (per barrel)(c).........    $ 4.72       $ 6.30       $ 8.99       $ 9.36
</TABLE>
----------
 
(a) The average natural gas price for sales volumes is calculated by dividing
    the total net sales value for all natural gas sold by the Company,
    including residue gas remaining after the removal of natural gas liquids,
    by the annual natural gas sales volume.
(b) The average natural gas price for produced volumes is calculated by
    dividing the total net value received from the sale of natural gas and
    natural gas liquids produced by the Company by the annual natural gas
    production volume.
(c) Production or lifting cost is exclusive of depreciation and depletion
    applicable to capitalized lease acquisition, exploration and development
    expenditures. Average production costs are calculated by dividing total
    operating costs by the sum of crude oil and equivalent barrels of oil for
    natural gas production. Gas volumes produced were converted to equivalent
    barrels of crude oil by dividing the mcf volume by six. Six mcf of gas
    have approximately the heating value of one barrel of crude oil.
 
  The Company periodically hedges against the effects of fluctuations in the
prices of natural gas through price swap agreements and futures contracts.
During 1996, a hedging program covered an average of 60% of the Company's
United States natural gas production and 35% of its United States natural gas
liquids sales. The Company anticipates hedging approximately 85% of its United
States natural gas production and 40% of its United States natural gas liquids
sales during 1997.
 
  Information regarding the Company's oil and gas producing activities for the
periods indicated is set forth on pages F-27 through F-31 and F-66 through F-
69 of this report. The Company's estimates of its net interests in proved
reserves at December 31, 1996 are based upon records regularly prepared and
maintained by its engineers. In 1996, the Company filed estimates of certain
of its proved reserves of crude oil and natural gas in the United States at
December 31, 1995 with the United States Department of Energy. The total
reserve estimates included therein do not differ by more than 5% from the
total reserve estimates for the comparable period for the same reserves
included in the Company's filings with the Securities and Exchange Commission.
 
                                       6
<PAGE>
 
  The following table shows the Company's average daily sales and net
production (after deducting royalty and operating interests of others) by
geographic area for the periods presented.
 
<TABLE>
<CAPTION>
                                         NINE MONTHS  THREE MONTHS
                             YEAR ENDED     ENDED        ENDED      YEAR ENDED
                            DECEMBER 31, DECEMBER 31,  MARCH 31,   DECEMBER 31,
                                1996         1995         1995         1994
                            ------------ ------------ ------------ ------------
<S>                         <C>          <C>          <C>          <C>
United States
 Average Daily Production
  Crude Oil (m barrels)....      1.2          1.1          1.0          2.4
  Natural Gas (mmcf)(a)....      145          130          125          156
 Average Daily Sales
  Natural Gas Liquids (m
   barrels)................      9.9          8.7          8.8          8.2
  Natural Gas (mmcf)(b)....      116          104           98          131
Indonesia
 Average Daily Production
  Crude Oil (m barrels)....     43.6         53.0         52.0         59.3
 Average Daily Sales
  Natural Gas Liquids (m
   barrels)................      2.3          1.7          0.9          2.1
  Natural Gas (mmcf)(b)....       69           61           40           44
South America
 Average Daily Production
  Crude Oil (m barrels)....     11.9         12.4          8.5          4.6
 Average Daily Sales
  Crude Oil (m barrels)....     14.1         10.4          6.9          5.2
</TABLE>
----------
 
(a) Reflects the average amount of daily wellhead production.
 
(b) Average daily sales volumes for natural gas production, reduced, in those
    cases where the gas is processed for extraction of natural gas liquids, by
    the shrinkage resulting therefrom.
 
  In addition to gathering and processing a substantial part of the Company's
own natural gas, the Company purchases natural gas in the Texas Panhandle and
western Oklahoma for resale. The majority of this natural gas is processed
through the Company's processing facility. The table below reflects the
average daily sales and average sales prices received for such purchased
natural gas and the natural gas liquids extracted in processing for the
periods presented.
 
<TABLE>
<CAPTION>
                                         NINE MONTHS  THREE MONTHS
                             YEAR ENDED     ENDED        ENDED      YEAR ENDED
                            DECEMBER 31, DECEMBER 31,  MARCH 31,   DECEMBER 31,
                                1996         1995         1995         1994
                            ------------ ------------ ------------ ------------
<S>                         <C>          <C>          <C>          <C>
Average Sales Price
  Natural Gas Liquids (per
   barrel).................    $14.70       $10.57       $10.48       $10.12
  Natural Gas (per mcf)....    $ 2.19       $ 1.42       $ 1.49       $ 1.90
Average Daily Sales
  Natural Gas Liquids (m
   barrels)................       8.6          8.9          9.6          9.7
  Natural Gas (mmcf).......        66           68           69          144
</TABLE>
 
                                       7
<PAGE>
 
  The following tables set forth information regarding the Company's wells and
leasehold acres. "Gross" wells or acres are the total number of wells or acres
in which the Company owns any interest. "Net" wells or acres are the sum of
the fractional working interests the Company owns in gross wells or acres.
"Productive" wells are either producing wells or wells capable of commercial
production although currently shut-in. One or more completions ("multiple
completions") in the same bore hole are counted as one well.
 
  At December 31, 1996, total gross and net productive oil and gas wells,
including multiple completions, by geographic area were as follows:
 
<TABLE>
<CAPTION>
                                                                 WELLS
                                                       -------------------------
                                                           OIL          GAS
                                                       ----------- -------------
                                                       GROSS  NET  GROSS   NET
                                                       ----- ----- ----- -------
<S>                                                    <C>   <C>   <C>   <C>
Oil and Gas Wells
  United States.......................................   329 229.1 1,547 1,187.6
  Indonesia...........................................   770 300.2    10     2.4
  South America.......................................    33  11.6     0     0.0
                                                       ----- ----- ----- -------
    Total............................................. 1,132 540.9 1,557 1,190.0
Multiple Completions
  United States.......................................     0   0.0    31    14.7
  Indonesia...........................................    93  22.6     0     0.0
                                                       ----- ----- ----- -------
    Total.............................................    93  22.6    31    14.7
</TABLE>
 
  At December 31, 1996, total gross and net developed and undeveloped acreage
by geographic area was as follows:
 
<TABLE>
<CAPTION>
                                               UNITED             SOUTH   OTHER
                                               STATES  INDONESIA AMERICA FOREIGN
                                               ------- --------- ------- -------
<S>                                            <C>     <C>       <C>     <C>
Gross Acres
  Developed Acres............................. 557,717   143,738   5,160       0
  Undeveloped Acres........................... 310,141 7,027,662 506,137 971,587
                                               ------- --------- ------- -------
    Total..................................... 867,858 7,171,400 511,297 971,587
Net Acres
  Developed Acres............................. 469,612    54,254   1,806       0
  Undeveloped Acres........................... 176,242 2,543,306 177,148 582,952
                                               ------- --------- ------- -------
    Total..................................... 645,854 2,597,560 178,954 582,952
</TABLE>
 
                                       8
<PAGE>
 
 Exploration and Development Activities
 
  Drilling activities of the Company for each year in the three-year period
ended December 31, 1996 are summarized by geographic area in the following
table:
 
<TABLE>
<CAPTION>
                                                             FOR THE YEAR ENDED
                                                                DECEMBER 31,
                                                            ----------------------
                                                             1996    1995    1994
                                                            ------  ------  ------
<S>                                                         <C>     <C>     <C>
Gross wells drilled(*)
 United States
  Exploratory
   Oil.....................................................      0       0       0
   Gas.....................................................      0       0       1
   Dry.....................................................      0       2       6
                                                            ------  ------  ------
    Total..................................................      0       2       7
  Development
   Oil.....................................................      8       3       2
   Gas.....................................................     96      73      44
   Dry.....................................................      5       5       4
                                                            ------  ------  ------
    Total..................................................    109      81      50
 Indonesia
  Exploratory
   Oil.....................................................      1       0       3
   Gas.....................................................      0       0       0
   Dry.....................................................     10      12       7
                                                            ------  ------  ------
    Total..................................................     11      12      10
  Development
   Oil.....................................................     45      35      38
   Gas.....................................................      4       0       1
   Dry.....................................................      1       2       2
                                                            ------  ------  ------
    Total..................................................     50      37      41
 South America
  Exploratory
   Oil.....................................................      4       1       1
   Gas.....................................................      0       0       0
   Dry.....................................................      0       1       0
                                                            ------  ------  ------
    Total..................................................      4       2       1
  Development
   Oil.....................................................     16      17      13
   Gas.....................................................      0       0       0
   Dry.....................................................      0       0       0
                                                            ------  ------  ------
    Total..................................................     16      17      13
 Other Foreign
  Exploratory
   Oil.....................................................      0       0       0
   Gas.....................................................      0       0       0
   Dry.....................................................      1       3       0
                                                            ------  ------  ------
    Total..................................................      1       3       0
</TABLE>
 
                                       9
<PAGE>
 
<TABLE>
<CAPTION>
                                                              FOR THE YEAR ENDED
                                                                 DECEMBER 31,
                                                              -------------------
                                                               1996  1995  1994
                                                              ------ ------------
<S>                                                           <C>    <C>   <C>
  Development
   Oil.......................................................      0     0     0
   Gas.......................................................      0     0     0
   Dry.......................................................      0     0     0
                                                              ------ ----- -----
    Total....................................................      0     0     0
Net Wells Drilled*
 United States
  Exploratory
   Oil.......................................................    0.0   0.0   0.0
   Gas.......................................................    0.0   0.0   1.0
   Dry.......................................................    0.0   1.5   3.5
                                                              ------ ----- -----
    Total....................................................    0.0   1.5   4.5
  Development
   Oil.......................................................    7.9   3.0   0.2
   Gas.......................................................   89.4  65.7  22.1
   Dry.......................................................    5.0   5.0   1.6
                                                              ------ ----- -----
    Total....................................................  102.3  73.7  23.9
 Indonesia
  Exploratory
   Oil.......................................................    0.6   0.0   0.7
   Gas.......................................................    0.0   0.0   0.0
   Dry.......................................................    4.3   6.4   3.3
                                                              ------ ----- -----
    Total....................................................    4.9   6.4   4.0
  Development
   Oil.......................................................   20.0  14.5  17.1
   Gas.......................................................    1.0   0.0   0.2
   Dry.......................................................    0.6   1.1   0.5
                                                              ------ ----- -----
    Total....................................................   21.6  15.6  17.8
 South America
  Exploratory
   Oil.......................................................    1.4   0.4   0.4
   Gas.......................................................    0.0   0.0   0.0
   Dry.......................................................    0.0   0.6   0.0
                                                              ------ ----- -----
    Total....................................................    1.4   1.0   0.4
  Development
   Oil.......................................................    5.6   7.2   4.6
   Gas.......................................................    0.0   0.0   0.0
   Dry.......................................................    0.0   0.0   0.0
                                                              ------ ----- -----
    Total....................................................    5.6   7.2   4.6
 Other Foreign
  Exploratory
   Oil.......................................................    0.0   0.0   0.0
   Gas.......................................................    0.0   0.0   0.0
   Dry.......................................................    1.0   2.6   0.0
                                                              ------ ----- -----
    Total....................................................    1.0   2.6   0.0
</TABLE>
 
                                       10
<PAGE>
 
<TABLE>
<CAPTION>
                                                            FOR THE YEAR ENDED
                                                               DECEMBER 31,
                                                           ----------------------
                                                            1996    1995    1994
                                                           ------  ------  ------
<S>                                                        <C>     <C>     <C>
  Development
   Oil....................................................    0.0     0.0     0.0
   Gas....................................................    0.0     0.0     0.0
   Dry....................................................    0.0     0.0     0.0
                                                           ------  ------  ------
    Total.................................................    0.0     0.0     0.0
</TABLE>
----------
 * "Gross" wells means all wells in which the Company has an interest. "Net"
   wells means gross wells after deducting interests of others.
 
  At December 31, 1996, the Company was participating in the drilling of 7
gross and 6.3 net wells in the United States, 4 gross and 1.6 net wells in
Indonesia and 3 gross and 1.5 net wells in areas outside the United States
other than Indonesia.
 
 Competition and Markets
 
  The primary markets for the Company's Indonesian oil production are the
Pacific Rim countries, including Japan, China and Indonesia. The continued
increasing environmental consciousness of this region has resulted in premium
prices for low sulfur oil such as that produced from the Southeast Sumatra and
Northwest Java areas. The Company has ongoing business relationships with
government oil companies, utilities, refiners and trading companies which are
expected to continue to facilitate sales in this area.
 
  The Company believes the long-term potential for natural gas demand growth
in North America remains positive for several reasons. Chief among these
reasons are the environmental advantages of natural gas relative to other
energy sources, opportunities for natural gas as a result of the deregulation
of the electrical generating industry and natural gas' favorable position with
regard to the anticipated decommission of a number of nuclear power plants.
Natural gas prices, however, remained volatile during 1996, especially during
the first and fourth quarters. Cold winter weather coupled with low storage
levels contributed to regional price imbalances.
 
  The Company's domestic natural gas reserve base and production is
concentrated in its Mid-continent division (Midgard), which encompasses
Anadarko Basin production in the Texas Panhandle and western Oklahoma areas.
The Company's Sunray gas plant is located in Moore County, Texas and is
directly connected to three major interstate pipelines. This multiple pipeline
access provides the Company with the ability to maximize the value of natural
gas from this plant.
 
  During 1996, the Company elected to decrease emphasis on its national
natural gas marketing efforts to local distribution companies, industrial
customers and utility companies due to the decline in value associated with
the services demanded by these markets and the increased cost and investment
required in providing those services. The Company has instead elected to
pursue an arrangement to sell a portion of its gas to a larger natural gas
marketing concern at a price competitive with prices received in direct
marketing without the cost and investment associated with direct marketing.
The Company continues to emphasize its natural gas sales for agricultural
purposes and for supply to local area markets. Approximately 15% of the
Company's natural gas sales in 1996 were made directly to local gas
distribution companies and industrial and agricultural users through term
contracts, and the remaining 85% was sold on the spot market.
 
  The Company sells crude oil, natural gas and natural gas liquids to an
assortment of customers including refinery, industrial and agricultural type
customers. Oil and gas are commodities and the Company's production represents
only a small fraction of the total market for these products. As a result, the
prices the Company receives depend primarily on the relative balance between
supply and demand for these products.
 
  The world oil market continues to be subject to uncertainty. World crude
supplies during 1996 were tighter than most analysts had predicted and
consequently prices were higher. The Iraqi "oil for food" sales were
 
                                      11
<PAGE>
 
repeatedly delayed and non-OECD demand was consistently underestimated. The
prospect of Iraqi sales depressed the medium term futures prices relative to
the short term, discouraging refiners from holding inventory. The lack of
inventory, in turn, contributed to increased price volatility. Limited Iraqi
sales returned in December 1996 and North Sea production is currently at
record high levels. Prices declined during the first quarter of 1997 and are
expected to continue to be volatile in the near future.
 
 Health, Safety and Environmental Controls
 
  Federal, state and local laws and regulations relating to health and
environmental quality in the United States, as well as environmental laws and
regulations of other countries in which the Company operates, affect nearly
all of the operations of the Company. These laws and regulations set various
standards regulating certain aspects of health and environmental quality,
provide for penalties and other liabilities for the violation of such
standards and establish in certain circumstances 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. CERCLA imposes retroactive liability upon certain parties
for the response costs associated with cleaning up old hazardous substance
sites. CERCLA liability to the Government is joint and several. CERCLA allows
authorized trustees to seek recovery of natural resource damages from
potentially responsible parties. CERCLA also grants the Government the
authority to require potentially responsible parties to implement interim
remedies to abate an imminent and substantial endangerment to the environment.
 
  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
$42 million as of December 31, 1996. Occidental
 
                                      12
<PAGE>
 
Chemical Corporation ("OxyChem"), a subsidiary of Occidental, and Henkel
Corporation ("Henkel"), an assignee of certain of Occidental's rights and
obligations, filed a declaratory judgment action in Texas state court with
respect to the Company's agreement in this regard. The lower court found in
favor of Occidental and Henkel, and the Company has appealed the judgment.
(See "Item 3. Legal Proceedings".)
 
  In connection with the spin-off of Diamond Shamrock R&M, Inc., now known as
Ultramar Diamond Shamrock Corporation ("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. Thereafter, such ongoing costs were
borne one-third by DSI and two-thirds by the Company until DSI had borne an
additional $47.5 million. As of December 31, 1996, DSI had fulfilled its
remaining responsibility under the cost-sharing arrangement, and it has no
further obligation thereunder.
 
  During 1996, the Company spent $8 million in environmental related
expenditures in its oil and gas operations. Expenditures for 1997 are expected
to be approximately $13 million.
 
  For the seven months ended July 31, 1996, the Company's total expenditures
for environmental compliance for disposed of businesses, including Chemicals,
were approximately $13 million, $5 million of which was recovered from DSI
under the above described cost-sharing arrangement.
 
  At December 31, 1996, reserves for the environmental contingencies discussed
herein totaled $101.6 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 Company transferred certain liabilities related to environmental matters
to CLH effective as of August 1, 1996. In connection with this transfer, CLH
assumed (the "Assumption") the liabilities so transferred and YPF committed to
contribute capital to CLH up to an amount of $106.9 million that will enable
CLH to satisfy its obligations under the Assumption based on the Company's
reserves established in respect of the assumed liabilities as of July 31, 1996
plus certain operating expenses budgeted by CLH from time to time. YPF will
not be obligated to contribute capital to CLH beyond the amount of its initial
undertaking. The Company will remain responsible for any obligations assumed
by CLH in the event CLH does not perform or fulfill such obligations. The
environmental contingencies discussed herein and the declaratory judgment
action filed by OxyChem and Henkel are among the matters for which CLH has
assumed responsibility, and the Company transferred to CLH its then remaining
rights to recover costs under the arrangement with DSI. The contribution
obligation of YPF related to the Assumption was reflected on the Company's
financial statements as a long-term and short-term funding guarantee from
parent totaling $106.9 million, an increase to deferred income taxes of $37.4
million and an increase to paid-in capital of $69.5 million. At December 31,
1996, the outstanding funding guarantee totaled $102.6 million. Insofar as CLH
has assumed the Company's environmental liabilities and YPF has committed to
pay for the liabilities, such liabilities are not expected to have an adverse
impact on the financial reporting books of the Company.
 
  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. The Company has entered into settlement
 
                                      13
<PAGE>
 
agreements with certain of the insurers in this second suit, the terms of
which are required to be held confidential. The Company also is engaged in
settlement discussions with other defendant insurers; however, there can be no
assurance that such discussions will result in settlements with such other
insurers.
 
  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 late 1997 or in 1998,
cost approximately $23 million and take three to four years to complete. The
work is being supervised and paid for by CLH on behalf of the Company pursuant
to the Assumption and under the Company's above described indemnification
obligation to Occidental. The Company has 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. These studies suggest that the older and more
contaminated sediments located adjacent to the Newark plant generally are
buried under more recent sediment deposits. The Company, on behalf of
Occidental, negotiated an agreement with the EPA under which CLH, on the
Company's behalf, is conducting further testing and studies to characterize
contaminated sediment and biota in a six-mile portion of the Passaic River
near the plant site. The stability of the sediments in the entire six-mile
portion of the Passaic River study area is also being examined as a part of
CLH's studies. The Company currently expects the testing and studies to be
completed in 1999 and cost from $4 million to $6 million after December 31,
1996. The Company has reserved for the amount of its estimate of the remaining
costs to be incurred in performing these studies. The Company and later CLH
have been conducting similar studies under their 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. However, it is
possible that additional work, including interim remedial measures, may be
ordered with respect to the Passaic River.
 
  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 and near 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 presently being
performed by CLH on behalf of the Company and Occidental, and CLH is funding
Occidental's share of the cost of investigation and remediation of these
sites. The Company 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 and
CLH have participated in the cost of studies and CLH is implementing interim
remedial actions and conducting remedial investigations and feasibility
studies, the ultimate cost of remediation is uncertain. The Company
anticipates CLH will submit its remedial investigation and feasibility study
report to the DEP in 1997. The results of the DEP's review of this report
could increase 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 approximately $47 million at
December 31, 1996. 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
 
                                      14
<PAGE>
 
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 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 $5 million to $8 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 reserved for the amount of its estimated 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. The Company's obligations regarding the Chrome
Plant described above have been assumed by CLH pursuant to the Assumption.
 
  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 for its
estimated costs related to these sites, none of which individually is
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. The matters described below are among those for
which CLH has assumed responsibility under the Assumption.
 
  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.
 
 
                                      15
<PAGE>
 
  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. 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.
 
  3. Chemical Control Site; Elizabeth, New Jersey. The PRPs and the EPA have
settled the federal claims for cost recovery and site remediation, and
remediation is now complete. 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.
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.
 
 Employees
 
  As of December 31, 1996, the Company had approximately 2,027 employees.
 
ITEM 3. LEGAL PROCEEDINGS.
 
  In 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 court denied the Company's
motion for summary judgment and granted OxyChem's and Henkel's joint motion
for summary judgment, thereby granting OxyChem and Henkel the declaration they
sought. The Company believes the court's orders are erroneous and has
appealed.
 
  The Company has established reserves based on its 50% share of remaining
costs expected to be paid or incurred by OxyChem and Henkel prior to September
4, 1996, the tenth anniversary of the Closing Date. As of December 31, 1996,
the Company and CLH on its behalf had paid OxyChem and Henkel a total of
approximately $42 million against the $75 million cap and, based on OxyChem's
and Henkel's historical annual expenditures,
 
                                      16
<PAGE>
 
the Company had approximately $4 million reserved. The Company cannot predict
with any certainty what portion of the approximately $29 million unreserved
portion of the $33 million amount remaining at December 31, 1996, OxyChem and
Henkel may incur; however, OxyChem and Henkel have asserted in court that the
entire amount will be spent. In the event that the Company does not prevail in
its appeal, it could be required to pay up to approximately $29 million in
additional costs which have not been reserved related to this indemnification.
CLH has assumed, pursuant to the Assumption, responsibility for this
litigation.
 
  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. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS.
 
  Inapplicable.
 
                                    PART II
 
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, 1997, YPF was the sole holder of record of the Common Stock.
 
  Midgard, a subsidiary of the Company, is party to a credit agreement which
places certain restrictions on its ability to make or declare certain
payments, advances and loans specified therein, including dividends to the
Company. (For a further description of such credit agreement, 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 only
other equity issue currently outstanding, the $2.50 Preferred Stock.
 
                                      17
<PAGE>
 
ITEM 6. SELECTED FINANCIAL DATA.
 
                          FIVE-YEAR FINANCIAL SUMMARY
                  (DOLLARS IN MILLIONS, EXCEPT PER SHARE DATA)
 
<TABLE>
<CAPTION>
                                    NINE MONTHS   THREE MONTHS
                                       ENDED         ENDED
                                    DECEMBER 31,   MARCH 31,
                            1996        1995          1995       1994      1993      1992
                          --------  ------------  ------------ --------  --------  --------
<S>                       <C>       <C>           <C>          <C>       <C>       <C>
OPERATIONS
Sales and operating
 revenues...............  $  718.0    $  463.8      $  142.5   $  682.1  $  786.7  $  718.4
Net income (loss) before
 extraordinary item and
 cumulative effect of
 change in accounting
 principle..............      20.6        (73.7)       (56.9)     (22.7)    (37.9)     74.2
Extraordinary item......      (5.6)                                          (7.1)
Cumulative effect of
 change in accounting
 principle..............                                                     (4.4)
                          --------    --------      --------   --------  --------  --------
Net income (loss).......  $   15.0     $  (73.7)    $  (56.9)  $  (22.7) $  (49.4) $   74.2
FINANCIAL POSITION
Current assets..........  $  314.7    $  266.4      $  394.6   $  441.9  $  404.7  $  391.2
Current liabilities.....     354.8        306.4        224.3      171.0     263.4     327.9
Properties and
 equipment, less
 accumulated
 depreciation, depletion
 and amortization.......   2,022.2     2,363.6       1,110.7    1,088.4   1,305.6   1,138.3
Total assets............   2,456.5      2,716.8      1,692.1    1,706.7   1,987.4   1,811.6
Long-term debt,
 including current
 portion................   1,270.7      1,295.5        975.6      975.6   1,055.1     829.4
Deferred income taxes...     502.7        551.2        199.7      199.3     198.3     152.9
Redeemable preferred
 stock..................      62.5        125.0        125.0      125.0     250.0     250.0
Stockholders' equity....     148.9        240.0         13.5       91.1     147.9     171.6
OTHER DATA
Expenditures for
 properties and
 equipment--including
 dry hole costs.........  $  203.3    $  137.4      $   53.6   $  166.2  $  340.0  $  261.1
Total exploration and
 development
 expenditures (whether
 capitalized or
 expensed)..............     219.0        165.5         60.6      197.1     376.8     256.7
Preferred dividends
 paid...................      27.4          28.8         9.6       43.6      41.7      41.7
Depreciation, depletion
 and amortization.......     168.9        142.1         29.9      140.2     153.6     174.4
PER COMMON SHARE
Net income (loss) before
 extraordinary item and
 cumulative effect of
 change in accounting
 principle..............  $             $           $  (0.49)  $  (0.49) $  (0.60) $   0.27
Extraordinary item......                                                    (0.05)
Cumulative effect of
 change in accounting
 principle..............                                                    (0.03)
                          --------    --------      --------   --------  --------  --------
Net income (loss).......  $             $           $  (0.49)  $  (0.49) $  (0.68) $   0.27
</TABLE>
 
                                       18
<PAGE>
 
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
 
 Significant Events 1996
 
  On June 18, 1996, Maxus Energy Corporation (the "Company" or "Maxus")
announced a reorganization which included the sale of three of its
subsidiaries holding certain Bolivian and Venezuelan assets to YPF Sociedad
Anonima ("YPF"), the redemption of the outstanding shares of $4.00 Cumulative
Convertible Preferred Stock (the "$4.00 Preferred Stock") and the transfer to
a YPF subsidiary of a Maxus subsidiary that assumed certain liabilities
related to environmental matters.
 
  On July 1, 1996, Maxus International Energy Company ("Seller"), a wholly
owned subsidiary of Maxus, sold all of the issued and outstanding shares of
capital stock of its wholly owned subsidiary, YPF International Ltd.
("International"), to YPF, pursuant to a Stock Purchase and Sale Agreement by
and between YPF and Seller. The sole assets of International at the time of
the transaction were all of the issued and outstanding shares of capital stock
of Maxus Bolivia, Inc. ("Maxus Bolivia"), Maxus Venezuela (C.I.) Ltd.
("Venezuela C.I.") and Maxus Venezuela S.A. ("Venezuela S.A."). The assets of
Maxus Bolivia consisted of all of the former assets and operations of Maxus in
Bolivia, including the interests of Maxus in the Surubi Field and Secure and
Caipipendi Blocks. The assets of Venezuela C.I. and Venezuela S.A. consisted
of all of the former assets and operations of Maxus in Venezuela, except those
held through Maxus Guarapiche Ltd. ("Maxus Guarapiche"), including the
interests of Maxus in the Quiriquire Unit.
 
  The purchase price for the outstanding shares of capital stock of
International was $266.2 million which represented the carrying amount of
International on the financial reporting books of Seller as of June 30, 1996.
Maxus used the proceeds from this transaction for general corporate purposes,
including the redemption of its $4.00 Preferred Stock, which is discussed
below.
 
  While not a part of the above-described sale transaction, effective
September 1, 1996, Seller sold all of the capital stock of Maxus Guarapiche to
International for $26 million which represented the carrying amount of Maxus
Guarapiche on the financial reporting books of Seller as of August 31, 1996.
Maxus Guarapiche had a 25% interest in the Guarapiche Block, an exploration
block, in Venezuela.
 
  Also as part of the general reorganization, on August 13, 1996 Maxus
redeemed all of its outstanding shares of $4.00 Preferred Stock at a price of
$50 per share plus accrued and unpaid dividends (approximately $221 million in
the aggregate). The excess of the redemption price over the carrying value of
the $4.00 Preferred Stock resulted in an increase in the Company's accumulated
deficit of $214 million. The Company used a portion of the proceeds from the
sale of all of the issued and outstanding shares of capital stock of
International as well as an advance from an indirect, wholly owned subsidiary
of YPF, YPF Holdings, Inc. ("Holdings"), of approximately $56 million to
redeem the $4.00 Preferred Stock.
 
  As a further part of the reorganization, the Company transferred certain
liabilities related to environmental matters to Chemical Land Holdings, Inc.
("CLH"), an indirect subsidiary of YPF, effective as of August 1, 1996. In
connection with this transfer, CLH assumed (the "Assumption") the liabilities
so transferred and YPF committed to contribute capital (the "Contribution
Agreement") to CLH up to an amount of $107 million that will enable CLH to
satisfy its obligations under the Assumption based on the Company's reserves
established in respect of the assumed liabilities as of July 31, 1996 plus
certain operating expenses budgeted by CLH from time to time. YPF will not be
obligated to contribute capital to CLH beyond the amount of its initial
undertaking. The Company will remain responsible for any obligations assumed
by CLH in the event CLH does not perform or fulfill such obligations. CLH has
assumed responsibility for, among other things, the environmental
contingencies discussed in "Environmental Matters" below and a declaratory
judgment action discussed in "Legal Proceedings" below, and the Company
transferred to CLH its remaining rights to recover costs under a cost-sharing
arrangement with Ultramar Diamond Shamrock Corporation.
 
  The contribution obligation of YPF related to the Assumption was reflected
on the Company's financial statements as a long-term and short-term funding
guarantee from parent totaling $107 million, an increase to
 
                                      19
<PAGE>
 
deferred income taxes of $37 million and an increase to paid-in capital of $70
million. At December 31, 1996, the outstanding funding guarantee totaled $103
million. Insofar as CLH has assumed the Company's environmental liabilities
and YPF has committed to pay for the liabilities, such liabilities are not
expected to have an adverse impact on the financial reporting books of the
Company.
 
  Under the terms of the Contribution Agreement, Maxus agreed that any
contributions to the equity capital of CLH by YPF shall reduce the obligation
of YPF to capitalize Maxus pursuant to the Agreement of Merger ("Merger
Agreement"). During 1996, YPF made capital contributions of $8 million to CLH.
 
  Effective August 13, 1996, YPF transferred ownership of its shares of the
Company's Common Stock to Holdings.
 
 Significant Events 1995
 
  On June 8, 1995, a special meeting of the stockholders of the Company was
held to approve the Merger Agreement dated February 28, 1995, between the
Company, YPF Acquisition Corp. ("YPFA Corp.") and YPF. The holders of the
Company's common stock, $1.00 par value per share (the "Shares" or "Common
Stock"), and $4.00 Preferred Stock (together with the Shares, the "Voting
Shares") approved the Merger Agreement, and YPFA Corp. was merged into the
Company (the "Merger") on June 8, 1995 (the "Merger Date").
 
  The Merger was the consummation of transactions contemplated by a tender
offer (the "Offer") which was commenced on March 6, 1995 by YPFA Corp. for all
the outstanding Shares at $5.50 per Share. Pursuant to the Offer, in April
1995 YPFA Corp. 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 YPFA Corp., YPF or any of
their subsidiaries or in the treasury of the Company, all of which were
canceled 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 total amount of funds required by YPFA Corp. 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. In
addition, YPFA Corp. assumed all outstanding obligations of the Company. On
April 5, 1995, YPFA Corp. entered into a credit agreement with lenders for
which The Chase Manhattan Bank (National Association) ("Chase") acted as
agent, pursuant to which the lenders extended to YPFA Corp. a credit facility
for up to $550 million (the "Purchaser Facility"). On April 5, 1995, YPFA
Corp. borrowed $442 million under the Purchaser Facility and received a
capital contribution of $250 million from YPF. YPFA Corp. 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.
 
  Effective April 1, 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 to acquire the Company. The Company's
oil and gas properties were assigned carrying amounts based on their relative
fair market values.
 
  Following the Merger, Chase provided two additional credit facilities
aggregating $425 million: (i) a credit facility of $250 million (the "Midgard
Facility") extended to Midgard Energy Company, a wholly owned subsidiary of
the Company, and (ii) a credit facility of $175 million (the "Indonesian
Facility") extended to Maxus Indonesia, Inc., 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
 
                                      20
<PAGE>
 
receive cash in the Merger. In December 1996, International, the parent of
Holdings, loaned the Company approximately $175 million to repay the
Indonesian Facility.
 
 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 Twelve Months Ended December 31, 1996
 
  For the twelve months ended December 31, 1996, Maxus reported net income of
$15 million. During 1996, performance improved as higher crude oil, natural
gas and natural gas liquids ("NGL") prices, higher natural gas sales volumes
and lower costs more than offset higher income taxes resulting from higher
operating income. Comparative information for the twelve months ended December
31, 1995 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 twelve
months ended December 31, 1996 were $718 million composed of $404 million from
Maxus' Indonesian operations, $233 million from U.S. operations and $81
million from South American operations.
 
  Maxus' net worldwide crude oil sales volumes averaged 59 thousand barrels
per day ("mbpd") during the twelve-month period ended December 31, 1996, which
were comprised of 44 mbpd from Maxus' Indonesian operations, 14 mbpd from
South American operations and one mbpd from U.S. operations. Maxus' net
worldwide crude oil sales volumes declined four mbpd from an average of 63
mbpd during the twelve months ended December 31, 1995 due primarily to lower
net crude oil sales in Indonesia. In Northwest Java, 1996 average net crude
oil sales declined four mbpd compared to the same period last year due to
natural declines in gross crude oil production and lower cost recovery. In
Southeast Sumatra, 1996 average net crude oil sales declined six mbpd compared
to the same period in 1995 due primarily to lower cost recovery. During 1996,
natural declines in gross crude oil production in Southeast Sumatra were
offset by new crude oil production resulting from the introduction of
horizontal well technology and use of high volume electrical submersible pumps
combined with an active drilling program. Partially offsetting the overall
decline in Indonesia, average net crude oil sales in South America increased
five mbpd from nine mbpd in 1995. In Ecuador, 1996 average net crude oil sales
of 10 mbpd were two mbpd higher than 1996 primarily as a result of crude oil
production from the Amo, Iro, Ginta and Diami fields. Although Maxus owned an
interest in its Bolivian operations for only six months in 1996, average net
crude oil sales increased three mbpd from one mbpd for the year ended December
31, 1995 due primarily to the sale of approximately nine months of crude oil
inventory to the Bolivian Government during the first quarter of 1996. During
the twelve months ended December 31, 1996, Maxus' average worldwide crude oil
price of $19.22 per barrel ("bbl") increased $2.77 per bbl from $16.46 per bbl
in 1995.
 
 
                                      21
<PAGE>
 
  During the twelve months ended December 31, 1996, average U.S. natural gas
sales volumes of 182 mmcfpd increased 11 mmcfpd over the same period a year
ago. Continued successful Midgard infill drilling more than offset natural
declines from the area during 1996. In the next several years, Maxus expects
its Midgard infill drilling program to continue to offset any natural
declines. Average U.S. natural gas prices rose significantly, from $1.48 per
thousand cubic feet ("mcf") in 1995 to $1.96 per mcf 1996, although this price
increase was net of losses of $13 million on natural gas price swap agreements
and futures contracts. In Northwest Java, 1996 average net natural gas sales
volumes of 69 mmcfpd increased 13 mmcfpd compared to the same period last year
as a result of higher natural gas production in connection with new natural
gas sales contracts as well as increased demand from existing contracts.
Average Northwest Java natural gas prices rose slightly, from $2.63 per mcf in
1995 to $2.65 per mcf in 1996.
 
  Average 1996 net NGL sales volumes in the U.S. of 19 mbpd were relatively
flat compared to the same period last year. Annual 1996 average U.S. NGL
prices increased from $10.46 per bbl in 1995 to $13.23 per bbl in 1996,
although this price increase was net of losses of $10 million on NGL price
swap agreements.
 
  Costs and Expenses. Costs and expenses were $640 million during the twelve
months ended December 31, 1996. Costs and expenses during this period included
operating expenses of $202 million; gas purchase costs of $74 million;
exploration expenses of $35 million; depreciation, depletion and amortization
("DD&A") of $169 million; interest and debt expenses of $135 million and other
costs and expenses totaling $25 million.
 
  DD&A of $169 million during the twelve-month period ended December 31, 1996,
included $43 million of additional DD&A reflecting the impact of the 1995
purchase price allocation which increased the book value of the Company's oil
and gas properties and equipment.
 
  In the twelve-month period ended December 31, 1996, interest and debt
expenses of $135 million included $31 million of interest expense associated
with the Midgard and Indonesian credit facilities. Also included in interest
and debt expenses during this period was $9 million of interest associated
with the accretion of discount on the Company's long-term debt which was
outstanding prior to the Merger. In 1995, 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 continue to be amortized to interest expense over the
remaining term of the borrowings.
 
  Other Revenues, Net. For the twelve months ended December 31, 1996, other
revenues, net of $20 million included interest income, a refund from the
United Mine Workers Association Combined Benefit Fund of assessments stemming
from a discontinued business and litigation proceeds partially offset by a net
loss on the sale of fixed assets, a contract signing bonus in Ecuador (See
"Future Outlook" below), a performance bonus paid to all Company employees in
connection with an incentive program designed to improve the Company's
financial performance and certain other miscellaneous expenses.
 
  Income Taxes. Income tax expense of $78 million for the twelve-month period
ended December 31, 1996, included $99 million of current income tax expense
primarily from Indonesian operations partially offset by a $21 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 1995. In the future, the
Company expects to realize additional deferred tax benefits as a result of the
higher DD&A.
 
  Extraordinary Item. In December 1996, the Company used the proceeds of a
$175 million loan from International to repay the Indonesian Facility.
Unamortized debt issue costs associated with this early retirement were
recorded as an extraordinary loss of $6 million, net of taxes. The tax impact
of this transaction was less than $.1 million.
 
 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.
 
                                      22
<PAGE>
 
  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 averaged 64 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 an average of 60 mbpd in the third quarter of 1995 to an
average of 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 bbl.
 
  During the nine-month period ended December 31, 1995, U.S. net natural gas
sales volumes averaged 172 mmcfpd and U.S. natural gas prices averaged $1.49
per 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. Average
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 net natural gas sales volumes averaged 61 mmcfpd and Northwest
Java natural gas prices averaged $2.62 per mcf.
 
  During the nine months ended December 31, 1995, average NGL net sales
volumes in the U.S. were 18 mbpd and U.S. NGL prices averaged $10.49 per bbl.
 
  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; 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, Midgard and Indonesian 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.
 
  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
 
                                      23
<PAGE>
 
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.
 
 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 averaged 60 mbpd in the first quarter
1995, compared to 69 mbpd in the same quarter in 1994. Average net 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. Net crude oil sales from the Company's Indonesian operations were
also down an average of 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, average net production from South America of seven
mbpd provided an additional $8 million of revenues in 1995.
 
  Average net 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.
 
  Average net 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 in 1994 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.
 
  Average net NGL sales in the U. S. for the first quarter 1995 were 18 mbpd,
a slight decrease over the first quarter of 1994. The average sales price for
U.S. NGL in the first quarter of 1995 was $10.38 per barrel, an increase of
$1.15 per bbl 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.
 
                                      24
<PAGE>
 
  DD&A of $30 million for the first quarter 1995 was $8 million lower than the
same period in 1994. 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.
 
 Results for the Twelve Months Ended December 31, 1994
 
  Maxus reported a net loss of $23 million in 1994.
 
  Sales and Operating Revenues. 1994 sales and operating revenues of $682
million were negatively impacted due primarily to 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.
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 average net crude oil production was 67 mbpd in 1994 which was
comprised of 60 mbpd from Maxus' Indonesian operations, five mbpd from South
American operations and two mbpd from U.S. operations. Initial production from
South American operations commenced during 1994 which favorably impacted
revenues by $24 million. Crude oil volumes in the United States were
negatively impacted by the loss of production from the Divested Properties.
Additionally, crude oil sales from the Company's Indonesian operations
reflected the unfavorable impact of temporary production problems in Northwest
Java, which were corrected. Maxus' 1994 average worldwide crude price hit a
five-year low of $15.31 per bbl.
 
  Average net U.S. natural gas sales volumes of 275 mmcfpd in 1994 included a
decline attributable to the loss of production from the Divested Properties
and a decrease in purchased gas volumes which were aggregated and sold with
the production from the Divested Properties. Maxus' U.S. natural gas prices
averaged $1.95 per mcf in 1994.
 
  Average net Northwest Java natural gas sales volumes were 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.
 
  Average net NGL sales in the U.S. were 17.9 mbpd in 1994 and prices received
averaged $10.07 per barrel.
 
  Costs and Expenses. Costs and expenses, excluding restructuring, were $728
million in 1994. Costs and expenses during this period included operating
expenses of $243 million; gas purchase costs of $117 million; exploration
expenses of $36 million; DD&A of $140 million; interest and debt expenses of
$97 million; an environmental studies and remediation accrual of $60 million
and other costs and expenses totaling $35 million. Overall, the favorable
impact on costs and expenses related to the Divested Properties was partially
offset by additional costs and expenses incurred in South America due to the
start-up of production in Ecuador, Bolivia and Venezuela.
 
  The Company increased its reserve for environmental liabilities in 1994 by
$60 million, primarily in response to the EPA's proposed chromium clean-up
standards and for additional costs expected to be incurred at the Company's
former Newark, New Jersey 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 sale of the Divested Properties. This gain was
 
                                      25
<PAGE>
 
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 operating
areas.
 
  Other Revenues, Net. Other revenues, net of $9 million in 1994 included
primarily interest income partially offset by a net loss on the sale of the
Company's geothermal subsidiary, Thermal Power Company.
 
  Income Taxes. The Company's provision for income taxes of $87 million in
1994 was comprised primarily of current and deferred foreign taxes in
Indonesia.
 
 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, equity issuances, and capital contributions and cash advances
from YPF and its subsidiaries.
 
  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 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 Facility and the
Indonesian 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. During the twelve months
ended December 31, 1996, YPF made capital contributions to the Company and CLH
(see "Significant Events 1996") in the aggregate amount of $64 million and $8
million, respectively. These amounts represent the cumulative contribution
received by Maxus and CLH from YPF pursuant to the terms of the Keepwell
Covenant. Based on current projections, it is anticipated that YPF will make
capital contributions to CLH in the aggregate amount of approximately $25 to
$50 million under the Keepwell Covenant during 1997. No such capital
contributions to the Company are projected during 1997.
 
  The Midgard 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 may not
permit (a) consolidated tangible net worth to be less than $200 million, plus
(or minus) the amount of any adjustment in the book value of assets 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 Midgard Facility may
be required in connection with certain asset sales and casualty losses, upon
the issuance of subordinated indebtedness and in 1997 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, 1996.
 
  Maxus has guaranteed the obligations of Midgard under the Midgard Facility
(the "Midgard Guaranty"). The Midgard 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 is
required to be a wholly owned subsidiary 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.
 
 
                                      26
<PAGE>
 
  In management's opinion, cash on hand and cash from operations will be
inadequate to fund the 1997 program spending budget, service debt, meet
redemption obligations on redeemable preferred stock and pay preferred stock
dividends and trade obligations. It is anticipated that YPF could be required
to make cash advances to Maxus in 1997 totaling approximately $150 million to
$200 million to help fund the Company's obligations. Actual cash advances made
by YPF could vary significantly depending on, among other circumstances, oil
and gas prices and program spending commitments.
 
  Operating Activities. For the twelve months ended December 31, 1996, net
cash provided by operating activities was $152 million. Excluding the change
in working capital requirements of $27 million, net cash from operating
activities was $179 million for the year. Additional working capital was
required primarily due to the recognition of deferred revenue in Northwest
Java and Bolivia during 1996 as well as higher receivables in Ecuador.
 
  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.
 
  Investing Activities. Expenditures for properties and equipment, including
dry hole costs, were $203 million in 1996, a slight increase from 1995. During
1996, the Company focused its spending efforts on developmental drilling in
established areas of the United States, Indonesia and Ecuador with the
intention of increasing reserves and production in already proven areas. In
the U.S., the Company drilled over 100 development wells during 1996, which
contributed to the 13% increase in total net production as compared to last
year. In addition, due to the increased drilling and detailed engineering
work, approximately 174 billion cubic feet of gas reserves were added. During
1996, natural declines in gross crude oil production in the Southeast Sumatra
contract area of Indonesia were offset by new crude oil production resulting
from the introduction of horizontal well technology combined with an active
drilling program. Expenditures for the year also included the acquisition of a
25% interest in the Guarapiche block in Venezuela for $27 million, which was
subsequently sold to International (see "Significant Events 1996").
 
  During 1995, the Company concentrated 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.
 
  In 1996 the Company sold Maxus Bolivia, Maxus Venezuela, and Maxus
Guarapiche to YPF and its subsidiaries for approximately $293 million. The
proceeds were used for general corporate purposes, including the redemption of
the $4.00 Preferred Stock on August 13, 1996 for $221 million (see
"Significant Events 1996"). The Company also received approximately $14
million from the sale of non-oil and gas properties, including the Company's
ranch and other real estate holdings.
 
                                      27
<PAGE>
 
  In December 1995, the Company sold its overriding royalty interest in the
Recetor Block in Colombia to an unrelated party 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 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 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, held
the remaining 5%. Both Maxus Bolivia and Maxus Venezuela were sold to YPF in
1996 (see "Significant Events 1996").
 
  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 1996, the Company released $47 million of restricted cash of which $26
million had been backing trade letters of credit, $9 million was for assets
held in trust as previously required by certain insurance policies, and $8
million had been required by the Indonesian Facility. 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 Indonesian Facility. During 1994, $36 million in restricted
cash backing letters of credit in Venezuela were released when the Company
took on a partner and reduced its interest to 50%.
 
  During 1994, the Company purchased $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.
 
  Financing Activities. In 1996 the Company received capital contributions in
the aggregate amount of $64 million from YPF, for which the Company issued to
YPF an additional 11,636,363 Shares at $5.50 per Share. The proceeds from this
issuance were used for general corporate purposes including the mandatory
redemption of 625,000 shares of the $9.75 Preferred Stock for $63 million. As
discussed in "Significant Events 1996", the Company also redeemed its
outstanding $4.00 Preferred Stock for $221 million (including accrued
dividends of approximately $3 million) using proceeds provided by the sale of
the Company's Bolivian and Venezuelan assets. International advanced the
Company $175 million in the form of a demand note, bearing 5.75% interest
compounded annually, to repay the Indonesian Facility. Additionally, the
Company repaid $34 million of medium-term notes, which matured in 1996.
 
  The Company and YPF entered into a loan agreement (the "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. At December 31,
1996, there were no loans outstanding under the Loan Agreement. It is expected
that loans will be made by the parties under the loan agreement during 1997;
however, the number and amounts thereof are not presently known.
 
  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 Indonesian credit facilities
 
                                      28
<PAGE>
 
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.
 
  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 was deferred.
 
  During 1994, the Company was able to take advantage of lower interest rates
and, at the same time, to extend the average debt maturities. Accordingly, 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 higher interest debt obligations due 1994 and
beyond and to prepay $63 million of $9.75 Preferred Stock due in February
1995.
 
  In February 1994, the Company redeemed 625,000 shares of $9.75 Preferred
Stock for $63 million, using proceeds received in 1993 from the issuance of
the $2.50 Preferred Stock in 1993.
 
 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. CERCLA imposes retroactive liability upon certain parties
for the response costs associated with cleaning up old hazardous substance
sites. CERCLA liability to the Government is joint and several. CERCLA allows
authorized trustees to seek recovery of natural resource damages from
potentially responsible parties. CERCLA also grants the Government the
authority to require potentially responsible parties to implement interim
remedies to abate an imminent and substantial endangerment to the environment.
 
  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.
 
                                      29
<PAGE>
 
  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 and CLH on the Company's behalf under this cost
sharing arrangement was about $42 million as of December 31, 1996. Occidental
Chemical Corporation ("OxyChem"), a subsidiary of Occidental, and Henkel
Corporation ("Henkel"), an assignee of certain of Occidental's rights and
obligations, filed a declaratory judgment action in Texas state court with
respect to the Company's agreement in this regard. The lower court found in
favor of Occidental and Henkel and the Company has appealed the judgment (see
"Legal Proceedings").
 
  In connection with the spin-off of Diamond Shamrock R&M, Inc., now known as
Ultramar Diamond Shamrock Corporation ("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. Thereafter, such ongoing costs were
borne one-third by DSI and two-thirds by the Company until DSI had borne an
additional $47.5 million. As of December 31, 1996, DSI had fulfilled its
remaining responsibility under the cost-sharing arrangement, and it has no
further obligation thereunder.
 
  During the twelve months ended December 31, 1996, the Company spent $8
million in environmental related expenditures in its oil and gas operations.
Expenditures for 1997 are expected to be approximately $13 million.
 
  For the seven months ended July 31, 1996, the Company's total expenditures
for environmental compliance for disposed of businesses, including Chemicals,
were approximately $13 million, $5 million of which was recovered from DSI
under the above described cost-sharing arrangement.
 
  At December 31, 1996, reserves for the environmental contingencies discussed
herein totaled $101.6 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 Company has transferred certain liabilities related to environmental
matters to CLH (see "Significant Events 1996") effective as of August 1, 1996.
In connection with this transfer, CLH assumed the liabilities so transferred
and YPF committed to contribute capital to CLH up to an amount of $106.9
million that will enable CLH to satisfy its obligations under the Assumption
based on the Company's reserves established in respect of the assumed
liabilities as of July 31, 1996 plus certain operating expenses budgeted by
CLH from time to time. YPF will not be obligated to contribute capital to CLH
beyond the amount of its initial undertaking. The Company will remain
responsible for any obligations assumed by CLH in the event CLH does not
perform or fulfill such obligations. The environmental contingencies discussed
herein and the declaratory judgment action filed by OxyChem and Henkel are
among the matters for which CLH has assumed responsibility, and the Company
transferred to CLH its then remaining rights to recover costs under the
arrangement with DSI. The contribution obligation of YPF related to the
Assumption was reflected on the Company's financial statements as a long-term
and short-term funding guarantee from parent totaling $106.9 million, an
increase to deferred income taxes of $37.4 million and an increase to paid-in
capital of $69.5 million. At December 31, 1996, the outstanding funding
guarantee totaled $102.6 million. Insofar as CLH has assumed the Company's
environmental liabilities and YPF has committed to pay for the liabilities,
such liabilities are not expected to have an adverse impact on the financial
reporting books of the Company.
 
                                      30
<PAGE>
 
  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. The Company has entered into settlement
agreements with certain of the insurers in this second suit, the terms of
which are required to be held confidential. The Company also is engaged in
settlement discussions with other defendant insurers; however, there can be no
assurance that such discussions will result in settlements with such other
insurers.
 
  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 late 1997 or in 1998,
cost approximately $23 million and take three to four years to complete. The
work is being supervised and paid for by CLH, on behalf of the Company
pursuant to the Assumption and under the Company's above described
indemnification obligation to Occidental. The Company has 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. These studies suggest that the older and more
contaminated sediments located adjacent to the Newark plant generally are
buried under more recent sediment deposits. The Company, on behalf of
Occidental, negotiated an agreement with the EPA under which CLH, on the
Company's behalf, is conducting further testing and studies to characterize
contaminated sediment and biota in a six-mile portion of the Passaic River
near the plant site. The stability of the sediments in the entire six-mile
portion of the Passaic River study area is also being examined as a part of
CLH's studies. The Company currently expects the testing and studies to be
completed in 1999 and cost from $4 million to $6 million after December 31,
1996. The Company has reserved for the amount of its estimate of the remaining
costs to be incurred in performing these studies. The Company and later CLH
have been conducting similar studies under their 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. However, it is
possible that additional work, including interim remedial measures, may be
ordered with respect to the Passaic River.
 
  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 and near 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 presently being
performed by CLH on behalf of the Company and Occidental, and CLH is funding
Occidental's share of the cost of investigation and remediation of these
sites. The Company 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 and
CLH have participated in the cost of studies
 
                                      31
<PAGE>
 
and CLH is implementing interim remedial actions and conducting remedial
investigations and feasibility studies, the ultimate cost of remediation is
uncertain. The Company anticipates CLH will submit its remedial investigation
and feasibility study report to the DEP in 1997. The results of the DEP's
review of this report could increase 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 approximately
$47 million. 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 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 $5 million to $8 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 reserved for the amount of its 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. The Company's obligations regarding the Chrome
Plant described above have been assumed by CLH pursuant to the Assumption.
 
  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 for its
estimated costs related to these sites, none of which is 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. The matters described below are among those for
which CLH has assumed responsibility under the Assumption.
 
                                      32
<PAGE>
 
  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. 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.
 
  3. Chemical Control Site; Elizabeth, New Jersey. The PRPs and the EPA have
settled the federal claims for cost recovery and site remediation, and
remediation is now complete. 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.
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 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 court denied the Company's
motion for summary judgment and granted OxyChem's and Henkel's joint motion
for summary judgment, thereby granting OxyChem and Henkel the declaration they
sought. The Company believes the court's orders are erroneous and has
appealed.
 
                                      33
<PAGE>
 
  The Company has established reserves based on its 50% share of remaining
costs expected to be paid or incurred by OxyChem and Henkel prior to September
4, 1996, the tenth anniversary of the Closing Date. As of December 31, 1996,
the Company and CLH on its behalf had paid OxyChem and Henkel a total of
approximately $42 million against the $75 million cap and, based on OxyChem's
and Henkel's historical annual expenditures, the Company had approximately $4
million reserved. The Company cannot predict with any certainty what portion
of the approximately $29 million unreserved portion of the $33 million amount
remaining at December 31, 1996, OxyChem and Henkel may incur; however, OxyChem
and Henkel have asserted in court that the entire amount will be spent. In the
event that the Company does not prevail in its appeal, it could be required to
pay up to approximately $29 million in additional costs which have not been
reserved related to this indemnification. CLH has assumed, pursuant to the
Assumption, responsibility for this litigation.
 
  The Company has established reserves for legal contingencies in situations
where a loss is probable and can be reasonably estimated.
 
 Future Outlook
 
  Maxus currently projects total program spending (capital expenditures plus
exploration expenses) for 1997 to be approximately $221 million, compared to
$233 million in 1996. The planned allocation is Indonesia $110 million,
Midgard (U.S.) $66 million, Ecuador $26 million and domestic and overseas new
ventures $19 million. Funding for the 1997 spending program is expected to be
provided by cash from operations and cash advances from YPF as necessary. In
addition to the 1997 program, Maxus has financial and/or performance
commitments for exploration and development activities in 1998 and beyond,
none of which are material.
 
  Midgard has signed a letter of intent with Amoco Production Company
("Amoco") concerning the establishment of a partnership with regard to
Midgard's business and assets. It is anticipated that Midgard and Amoco will
each contribute to the partnership oil and gas properties in the Texas
Panhandle and western Oklahoma and that Amoco will contribute certain other
assets. Midgard and Amoco have commenced negotiations of definitive agreements
covering the partnership. However, no definitive agreements have been entered
into, and consequently no assurances can be given that the attempts to
establish the partnership will be successful. In addition to the general
reorganization discussed in "Significant Events 1996" above, Maxus is
continuing to consider a number of possible capital and business restructuring
alternatives; however, no decisions have been made to take any additional
specific action nor can there be any assurance that any specific action will
be taken.
 
  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 changes in governments, civil
strife, guerrilla activities and insurrection. Areas in which the Company has
significant operations include the United States, Indonesia and Ecuador.
 
  On August 10, 1996, a new Government was inaugurated in Ecuador and on
August 20, 1996, the new Energy Minister announced his intention to cancel the
Company's risk service contract unless the Company and the other members of
its consortium for the Block 16 project ("Block 16") agreed to convert such
contract into a production sharing contract. Effective January 1, 1997, the
Company and the Government entered into a new contract governing Block 16. The
principal difference between the two contracts is the manner in which the
consortium's costs in the Block are recovered. Under the former contract, the
Company had the right to recover its investment before the Government began to
share in significant proceeds from the sale of production; under the new
contract, the Government receives a royalty, and the Company's recovery of its
investment is out of the proceeds after deducting such royalty. Previous
Governments had signaled their dissatisfaction with the former arrangement and
in recent years a series of auditing, contract administration and
certification of new field disputes had arisen that made it increasingly
difficult to develop Block 16. Partly in response to these difficulties, the
Company reduced its 1996 program spending on Block 16 to $17 million from $32
million in 1995.
 
                                      34
<PAGE>
 
  The new contract also resolves certain outstanding disputes and amends the
prior agreement in various other ways, some of which are expected to
significantly improve the Company's current and future operating costs. The
Company believes that the new contract permits the Company to go forward with
the development of Block 16 and permits it to do so on a more cost-effective
basis, subject to the eventual permanent increase of pipeline capacity
discussed below. Based on the terms of the newly approved contract and events
which have transpired since such approval, no write down of carrying value of
the Block is required. During 1996, pipeline capacity available to the Company
was sufficient to transport only about 60 to 80% of the oil which the Company
produced daily in Ecuador. Due to the decreased usage by PetroEcuador,
however, pipeline capacity has presently been available to transport close to
100% of the oil which the Company produces daily. It is not known whether this
availability is temporary and, if permanent, whether it will be adequate to
accommodate expected increased production in mid-1997. Additionally, the
Ecuadorian Government has announced its intention to solicit bids in early
1997 for the construction of a new pipeline system and expects completion of
the pipeline within 18 to 24 months from the date of execution of a contract.
It is unknown what impact, if any, a recent change in the country's political
leadership will have on these plans to solicit such bids.
 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
 
  The information required by this item appears on pages F-1 to F-23 and F-27
to F-70 of this report.
 
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
 
  Inapplicable.
 
                                   PART III
 
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
 
 Executive Officers of the Company
 
  The following table sets forth certain information as of March 1, 1997
concerning the executive officers of the Company.
 
<TABLE>
<CAPTION>
                                                                         SERVED
                                                                          AS AN
                                                                         OFFICER
      NAME                          POSITION WITH THE COMPANY        AGE  SINCE
      ----                          -------------------------        --- -------
   <S>                        <C>                                    <C> <C>
   Roberto Monti............. President and Chief Executive Officer*  58  1995
   W. Mark Miller............ Executive Vice President and Treasurer  43  1995
   Michael C. Forrest........ Senior Vice President                   63  1992
   David A. Wadsworth........ Vice President, Legal                   47  1995
   Linda R. Engelbrecht...... Controller                              41  1995
</TABLE>
 
  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. Certain information regarding the principal
occupations and employment of each of the officers named above during the
prior five years is set forth below.
----------
* YPF, the Company's indirect parent company, has announced that Mr. Monti
 will be presented for election as CEO and executive vice president of YPF as
 of April 30, 1997. Mario B. Rosso is expected to be nominated as president
 and chief executive officer of Maxus effective as of Mr. Monti's assumption
 of such position with YPF, and since February 15, 1997 during Mr. Monti's
 absence, Mr. Rosso acts as chief executive officer. Mr. Rosso, age 55, joined
 the Company as general manager of the Company's Indonesian operations, the
 position he currently holds, on May 1, 1996. Prior to joining the Company,
 Mr. Rosso was Vice President, Worldwide Operations of GeoQuest, an
 exploration and production software products and information technology
 services division of Schlumberger Limited.
 
                                      35
<PAGE>
 
  Mr. Monti was elected President and Chief Executive Officer and a director
of the Company in 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 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 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 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: 69, a director of the Company since 1986. For more
than five years prior to his retirement in 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: 61, a director of the Company since 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: 68, a director of the Company since 1987. Mr. Jackson has
been an oil field service consultant for more than five years.
 
  NELLS LEON: 70, a director of the Company since 1995. Mr. Leon has been a
director of YPF since 1991 and was elected President of YPF in 1995. He has
been associated with YPF since 1990, serving as Executive Vice President. He
was Vice President of Operations of Sol Petroleo S.A. from 1987 to 1990.
 
  JAMES R. LESCH: 75, a director of the Company since 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: 58, a director, President and Chief Executive Officer of the
Company since 1995. Prior to such time, Mr. Monti had been employed since 1963
by Schlumberger Limited, an oil field services company, in
 
                                      36
<PAGE>
 
various capacities. He most recently served as President of Dowell, a division
of Schlumberger Limited. Mr. Monti is an alternate director of YPF.
 
  P. DEXTER PEACOCK: 55, a director of the Company since 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: 40, 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
originally elected to the Board of Directors of Maxus by Prudential pursuant
to the terms of the $9.75 Preferred Stock.
 
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. Under the terms of Mr. Blackburn's consulting agreement with the
Company, he will not be entitled to such compensation paid to other non-
employee Directors for so long as he remains an international consultant to
the Company. 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 1994, 1995 and 1996.
 
                          SUMMARY COMPENSATION TABLE
 
<TABLE>
<CAPTION>
                                                          LONG TERM
                               ANNUAL COMPENSATION       COMPENSATION
                               ----------------------    ------------
                                                          SECURITIES
                                                          UNDERLYING   ALL OTHER
        NAME AND                SALARY        BONUS      OPTIONS/SARS COMPENSATION
     PRINCIPAL POSITION   YEAR    ($)          ($)           (#)          ($)
     ------------------   ---- ----------   ---------    ------------ ------------
<S>                       <C>  <C>          <C>          <C>          <C>
Roberto Monti...........  1996   800,004        1,460       35,477(4)     48,000(1)
 President and Chief Ex-
 ecutive Officer          1995   302,052(2)    30,000(3)         0        10,923(1)
                          1994       N/A          N/A          N/A           N/A
W. Mark Miller..........  1996   180,000       67,250        7,982(4)     87,392(5)
 Executive Vice Presi-
 dent and Treasurer       1995   174,900       60,000            0        87,086(6)
                          1994       N/A          N/A          N/A           N/A
Michael C. Forrest......  1996   175,008       62,713        7,761(4)    192,602(7)
 Senior Vice President    1995   261,016       60,000            0     1,291,032(8)
                          1994   304,020      100,000       65,000        18,241(1)
David A. Wadsworth......  1996   164,448       63,950            0         9,869(1)
 Vice President, Legal    1995   155,640       52,000            0         9,338(1)
                          1994       N/A          N/A          N/A           N/A
Linda R. Engelbrecht....  1996   132,000       51,460            0         7,920(1)
 Controller               1995   119,910       36,000            0         7,195(1)
                          1994       N/A          N/A          N/A           N/A
</TABLE>
 
                                      37
<PAGE>
 
----------
(1) These payments represent the Company's matching contributions to this
    individual's qualified and non-qualified savings plans' accounts.
 
(2) 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.
 
(3) Mr. Monti was paid this amount as a signing bonus upon commencement of his
    employment with the Company.
 
(4) Effective July 1, 1996, Messrs. Monti, Miller and Forrest were granted
    stock appreciation rights ("SARs") pursuant to the Maxus Energy
    Corporation Stock Appreciation Rights Plan (the "Probac") as indicated.
    The securities underlying the SARs granted pursuant to the Probac are
    YPF's Class D shares. Each such SAR represents the right to receive in
    cash on the exercise dates the amount, if any, by which the value of the
    YPF Class D shares on such exercise dates exceeds the "Initial Value"
    thereof as defined in the Probac, not to exceed 100%. The SARs are
    automatically exercised without any action by the holders in equal one-
    thirds on the third, fourth and fifth anniversaries of the grant date of
    such SARs. Under the Probac, holders of SARs do not acquire any right to
    receive YPF Class D shares; SARs are payable in cash only.
 
(5) $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 $10,800 represents the
    Company's matching contribution to Mr. Miller's qualified and non-
    qualified savings plan account.
 
(6) $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 contribution to Mr. Miller's qualified
    and non-qualified savings plan accounts.
 
(7) $182,102 of this amount represents payment in 1996 with respect to the
    surrender in 1995 pursuant to the terms of the Merger Agreement of options
    and SARs held by Mr. Forrest (see "Aggregated Option/SAR Exercises in the
    Last Fiscal Year and FY-End Option/SAR Values") and $10,500 represents the
    Company's matching contributions to Mr. Forrest's qualified and non-
    qualified savings plans' account.
 
(8) $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 SARS held by Mr. Forrest; and $15,661
    of such amount represents the Company's matching contributions to Mr.
    Forrest's qualified and non-qualified savings plan accounts.
 
                                      38
<PAGE>
 
                     OPTION/SAR GRANTS IN LAST FISCAL YEAR
 
<TABLE>
<CAPTION>
                                      INDIVIDUAL GRANTS(1)
                         ----------------------------------------------
                          NUMBER OF   PERCENT OF TOTAL
                          SECURITIES    OPTIONS/SARS
                          UNDERLYING     GRANTED TO                                     GRANT DATE PRESENT
                         OPTIONS/SARS   EMPLOYEES IN   EXERCISE OF BASE                       VALUE
          NAME           GRANTED (#)    FISCAL YEAR      PRICE ($/SH)   EXPIRATION DATE        $(2)
          ----           ------------ ---------------- ---------------- --------------- ------------------
<S>                      <C>          <C>              <C>              <C>             <C>
Roberto Monti...........    35,477          44.8%           $22.55          7/01/01         164,252.87
W. Mark Miller..........     7,982          10.1%           $22.55          7/01/01          36,955.39
Michael C. Forrest......     7,761           9.8%           $22.55          7/01/01          35,932.20
David A. Wadsworth......         0           N/A               N/A              N/A                N/A
Linda R. Engelbrecht....         0           N/A               N/A              N/A                N/A
</TABLE>
----------
(1) Effective July 1, 1996, Messrs. Monti, Miller and Forrest were granted
    SARs pursuant to the Probac. The securities underlying the SARs granted
    pursuant to the Probac are YPF's Class D shares. Each such SAR represents
    the right to receive in cash on the exercise dates the amount, if any, by
    which the value of the YPF Class D shares on such exercise dates exceeds
    the "Initial Value" thereof as defined in the Probac, not to exceed 100%.
    The SARs are automatically exercised without any action by the holders in
    equal one-thirds on the third, fourth and fifth anniversaries of the grant
    date of such SARs. Under the Probac, holders of SARs do not acquire any
    right to receive YPF Class D shares; SARs are payable in cash only.
 
(2) The grant date present value was determined using a variation of the
    Black-Sholes option pricing model. In determining such value, the expected
    volatility of the YPF Class D shares was assumed to be 24%, the risk-free
    rate of return was based on zero-coupon Treasury yields as listed in "The
    Wall Street Journal" on July 1, 1996 for close of trading activity on July
    1, 1996 (range from 6.4% to 6.6%), dividend yield was assumed to be 3.6%,
    and the time of exercise was assumed to be, as to one-third of the SARs
    granted on a particular date, the third, fourth and fifth anniversaries of
    such grant date. No adjustments were made for non-transferability or risk
    of forfeiture.
 
            AGGREGATED OPTION/SAR EXERCISES IN THE LAST FISCAL YEAR
                         AND FY-END OPTION/SAR VALUES
 
<TABLE>
<CAPTION>
                                                       NUMBER OF
                                                      SECURITIES      VALUE OF
                                                      UNDERLYING     UNEXERCISED
                                  SHARES              UNEXERCISED   IN-THE-MONEY
                                 ACQUIRED           OPTIONS/SARS AT OPTIONS/SARS
                                    ON     VALUE      FY-END (#)    AT FY-END ($)
                                 EXERCISE REALIZED   EXERCISABLE/   EXERCISABLE/
              NAME                 (#)      ($)      UNEXERCISABLE  UNEXERCISABLE
              ----               -------- --------  --------------- -------------
<S>                              <C>      <C>       <C>             <C>
Roberto Monti...................     0          0         0/0            0/0
W. Mark Miller..................     0          0         0/0            0/0
Michael C. Forrest..............     0    182,102*        0/0            0/0
David A. Wadsworth..............     0          0         0/0            0/0
Linda R. Engelbrecht............     0          0         0/0            0/0
</TABLE>
----------
* Although Mr. Forrest surrendered all of his options and SARs in 1995,
 payment was not made in 1995 by the Company with respect to a certain number
 of such options and SARs due to then pending tax and other questions. Such
 questions have been resolved and Mr. Forrest received this amount in 1996 for
 his surrendered options and SARs.
 
 
                                      39
<PAGE>
 
EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND CHANGE IN CONTROL
AGREEMENTS
 
  The Company entered into an agreement effective July 1, 1995 in replacement
of a change in control agreement (discussed below under Change in Control
Agreements) 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 from July 1, 1995 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.
 
  In December 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 the Company. 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 1996, Mr. Blackburn
was paid a total of $180,000 under the terms of this contract which expires
April 30, 1997.
 
  Termination of Employment Agreements. In August 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; (iii) 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.
 
  Change in Control Agreements. In 1987 or thereafter, the Company entered
into agreements with certain executive officers including Messrs. Forrest 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.
 
                                      40
<PAGE>
 
  Under these agreements, the executive officer was 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. 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.
 
  In April 1995, all of the Company's then executive officers, including Mr.
Forrest, 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, and the Company paid the prescribed severance amounts. Mr. Forrest
subsequently agreed to continue in the employment of the Company as an "at
will" employee at a reduced salary.
 
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 (the
"SERP") 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 his years of service
through January 31, 1987, plus (ii) 2% of the participant's average monthly
compensation after January 31, 1987 times his 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 his
death with a vested interest under the SERP and that the participant survived
to his 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, 1997 in those cases in which the participant's age on that
date was greater than normal retirement age) under the Company's
 
                                      41
<PAGE>
 
retirement plans as supplemented by the SERP based on service and compensation
through December 31, 1996 for the executive officers named in the compensation
table are as follows: Mr. Monti--$98,668, Mr. Miller--$50,687, Mr. Forrest--
$63,622, Mr. Wadsworth--$56,356 and Mrs. Engelbrecht--$36,956.
 
  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
 
  During 1996, the Compensation Committee of the Board of Directors consisted
of Nells Leon, Cedric Bridger and James R. Lesch.
 
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
 
BENEFICIAL OWNERSHIP OF SECURITIES
 
  The following table sets forth the beneficial ownership (as defined in the
rules of the Securities and Exchange Commission) as of February 1, 1997 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 $2.50
Preferred Stock.
<TABLE>
<CAPTION>
                                                              AMOUNT AND NATURE
                                                                OF SECURITIES
                                                                BENEFICIALLY
NAME OF BENEFICIAL OWNER             TITLE OF SECURITY              OWNED
------------------------             -----------------        -----------------
<S>                                  <C>                      <C>
C. L. Blackburn..................... Common Stock............           0
                                     YPF Class "D"...........           0
Cedric Bridger...................... Common Stock............           0(1)
                                     YPF Class "D"...........       3,942
Linda R. Engelbrecht................ Common Stock............           0
                                     YPF Class "D"...........           0
Michael C. Forrest.................. Common Stock............           0
                                     YPF Class "D"...........       4,000
George L. Jackson................... Common Stock............           0
                                     YPF Class "D"...........           0
Nells Leon.......................... Common Stock............           0(1)
                                     YPF Class "D"...........           0(2)
James R. Lesch...................... Common Stock............           0(1)
                                     YPF Class "D"...........       2,000
W. Mark Miller...................... Common Stock............           0
                                     YPF Class "D"...........           0
Roberto Monti....................... Common Stock............           0(1)
                                     YPF Class "D"...........           0
P. Dexter Peacock................... Common Stock............           0(1)
                                     YPF Class "D"...........           0
David A. Wadsworth.................. Common Stock............           0
                                     YPF Class "D"...........           0
R. A. Walker........................ Common Stock............           0
                                     YPF Class "D"...........           0
Directors and Executive Officers as
 a group............................ Common Stock............           0(1)(3)
                                     YPF Class "D"...........       9,942(2)(3)
</TABLE>
----------
(1) Does not include Common Stock owned by YPF, as to which each of Messrs.
    Bridger, Leon, Lesch, Monti 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) Directors and executive officers as a group owned no Common Stock and less
    than 1% of the YPF Class "D" shares.
 
                                      42
<PAGE>
 
  To the knowledge of the Company, as of February 1, 1997, no person
beneficially owned more than 5% of any class of the Company's voting
securities except as set forth below:
 
<TABLE>
<CAPTION>
                                                        AMOUNT AND
                                                        NATURE OF
                                                          SHARES
                                                       BENEFICIALLY    PERCENT
NAME AND ADDRESS OF BENEFICIAL OWNER    TITLE OF CLASS    OWNED        OF CLASS
------------------------------------    -------------- ------------    --------
<S>                                     <C>            <C>             <C>
YPF Sociedad Anonima...................  Common Stock  147,246,135       100%
 Avenida Pte. Roque
 Saenz Pena 777
 1364 Buenos Aires
 Argentina
Kidder, Peabody Group Inc..............  Common Stock    8,000,000(1)    5.2%
 10 Hanover Square
 New York, New York 10005
</TABLE>
----------
(1) Kidder, Peabody Group Inc. ("Kidder") reported on Schedule 13D dated
    October 10, 1992 that it owns 8,000,000 warrants, each representing the
    right to purchase from the Company at any time prior to 5:00 p.m. on
    October 10, 1997 one share of Common Stock at a price of $13.00 per share.
    The 8,000,000 shares of Common Stock reported as beneficially owned by
    Kidder result from the assumed exercise of all 8,000,000 of such warrants.
    According to said Schedule 13D, General Electric Company is the indirect
    parent of Kidder. The information herein regarding such shares assumes
    that Kidder's beneficial ownership thereof had not changed as of February
    1, 1997 and is included herein in reliance on such filing, 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 filing.
 
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.
 
  On July 1, 1996, Maxus International Energy Company ("Seller"), a wholly
owned subsidiary of Maxus, sold all of the issued and outstanding stock of its
wholly owned subsidiary, YPF International Ltd. ("International"), to YPF, the
indirect parent of YPF Holdings, Inc., the owner of all of the issued and
outstanding capital stock of Maxus. As of September 1, 1996, Seller sold all
of the capital stock of Maxus Guarapiche Ltd., a wholly owned subsidiary of
Maxus, to International. As of August 1, 1996, Maxus transferred certain
liabilities related to environmental matters to Chemical Land Holdings, Inc.
("CLH"), an indirect wholly owned subsidiary of YPF. In connection with the
transfer, CLH assumed (the "Assumption") the liabilities so transferred and
YPF committed to contribute to the capital of CLH up to the amount of $108
million to enable CLH to satisfy its obligations under the Assumption. For a
further discussion of these transactions, see "Item 1. Business and
Properties--General Reorganization." During 1996 and in the ordinary course of
its business, the Company sold electrical generators to YPF for $5.4 million.
 
  During the twelve months ended December 31, 1996, YPF 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 not anticipated that YPF will be required to make
capital contributions to the Company in 1997. However, should such capital
contributions be required during 1997, they will be credited to YPF's
obligations under the Keepwell Covenant and will entitle YPF to shares of
Common Stock. In addition, YPF made capital contributions to CLH in 1996 in
the amount of $8 million to enable CLH to perform its obligations under the
Assumption, and it is anticipated that YPF could be required to make capital
contributions in 1997 to CLH totalling $25 million to $50 million.
 
                                      43
<PAGE>
 
  At December 31, 1996, advances to the Company from YPF were $182 million.
Based on 1997 projections, the Company anticipates that YPF will make cash
advances of approximately $150 to $200 million to the Company during 1997. The
Company and YPF entered into a loan agreement ("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. At December 31, 1996, there were
no loans outstanding under the Loan Agreement. It is expected that loans will
be made by the parties under the Loan Agreement during 1997, 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, the fees for which the Company paid the firm approximately $1.4
million in 1996. It is anticipated that Andrews & Kurth will continue to
provide legal services to the Company during 1997 and that the fees for such
services will be somewhat lower.
 
  During 1996, the Company and YPF entered into a services agreement
("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. During 1996, the Company did not render services to YPF under the
Services Agreement. It is expected that the parties will render services to
each other during 1997. The cost of these services is not presently known, but
it is expected that it will exceed $60,000.
 
  During 1996, 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 1996, the Company paid Prudential approximately $200,000
for these services. The Company and Prudential have agreed that Prudential
will continue to perform such services during 1997 and anticipate that the
fees for the year will be somewhat higher.
 
                                    PART IV
 
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
 
  (a)Documents filed as part of this report:
 
    (1) Financial Statements--The following financial statements appear on
        pages F-1 through F-23 and pages F-25 through F-70 of this report.
 
 
      Consolidated Statement of Operations for the three months ended
      March 31, 1995 and the year ended December 31, 1994.
 
      Consolidatd Balance Sheet at March 31, 1995.
 
      Consolidated Statement of Cash Flows for the three months ended
      March 31, 1995 and the year ended December 31, 1994.
 
      Notes to Consolidated Financial Statements.
 
      Report of Independent Public Accountants--Arthur Andersen LLP.
 
      Report of Independent Public Accountants--Price Waterhouse LLP.
 
      Financial Supplementary Information (unaudited).
 
      Consolidated Statement of Operations for the twelve months ended
      December 31, 1996 and the nine months ended December 31, 1995.
 
      Consolidated Balance Sheet at December 31, 1996 and 1995.
 
      Consolidated Statement of Cash Flows for the twelve months ended
      December 31, 1996 and the nine months ended December 31, 1995.
 
      Notes to Consolidated Financial Statements.
 
      Financial Supplementary Information (unaudited).
 
      Quarterly Data (unaudited).
 
    (2) Financial Statement Schedules.
 
      None
 
 
                                      44
<PAGE>
 
  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 10.23 is a
management contract or compensatory plan, contract or arrangement required to
be filed as an exhibit hereto by Item 14(c) of Form 10-K.
 
     3(i)    --Restated Certificate of Incorporation of the Company, filed
              herewith.
 
     3(ii)   --By-Laws of the Company (Exhibit 3(ii).2 to the Company's
              Quarterly Report on Form 10-Q for the quarter ended September
              30, 1995).*
 
     4.1     --Indenture dated as of April 1, 1978 between Diamond Shamrock
              Corporation ("Diamond") and Mellon Bank, N.A. relating to
              Diamond's $150,000,000 8 1/2% Sinking Fund Debentures due April
              1, 2008 (Exhibit 4.1 to the Company's Annual Report on Form 10-K
              for the year ended December 31, 1992 [the "1992 Form 10-K"]).*
 
     4.2     --First Supplemental Indenture dated as of January 26, 1984 among
              the Company, Diamond Shamrock Chemicals Company ("Chemicals")
              and Mellon Bank, N.A. supplementing the Indenture described in
              Exhibit 4.1 above (Exhibit 4.2 to the 1992 Form 10-K).*
 
     4.3     --Tri Party Agreement dated January 24, 1993 appointing Chemical
              Bank as successor trustee under the Indenture described in
              Exhibit 4.1 above (Exhibit 4.3 to the Company's Current Report
              on Form 8-K dated January 12, 1994 [the "January 12 Form 8-
              K"]).*
 
     4.4     --Indenture dated as of May 1, 1983 between Diamond and The Bank
              of New York, successor in interest to NationsBank of Texas,
              N.A., successor trustee to Mellon Bank, N.A. relating to
              unspecified Debt Securities of Diamond (Exhibit 4.4 to the 1992
              Form 10-K).*
 
     4.5     --Resolutions of the Board of Directors of Diamond supplementing
              the Indenture described in Exhibit 4.4 above and establishing
              terms and conditions of Diamond's $150,000,000 11 1/4% Sinking
              Fund Debentures due May 1, 2013 (Exhibit 4.5 to the 1992 Form
              10-K).*
 
     4.6     --First Supplemental Indenture dated as of January 26, 1984 among
              the Company, Chemicals and Mellon Bank, N.A. supplementing the
              Indenture and the resolutions described in Exhibits 4.4 and 4.5,
              respectively, above (Exhibit 4.6 to the 1992 Form 10-K).*
 
     4.7     --Tri Party Agreement dated January 12, 1994 appointing
              NationsBank of Texas, N.A. as successor trustee under the
              Indenture described in Exhibit 4.4 above (Exhibit 4.1 to the
              January 12 Form 8-K).*
 
     4.8     --Indenture dated as of November 1, 1985 between the Company and
              The Bank of New York, successor in interest to NationsBank of
              Texas, N.A., successor trustee to Mellon Bank, N.A. relating to
              unspecified Debt Securities of the Company (Exhibit 4.8 to the
              1992 Form 10-K).*
 
     4.9     --Resolutions of an ad hoc committee of the Board of Directors of
              the Company supplementing the Indenture described in Exhibit 4.8
              above and establishing terms and conditions of the Company's
              $150,000,000 11 1/2% Sinking Fund Debentures due November 15,
              2015 (Exhibit 4.9 to the 1992 Form 10-K).*
 
     4.10
             --Tri Party Agreement dated January 12, 1994 appointing
              NationsBank of Texas, N.A. as successor trustee under the
              Indenture described in Exhibit 4.8 above (Exhibit 4.2 to the
              January 12 Form 8-K).*
 
                                      45
<PAGE>
 
     4.11    --Indenture dated as of April 1, 1988 between the Company and
              Chemical Bank relating to unspecified debt securities of the
              Company (Exhibit 4.11 to the 1992 Form 10-K).*
 
     4.12    --Officers' Certificate dated June 1, 1988 establishing a series
              of debt securities ($150,000,000 Medium-Term Notes, Series A) to
              be issued under the Indenture described in Exhibit 4.11 above
              (Exhibit 4.12 to the 1992 Form 10-K).*
 
     4.13    --Indenture dated as of November 1, 1990 between the Company and
              Chemical Bank relating to unspecified debt securities of the
              Company (Exhibit 4.13 to the 1992 Form 10-K).*
 
     4.14    --Officers' Certificate dated February 13, 1991 establishing a
              series of debt securities ($150,000,000 Medium-Term Notes,
              Series B) to be issued under the Indenture described in Exhibit
              4.13 above (Exhibit 4.14 to the 1992 Form 10-K).*
 
     4.15    --Officers' Certificate dated September 28, 1992 establishing a
              series of debt securities ($250,000,000 9% Notes Due 2002) to be
              issued under the Indenture described in Exhibit 4.13 above
              (Exhibit 4.15 to the 1992 Form 10-K).*
 
     4.16    --Officers' Certificate dated January 26, 1993 establishing a
              series of debt securities ($100,000,000 9 1/2% Notes Due 2003)
              to be issued under the Indenture described in Exhibit 4.13 above
              (Exhibit 4.16 to the 1992 Form 10-K).*
 
     4.17    --Officer's Certificate dated June 30, 1993 establishing a series
              of debt securities ($150,000,000 Medium-Term Notes, Series C) to
              be issued under the Indenture described in Exhibit 4.13 above
              (Exhibit 4 to the Company's Current Report on Form 8-K dated
              June 21, 1993).*
 
     4.18    --Officer's Certificate dated October 27, 1993 establishing a
              series of debt securities ($200,000,000 9 3/8% Notes due 2003)
              to be issued under the Indenture described in Exhibit 4.13 above
              (Exhibit 4 to the Company's current Report on Form 8-K dated
              October 20, 1993).*
 
     4.19    --Officer's Certificate dated January 18, 1994 establishing a
              series of debt securities ($60,000,000 9 3/8% Notes due 2003) to
              be issued under the Indenture described in Exhibit 4.13 (Exhibit
              4 to the Company's Current Report on Form 8-K dated January 10,
              1994).*
 
     4.20    --Warrant Certificate No. 1 dated October 10, 1992 issued to
              Kidder, Peabody Group Inc. for 8,000,000 warrants each
              representing the right to purchase from the Company on or prior
              to October 10, 1997 one share of common stock, $1.00 par value,
              of the Company at a price of $13.00 per share (Exhibit 4.23 to
              the 1992 Form 10-K).*
 
     4.21    --Registration Rights Agreement dated as of October 10, 1992
              between Kidder, Peabody Group Inc. and the Company (Exhibit 4.24
              to the 1992 Form 10-K).*
 
     4.22    --Agreement of Merger, dated February 28, 1995, among the
              Company, YPF Sociedad Anonima ("YPF") and YPF Acquisition Corp.
              ("YPFA") (Exhibit 3 to the Company's Schedule 14D-9 dated March
              3, 1995 [the "Schedule 14D-9"]).*
 
     4.23    --Credit Agreement dated as of June 8, 1995, between Midgard
              Energy Company, the lenders signatory thereto and The Chase
              Manhattan Bank (National Association) ("Chase"), as agent
              (Exhibit 4.1 to the Company's Current Report on Form 8-K dated
              June 8, 1995 [the "June 8, 1995 Form 8-K"]).*
 
     4.24    --Assumption Agreement dated August 14, 1996 between the Company
              and Chemical Land Holdings, Inc., filed herewith.
 
    10.1
             --Performance Incentive Plan of the Company, as amended effective
              January 1, 1986 (Exhibit 10.6 to the 1992 Form 10-K).*
 
    10.2
             --Specimen copy of Change of Control Agreement between the
              Company and certain of its former executive officers (Exhibit
              10.7 to the 1992 Form 10-K).*
 
                                      46
<PAGE>
 
    10.3     --Specimen copy of letter agreement between the Company and
              certain of its former executive officers relating to the
              Agreements referred to in Exhibit 10.2 above (Exhibit 10.8 to
              the 1992 Form 10-K).*
 
    10.4     --Specimen copy of disability benefit arrangement between the
              Company and its executive officers (Exhibit 10.10 to the 1992
              Form 10-K).*
 
    10.5     --Supplemental Executive Retirement Plan of the Company,
              effective May 1, 1987 (Exhibit 10.11 to the 1992 Form 10-K).*
 
    10.6     --Supplemental Executive Retirement Plan of the Company,
              effective March 1, 1990 (Exhibit 10.12 to the 1992 Form 10-K).*
 
    10.7     --Specimen copy of supplemental death benefit arrangement between
              the Company and its executive officers (Exhibit 10.13 to the
              1992 Form 10-K).*
 
    10.8     --Maxus Energy Corporation Supplemental Savings Plan (as amended
              and restated effective June 8, 1995) (Exhibit 10.8 to the
              Company's Annual Report on Form 10-K for the year ended December
              31, 1995 [the "1995 Form 10-K"]).*
 
    10.9     --Trust Agreement dated December 18, 1986 between the Company and
              AmeriTrust Company National Association (Exhibit 10.15 to the
              1992 Form 10-K).*
 
    10.10    --Deferred Compensation Plan for Executives of the Company,
              effective September 28, 1993 (Exhibit 10.17 to the Company's
              Annual Report on Form 10-K for the year ended December 31,
              1993).*
 
    10.11    --Distribution Agreement dated as of April 22, 1987 between the
              Company and Diamond Shamrock R&M, Inc. (Exhibit 10.23 to the
              1992 Form 10-K).*
 
    10.12    --Stock Purchase Agreement by and among the Company and
              Occidental Petroleum Corporation, et. al. dated September 4,
              1986 (Exhibit 10.25 to the 1992 Form 10-K).*
 
    10.13    --Agreement of Merger dated as of February 28, 1995 among YPF,
              YPFA and the Company (Exhibit 3 to the Schedule 14D-9).*
 
    10.14    --International Consulting Agreement, dated May 1, 1995 between
              C. L. Blackburn and YPF (Exhibit 10.15 to the 1995 Form 10-K).*
 
    10.15    --Assignment of International Consulting Agreement, dated
              November 2, 1995 between C. L. Blackburn, YPF, and the Company
              (Exhibit 10.16 to the 1995 Form 10-K).*
 
    10.16    --Maxus Severance Agreement dated August 3, 1995 between the
              Company and Roberto Luis Monti (Exhibit 10.17 to the 1995 Form
              10-K).*
 
    10.17    --Compensation Agreement dated December 27, 1995 between the
              Company and Roberto L. Monti (Exhibit 10.18 to the 1995 Form 10-
              K).*
 
    10.18    --Amendment to Change in Control Agreement dated May 11, 1995
              between the Company and W. Mark Miller (Exhibit 10.21 to the
              1995 Form 10-K).*
 
    10.19    --Employment Agreement effective as of July 1, 1995 between the
              Company and W. Mark Miller (Exhibit 10.22 to the 1995 From 10-
              K).*
 
    10.20    --Specimen copy of a letter agreement regarding Change in Control
              Agreement dated April 7, 1995 between the Company and certain of
              its executive officers (Exhibit 10.23 to the 1995 Form 10-K).*
 
    10.21
             --Letter Agreement regarding Change in Control Agreement dated
              April 13, 1995 between the Company and Michael C. Forrest
              (Exhibit 10.24 to the 1995 Form 10-K).*
 
    10.22
             --Specimen copy of a letter agreement regarding Change in Control
              Agreement dated April 13, 1995 between the Company and certain
              of its executive officers (Exhibit 10.26 to the 1995 Form 10-
              K).*
 
                                      47
<PAGE>
 
    10.23    --Maxus Energy Corporation Stock Appreciation Rights Plan dated
              August 30, 1996, filed herewith.
 
    21.1     --List of Subsidiaries of the Company, filed herewith.
 
    23.1     --Consent of Independent Accountants, filed herewith.
 
    23.2     --Consent of Independent Accountants, filed herewith.
 
    24.1     --Powers of Attorney of directors and officers of the Company,
              filed herewith.
 
    24.2     --Power of Attorney of the Company, filed herewith.
 
    27.1     --Financial Data Schedule, filed herewith.
 
  (b)Reports on Form 8-K.
 
    None.
 
                                      48
<PAGE>
 
                                  SIGNATURES
 
  PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
 
                                          Maxus Energy Corporation
 
                                                      Roberto Monti*
                                          By __________________________________
                                                       Roberto Monti
                                                       President and
                                                  Chief Executive Officer
 
March 20, 1997
 
  PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATE INDICATED.
 
                SIGNATURE                                  TITLE
 
              Roberto Monti*                President and Chief Executive
------------------------------------------   Officer and Director
              Roberto Monti
 
             W. Mark Miller*                Executive Vice President and
------------------------------------------   Treasurer (principal financial
              W. Mark Miller                 officer)
 
          Linda R. Engelbrecht*             Controller (principal accounting
------------------------------------------  officer)
           Linda R. Engelbrecht
 
          Charles L. Blackburn*             Director
------------------------------------------
           Charles L. Blackburn
 
             Cedric Bridger*                Director
------------------------------------------
              Cedric Bridger
 
            George L. Jackson*              Director
------------------------------------------
            George L. Jackson
 
               Nells Leon*                  Director
------------------------------------------
                Nells Leon
 
             James R. Lesch*                Director
------------------------------------------
              James R. Lesch
 
            P. Dexter Peacock*              Director
------------------------------------------
            P. Dexter Peacock
 
              R. A. Walker*                 Director
------------------------------------------
               R. A. Walker
 
  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.
 
            /s/ Lynne P. Ciuba              March 20, 1997
 
*By ______________________________________
              Lynne P. Ciuba
             Attorney-in-fact
 
                                      49
<PAGE>
 
                            MAXUS ENERGY CORPORATION
 
                      CONSOLIDATED STATEMENT OF OPERATIONS
 
<TABLE>
<CAPTION>
                                                          THREE
                                                       MONTHS ENDED  YEAR ENDED
                                                        MARCH 31,   DECEMBER 31,
                                                           1995         1994
                                                       ------------ ------------
                                                       (IN MILLIONS, EXCEPT PER
                                                                SHARE)
<S>                                                    <C>          <C>
Revenues
  Sales and operating revenues........................    $142.5      $ 682.1
  Other revenues, net.................................       9.6          9.0
                                                          ------      -------
                                                           152.1        691.1
Costs and Expenses
  Operating expenses..................................      64.6        242.8
  Gas purchase costs..................................      12.7        116.9
  Exploration, including exploratory dry holes........       8.9         35.5
  Depreciation, depletion and amortization............      29.9        140.2
  General and administrative expenses.................       4.2         22.4
  Taxes other than income taxes.......................       3.1         12.9
  Interest and debt expenses..........................      24.1         96.7
  Pre-merger costs....................................      42.4
  Environmental studies and remediation...............                   60.5
  Restructuring:
    Gain on sale of assets............................                 (201.9)
    Restructuring costs...............................                  100.9
                                                          ------      -------
                                                           189.9        626.9
                                                          ------      -------
Income (Loss) Before Income Taxes.....................     (37.8)        64.2
  Income Taxes........................................      19.1         86.9
                                                          ------      -------
Net Loss..............................................     (56.9)       (22.7)
  Dividend requirement on Preferred Stock.............      (9.6)       (43.6)
                                                          ------      -------
Net Loss Applicable to Common Shares..................    $(66.5)     $ (66.3)
                                                          ======      =======
Net Loss Per Common Share.............................    $ (.49)     $  (.49)
                                                          ======      =======
Average Common Shares Outstanding.....................     135.5        134.7
</TABLE>
 
 
                See Notes to Consolidated Financial Statements.
 
                                      F-1
<PAGE>
 
                            MAXUS ENERGY CORPORATION
 
                           CONSOLIDATED BALANCE SHEET
 
<TABLE>
<CAPTION>
                                                                   MARCH 31,
                             ASSETS                                   1995
                             ------                              --------------
                                                                 (IN MILLIONS,
                                                                 EXCEPT SHARES)
<S>                                                              <C>
Current Assets
  Cash and cash equivalents.....................................   $    91.6
  Short-term investments........................................        65.0
  Receivables, less allowance for doubtful accounts.............       127.8
  Taxes receivable..............................................        13.7
  Inventories...................................................        28.6
  Restricted cash...............................................        48.5
  Prepaids and other current assets.............................        19.4
                                                                   ---------
    Total Current Assets........................................       394.6
Properties and Equipment, less accumulated depreciation, deple-
 tion and amortization..........................................     1,110.7
Investments and Long-Term Receivables...........................        41.5
Restricted Cash.................................................        79.9
Intangible Assets, less accumulated amortization................        35.5
Deferred Income Taxes...........................................         9.4
Deferred Charges................................................        20.5
                                                                   ---------
                                                                   $ 1,692.1
                                                                   =========
<CAPTION>
              LIABILITIES AND STOCKHOLDERS' EQUITY
              ------------------------------------
<S>                                                              <C>
Current Liabilities
  Long-term debt................................................   $     4.7
  Accounts payable..............................................        49.8
  Accrued liabilities...........................................       169.8
                                                                   ---------
    Total Current Liabilities...................................       224.3
Long-Term Debt..................................................       970.9
Deferred Income Taxes...........................................       199.7
Other Liabilities and Deferred Credits..........................       158.7
$9.75 Redeemable Preferred Stock, $1.00 par value
 Authorized and issued shares--1,250,000........................       125.0
Stockholders' Equity
  $2.50 Preferred Stock, $1.00 par value
   Authorized shares--5,000,000
   Issued shares--3,500,000.....................................         3.5
  $4.00 Preferred Stock, $1.00 par value
   Authorized shares--5,915,017
   Issued shares--4,356,958.....................................         4.4
  Common Stock, $1.00 par value
   Authorized shares--300,000,000
   Issued shares--135,897,899...................................       135.9
  Paid-in capital...............................................       966.2
  Accumulated deficit...........................................    (1,073.3)
  Minimum pension liability.....................................       (18.3)
  Unrealized loss on marketable securities......................        (1.3)
  Common Treasury Stock, at cost--310,535.......................        (3.6)
                                                                   ---------
    Total Stockholders' Equity..................................        13.5
                                                                   ---------
                                                                   $ 1,692.1
                                                                   =========
</TABLE>
                      See "Commitments and Contingencies."
                See Notes to Consolidated Financial Statements.
 The Company uses the successful efforts method to account for its oil and gas
                             producing activities.
 
                                      F-2
<PAGE>
 
                            MAXUS ENERGY CORPORATION
 
                      CONSOLIDATED STATEMENT OF CASH FLOWS
 
<TABLE>
<CAPTION>
                                                     THREE MONTHS TWELVE MONTHS
                                                        ENDED         ENDED
                                                      MARCH 31,   DECEMBER 31,
                                                         1995         1994
                                                     ------------ -------------
                                                           (IN MILLIONS)
<S>                                                  <C>          <C>
Cash Flows From Operating Activities:
  Net loss..........................................    $(56.9)      $ (22.7)
  Adjustments to reconcile net loss to net cash
   provided by operating activities:
    Depreciation, depletion and amortization........      29.9         140.2
    Dry hole costs..................................       1.0           2.8
    Deferred income taxes...........................       0.4          (9.3)
    Net gain on sale of assets and investments......      (1.7)       (166.7)
    Postretirement benefits.........................       1.4           6.2
    Pre-merger costs................................      42.4
    Restructuring costs.............................                    91.0
    Environmental studies and remediation...........                    60.5
    Other...........................................       1.3           9.2
    Changes in components of working capital:
      Receivables...................................      23.8          (1.8)
      Inventories, prepaids and other current
       assets.......................................      (1.4)         (2.3)
      Accounts payable..............................     (15.1)        (22.3)
      Accrued liabilities...........................      26.3         (12.5)
      Taxes payable/receivable......................      10.1          (2.8)
                                                        ------       -------
        Net Cash Provided by Operating Activities...      61.5          69.5
                                                        ------       -------
Cash Flows From Investing Activities:
  Expenditures for properties and equipment--
   including dry hole costs.........................     (53.6)       (166.2)
  Expenditures for investments......................                   (20.1)
  Proceeds from sales of assets.....................       2.1         377.0
  Proceeds from sale/maturity of short-term
   investments......................................      63.4          10.9
  Purchases of short-term investments...............     (24.6)       (111.8)
  Restricted cash...................................      12.2          19.6
  Other.............................................       9.8         (10.8)
                                                        ------       -------
        Net Cash Provided by Investing Activities...       9.3          98.6
                                                        ------       -------
Cash Flows From Financing Activities:
  Net borrowings from joint venture partners........                    (4.4)
  Interest rate swap................................       3.4          (7.9)
  Proceeds from issuance of short-term debt.........                    30.0
  Repayment of short-term debt......................                   (69.1)
  Proceeds from issuance of long-term debt..........                   101.3
  Repayment of long-term debt.......................                  (137.5)
  Stock rights redemption...........................     (13.6)
  Redemption of Preferred Stock.....................                  (125.0)
  Dividends paid on Preferred Stock.................      (9.6)        (43.6)
                                                        ------       -------
        Net Cash Used in Financing Activities.......     (19.8)       (256.2)
                                                        ------       -------
Net Increase (Decrease) in Cash and Cash
 Equivalents........................................      51.0         (88.1)
Cash and Cash Equivalents at Beginning of Year......      40.6         128.7
                                                        ------       -------
Cash and Cash Equivalents at End of Year............    $ 91.6       $  40.6
                                                        ======       =======
</TABLE>
 
                See Notes to Consolidated Financial Statements.
 
                                      F-3
<PAGE>
 
                           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 year ended December 31, 1994 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 year ended December 31, 1994 are
presented separately as pre-Merger and post-Merger financial information are
not comparable.
 
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. 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:
 
<TABLE>
<CAPTION>
                                                      THREE MONTHS TWELVE MONTHS
                                                         ENDED         ENDED
                                                       MARCH 31,   DECEMBER 31,
                                                          1995         1994
                                                      ------------ -------------
     <S>                                              <C>          <C>
     Interest receipts...............................    $ 7.0         $12.4
     Interest payments...............................     12.2          98.7
     Income tax payments.............................     18.6          98.1
</TABLE>
 
 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.
 
                                      F-4
<PAGE>
 
                           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. 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.
 
 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.
 
                                      F-5
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
 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 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.
 
                                      F-6
<PAGE>
 
                           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,
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
 
  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. 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.
 
 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--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.
 
                                      F-7
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
NOTE THREE--RESTRUCTURING
 
 Asset Sales
 
  On April 25, 1994, Diamond Shamrock Offshore Partners Limited Partnership
("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. 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 the time of the sale.
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 did 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.
 
NOTE FOUR--ASSET 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.
 
  During the second quarter of 1994, Maxus Venezuela (C.I.) Ltd., a subsidiary
of Maxus, signed an agreement with BP Exploration 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 FIVE--GEOGRAPHIC DATA
 
  The Company is engaged primarily in the exploration for and the production
and sale of crude oil and natural gas.
 
  Sales, operating profit and identifiable assets by geographic area were as
follows:
 
<TABLE>
<CAPTION>
                                                    SALES AND OPERATING REVENUES
                                                    ----------------------------
                                                     THREE MONTHS    YEAR ENDED
                                                    ENDED MARCH 31, DECEMBER 31,
                                                         1995           1994
                                                    --------------- ------------
     <S>                                            <C>             <C>
     United States.................................     $ 41.6         $276.9
     Indonesia.....................................       93.1          381.2
     South America.................................        7.8           24.0
                                                        ------         ------
                                                        $142.5         $682.1
                                                        ======         ======
</TABLE>
 
                                      F-8
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
<TABLE>
<CAPTION>
                                                      OPERATING PROFIT (LOSS)
                                                    ----------------------------
                                                     THREE MONTHS    YEAR ENDED
                                                    ENDED MARCH 31, DECEMBER 31,
                                                         1995           1994
                                                    --------------- ------------
     <S>                                            <C>             <C>
     United States.................................     $  2.9        $  35.0
     Indonesia.....................................       36.8          138.5
     South America.................................       (3.7)          (2.6)
     Other foreign.................................       (1.7)         (11.6)
                                                        ------        -------
                                                          34.3          159.3
     Equity earnings...............................                       5.2
     General corporate expenses....................       (5.6)        (104.6)
     Interest and debt expenses....................      (24.1)         (96.7)
     Pre-merger costs..............................      (42.4)
     Restructuring costs...........................                     101.0
                                                        ------        -------
                                                        $(37.8)       $  64.2
                                                        ======        =======
</TABLE>
 
<TABLE>
<CAPTION>
                                                           IDENTIFIABLE ASSETS
                                                          ----------------------
                                                          MARCH 31, DECEMBER 31,
                                                            1995        1994
                                                          --------- ------------
     <S>                                                  <C>       <C>
     United States....................................... $  295.7    $  327.0
     Indonesia...........................................    639.0       647.5
     South America.......................................    317.2       304.2
     Other foreign.......................................     15.3        11.4
                                                          --------    --------
                                                           1,267.2     1,290.1
     Corporate assets....................................    424.9       416.6
                                                          --------    --------
                                                          $1,692.1    $1,706.7
                                                          ========    ========
</TABLE>
 
  Net foreign assets were $685.5 million at March 31, 1995 and $701.4 million
at December 31, 1994.
 
  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 for
the year ended December 31, 1994.
 
  Sales to three customers for the three months ended March 31, 1995 and the
year ended December 31, 1994 each represented 10% or more of consolidated
sales:
 
<TABLE>
<CAPTION>
                                                      THREE MONTHS TWELVE MONTHS
                                                         ENDED         ENDED
                                                       MARCH 31,   DECEMBER 31,
                                                          1995         1994
                                                      ------------ -------------
     <S>                                              <C>          <C>
     Phillips Petroleum Company......................    $14.3        $ 56.4
     Mitsubishi Corporation..........................     23.4          66.5
     Indonesian Government...........................     36.4         145.8
</TABLE>
 
  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
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.
 
                                      F-9
<PAGE>
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
NOTE SIX--TAXES
 
Income before income taxes was comprised of income (loss) from:
 
<TABLE>
<CAPTION>
                                                     THREE MONTHS    YEAR ENDED
                                                    ENDED MARCH 31, DECEMBER 31,
                                                         1995           1994
                                                    --------------- ------------
     <S>                                            <C>             <C>
     United States.................................     $(69.2)        $(60.1)
     Foreign.......................................       31.4          124.3
                                                        ------         ------
                                                        $(37.8)        $ 64.2
                                                        ======         ======
</TABLE>
 
  The Company's provision for income taxes was comprised of the following:
 
<TABLE>
<CAPTION>
                                                     THREE MONTHS    YEAR ENDED
                                                    ENDED MARCH 31, DECEMBER 31,
                                                         1995           1994
                                                    --------------- ------------
     <S>                                            <C>             <C>
     Current
       Federal.....................................                    $(20.1)
       Foreign.....................................      $18.7           73.7
       State and local.............................                       5.5
                                                         -----         ------
                                                          18.7           59.1
     Deferred
       Federal.....................................                      24.7
       Foreign.....................................         .4            3.1
                                                         -----         ------
                                                            .4           27.8
                                                         -----         ------
     Provision for income taxes....................      $19.1         $ 86.9
                                                         =====         ======
</TABLE>
 
  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:
 
<TABLE>
<CAPTION>
                                                    THREE MONTHS    YEAR ENDED
                                                   ENDED MARCH 31, DECEMBER 31,
                                                        1995           1994
                                                   --------------- ------------
     <S>                                           <C>             <C>
     Tax expense at statutory federal rate........     $(13.2)        $ 22.5
     Increase (reduction) resulting from:
       Taxes on foreign income....................       12.4           49.5
       Excess statutory depletion.................                       (.7)
       Asset sales................................                      20.5
       Alternative minimum tax....................                       (.3)
       Nondeductible pre-Merger costs.............        4.4
       Valuation allowance........................       13.9           24.9
       Items not related to current year earn-
        ings......................................        1.5          (33.4)
       Other, net.................................         .1            3.9
                                                       ------         ------
       Provision for income taxes.................     $ 19.1         $ 86.9
                                                       ======         ======
</TABLE>
 
  "Items not related to current year earnings" in 1994 includes a tax benefit
from the favorable resolution of a federal tax refund suit.
 
                                      F-10
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
  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 were as follows:
 
<TABLE>
<CAPTION>
                                                                       MARCH 31,
                                                                         1995
                                                                       ---------
     <S>                                                               <C>
     U. S. deferred tax liabilities
       Properties and equipment.......................................  $   5.1
       Other..........................................................       .2
                                                                        -------
         Deferred U. S. tax liabilities...............................      5.3
                                                                        -------
     U. S. deferred tax assets
       Foreign deferred taxes.........................................    (69.9)
       Book accruals..................................................    (34.4)
       Loss carryforwards.............................................    (50.8)
       Credit carryforwards...........................................    (23.2)
       Other..........................................................      (.6)
                                                                        -------
         Gross deferred U. S. tax assets..............................   (178.9)
                                                                        -------
     Valuation allowance..............................................    163.9
                                                                        -------
     Net deferred U. S. tax assets....................................    (15.0)
                                                                        -------
     Net deferred U. S. taxes.........................................     (9.7)
                                                                        -------
     Foreign deferred tax liabilities
       Properties and equipment.......................................    199.7
                                                                        -------
         Net deferred foreign taxes...................................    199.7
                                                                        -------
     Net deferred taxes...............................................  $ 190.0
                                                                        =======
</TABLE>
 
  The valuation allowance was $116.0 million at December 31, 1994. The
valuation allowance was increased $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:
 
<TABLE>
<CAPTION>
                                                     THREE MONTHS    YEAR ENDED
                                                    ENDED MARCH 31, DECEMBER 31,
                                                         1995           1994
                                                    --------------- ------------
     <S>                                            <C>             <C>
     Gross production..............................      $1.2          $ 6.5
     Real and personal property....................       1.8            5.5
     Other.........................................        .1             .9
                                                         ----          -----
                                                         $3.1          $12.9
                                                         ====          =====
</TABLE>
 
                                     F-11
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
NOTE SEVEN--POSTEMPLOYMENT BENEFITS
 
 Pensions
 
  The components of net periodic pension expense are as follows:
 
<TABLE>
<CAPTION>
                                                   THREE MONTHS    YEAR ENDED
                                                  ENDED MARCH 31, DECEMBER 31,
                                                       1995           1994
                                                  --------------- ------------
     <S>                                          <C>             <C>
     Service cost for benefits earned during the
      period.....................................      $  .5         $ 2.9
     Interest cost on projected benefit obliga-
      tion.......................................        2.2           8.7
     Actual return on plan assets................       (4.5)         (2.5)
     Net amortization and deferrals..............        2.5          (5.4)
                                                       -----         -----
                                                       $  .7         $ 3.7
                                                       =====         =====
</TABLE>
 
  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.
 
  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:
 
<TABLE>
     <S>                                                                    <C>
     Discount rate......................................................... 8.5%
     Expected long-term rate of return on plan assets...................... 9.0%
     Rate of increase in compensation levels............................... 5.5%
</TABLE>
 
  The funded status of the plans at March 31, 1995 was as follows:
 
<TABLE>
<CAPTION>
                                                              PLANS WITH
                                                        -----------------------
                                                        ACCUMULATED   ASSETS
                                                         BENEFITS    EXCEEDING
                                                         EXCEEDING  ACCUMULATED
                                                          ASSETS     BENEFITS
                                                          3/31/95     3/31/95
                                                        ----------- -----------
     <S>                                                <C>         <C>
     Actuarial present value of:
       Vested benefit obligation.......................   $ 86.3       $ 9.8
                                                          ------       -----
       Accumulated benefit obligation..................   $ 90.6       $11.9
                                                          ------       -----
       Projected benefit obligation....................   $ 91.4       $15.0
     Plan assets at fair value.........................     76.2        14.5
                                                          ------       -----
     Plan assets less than projected benefit obliga-
      tion.............................................   $(15.2)      $ (.5)
     Unrecognized net loss.............................     24.1         1.0
     Unrecognized net transition obligation (asset)....     (3.8)         .1
     Unrecognized prior service cost...................      (.3)        (.9)
     Adjustment required to recognize minimum liabili-
      ty...............................................    (18.3)
                                                          ------       -----
     Prepaid (accrued) pension cost....................   $(13.5)      $ (.3)
                                                          ======       =====
</TABLE>
 
  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.
 
                                     F-12
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
  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
 
  The Company reports its obligation for postretirement benefits other than
pensions in accordance with 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 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 requirements.
 
  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
Three), 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 year ended December 31, 1994 are as
follows:
 
<TABLE>
<CAPTION>
                                                    THREE MONTHS    YEAR ENDED
                                                   ENDED MARCH 31, DECEMBER 31,
                                                        1995           1994
                                                   --------------- ------------
     <S>                                           <C>             <C>
     Service cost for benefits earned during the
      period......................................      $ .1           $ .5
     Interest cost on accumulated postretirement
      benefit obligation..........................        .9            3.4
     Amortization of transition obligation........        .5            2.3
                                                        ----           ----
                                                        $1.5           $6.2
                                                        ====           ====
</TABLE>
 
  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 is as follows:
 
<TABLE>
<CAPTION>
                                                                  MARCH 31, 1995
                                                                  --------------
     <S>                                                          <C>
     Retirees....................................................     $ 39.0
     Fully eligible active employees.............................        1.8
     Other active employees......................................        3.6
                                                                      ------
       Total.....................................................       44.4
     Unrecognized transition obligation..........................      (33.7)
     Unrecognized net gain.......................................        2.1
                                                                      ------
                                                                      $ 12.8
                                                                      ======
</TABLE>
 
  A discount rate of 8.5% was used in determining the APBO for the three
months ended March 31, 1995. 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
 
                                     F-13
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
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
 
  The Company reports its obligation for postemployment benefits in accordance
with 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. This
liability primarily represents medical benefits for long-term disability
recipients. Annual costs are expected to be immaterial. Net periodic
postemployment benefit expense was insignificant for the three months ended
March 31, 1995 and for the year ended December 31, 1994.
 
NOTE EIGHT--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:
 
<TABLE>
<CAPTION>
                                                                MARCH 31, 1995
                                                               -----------------
                                                                          FAIR
                                                               CARRYING VALUE OF
                                                                AMOUNT   ASSETS
                                                               -------- --------
<S>                                                            <C>      <C>
ASSETS
  Restricted cash, including current and long-term portion....  $128.4   $125.6
  Long-term investments.......................................    41.5     36.7
LIABILITIES
  Long-term debt, including current portion...................   975.6    862.4
</TABLE>
 
  For information on the Company's derivative financial instruments, see Note
Sixteen.
 
                                     F-14
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
NOTE NINE--RECEIVABLES
 
<TABLE>
<CAPTION>
                                                                  MARCH 31, 1995
                                                                  --------------
     <S>                                                          <C>
     Trade receivables...........................................     $ 97.0
     Notes and other receivables.................................       32.0
     Less--Allowance for doubtful receivables....................        1.2
                                                                      ------
                                                                      $127.8
                                                                      ======
</TABLE>
 
NOTE TEN--PROPERTIES AND EQUIPMENT
 
<TABLE>
<CAPTION>
                                                                 MARCH 31, 1995
                                                                 --------------
     <S>                                                         <C>
     Proved properties..........................................    $2,445.5
     Unproved properties........................................        31.7
     Gas plants and other.......................................       220.0
                                                                    --------
       Total Oil and Gas........................................     2,697.2
                                                                    --------
     Corporate..................................................        51.5
                                                                     2,748.7
     Less--Accumulated depreciation, depletion and amortiza-
      tion......................................................     1,638.0
                                                                    --------
                                                                    $1,110.7
                                                                    ========
</TABLE>
 
  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 for the year ended December 31, 1994. The charge
against earnings for maintenance and repairs was $7.4 million for the three
months ended March 31, 1995, and $38.9 million for the year ended December 31,
1994.
 
NOTE ELEVEN--INVESTMENTS AND LONG-TERM RECEIVABLES
 
<TABLE>
<CAPTION>
                                                                  MARCH 31, 1995
                                                                  --------------
     <S>                                                          <C>
     Investments, at cost, and long-term receivables.............     $12.0
     U. S. Treasury notes........................................      29.5
                                                                      -----
                                                                      $41.5
                                                                      =====
</TABLE>
 
  In September 1994, the Company sold its geothermal subsidiary, Thermal Power
Company, which owned Union-Magma-Thermal Tax Partnership ("UMT") (See Note
Four). 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:
 
<TABLE>
<CAPTION>
                                                               DECEMBER 31, 1994
                                                               -----------------
     <S>                                                       <C>
     Summarized Statement of Income:
       Sales..................................................       $50.0
       Gross profit...........................................        24.8
       Net income.............................................        24.8
</TABLE>
 
  The Company's equity earnings are principally from UMT and were $5.2 million
in 1994.
 
                                     F-15
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
NOTE TWELVE--RESTRICTED CASH
 
  At March 31, 1995, the Company had $128.4 million in restricted cash, of
which $64.0 million represented collateral for outstanding letters of credit.
Assets held in trust as required by certain insurance policies were $64.4
million in 1995. Approximately $48.5 million of collateral for outstanding
letters of credit at March 31, 1995 was classified as a current asset.
 
NOTE THIRTEEN--INTANGIBLE ASSETS
 
  Intangibles, primarily the excess of cost over fair market value of net
assets acquired, were $50.0 million at March 31, 1995. Accumulated
amortization at March 31, 1995 was $14.5 million. 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 year ended December 31, 1994.
 
NOTE FOURTEEN--ACCRUED LIABILITIES
 
<TABLE>
<CAPTION>
                                                                  MARCH 31, 1995
                                                                  --------------
     <S>                                                          <C>
     Accrued interest payable....................................     $ 34.8
     Joint interest billings for international operations........       32.3
     Merger reserve..............................................       41.0
     Environmental reserve.......................................       14.9
     Overlift payable............................................       12.2
     Postretirement and postemployment benefits..................        4.5
     Accrued compensation, benefits and withholdings.............        5.0
     Other.......................................................       25.1
                                                                      ------
                                                                      $169.8
                                                                      ======
</TABLE>
 
NOTE FIFTEEN--LONG-TERM AND CREDIT ARRANGEMENTS
 
<TABLE>
<CAPTION>
                                                                  MARCH 31, 1995
                                                                  --------------
     <S>                                                          <C>
     Senior Indebtedness
      Sinking Fund Debentures
       11 1/4% due 2013..........................................     $ 16.9
       11 1/2% due 2001-2015.....................................      109.0
       8 1/2% due 1998-2008......................................       93.4
     Notes
       9 7/8% due 2002...........................................      247.3
       9 1/2% due 2003...........................................       99.5
       9 3/8% due 2003...........................................      260.0
     Medium-term notes...........................................      149.3
     Bank and other loans........................................         .2
                                                                      ------
       Total senior indebtedness.................................      975.6
     Less--current portion.......................................        4.7
                                                                      ------
                                                                      $970.9
                                                                      ======
</TABLE>
 
                                     F-16
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
  The aggregate maturities of long-term debt outstanding at March 31, 1995,
for the next five years will be as follows:
 
<TABLE>
     <S>                                                                  <C>
     April 1, 1995--March 31, 1996....................................... $ 4.7
     April 1, 1996--March 31, 1997.......................................  34.3
     April 1, 1997--March 31, 1998.......................................  14.2
     April 1, 1998--March 31, 1999.......................................  20.5
     April 1, 1999--March 31, 2000.......................................   8.5
</TABLE>
 
  At March 31, 1995, 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:
 
<TABLE>
<CAPTION>
                                                     THREE MONTHS    YEAR ENDED
                                                    ENDED MARCH 31, DECEMBER 31,
                                                         1995           1994
                                                    --------------- ------------
     <S>                                            <C>             <C>
     Interest and debt expenses....................      $24.1         $96.7
     Capitalized interest..........................         .1           3.2
                                                         -----         -----
                                                         $24.2         $99.9
                                                         =====         =====
</TABLE>
 
NOTE SIXTEEN--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. 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
 
                                     F-17
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
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.
 
 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 SEVENTEEN--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. At March 31, 1995, 1,250,000 shares of $9.75 Preferred Stock were
outstanding, each receiving an annual cash dividend of $9.75. In addition,
375,000 of such shares (the "Conversion Waiver Shares") each received 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") was entitled to one vote, was convertible at any time
into shares of the Company's Common Stock (2.29751 shares
 
                                     F-18
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
at March 31, 1995), was entitled to receive annual cash dividends of $4.00 per
share, was callable at and had 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. The Company redeemed the $4.00 Preferred Stock on August 13, 1996.
 
 $2.50 Cumulative Preferred Stock
 
  Each outstanding share of the $2.50 Preferred 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
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 EIGHTEEN--COMMON STOCK
 
<TABLE>
<CAPTION>
                                                              SHARES     AMOUNT
                                                            -----------  ------
     <S>                                                    <C>          <C>
     January 1, 1994....................................... 134,373,523  $134.4
       Employee Shareholding and Investment Plan...........     830,798      .8
       Restricted stock....................................     490,430      .5
       Fractional shares exchanged for cash................         (29)
                                                            -----------  ------
     January 1, 1995....................................... 135,694,722   135.7
       Employee Shareholding and Investment Plan...........     199,274      .2
       Conversion of $4.00 Preferred Stock.................       5,588
       Fractional shares exchanged for cash................      (1,685)
                                                            -----------  ------
     March 31, 1995........................................ 135,897,899  $135.9
                                                            ===========  ======
</TABLE>
 
  In 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
were to pay 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, there were 32.4 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 Group Inc. 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, now known as
the Employee Savings 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
 
                                     F-19
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
million and $2.8 million at March 31, 1995 and December 31, 1994,
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 Preferred Stock outstanding as of the close of business on
September 12, 1988. The rights, which entitled 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, became exercisable if a person had become the beneficial
owner of 20% or more of the Company's Common Stock or of an amount that the
Board of Directors determined was 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 became exercisable if a person made a tender
offer or exchange offer for 30% or more of the Company's outstanding Common
Stock. The rights could 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 NINETEEN--PAID-IN CAPITAL AND ACCUMULATED DEFICIT
 
<TABLE>
<CAPTION>
                                                          PAID-IN   ACCUMULATED
                                                          CAPITAL     DEFICIT
                                                          --------  -----------
     <S>                                                  <C>       <C>
     January 1, 1994..................................... $1,026.2   $  (993.7)
       Net loss..........................................                (22.7)
       Dividends on Preferred Stock......................    (43.6)
       Employee Shareholding and Investment Plan.........      3.1
       Restricted stock..................................      2.4
                                                          --------   ---------
     January 1, 1995.....................................    988.1    (1,016.4)
       Net loss..........................................                (56.9)
       Dividends on Preferred Stock......................     (9.6)
       Stock rights redemption...........................    (13.6)
       Restricted stock..................................       .6
       Employee Shareholding and Investment Plan.........       .7
                                                          --------   ---------
     March 31, 1995...................................... $  966.2   $(1,073.3)
                                                          ========   =========
</TABLE>
 
NOTE TWENTY--UNREALIZED LOSS ON INVESTMENT IN MARKETABLE SECURITIES
 
  The amortized cost and estimated fair value of marketable securities at
March 31, 1995 are as follows:
 
<TABLE>
<CAPTION>
                                                          MARCH 31, 1995
                                                    ---------------------------
                                                                GROSS
                                                    AMORTIZED UNREALIZED MARKET
                                                      COST       LOSS    VALUE
                                                    --------- ---------- ------
     <S>                                            <C>       <C>        <C>
     Held-to-maturity:
       Corporate and other debt securities.........  $280.0      $2.8    $277.2
     Held-for-sale:
       Corporate and other debt securities.........    30.7       1.3      29.4
</TABLE>
 
                                     F-20
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
  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 Eleven).
 
NOTE TWENTY-ONE--COMMON TREASURY STOCK
 
<TABLE>
<CAPTION>
                                                                SHARES   AMOUNT
                                                               --------  ------
     <S>                                                       <C>       <C>
     January 1, 1994.......................................... (173,963) $(2.5)
       Restricted Stock....................................... (122,032)  (1.0)
                                                               --------  -----
     January 1, 1995.......................................... (295,995)  (3.5)
       Restricted Stock.......................................  (14,540)   (.1)
                                                               --------  -----
     March 31, 1995........................................... (310,535) $(3.6)
                                                               ========  =====
</TABLE>
 
NOTE TWENTY-TWO--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, permitted 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.
 
  The grant or exercise of an option did 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, would result in a charge against the Company's earnings; a
subsequent decline in market price would result 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:
 
<TABLE>
<CAPTION>
                                                        MARCH 31,  DECEMBER 31,
                                                          1995         1994
                                                        ---------  ------------
     <S>                                                <C>        <C>
     Outstanding at January 1.........................  2,268,068     1,694,445
       Granted........................................                  758,000
       Cancelled......................................    (77,495)     (184,377)
                                                        ---------  ------------
     Outstanding at end of period.....................  2,190,573     2,268,068
       Grant price....................................             $5.00-$8.625
     Available for future grants at end of period.....  2,496,936     2,419,441
     Restricted stock held for vesting at end of peri-
      od..............................................    936,066       951,410
     Performance units held for vesting at end of pe-
      riod............................................    653,355       653,355
</TABLE>
 
  Exercise prices of stock options outstanding at March 31, 1995 ranged from
$5.00 to $13.75 per share. No stock options were exercised during 1994 or the
first three months of 1995. 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.
 
                                     F-21
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
  Under the 1986 Long-Term Incentive Plan, the Company granted Restricted
Stock. The amount of the grant price was 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 and $1.4 million in 1994.
 
  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 Two).
 
NOTE TWENTY-THREE--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:
 
<TABLE>
     <S>                                                                 <C>
     March 31, 1996..................................................... $ 34.4
     March 31, 1997.....................................................   19.4
     March 31, 1998.....................................................   15.7
     March 31, 1999.....................................................    9.0
     March 31, 2000.....................................................    8.2
     March 31, 2001 and thereafter......................................   34.0
                                                                         ------
                                                                         $120.7
                                                                         ======
</TABLE>
 
  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:
 
<TABLE>
<CAPTION>
                                                     THREE MONTHS    YEAR ENDED
                                                    ENDED MARCH 31, DECEMBER 31,
                                                         1995           1994
                                                    --------------- ------------
     <S>                                            <C>             <C>
     Total rentals.................................      $14.0         $60.1
     Less--Sublease rental income..................         .9           2.9
                                                         -----         -----
     Rental expense................................      $13.1         $57.2
                                                         =====         =====
</TABLE>
 
NOTE TWENTY-FOUR--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
 
                                     F-22
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
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.
 
  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 was 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 had significant
operations include the United States, Indonesia, Ecuador, Bolivia and
Venezuela.
 
                                     F-23
<PAGE>
 
                             REPORT OF MANAGEMENT
 
To the Stockholders of
 Maxus Energy Corporation
 
  The Consolidated Financial Statements have been prepared in conformity with
generally accepted accounting principles and have been audited by Arthur
Andersen LLP, independent accountants, for the three months ended March 31,
1995, the nine months ended December 31, 1995 and the year ended December 31,
1996 and have been audited by Price Waterhouse LLP, independent accountants,
for the year 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
Vice President and Chief Financial Officer
 
/s/ Linda R. Engelbrecht
Linda R. Engelbrecht
Controller
 
Dallas, Texas
January 29, 1997
 
                                     F-24
<PAGE>
 
                       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 December 31, 1996
and 1995 and March 31, 1995, and the related consolidated statements of
operations and cash flows for the year ended December 31, 1996, the nine
months ended December 31, 1995 and the three months ended March 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 provide a reasonable basis
for our opinion.
 
  In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position
of Maxus Energy Corporation and its subsidiaries as of December 31, 1996 and
1995 and March 31, 1995, and the results of its operations and its cash flows
for the year ended December 31, 1996, the nine months ended December 31, 1995,
and the three months ended March 31, 1995, in conformity with generally
accepted accounting principles.
 
/s/ Arthur Andersen LLP
Arthur Andersen LLP
 
Dallas, Texas
January 29, 1997
 
                                     F-25
<PAGE>
 
                       REPORT OF INDEPENDENT ACCOUNTANTS
 
To the Stockholders and Board of Directors of
 Maxus Energy Corporation
 
  In our opinion, the accompanying consolidated statements of operations and
of cash flows present fairly, in all material respects, the results of
operations and cash flows of Maxus Energy Corporation and its subsidiaries for
the year 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 audit. We conducted our audit 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 audit provides a
reasonable basis for the opinion expressed above. We have not audited the
consolidated financial statements of Maxus Energy Corporation for any period
subsequent to December 31, 1994.
 
/s/ Price Waterhouse LLP
Price Waterhouse LLP
 
Dallas, Texas
February 28, 1995
 
                                     F-26
<PAGE>
 
                      FINANCIAL SUPPLEMENTARY INFORMATION
                                  (UNAUDITED)
 (DATA IS AS OF DECEMBER 31 FOR THE YEAR ENDED 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.
 
<TABLE>
<CAPTION>
                                     UNITED STATES              INDONESIA
                                 -----------------------  ----------------------
                                 MARCH 31,  DECEMBER 31,  MARCH 31, DECEMBER 31,
                                   1995         1994        1995        1994
                                 ---------  ------------  --------- ------------
<S>                              <C>        <C>           <C>       <C>
Sales...........................   $22.7      $ 132.3       $93.1      $381.2
                                   -----      -------       -----      ------
Production costs................     7.4         35.0        39.7       151.5
Exploration costs...............     3.7         12.2         2.7        13.8
Depreciation, depletion and am-
 ortization.....................     7.0         45.3        16.9        75.6
(Gain) loss on sale of assets...     (.1)      (201.8)
Other...........................     2.9(a)      10.8(a)     (3.0)        1.8
                                   -----      -------       -----      ------
                                    20.9        (98.5)       56.3       242.7
                                   -----      -------       -----      ------
Income (loss) before tax provi-
 sion...........................     1.8        230.8        36.8       138.5
Provision (benefit) for income
 taxes..........................                  4.6        18.7        74.4
                                   -----      -------       -----      ------
Results of operations...........   $ 1.8      $ 226.2       $18.1      $ 64.1
                                   =====      =======       =====      ======
</TABLE>
 
<TABLE>
<CAPTION>
                              SOUTH AMERICA           OTHER FOREIGN           WORLDWIDE
                          ---------------------- ---------------------- ----------------------
                          MARCH 31, DECEMBER 31, MARCH 31, DECEMBER 31, MARCH 31, DECEMBER 31,
                            1995        1994       1995        1994       1995        1994
                          --------- ------------ --------- ------------ --------- ------------
<S>                       <C>       <C>          <C>       <C>          <C>       <C>
Sales...................    $ 7.8      $24.0                             $123.6     $ 537.5
                            -----      -----                             ------     -------
Production costs........      6.8       17.8                               53.9       204.3
Exploration costs.......       .4        2.4       $ 2.2      $ 7.2         9.0        35.6
Depreciation, depletion
 and amortization.......      3.9        7.5          .4        2.7        28.2       131.1
(Gain) loss on sale of
 assets.................                  .2        (1.1)                  (1.2)     (201.6)
Other...................       .4       (1.4)                   (.3)         .3        10.9
                            -----      -----       -----      -----      ------     -------
                             11.5       26.5         1.5        9.6        90.2       180.3
                            -----      -----       -----      -----      ------     -------
Income (loss) before tax
 provision..............     (3.7)      (2.5)       (1.5)      (9.6)       33.4       357.2
Provision (benefit) for
 income taxes...........       .5        5.2                    (.2)       19.2        84.0
                            -----      -----       -----      -----      ------     -------
Results of operations...    $(4.2)     $(7.7)      $(1.5)     $(9.4)     $ 14.2     $ 273.2
                            =====      =====       =====      =====      ======     =======
</TABLE>
----------
(a) Includes United States gathering and processing costs related to sales.
    Such costs were $3.1 million and $11.8 million for March 31, 1995,
    December 31, 1994, respectively.
 
 
                                     F-27
<PAGE>
 
CAPITALIZED COSTS
 
  Included in properties and equipment are capitalized amounts applicable to
the Company's oil and gas producing activities. Such capitalized amounts
include the cost of mineral interests in properties, completed and incomplete
wells and related support equipment as follows:
 
<TABLE>
<CAPTION>
                                      UNITED STATES            INDONESIA
                                  ---------------------- ----------------------
                                  MARCH 31, DECEMBER 31, MARCH 31, DECEMBER 31,
                                    1995        1994       1995        1994
                                  --------- ------------ --------- ------------
<S>                               <C>       <C>          <C>       <C>
Proved properties................  $605.4      $584.0    $1,588.1    $1,572.9
Unproved properties..............    10.7         7.8          .7          .7
                                   ------      ------    --------    --------
                                    616.1       591.8     1,588.8     1,573.6
                                   ------      ------    --------    --------
Less--Accumulated depreciation,
 depletion and amortization......   422.6       416.8     1,060.6     1,043.7
                                   ------      ------    --------    --------
                                   $193.5      $175.0    $  528.2    $  529.9
                                   ======      ======    ========    ========
</TABLE>
 
<TABLE>
<CAPTION>
                              SOUTH AMERICA          OTHER FOREIGN            WORLDWIDE
                          ---------------------- ---------------------- ----------------------
                          MARCH 31, DECEMBER 31, MARCH 31, DECEMBER 31, MARCH 31, DECEMBER 31,
                            1995        1994       1995        1994       1995        1994
                          --------- ------------ --------- ------------ --------- ------------
<S>                       <C>       <C>          <C>       <C>          <C>       <C>
Proved properties.......   $252.1      $240.8                           $2,445.6    $2,397.7
Unproved properties.....     15.2        15.2      $5.0        $5.4         31.6        29.1
                           ------      ------      ----        ----     --------    --------
                            267.3       256.0       5.0         5.4      2,477.2     2,426.8
                           ------      ------      ----        ----     --------    --------
Less--Accumulated
 depreciation, depletion
 and amortization.......     12.3         8.5       4.2         4.0      1,499.7     1,473.0
                           ------      ------      ----        ----     --------    --------
                           $255.0      $247.5      $ .8        $1.4     $  977.5    $  953.8
                           ======      ======      ====        ====     ========    ========
</TABLE>
 
COSTS INCURRED
 
  Costs incurred by the Company in its oil and gas producing activities
(whether capitalized or charged against earnings) were as follows:
 
<TABLE>
<CAPTION>
                                       UNITED STATES            INDONESIA
                                   ---------------------- ----------------------
                                   MARCH 31, DECEMBER 31, MARCH 31, DECEMBER 31,
                                     1995        1994       1995        1994
                                   --------- ------------ --------- ------------
<S>                                <C>       <C>          <C>       <C>
Property acquisition costs........   $13.6      $ 2.4
Exploration costs.................     7.0       12.8       $ 7.0      $13.8
Development costs.................     8.2       20.9        10.9       58.7
                                     -----      -----       -----      -----
                                     $28.8      $36.1       $17.9      $72.5
                                     =====      =====       =====      =====
</TABLE>
 
<TABLE>
<CAPTION>
                             SOUTH AMERICA          OTHER FOREIGN            WORLDWIDE
                         ---------------------- ---------------------- ----------------------
                         MARCH 31, DECEMBER 31, MARCH 31, DECEMBER 31, MARCH 31, DECEMBER 31,
                           1995        1994       1995        1994       1995        1994
                         --------- ------------ --------- ------------ --------- ------------
<S>                      <C>       <C>          <C>       <C>          <C>       <C>
Property acquisition
 costs..................                                                 $13.6      $  2.4
Exploration costs.......   $  .4      $ 3.4       $2.2        $7.4        16.6        37.4
Development costs.......    11.3       77.7                               30.4       157.3
                           -----      -----       ----        ----       -----      ------
                           $11.7      $81.1       $2.2        $7.4       $60.6      $197.1
                           =====      =====       ====        ====       =====      ======
</TABLE>
 
                                     F-28
<PAGE>
 
OIL AND GAS RESERVES
 
  The following table represents the Company's net interest in estimated
quantities of developed and undeveloped reserves of crude oil, condensate,
natural gas liquids and natural gas and changes in such quantities at quarter-
end March 31, 1995 and at year-end 1994. 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.
 
<TABLE>
<CAPTION>
                                MARCH 31, 1995(D)               DECEMBER 31, 1994
                          ------------------------------  -----------------------------------
                          UNITED            SOUTH         UNITED              SOUTH
       CRUDE OIL          STATES INDONESIA AMERICA TOTAL  STATES INDONESIA   AMERICA    TOTAL
       ---------          ------ --------- ------- -----  ------ ---------   -------    -----
                                              (MILLIONS OF BARRELS)
<S>                       <C>    <C>       <C>     <C>    <C>    <C>         <C>        <C>
Net Proved Developed and
 Undeveloped Reserves
Beginning of period.....   3.5     158.8    67.1   229.4   12.3    180.1      71.6      264.0
  Revisions of previous
   estimates............                                     .2     (3.2)(a)   5.1        2.1
  Purchase of reserves
   in place.............    .3                        .3
  Extensions,
   discoveries and other
   additions............                                     .1      3.5(a)               3.6
  Production............   (.1)     (4.7)    (.8)   (5.6)   (.9)   (21.6)     (1.8)(c)  (24.3)
  Sales of reserves in
   place................                                   (8.2)              (7.8)     (16.0)
                           ---     -----    ----   -----   ----    -----      ----      -----
End of period...........   3.7     154.1    66.3   224.1    3.5    158.8      67.1      229.4
                           ---     -----    ----   -----   ----    -----      ----      -----
Net Proved Developed
 Reserves
Beginning of period.....   2.9     141.5    14.8   159.2   11.0    161.1      14.1      186.2
End of period...........   2.8     136.8    14.0   153.6    2.9    141.5      14.8      159.2
                           ===     =====    ====   =====   ====    =====      ====      =====
</TABLE>
 
                                     F-29
<PAGE>
 
<TABLE>
<CAPTION>
                                    MARCH 31, 1995(D)       DECEMBER 31, 1994
                                  ----------------------  ----------------------
                                  UNITED                  UNITED
         NATURAL GAS(B)           STATES INDONESIA TOTAL  STATES INDONESIA TOTAL
         --------------           ------ --------- -----  ------ --------- -----
                                            (BILLIONS OF CUBIC FEET)
<S>                               <C>    <C>       <C>    <C>    <C>       <C>
Net Proved Developed and
 Undeveloped Reserves
Beginning of period..............   492     304     796     679     262     941
  Revisions of previous
   estimates.....................                            21       1      22
  Purchase of reserves in place..    24              24
  Extensions, discoveries and
   other additions...............                            13      58      71
  Production.....................   (11)     (4)    (15)    (57)    (17)    (74)
  Sales of reserves in place.....                          (164)           (164)
                                   ----     ---    ----    ----    ----    ----
End of period....................   505     300     805     492     304     796
                                   ----     ---    ----    ----    ----    ----
Net Proved Developed Reserves
Beginning of period..............   384     107     491     507      85     592
End of period....................   373     103     476     384     107     491
                                   ====     ===    ====    ====    ====    ====
<CAPTION>
                                    MARCH 31, 1995(D)       DECEMBER 31, 1994
                                  ----------------------  ----------------------
                                  UNITED                  UNITED
       NATURAL GAS LIQUIDS        STATES INDONESIA TOTAL  STATES INDONESIA TOTAL
       -------------------        ------ --------- -----  ------ --------- -----
                                              (MILLIONS OF BARRELS)
<S>                               <C>    <C>       <C>    <C>    <C>       <C>
Net Proved Developed and
 Undeveloped Reserves
Beginning of period..............  36.5     9.4    45.9    37.1    10.2    47.3
  Revisions of previous
   estimates.....................                           2.0     (.7)    1.3
  Purchase of reserves in place..    .4              .4
  Extensions, discoveries and
   other additions...............                            .4      .7     1.1
  Production.....................   (.8)    (.1)    (.9)   (3.0)    (.8)   (3.8)
                                   ----     ---    ----    ----    ----    ----
End of period....................  36.1     9.3    45.4    36.5     9.4    45.9
                                   ----     ---    ----    ----    ----    ----
Net Proved Developed Reserves
 Beginning of period.............  29.7     3.2    32.9    29.5     3.3    32.8
End of period....................  28.9     3.1    32.0    29.7     3.2    32.9
                                   ====     ===    ====    ====    ====    ====
</TABLE>
--------
(a) The changes reflect the impact of the change in the price of crude oil on
    the barrels to which the Company is entitled under the terms of the
    Indonesian production sharing contracts. The Indonesian production sharing
    contracts allow the Company to recover tangible 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.
(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.
 
 
                                     F-30
<PAGE>
 
FUTURE NET CASH FLOWS
 
  The standardized measure of discounted future net cash flows relating to the
Company's proved oil and gas reserves is calculated and presented in
accordance with Statement of Financial Accounting Standards No. 69.
Accordingly, future cash inflows were determined by applying year-end oil and
gas prices (adjusted for future fixed and determinable price changes) to the
Company's estimated share of future production from proved oil and gas
reserves. Future 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.
 
<TABLE>
<CAPTION>
                                              DECEMBER 31, 1994
                               ------------------------------------------------
                               UNITED STATES INDONESIA  SOUTH AMERICA WORLDWIDE
                               ------------- ---------  ------------- ---------
<S>                            <C>           <C>        <C>           <C>
Future cash flows............     $ 967.3    $ 3,389.0     $ 831.9    $ 5,188.2
Future production and devel-
 opment costs................      (324.7)    (2,246.8)     (371.8)    (2,943.3)
Future income tax expenses...       (92.8)      (503.1)      (53.6)      (649.5)
                                  -------    ---------     -------    ---------
Future net cash flows........       549.8        639.1       406.5      1,595.4
Annual discount at 10% rate..      (241.1)      (261.7)     (162.8)      (665.6)
                                  -------    ---------     -------    ---------
Standardized measure of dis-
 counted future net cash
 flows.......................     $ 308.7    $   377.4     $ 243.7    $   929.8
                                  =======    =========     =======    =========
</TABLE>
 
  The following are the principal sources for change in the standardized
measure:
 
<TABLE>
<CAPTION>
                                                              DECEMBER 31, 1994
                                                              -----------------
     <S>                                                      <C>
     Beginning of year.......................................     $1,061.3
       Sales and transfers of oil and gas produced, net of
        production costs.....................................       (333.2)
       Net changes in prices and production costs............        103.4
       Extensions, discoveries and improved recovery, less
        related costs........................................         68.0
       Development costs incurred during the year that
        reduced future development costs.....................        123.2
       Revisions of previous quantity estimates..............         56.6
       Purchase of reserves in place.........................           .4
       Sale of reserves in place.............................       (275.7)
       Net change in income taxes............................        (22.6)
       Accretion of discount.................................        132.4
       Other.................................................         16.0
                                                                  --------
     End of year.............................................     $  929.8
                                                                  ========
</TABLE>
 
 
                                     F-31
<PAGE>
 
                            MAXUS ENERGY CORPORATION
 
                      CONSOLIDATED STATEMENT OF OPERATIONS
 
<TABLE>
<CAPTION>
                                                     TWELVE MONTHS NINE MONTHS
                                                         ENDED        ENDED
                                                     DECEMBER 31,  DECEMBER 31,
                                                         1996          1995
                                                     ------------- ------------
                                                           (IN MILLIONS)
<S>                                                  <C>           <C>
Revenues
  Sales and operating revenues......................    $718.0        $463.8
  Other revenues, net...............................      20.1           7.1
                                                        ------        ------
                                                         738.1         470.9
Costs and Expenses
  Operating expenses................................     201.5         173.5
  Gas purchase costs................................      74.4          41.4
  Exploration, including exploratory dry holes......      35.1          51.2
  Depreciation, depletion and amortization..........     168.9         142.1
  General and administrative expenses...............      11.4          12.7
  Taxes other than income taxes.....................      14.0           9.7
  Interest and debt expenses........................     134.6         104.9
                                                        ------        ------
                                                         639.9         535.5
                                                        ------        ------
Income (Loss) Before Income Taxes and Extraordinary
 Item...............................................      98.2         (64.6)
  Income Taxes......................................      77.6           9.1
                                                        ------        ------
Net Income (Loss) Before Extraordinary Item.........      20.6         (73.7)
  Extraordinary Item................................      (5.6)
                                                        ------        ------
Net Income (Loss)...................................    $ 15.0        $(73.7)
                                                        ======        ======
</TABLE>
 
 
                See Notes to Consolidated Financial Statements.
 
                                      F-32
<PAGE>
 
                            MAXUS ENERGY CORPORATION
 
                           CONSOLIDATED BALANCE SHEET
 
<TABLE>
<CAPTION>
                                                       DECEMBER 31, DECEMBER 31,
                       ASSETS                              1996         1995
                       ------                          ------------ ------------
                                                         (IN MILLIONS, EXCEPT
                                                                SHARES)
<S>                                                    <C>          <C>
Current Assets
  Cash and cash equivalents..........................    $   28.9     $   38.3
  Receivables, less allowance for doubtful accounts..       199.0        141.8
  Funding guarantee from parent......................        27.4
  Inventories........................................        26.3         40.8
  Restricted cash....................................         7.3         19.0
  Deferred income taxes..............................        15.3          6.9
  Prepaid expenses...................................        10.5         19.6
                                                         --------     --------
    Total Current Assets.............................       314.7        266.4
Properties and Equipment, less accumulated
 depreciation, depletion and amortization............     2,022.2      2,363.6
Investments and Long-Term Receivables................          .4          7.1
Restricted Cash......................................        26.5         61.4
Funding Guarantee from Parent........................        75.2
Deferred Charges.....................................        17.5         18.3
                                                         --------     --------
                                                         $2,456.5     $2,716.8
                                                         ========     ========
        LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
  Current portion of long-term debt..................    $   54.1     $   34.3
  Accounts payable...................................        98.1         59.0
  Taxes payable......................................        44.6         39.7
  Accrued liabilities................................       158.0        173.4
                                                         --------     --------
    Total Current Liabilities........................       354.8        306.4
Long-Term Debt.......................................     1,034.4      1,254.6
Advances from Parent.................................       182.2          6.6
Deferred Income Taxes................................       502.7        551.2
Other Liabilities and Deferred Credits...............       171.0        233.0
$9.75 Redeemable Preferred Stock, $1.00 par value
 Authorized and issued shares 625,000 and 1,250,000..        62.5        125.0
Stockholders' Equity
  $2.50 Preferred Stock, $1.00 par value
   Authorized shares--5,000,000
   Issued shares--3,500,000..........................        57.8         66.5
  $4.00 Preferred Stock, $1.00 par value
   Authorized shares--0 and 5,915,017
   Issued shares--0 and 4,356,958....................                     11.7
  Common Stock, $1.00 par value
   Authorized shares--300,000,000
   Issued shares--147,246,364 and 135,609,772........       147.2        135.6
  Paid-in capital....................................       216.4        105.8
  Accumulated deficit................................      (272.3)       (73.7)
  Minimum pension liability..........................         (.2)        (5.9)
                                                         --------     --------
    Total Stockholders' Equity.......................       148.9        240.0
                                                         --------     --------
                                                         $2,456.5     $2,716.8
                                                         ========     ========
</TABLE>
                      See "Commitments and Contingencies."
                See Notes to Consolidated Financial Statements.
 The Company uses the successful efforts method to account for its oil and gas
                             producing activities.
 
                                      F-33
<PAGE>
 
                            MAXUS ENERGY CORPORATION
 
                      CONSOLIDATED STATEMENT OF CASH FLOWS
 
<TABLE>
<CAPTION>
                                                     TWELVE MONTHS NINE MONTHS
                                                         ENDED        ENDED
                                                     DECEMBER 31,  DECEMBER 31,
                                                         1996          1995
                                                     ------------- ------------
                                                           (IN MILLIONS)
<S>                                                  <C>           <C>
Cash Flows From Operating Activities:
  Net income/(loss).................................    $  15.0      $( 73.7)
  Adjustments to reconcile net income/(loss) to net
   cash provided by operating activities:
    Extraordinary item..............................        5.6
    Depreciation, depletion and amortization........      168.9        142.1
    Dry hole costs..................................        5.5         18.8
    Income taxes....................................      (26.2)       (49.2)
    Net (gain)/loss on sale of assets and
     investments....................................        2.3         (5.9)
    Postretirement benefits.........................        3.8          3.1
    Accretion of discount on long-term debt.........        9.0          7.3
    Release of excess insurance reserves............      (13.6)
    Other...........................................        8.2          1.4
    Changes in components of working capital:
      Receivables...................................      (72.9)        (5.4)
      Inventories, prepaids and other current
       assets.......................................       19.4        (12.8)
      Accounts payable..............................       42.7          9.2
      Accrued liabilities...........................      (25.7)       (31.5)
      Taxes payable/receivable......................        9.8         53.4
                                                        -------      -------
        Net Cash Provided by Operating Activities...      151.8         56.8
                                                        -------      -------
Cash Flows From Investing Activities:
  Expenditures for properties and equipment--
   including dry hole costs.........................     (203.3)      (137.4)
  Proceeds on asset sales to parent.................      292.7
  Proceeds from sales of assets.....................       13.7         27.4
  Proceeds from sale/maturity of short- and long-
   term investments.................................                    96.3
  Restricted cash...................................       46.6         45.3
  Other.............................................      (29.5)       (34.3)
                                                        -------      -------
        Net Cash Provided by/(Used in) Investing
         Activities.................................      120.2         (2.7)
                                                        -------      -------
Cash Flows From Financing Activities:
  Interest rate swap................................                     6.9
  Proceeds from issuance of short-term debt.........                    17.2
  Repayment of short-term debt......................      (60.7)       (21.8)
  Net proceeds from issuance of long-term debt......                   839.8
  Repayment of long-term debt.......................     (148.7)      (425.1)
  Cash advance from parent..........................      175.6
  Acquisition of common stock, including payment of
   merger costs.....................................       (3.7)      (746.6)
  Issuance of common stock to parent................       64.0
  Capital contribution from parent..................                   250.5
  Redemption of preferred stock.....................     (280.5)
  Dividends paid on preferred stock.................      (27.4)       (28.8)
                                                        -------      -------
        Net Cash Used in Financing Activities.......     (281.4)      (107.9)
                                                        -------      -------
Net Decrease in Cash and Cash Equivalents...........       (9.4)       (53.8)
Cash and Cash Equivalents at Beginning of Period....       38.3         92.1
                                                        -------      -------
Cash and Cash Equivalents at End of Period..........    $  28.9      $  38.3
                                                        =======      =======
</TABLE>
 
                See Notes to Consolidated Financial Statements.
 
                                      F-34
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
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. Effective April 1, 1995, the Company used the purchase method
of accounting to record the acquisition of the Company by YPF Sociedad Anonima
("YPF") as discussed in Note Two. Financial statements presented for periods
after April 1, 1995 reflect the effects of the Merger-related transactions.
Post-Merger financial information is not comparable to prior periods due to
the application of purchase accounting effective April 1, 1995. The following
post-Merger data is for the twelve months ended December 31, 1996, and the
nine months ended December 31, 1995 and dollar amounts in tables are in
millions.
 
  In June 1996, YPF and Maxus announced an internal reorganization of Maxus
which included the transfer of the Common Stock of Maxus to a YPF indirect
wholly owned subsidiary, YPF Holdings, Inc. ("Holdings"), and the sale of
common stock of certain subsidiaries of Maxus to a wholly owned subsidiary of
YPF (See Note Three).
 
 Consolidation Accounting
 
  The Consolidated Financial Statements include the accounts of the Company
and all domestic and foreign subsidiaries. All significant intercompany
accounts and transactions have been eliminated.
 
 Management's Estimates
 
  The preparation of financial statements in accordance with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
period. Actual results could differ from these estimates.
 
 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:
 
<TABLE>
<CAPTION>
                                          TWELVE MONTHS ENDED NINE MONTHS ENDED
                                           DECEMBER 31, 1996   DECEMBER 31, 1995
                                          ------------------- ------------------
     <S>                                  <C>                 <C>
     Interest receipts...................       $  9.3              $ 11.8
     Interest payments...................        127.4               107.9
     Income tax payments.................         93.0                64.7
</TABLE>
 
 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.
 
                                     F-35
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
  The Company follows the provisions of 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.
 
  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 prepared by independent petroleum
engineers 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 proved reserves. Other properties and equipment, which includes
gas gathering and processing equipment and plants, 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 are
amortized applying the same depreciation method over the same useful lives 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, 1996 are not material.
 
                                     F-36
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
 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 and selected key employees.
 
 Other Postretirement and Postemployment Benefits
 
  The Company provides certain health care and life insurance benefits for
eligible retired employees and certain insurance and other postemployment
benefits for eligible 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 periods. 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. During the third quarter 1996, the Company, as
part of its general reorganization, transferred certain liabilities related to
environmental matters to Chemical Land Holdings, Inc. ("CLH"), an indirect
subsidiary of YPF, effective as of August 1, 1996 (See Note Three).
 
 Litigation Contingencies
 
  The Company records liabilities for litigation when such amounts are
probable, material and can be reasonably estimated.
 
 Income Taxes
 
  Effective August 13, 1996, YPF transferred ownership of its shares of the
Company's Common Stock to Holdings, a U. S. corporation. The Company
subsequently transferred its ownership of the common stock of CLH to a
subsidiary of Holdings (See Note Three). As a result of these transactions
both the Company and CLH are now included as members of an affiliated group of
companies qualifying, within the meaning of the United States Internal Revenue
Code, to file a consolidated federal income tax return having Holdings as
common U. S. parent.
 
  The Company's financial statements reflect an allocation of income tax
expense or benefit from the Holdings consolidated income tax group. This
method of allocation is consistent with the principles established by
Statement of Financial Accounting Standard, No. 109 ("SFAS 109"), "Accounting
for Income Taxes." It is
 
                                     F-37
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
based on a calculation of income tax for the Company as a separate entity,
adjusted to reflect certain attributes of Holdings' consolidated income tax
return. The attributes include, but are not limited, to the consolidated loss
apportionment, tax credits, and the alternative minimum tax.
 
  Effective August 1, 1996, CLH assumed certain liabilities of the Company
relating to environmental matters (See Note Three); thus, current taxes and
deferred taxes associated with the assumption of these liabilities have been
transferred to the accounts of CLH.
 
 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, restricted cash and trade
receivables.
 
  The Company's cash equivalents 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 derivative 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, natural gas and natural gas liquids ("NGL") through price swap
agreements and futures contracts. During 1996, the Company hedged
approximately 35% of its NGL sales and 60% of its U. S. natural gas production
and anticipates hedging approximately 40% of its U. S. NGL sales and 85% of
its U. S. natural gas production in 1997. 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 entered
into interest rate swap agreements to hedge interest on long-term debt;
however, during the nine-month period ended December 31, 1995, the Company
unwound its sole interest rate swap agreement.
 
 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 Consolidated Statement of Operations as quantities are
delivered which fulfill the take-or-pay obligation. At December 31, 1996 and
1995, the Company had $3.1 million and $12.4 million, respectively, in
deferred revenue as a result of a take-or-pay payment received in 1995 related
to its Indonesian operations.
 
 
                                     F-38
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
 Uncertainties Involving Forward-Looking Disclosure
 
  Certain of the statements set forth in the accompanying "Notes to
Consolidated Financial Statements," such as the statements regarding expected
cash advances from parents, projected environmental expenditures and the
percentage of U. S. natural gas production anticipated to be hedged, are
forward-looking (within the meaning of the U. S. Private Securities Litigation
Reform Act of 1995) and are based upon assumptions that in the future may
prove not to have been accurate. Such statements are subject to a number of
risks and uncertainties including volatility of crude oil and natural gas
prices, uncertainties regarding program spending commitments, environmental
risks and operating hazards and risks. Because of the foregoing matters, the
Company's actual results for 1997 and beyond could differ from those expressed
in the forward-looking statements.
 
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. ("YPFA Corp.") and YPF.
The holders of the Company's common stock, $1.00 par value per share (the
"Shares" or "Common Stock"), 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").
 
  The Merger was the consummation of transactions contemplated by a tender
offer (the "Offer") which was commenced on March 6, 1995 by YPFA Corp. for all
the outstanding Shares at $5.50 per Share. Pursuant to the Offer, in April
1995 YPFA Corp. 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 YPFA Corp., YPF or any of their
subsidiaries or in the treasury of the Company, all of which were canceled 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 total amount of funds required by YPFA Corp. 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. In
addition, YPFA Corp. assumed all outstanding obligations of the Company. On
April 5, 1995, YPFA Corp. entered into a credit agreement with lenders for
which The Chase Manhattan Bank (National Association) ("Chase") acted as
agent, pursuant to which the lenders extended to YPFA Corp. 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. YPFA Corp. 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.
 
  Effective April 1, 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 to acquire the Company. The Company's
oil and gas properties were assigned carrying amounts based on their relative
fair market values.
 
  Following the Merger, Chase provided two additional credit facilities
aggregating $425 million: (i) a credit facility of $250 million (the "Midgard
Facility") extended to Midgard Energy Company, a wholly owned subsidiary of
the Company, and (ii) a credit facility of $175 million (the "Indonesian
Facility") extended to Maxus Indonesia, Inc., a wholly owned subsidiary of the
Company. The proceeds of the loans made pursuant to
 
                                     F-39
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
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. In December 1996, YPF
International Ltd. ("International"), the parent of Holdings, loaned the
Company approximately $175 million to repay the Indonesian Facility (See Note
Thirteen).
 
NOTE THREE--GENERAL REORGANIZATION
 
  On June 18, 1996, the Company announced a reorganization which included the
sale of three of its subsidiaries holding certain Bolivian and Venezuelan
assets to YPF, the redemption of the outstanding shares of $4.00 Preferred
Stock and the transfer to a YPF subsidiary of a Maxus subsidiary that had
assumed certain liabilities related to environmental matters.
 
  On July 1, 1996, Maxus International Energy Company ("Seller"), a wholly
owned subsidiary of Maxus, sold all of the issued and outstanding shares of
capital stock of its wholly owned subsidiary, International, to YPF, pursuant
to a Stock Purchase and Sale Agreement by and between YPF and Seller. The sole
assets of International at the time of the transaction were all of the issued
and outstanding shares of capital stock of Maxus Bolivia, Inc. ("Maxus
Bolivia"), Maxus Venezuela (C.I.) Ltd. ("Venezuela C.I.") and Maxus Venezuela
S.A. ("Venezuela S.A."). The assets of Maxus Bolivia consisted of all of the
former assets and operations of Maxus in Bolivia, including the interests of
Maxus in the Surubi Field and Secure and Caipipendi Blocks. The assets of
Venezuela C.I. and Venezuela S.A. consisted of all of the former assets and
operations of Maxus in Venezuela, except those held through Maxus Guarapiche
Ltd. ("Maxus Guarapiche"), including the interests of Maxus in the Quiriquire
Unit.
 
  The purchase price for the outstanding shares of capital stock of
International was $266.2 million which represented the carrying amount of
International on the financial reporting books of Seller as of June 30, 1996.
Maxus used the proceeds from this transaction for general corporate purposes,
including the redemption of its $4.00 Preferred Stock, which is discussed
below.
 
  While not a part of the above-described sale transaction, effective
September 1, 1996, Seller sold all of the capital stock of Maxus Guarapiche to
International for $26.4 million which represented the carrying amount of Maxus
Guarapiche on the financial reporting books of Seller as of August 31, 1996.
Maxus Guarapiche had a 25% interest in the Guarapiche Block, an exploration
block, in Venezuela.
 
  Also as part of the general reorganization, on August 13, 1996 Maxus
redeemed all of its outstanding shares of $4.00 Preferred Stock at a price of
$50 per share plus accrued and unpaid dividends (approximately $220.8 million
in the aggregate). The excess of the redemption price over the carrying value
of the $4.00 Preferred Stock resulted in an increase in the Company's
accumulated deficit of $213.6 million. The Company used a portion of the
proceeds from the sale of all of the issued and outstanding shares of capital
stock of International as well as an advance from Holdings of approximately
$55.6 million to redeem the $4.00 Preferred Stock.
 
  As a further part of the reorganization, the Company transferred certain
liabilities related to environmental matters to CLH, an indirect subsidiary of
YPF, effective as of August 1, 1996. In connection with this transfer, CLH
assumed (the "Assumption") the liabilities so transferred and YPF committed to
contribute capital (the "Contribution Agreement") to CLH up to an amount of
$106.9 million that will enable CLH to satisfy its obligations under the
Assumption based on the Company's reserves established in respect of the
assumed liabilities as of July 31, 1996 plus certain operating expenses
budgeted by CLH from time to time. YPF will not be obligated to contribute
capital to CLH beyond the amount of its initial undertaking. The Company will
remain responsible for any obligations assumed by CLH in the event CLH does
not perform or fulfill such obligations. CLH has assumed responsibility for,
among other things, the environmental contingencies discussed in Note
 
                                     F-40
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
Twenty-Two and a declaratory judgment action filed by Occidental Chemical
Corporation ("OxyChem") and Henkel Corporation ("Henkel"), and the Company
transferred to CLH its remaining rights to recover costs under a cost-sharing
arrangement with Ultramar Diamond Shamrock Corporation.
 
  The contribution obligation of YPF related to the Assumption was reflected
on the Company's financial statements as a long-term and short-term funding
guarantee from parent totaling $106.9 million, an increase to deferred income
taxes of $37.4 million and an increase to paid-in capital of $69.5 million. At
December 31, 1996, the outstanding funding guarantee totaled $102.6 million.
Insofar as CLH has assumed the Company's environmental liabilities and YPF has
committed to pay for the liabilities, such liabilities are not expected to
have an adverse impact on the financial reporting books of the Company.
 
  Under the terms of the Contribution Agreement, Maxus agreed that any
contributions to the equity capital of CLH shall reduce the obligation of YPF
to capitalize Maxus pursuant to the Merger Agreement. During 1996, capital
contributions of $8.0 million were made to CLH.
 
  Effective August 13, 1996, YPF transferred ownership of its shares of the
Company's Common Stock to one of its wholly owned subsidiaries, Holdings.
 
NOTE FOUR--ASSET ACQUISITION AND DIVESTITURES
 
  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.
In July 1996, 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. Effective September 1, 1996, Maxus sold
all of the capital stock of Maxus Guarapiche, which owns a 25% interest in the
Guarapiche Block, to International (See Note Three).
 
  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 FIVE--GEOGRAPHIC DATA AND SIGNIFICANT CUSTOMERS
 
  The Company is engaged primarily in the exploration for and the production
and sale of crude oil and natural gas.
 
  Sales, operating profit and identifiable assets by geographic area were as
follows:
 
<TABLE>
<CAPTION>
                                               SALES AND OPERATING REVENUES
                                          --------------------------------------
                                          TWELVE MONTHS ENDED NINE MONTHS ENDED
                                           DECEMBER 31, 1996   DECEMBER 31, 1995
                                          ------------------- ------------------
     <S>                                  <C>                 <C>
     United States.......................       $232.7              $128.9
     Indonesia...........................        403.9               298.3
     South America.......................         81.4                36.6
                                                ------              ------
                                                $718.0              $463.8
                                                ======              ======
</TABLE>
 
                                     F-41
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
<TABLE>
<CAPTION>
                                                OPERATING PROFIT/(LOSS)
                                         --------------------------------------
                                         TWELVE MONTHS ENDED NINE MONTHS ENDED
                                          DECEMBER 31, 1996   DECEMBER 31, 1995
                                         ------------------- ------------------
     <S>                                 <C>                 <C>
     United States......................       $  37.8            $ (15.1)
     Indonesia..........................         157.1               88.7
     South America......................          29.5              (11.5)
     Other foreign......................          (7.8)             (15.9)
                                               -------            -------
                                                 216.6               46.2
     General corporate
      income/(expenses).................          16.2               (5.9)
     Interest and debt expenses.........        (134.6)            (104.9)
                                               -------            -------
                                               $  98.2            $ (64.6)
                                               =======            =======
</TABLE>
 
<TABLE>
<CAPTION>
                                                     IDENTIFIABLE ASSETS
                                             -----------------------------------
                                             DECEMBER 31, 1996 DECEMBER 31, 1995
                                             ----------------- -----------------
     <S>                                     <C>               <C>
     United States..........................     $  737.6          $  715.9
     Indonesia..............................      1,174.0           1,157.1
     South America..........................        320.2             666.6
     Other foreign..........................         21.9              24.3
                                                 --------          --------
                                                  2,253.7           2,563.9
     Corporate assets.......................        202.8             152.9
                                                 --------          --------
                                                 $2,456.5          $2,716.8
                                                 ========          ========
</TABLE>
 
  Sales to three customers for the twelve months ended December 31, 1996 and
for the nine months ended December 31, 1995, each represented 10% or more of
consolidated sales:
 
<TABLE>
<CAPTION>
                                             TWELVE MONTHS
                                                  ENDED       NINE MONTHS ENDED
                                            DECEMBER 31, 1996  DECEMBER 31, 1995
                                           ------------------ ------------------
     <S>                                   <C>                <C>
     Phillips Petroleum Company...........       $ 88.7             $ 44.4
     Mitsubishi Corporation...............         61.0               49.6
     Indonesian Government................        123.1              102.4
</TABLE>
 
  The Company does not believe that the loss of Mitsubishi Corporation or
Phillips Petroleum Company 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 subsidiaries 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 SIX--TAXES
 
  Income (loss) before income taxes was comprised of income (loss) from:
 
<TABLE>
<CAPTION>
                                          TWELVE MONTHS ENDED NINE MONTHS ENDED
                                           DECEMBER 31, 1996   DECEMBER 31, 1995
                                          ------------------- ------------------
     <S>                                  <C>                 <C>
     United States.......................       $(80.6)            $(125.9)
     Foreign.............................        178.8                61.3
                                                ------             -------
                                                $ 98.2             $ (64.6)
                                                ======             =======
</TABLE>
 
                                     F-42
<PAGE>
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
  The Company's provision/(benefit) for income taxes was comprised of the
following:
 
<TABLE>
<CAPTION>
                                           TWELVE MONTHS ENDED NINE MONTHS ENDED
                                            DECEMBER 31, 1996  DECEMBER 31, 1995
                                           ------------------- -----------------
     <S>                                   <C>                 <C>
     Current
       Federal............................       $  2.6             $ (7.9)
       Foreign............................        101.2               64.9
       State and local....................         (5.0)               1.3
                                                 ------             ------
                                                   98.8               58.3
     Deferred
       Federal............................        (20.4)             (15.2)
       Foreign............................          (.8)             (34.0)
                                                 ------             ------
                                                  (21.2)             (49.2)
                                                 ------             ------
     Provision for income taxes...........       $ 77.6             $  9.1
                                                 ======             ======
</TABLE>
 
  As a result of signing the production sharing contract in Ecuador in 1996
(See Note Twenty-Two), foreign deferred tax expense was reduced by $3.5
million.
 
  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:
 
<TABLE>
<CAPTION>
                                         TWELVE MONTHS ENDED NINE MONTHS ENDED
                                          DECEMBER 31, 1996  DECEMBER 31, 1995
                                         ------------------- -----------------
     <S>                                 <C>                 <C>
     Tax expense (benefit) at statutory
      federal rate......................       $ 34.4             $(22.6)
     Increase (reduction) resulting
      from:
       Taxes on foreign income..........         65.0               19.8
       Asset sales......................          2.0                1.5
       Non-deductible depreciation and
        amortization of net purchase
        price adjustments...............          4.7                4.4
       Valuation allowance..............        (24.6)              11.7
       Audit settlements and other
        changes in tax position.........         (3.6)              (5.0)
       Other, net.......................          (.3)               (.7)
                                               ------             ------
       Provision for income taxes.......       $ 77.6             $  9.1
                                               ======             ======
</TABLE>
 
 
                                      F-43
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities as of
December 31, 1996 and 1995, were as follows:
 
<TABLE>
<CAPTION>
                                                               NINE MONTHS ENDED
                                           TWELVE MONTHS ENDED    DECEMBER 31,
                                            DECEMBER 31, 1996        1995
                                           ------------------- -----------------
     <S>                                   <C>                 <C>
     U. S. deferred tax liabilities
       Properties and equipment..........        $ 241.7            $ 296.3
       Discount on long-term debt........           35.2               38.7
       Other.............................            2.4
                                                 -------            -------
         Deferred U. S. tax liabilities..          279.3              335.0
                                                 -------            -------
     U. S. deferred tax assets
       Foreign deferred taxes............         (133.5)            (139.8)
       Book accruals.....................          (33.2)             (68.4)
       Interest limitation
        carryforwards....................                             (16.4)
       Loss carryforwards................          (46.0)             (72.7)
       Credit carryforwards..............          (20.6)             (19.9)
       Other.............................           (4.3)              (7.1)
                                                 -------            -------
         Gross deferred U. S. tax as-
          sets...........................         (237.6)            (324.3)
                                                 -------            -------
       Valuation allowance...............           64.4               87.1
                                                 -------            -------
         Net deferred U. S. tax assets...         (173.2)            (237.2)
                                                 -------            -------
         Net deferred U. S. taxes........          106.1               97.8
                                                 -------            -------
     Foreign deferred tax liabilities
       Properties and equipment..........          381.4              446.5
                                                 -------            -------
         Net deferred foreign taxes......          381.4              446.5
                                                 -------            -------
     Net deferred taxes..................        $ 487.5            $ 544.3
                                                 =======            =======
</TABLE>
 
  As a result of a decrease in U. S. net operating loss carryforwards, the
valuation allowance was decreased $22.7 million during the twelve months ended
December 31, 1996.
 
  At December 31, 1996, the Company had $13.5 million of general business
credit carryforwards that expire between 1997 and 2002; $132.1 million of U.
S. net operating loss carryforwards that expire from 2004 to 2010 and $7.1
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 $6.6 million for which no provision was necessary for
foreign withholding or other income taxes because that amount had been
reinvested in properties and equipment and working capital.
 
  On August 13, 1996, the Company became a member of an affiliated group of
corporations having YPF Holdings, Inc., as common U. S. parent, and which will
file a consolidated federal income tax return (See Note Three). As a member of
the group, the Company is jointly and severally liable for the consolidated
federal income tax liability of the group. The Company and its subsidiaries
may also be included in certain state and local income or franchise tax
returns of members of the group.
 
                                     F-44
<PAGE>
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
  Taxes other than income taxes were comprised of the following:
 
<TABLE>
<CAPTION>
                                           TWELVE MONTHS ENDED NINE MONTHS ENDED
                                            DECEMBER 31, 1996  DECEMBER 31, 1995
                                           ------------------- -----------------
     <S>                                   <C>                 <C>
     Gross Production.....................        $ 7.8              $4.1
     Real and Personal Property...........          5.2               5.2
     Other................................          1.0                .4
                                                  -----              ----
                                                  $14.0              $9.7
                                                  =====              ====
</TABLE>
 
NOTE SEVEN--POSTEMPLOYMENT BENEFIT
 
 Pensions
 
  The components of net periodic pension expense are as follows:
 
<TABLE>
<CAPTION>
                                         TWELVE MONTHS ENDED NINE MONTHS ENDED
                                          DECEMBER 31, 1996  DECEMBER 31, 1995
                                         ------------------- -----------------
     <S>                                 <C>                 <C>
     Service cost for benefits earned
      during the period.................        $ 2.1             $  1.4
     Interest cost on projected benefit
      obligation........................          8.9                6.5
     Actual return on plan assets.......         (9.1)             (13.4)
     Net amortization and deferrals.....           .4                7.4
                                                -----             ------
                                                $ 2.3             $  1.9
                                                =====             ======
</TABLE>
 
  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 dates, October 1, 1996 and 1995, were as follows:
 
<TABLE>
<CAPTION>
                                                                      1996  1995
                                                                      ----- ----
     <S>                                                              <C>   <C>
     Discount rate................................................... 7.75% 7.5%
     Expected long-term rate of return on plan assets................  9.0% 9.0%
     Rate of increase in compensation levels.........................  4.5% 4.5%
</TABLE>
 
  The funded status of the plans at December 31, 1996 and 1995 were as follows:
 
<TABLE>
<CAPTION>
                                    DECEMBER 31, 1996                        DECEMBER 31, 1995
                                        PLANS WITH                               PLANS WITH
                         ---------------------------------------- ----------------------------------------
                            ACCUMULATED            ASSETS            ACCUMULATED            ASSETS
                         BENEFITS EXCEEDING EXCEEDING ACCUMULATED BENEFITS EXCEEDING EXCEEDING ACCUMULATED
                               ASSETS             BENEFITS              ASSETS             BENEFITS
                         ------------------ --------------------- ------------------ ---------------------
<S>                      <C>                <C>                   <C>                <C>
Actuarial present value
 of:
  Vested benefit
   obligation...........       $25.0                $82.9               $111.7               $1.1
                               -----                -----               ------               ----
  Accumulated benefit
   obligation...........       $28.0                $85.8               $117.6               $1.1
                               -----                -----               ------               ----
  Projected benefit
   obligation...........       $33.8                $85.8               $122.6               $1.1
Plan assets at fair
 value..................        23.9                 93.6                102.8                1.3
                               -----                -----               ------               ----
Plan assets (less) more
 than projected benefit
 obligation.............       $(9.9)               $ 7.8               $(19.8)              $ .2
Unrecognized net loss
 (gain).................         7.6                 (7.8)                10.1
Adjustment required to
 recognize minimum
 liability..............         (.2)                                     (5.9)
                               -----                -----               ------               ----
Prepaid (accrued)
 pension cost...........       $(2.5)               $                   $(15.6)              $ .2
                               =====                =====               ======               ====
</TABLE>
 
                                      F-45
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
  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, 1996 and 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 $.2 million and
$5.9 million and a charge to equity of $.2 million and $5.9 million at
December 31, 1996 and 1995, respectively.
 
  The Company also has a defined contribution plan which covers Indonesian
nationals. In addition to employee contributions of 2% of each covered
employee's compensation, the Company contributes 6% of such employees'
compensation to the plan. The Company's contributions to the plan were $.4
million for 1996 and $.4 million in the last three quarters of 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 twelve
months ended December 31, 1996 and for the nine months ended December 31, 1995
are as follows:
 
<TABLE>
<CAPTION>
                                           TWELVE MONTHS ENDED NINE MONTHS ENDED
                                            DECEMBER 31, 1996  DECEMBER 31, 1995
                                           ------------------- -----------------
     <S>                                   <C>                 <C>
     Service cost for benefits earned
      during the period..................         $ .3               $ .3
     Interest cost on accumulated
      postretirement benefit obligation..          3.0                2.6
                                                  ----               ----
                                                  $3.3               $2.9
                                                  ====               ====
</TABLE>
 
  The Company's current policy is to fund postretirement health care benefits
on a pay-as-you-go basis as in prior years.
 
  The APBO as of December 31, 1996 was $41.7 million. The amount recognized in
the Company's statement of financial position at December 31, 1996 and 1995,
is as follows:
 
<TABLE>
<CAPTION>
                                                      DECEMBER 31, DECEMBER 31,
                                                          1996         1995
                                                      ------------ ------------
     <S>                                              <C>          <C>
     Retirees........................................    $36.4        $39.9
     Fully eligible active employees.................      1.8          2.3
     Other active employees..........................      3.5          4.4
     Total APBO......................................     41.7         46.6
     Unrecognized net gain (loss) and changes in
      assumptions....................................      2.8         (1.6)
     Prior year service cost.........................       .6
                                                         -----        -----
     Net postretirement benefit liability............    $45.1        $45.0
                                                         =====        =====
</TABLE>
 
                                     F-46
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
  A discount rate of 7.75% was used in determining the APBO at December 31,
1996. 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 2004 and remaining 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, 1996 by $3.4 million and increase the net periodic
postretirement benefit cost by $.3 million per year.
 
NOTE EIGHT--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 $1.0
million and $2.3 million at December 31, 1996 and December 31, 1995,
respectively. Such unrealized gain has not been reflected in the accompanying
Consolidated Balance Sheet as the Company has classified these investments as
held-to-maturity in accordance with Statement of Financial Accounting Standard
No. 115, "Accounting for Certain Investments In Debt and Equity Securities."
 
 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:
 
<TABLE>
<CAPTION>
                                                         DECEMBER 31, 1996
                                                     --------------------------
                                                     CARRYING AMOUNT FAIR VALUE
                                                     --------------- ----------
     <S>                                             <C>             <C>
     ASSETS
       Restricted cash, including current and long-
        term portion................................    $   33.8      $   34.8
     LIABILITIES
       Long-term debt, including current portion....     1,270.7       1,415.4
       $9.75 Preferred Stock........................        62.5          62.6
<CAPTION>
                                                         DECEMBER 31, 1995
                                                     --------------------------
                                                     CARRYING AMOUNT FAIR VALUE
                                                     --------------- ----------
     <S>                                             <C>             <C>
     ASSETS
       Restricted cash, including current and long-
        term portion................................    $   80.4      $   82.7
     LIABILITIES
       Long-term debt, including current portion....     1,295.5       1,408.7
       $9.75 Preferred Stock........................       125.0         125.8
</TABLE>
 
  For information on the Company's derivative financial instruments, see Note
Fourteen.
 
                                     F-47
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
NOTE NINE--RECEIVABLES
 
<TABLE>
<CAPTION>
                                            DECEMBER 31, 1996 DECEMBER 31, 1995
                                            ----------------- -----------------
     <S>                                    <C>               <C>
     Trade receivables.....................      $157.9            $101.4
     Notes and other receivables...........        36.4              41.3
     Receivable from YPF for generator
      sale.................................         5.4
     Less--Allowance for doubtful receiv-
      ables................................          .7                .9
                                                 ------            ------
                                                 $199.0            $141.8
                                                 ======            ======
</TABLE>
 
NOTE TEN--PROPERTIES AND EQUIPMENT
 
<TABLE>
<CAPTION>
                                            DECEMBER 31, 1996 DECEMBER 31, 1995
                                            ----------------- -----------------
     <S>                                    <C>               <C>
     Proved properties.....................     $1,618.1          $1,512.6
     Unproved properties...................        453.3             768.8
     Gas plants and other..................        244.6             208.8
                                                --------          --------
     Total Oil and Gas.....................      2,316.0           2,490.2
     Corporate.............................          5.3              13.3
                                                --------          --------
                                                 2,321.3           2,503.5
     Less--Accumulated depreciation,
      depletion and amortization...........        299.1             139.9
                                                --------          --------
                                                $2,022.2          $2,363.6
                                                ========          ========
</TABLE>
 
  The charge against earnings for depreciation, depletion and amortization of
property and equipment was $168.9 million and $142.1 million for the twelve
months ended December 31, 1996 and for the nine months ended December 31, 1995
and the charge against earnings for maintenance and repairs, which is included
in operating expenses, was $32.2 million and $25 million, respectively.
 
NOTE ELEVEN--RESTRICTED CASH
 
  At December 31, 1996, the Company had $33.8 million in restricted cash of
which $.6 million represented collateral for outstanding letters of credit and
$33.2 million represented assets held in trust as required by certain
insurance policies. At December 31, 1996, approximately $7.3 million of assets
held in trust as required by certain insurance policies were classified as a
current asset. 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, $7.4 million represented six months of interest on
outstanding borrowings as required by a credit agreement and $42.3 million
represented assets held in trust as required by certain insurance policies. At
December 31, 1995, approximately $19.0 million of collateral for outstanding
letters of credit were classified as a current asset.
 
NOTE TWELVE--ACCRUED LIABILITIES
 
<TABLE>
<CAPTION>
                                             DECEMBER 31, 1996 DECEMBER 31, 1995
                                             ----------------- -----------------
     <S>                                     <C>               <C>
     Accrued interest payable..............       $ 21.6            $ 24.2
     Joint interest billings for interna-
      tional operations....................         37.0              41.7
     Merger reserve........................         12.8              31.4
     Environmental reserve.................         27.4              28.5
     Overlift payable......................         15.6               6.6
     Postretirement and postemployment ben-
      efits................................          4.5               4.5
     Accrued compensation, benefits and
      withholdings.........................          6.0               8.1
     Other.................................         33.1              28.4
                                                  ------            ------
                                                  $158.0            $173.4
                                                  ======            ======
</TABLE>
 
                                     F-48
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
NOTE THIRTEEN--LONG-TERM DEBT AND CREDIT ARRANGEMENTS
 
<TABLE>
<CAPTION>
                                                    DECEMBER 31, 1996
                                          -------------------------------------
                                                     UNAMORTIZED
                                          FACE VALUE  DISCOUNT   CARRYING VALUE
                                          ---------- ----------- --------------
     <S>                                  <C>        <C>         <C>
     Senior Indebtedness
      Sinking Fund Debentures
       11 1/4% due 2013, effective rate
        13.45%...........................  $   16.9    $  2.5       $   14.4
       11 1/2% due 2001-2015, effective
        rate 13.82%......................     109.6      14.5           95.1
       8 1/2% due 1998-2008, effective
        rate 12.60%......................      93.8      16.0           77.8
     Notes
       9 7/8% due 2002, effective rate
        12.26%...........................     247.8      24.0          223.8
       9 1/2% due 2003, effective rate
        12.22%...........................     100.0      11.5           88.5
       9 3/8% due 2003, effective rate
        12.03%...........................     260.0      31.6          228.4
     Medium-term notes...................     110.6        .1          110.5
     Midgard Facility....................     250.0                    250.0
     Advances from parent................     182.2                    182.2
                                           --------    ------       --------
       Total senior indebtedness.........   1,370.9     100.2        1,270.7
     Less--current portion...............      54.1                     54.1
                                           --------    ------       --------
                                           $1,316.8    $100.2       $1,216.6
                                           ========    ======       ========
<CAPTION>
                                                    DECEMBER 31, 1995
                                          -------------------------------------
                                                     UNAMORTIZED
                                          FACE VALUE  DISCOUNT   CARRYING VALUE
                                          ---------- ----------- --------------
     <S>                                  <C>        <C>         <C>
     Senior Indebtedness
      Sinking Fund Debentures
       11 1/4% due 2013, effective rate
        13.45%...........................  $   16.9    $  2.5       $   14.4
       11 1/2% due 2001-2015, effective
        rate 13.82%......................     109.6      15.0           94.6
       8 1/2% due 1998-2008, effective
        rate 12.60%......................      93.8      17.7           76.1
     Notes
       9 7/8% due 2002, effective rate
        12.26%...........................     247.8      26.7          221.1
       9 1/2% due 2003, effective rate
        12.22%...........................     100.0      12.7           87.3
       9 3/8% due 2003, effective rate
        12.03%...........................     260.0      34.5          225.5
     Medium-term notes...................     144.9        .1          144.8
     Bank and other loans................        .1                       .1
     Midgard Facility....................     250.0                    250.0
     Indonesian Facility.................     175.0                    175.0
     Advances from parent................       6.6                      6.6
                                           --------    ------       --------
       Total senior indebtedness.........   1,404.7     109.2        1,295.5
     Less--current portion...............      34.3                     34.3
                                           --------    ------       --------
                                           $1,370.4    $109.2       $1,261.2
                                           ========    ======       ========
</TABLE>
 
  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. For the twelve months ended December 31, 1996 and
the nine months ended
 
                                     F-49
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
December 31, 1995, discount amortization of $9.0 million and $5.9 million,
respectively, was included as a component of interest expense.
 
  The aggregate maturities of long-term debt outstanding at December 31, 1996
for the next five years will be as follows:
 
<TABLE>
     <S>                                                                   <C>
     1997................................................................. $54.1
     1998.................................................................  60.5
     1999.................................................................  48.5
     2000.................................................................  46.0
     2001.................................................................  54.1
</TABLE>
 
  At December 31, 1996, the Company had $110.5 million of medium-term notes
outstanding, which were issued in prior years, with maturities from 1997 to
2004 and annual interest rates ranging from 7.57% to 11.08%.
 
  The Company maintains three credit facilities which are used for the
issuance of documentary or standby letters of credit. At December 31, 1996,
there were $.6 million of cash collateralized letters of credit outstanding
under an uncommitted credit facility. Also, at December 31, 1996, there were
$9.1 million of letters of credit outstanding under an uncommitted credit
facility of $10.0 million which is backed by a YPF guaranty. Finally, at
December 31, 1996, there were $11.5 million of letters of credit outstanding
under a committed credit facility of $40 million, which is also backed by a
YPF guaranty.
 
  During 1996, the Company repaid $34.2 million of medium-term notes maturing
in 1996. To fund this repayment, the Company used a portion of the proceeds
from the sale of the outstanding shares of capital stock of an indirect,
wholly owned subsidiary of Maxus (See Note Three).
 
  Total interest and debt expenses incurred, including capitalized interest,
were as follows:
 
<TABLE>
<CAPTION>
                                           TWELVE MONTHS ENDED NINE MONTHS ENDED
                                            DECEMBER 31, 1996  DECEMBER 31, 1995
                                           ------------------- -----------------
     <S>                                   <C>                 <C>
     Interest and debt expenses...........       $134.6             $104.9
     Capitalized interest.................          1.6                1.4
                                                 ------             ------
                                                 $136.2             $106.3
                                                 ======             ======
</TABLE>
 
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. ("Indonesia"), 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 Indonesia credit facilities. These costs are
recorded as deferred charges and amortized over the terms of the related
borrowings. For the twelve months ended December 31, 1996, $2.0 million of
debt issue costs amortization was included as a component of interest expense.
Such costs were $1.2 million for the nine months ended December 31, 1995.
 
                                     F-50
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
  Indonesian Facility. Approximately $175 million of the Purchaser Facility
was repaid with funds provided on June 16, 1995 to the Company by Indonesia.
Indonesia provided these funds from the proceeds of a $175 million loan (the
"Subsidiaries Loan") extended to it pursuant to a credit agreement (the
"Indonesian Facility") entered into on such date. In December 1996,
International advanced the Company $175 million in the form of a demand note
bearing 5.75% interest compounded annually, to repay the Indonesian Facility.
Unamortized debt issue costs associated with this early retirement were
recorded as an extraordinary loss of $5.6 million, net of taxes. The tax
impact of this transaction was less than $.1 million.
 
  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 quarterly
installments commencing on March 31, 1997, subject to semi-annual borrowing
base redeterminations. 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, 1996, the interest rate on the Midgard Facility based on the two-month
LIBOR plus 1 3/4% was 7.375%. 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.
 
  The Midgard 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 may not
permit (a) consolidated tangible net worth to be less than $200 million, plus
(or minus) the amount of any adjustment in the book value of assets (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 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. At December
31, 1996, the borrowing base for the Midgard Facility was $250 million. The
borrowing base is subject to redetermination on April 1, 1997. No borrowing
base deficiencies existed at December 31, 1996.
 
  The guaranty by Maxus of the obligations of Midgard under the Midgard
Facility (the "Midgard 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, is required to be
wholly owned subsidiary 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.
 
                                     F-51
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
 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 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 Facility and the
Indonesian 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. During the twelve months
ended December 31, 1996, YPF made capital contributions to the Company and CLH
(See Note Three) in the aggregate amount of $64 million and $8 million,
respectively. These amounts represent the cumulative contribution received by
Maxus and CLH from YPF pursuant to the terms of the Keepwell Covenant. Based
on current projections, it is anticipated that YPF will make capital
contributions to CLH in the aggregate amount of approximately $25 to $50
million under the Keepwell Covenant during 1997.
 
  In addition, YPF has guaranteed the Company's outstanding debt as of the
Merger Date, the principal amount of which was approximately $976 million. At
December 31, 1996, the principal amount of outstanding debt guaranteed by YPF
was approximately $939 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 (which was
redeemed in accordance with its terms on January 31, 1997).
 
 Advances from Parent
 
  At December 31, 1996 and 1995, the Company had $182.2 million and $6.6
million, respectively, outstanding in advances from parent. As discussed
above, in December 1996 the Company received a $175 million cash advance from
International to fund the early repayment of the Subsidiaries Loan. Based on
current projections, the Company anticipates that Holdings could be required
to make cash advances of approximately $150 million to $200 million during
1997.
 
  At December 31, 1996, the Company's outstanding advances from parent of
$182.2 million included a $175.3 million note payable to International. The
note is a demand note, bearing 5.75% annual compound interest. It is not
anticipated that International will request repayment of this note during
1997.
 
  The Company and YPF entered into a loan agreement (the "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. At December 31,
1996, there were no loans outstanding under the Loan Agreement. It is expected
that loans will be made by the parties under the Loan Agreement during 1997;
however, the number and amounts thereof are not presently known.
 
NOTE FOURTEEN--DERIVATIVE FINANCIAL INSTRUMENTS
 
  The Company's only derivative financial instruments are natural gas, NGL and
crude oil 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
was deferred.
 
                                     F-52
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
 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. Typically, the Company pays a variable price per million
British Thermal Units ("Mmbtu") and receives a fixed price per Mmbtu. During
the twelve months ended December 31, 1996, the Company had swap agreements
with other companies to exchange payments on 32.3 million Mmbtu of gas. Under
these swap agreements, the Company paid variable prices averaging $2.14 per
Mmbtu and received fixed prices averaging $1.79 per Mmbtu. Gross losses
realized on these swap agreements of $11.4 million were partially offset by
gross gains of $.1 million resulting in a net loss of $11.3 million. 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 variable prices averaging $1.68 per Mmbtu
and received fixed prices averaging $1.53 per Mmbtu. Gross losses realized on
these swap agreements of $2.1 million were partially offset by gross gains of
$.5 million resulting in a net loss of $1.6 million.
 
  As of December 31, 1996, the Company has outstanding price swap agreements
with other companies to exchange payments on 36.5 million Mmbtu of gas during
1997. Under these swap agreements, the Company will receive fixed prices
averaging $2.08 per Mmbtu. Actual gains and losses realized upon settlement of
these price swap agreements will depend upon the variable prices paid at the
time of settlement.
 
 Natural Gas Liquids Price Swap Agreements
 
  Under the price swap agreements used to hedge fluctuations in the price of
NGL, 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. Typically, the Company pays a variable price per barrel ("bbl")
and receives a fixed price per bbl. During the twelve months ended December
31, 1996, the Company had swap agreements with other companies to exchange
payments on 2.3 million barrels ("mmb") of NGL. Under these swap agreements,
the Company paid variable prices averaging $17.64 per bbl and received fixed
prices averaging $13.55 per bbl. Gross losses realized on these swap
agreements totaled $9.5 million during 1996. There were no NGL price swap
agreements in place during 1995.
 
  As of December 31, 1996, the Company had outstanding price swap agreements
with other companies to exchange payments on 2.5 mmb of NGL during 1997. Under
these swap agreements, the Company will receive fixed prices averaging $14.84
per bbl. Actual gains and losses realized upon settlement of these price swap
agreements will depend upon the variable prices paid at the time of
settlement.
 
 Natural Gas 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 of natural gas and the settlement price
per Mmbtu. During the twelve months ended December 31, 1996, the Company
settled futures contracts on 3.6 million Mmbtu of gas. Under these futures
contracts, the Company received selling prices averaging $2.01 per Mmbtu and
paid settlement prices averaging $2.57 per Mmbtu. Realized gross losses on
these futures contracts totaled $2.0 million during 1996. During the nine
months ended December 31, 1995, the Company settled futures contracts with
other companies on 4.9 million Mmbtu of natural 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. At December 31, 1996, the
Company had no open futures contracts.
 
                                     F-53
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
NOTE FIFTEEN--PREFERRED STOCK
 
  Maxus 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, Maxus sold 3,000,000 shares of the $9.75 Preferred Stock. Since
such time, Maxus 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, Maxus has repurchased 500,000 shares and the parties have
waived or amended various covenants, agreements and restrictions relating to
such stock. At December 31, 1996, 625,000 shares of $9.75 Preferred Stock were
outstanding, each receiving an annual cash dividend of $9.75. Pursuant to the
terms of the $9.75 Preferred Stock, on January 31, 1997, Maxus redeemed the
remaining 625,000 shares for $62.5 million.
 
 $4.00 Cumulative Convertible Preferred Stock
 
  As part of Maxus' internal reorganization (See Note Three), on August 13,
1996, Maxus redeemed all of its outstanding shares of $4.00 Preferred Stock at
a price of $50 per share plus accrued and unpaid dividends (approximately
$220.8 million in the aggregate). Prior to the redemption date, each
outstanding share of $4.00 Preferred Stock was convertible into shares of
Maxus' Common Stock (2.29751 shares at the redemption date). The excess of the
redemption price over the carrying value of the $4.00 Preferred Stock resulted
in an increase in the Company's accumulated deficit. YPF provided funding to
Maxus to redeem the $4.00 Preferred Stock.
 
 $2.50 Cumulative Preferred Stock
 
  Each outstanding share of the $2.50 Preferred Stock is entitled to receive
annual cash dividends of $2.50, is redeemable after December 1, 1998 and has a
liquidation value of $25.00 ($87.5 million in the aggregate at December 31,
1996), plus accrued but unpaid dividends, if any.
 
  The holders of the $2.50 Preferred Stock are entitled to limited voting
rights under certain conditions. In the event Maxus 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 SIXTEEN--COMMON STOCK
 
<TABLE>
<CAPTION>
                                                              SHARES     AMOUNT
                                                            -----------  ------
     <S>                                                    <C>          <C>
     April 1, 1995......................................... 135,897,899  $135.9
       Employee Savings Plan...............................      18,182
       Cancellation of treasury shares.....................    (306,307)    (.3)
       Fractional shares exchanged for cash................          (2)
                                                            -----------  ------
     December 31, 1995..................................... 135,609,772  $135.6
       Conversion of $4.00 Preferred Stock.................         229
       Shares issued to parent.............................  11,636,363    11.6
                                                            -----------  ------
     December 31, 1996..................................... 147,246,364  $147.2
                                                            ===========  ======
</TABLE>
 
  Pursuant to the Offer in April 1995, YPF acquired 120,000,613 Shares 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
 
                                     F-54
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
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 per share, and, accordingly, the Company's Common Stock ceased to be
publicly traded. (See Note Two).
 
  During 1996, YPF contributed $64 million of capital to the Company, for
which YPF received an additional 11,636,363 shares of the Company's Common
Stock at $5.50 per share. The difference between the par value of the Common
Stock and the amount of capital contributed was credited to Paid-in capital.
 
  In 1992, Kidder, Peabody Group Inc. 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 Savings Plan ("ESP") which presently allows
eligible participating employees to contribute a certain percentage of their
salaries (1%-10%) to a trust for investment in any of ten funds. Prior to the
Merger employees could invest in a fund consisting of the Company's Common
Stock. However, the Maxus Energy Stock Fund was eliminated from the ESP
effective April 19, 1995. The Company matches the participating employees
contributions to the ESP (up to 6% of base pay). Such matching contribution is
charged against earnings. For the twelve months ended December 31, 1996 and
the nine months ended December 31, 1995, the charge against earnings for the
Company's contribution was $1.9 million and $1.7 million, respectively.
 
NOTE SEVENTEEN--PAID-IN CAPITAL AND ACCUMULATED DEFICIT
 
<TABLE>
<CAPTION>
                                                             PAID-IN  ACCUMULATED
                                                             CAPITAL    DEFICIT
                                                             -------  -----------
     <S>                                                     <C>      <C>
     April 1, 1995.......................................... $118.2
       Net loss.............................................            $ (73.7)
       Dividends on Preferred Stock.........................   (9.2)
       Cancellation of treasury shares......................   (3.2)
       Employee Shareholding and Investment Plan............     .1
       Restricted stock.....................................    (.1)
                                                             ------     -------
     January 1, 1996........................................  105.8       (73.7)
       Net income...........................................               15.0
       Redemption of $4.00 Preferred Stock..................             (213.6)
       Dividends on Preferred Stock.........................  (11.3)
       Transfer of investment in CLH (See Note Three).......   69.5
       Issuance of Common Stock to parent...................   52.4
                                                             ------     -------
     December 31, 1996...................................... $216.4     $(272.3)
                                                             ======     =======
</TABLE>
 
                                     F-55
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
NOTE EIGHTEEN--UNREALIZED GAIN ON INVESTMENT IN MARKETABLE SECURITIES
 
  At December 31, 1996 and December 31, 1995, securities categorized as held-
to-maturity are included in cash equivalents and short- and long-term
restricted cash.
 
  The amortized cost and estimated fair value of marketable securities at
December 31, 1996 and 1995 are as follows:
 
<TABLE>
<CAPTION>
                                                DECEMBER 31, 1996
                                   --------------------------------------------
                                                  GROSS UNREALIZED
                                   AMORTIZED COST      GAINS       MARKET VALUE
                                   -------------- ---------------- ------------
     <S>                           <C>            <C>              <C>
     Held-to-maturity:
       Corporate and other debt
        securities................     $ 51.0           $1.0          $ 52.0
<CAPTION>
                                                DECEMBER 31, 1995
                                   --------------------------------------------
                                                  GROSS UNREALIZED
                                   AMORTIZED COST      GAINS       MARKET VALUE
                                   -------------- ---------------- ------------
     <S>                           <C>            <C>              <C>
     Held-to-maturity:
       Corporate and other debt
        securities................     $108.4           $2.3          $110.7
</TABLE>
 
NOTE NINETEEN--STOCK OPTIONS
 
  In 1996, the Company established a Stock Appreciation Rights Plan (the "SAR
Plan"). The SAR Plan permits the grant to officers and certain key employees
of Stock Appreciation Rights ("SARs"), the value of which is based upon the
price of American Depository Receipts with respect to YPF's Class D shares
("ADRs"). The excess of the ADRs market price over the grant price results 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. During 1996, the Company charged $.1 million
against earnings related to the SAR Plan.
 
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,
1996, were as follows:
 
<TABLE>
     <S>                                                                 <C>
     1997............................................................... $ 28.0
     1998...............................................................   23.2
     1999...............................................................   18.4
     2000...............................................................   15.5
     2001...............................................................   15.3
     December 31, 2002 and thereafter...................................   60.2
                                                                         ------
                                                                         $160.6
</TABLE>
 
  Minimum annual rentals have not been reduced by minimum sublease rentals of
$34.0 million due in the future under noncancelable subleases.
 
                                     F-56
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
  Rental expense for operating leases was as follows:
 
<TABLE>
<CAPTION>
                                           TWELVE MONTHS ENDED NINE MONTHS ENDED
                                            DECEMBER 31, 1996  DECEMBER 31, 1995
                                           ------------------- -----------------
     <S>                                   <C>                 <C>
     Total rentals........................        $46.2              $44.1
     Less--Sublease rental income.........          2.9                2.1
                                                  -----              -----
     Rental expense.......................        $43.3              $42.0
                                                  =====              =====
</TABLE>
 
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 $1.4 million and
$3.2 million during 1996 and 1995, respectively. Additionally, at December 31,
1996 and 1995, the Company had $182.2 million and $6.6 million outstanding,
respectively, in advances from its parent. During 1996, the Company sold
electrical generators to YPF for $5.4 million.
 
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. CERCLA imposes retroactive liability upon certain parties
for the response costs associated with cleaning up old hazardous substance
sites. CERCLA liability to the Government is joint and several. CERCLA allows
authorized trustees to seek recovery of natural resource damages from
potentially responsible parties. CERCLA also grants the Government the
authority to require potentially responsible parties to implement interim
remedies to abate an imminent and substantial endangerment to the environment.
 
  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
 
                                     F-57
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
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
$42 million as of December 31, 1996. OxyChem and Henkel, an assignee of
certain of Occidental's rights and obligations, filed a declaratory judgment
action in Texas state court with respect to the Company's agreement in this
regard. The lower court found in favor of Occidental and Henkel and the
Company has appealed the judgment (see "Legal Proceedings" below).
 
  In connection with the spin-off of Diamond Shamrock R&M, Inc., now known as
Ultramar Diamond Shamrock Corporation ("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. Thereafter, such ongoing costs were
borne one-third by DSI and two-thirds by the Company until DSI had borne an
additional $47.5 million. As of December 31, 1996, DSI had fulfilled its
remaining responsibility under the cost-sharing arrangement, and it has no
further obligation thereunder.
 
  During the twelve months ended December 31, 1996, the Company spent $8
million in environmental related expenditures in its oil and gas operations.
Expenditures for 1997 are expected to be approximately $13 million.
 
  For the seven months ended July 31, 1996, the Company's total expenditures
for environmental compliance for disposed of businesses, including Chemicals,
were approximately $13 million, $5 million of which was recovered from DSI
under the above described cost-sharing arrangement.
 
  At December 31, 1996, reserves for the environmental contingencies discussed
herein totaled $101.6 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 Company has transferred certain liabilities related to environmental
matters to CLH (See Note Three) effective as of August 1, 1996. In connection
with this transfer, CLH assumed (the "Assumption") the liabilities so
transferred and YPF committed to contribute capital to CLH up to an amount of
$106.9 million that will enable CLH to satisfy its obligations under the
Assumption based on the Company's reserves established in respect of the
assumed liabilities as of July 31, 1996 plus certain operating expenses
budgeted by CLH from time to time. YPF will not be obligated to contribute
capital to CLH beyond the amount of its initial undertaking. The Company will
remain responsible for any obligations assumed by CLH in the event CLH does
not perform or fulfill such obligations. The environmental contingencies
discussed herein and the declaratory judgment action filed by OxyChem and
Henkel are among the matters for which CLH has assumed responsibility, and the
 
                                     F-58
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
Company transferred to CLH its then remaining rights to recover costs under
the arrangement with DSI. The contribution obligation of YPF related to the
Assumption was reflected on the Company's financial statements as a long-term
and short-term funding guarantee from parent totaling $106.9 million, an
increase to deferred income taxes of $37.4 million and an increase to paid-in
capital of $69.5 million. At December 31, 1996, the outstanding funding
guarantee totaled $102.6 million. Insofar as CLH has assumed the Company's
environmental liabilities and YPF has committed to pay for the liabilities,
such liabilities are not expected to have an adverse impact on the financial
reporting books of the Company.
 
  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. The Company has entered into settlement
agreements with certain of the insurers in this second suit, the terms of
which are required to be held confidential. The Company also is engaged in
settlement discussions with other defendant insurers; however, there can be no
assurance that such discussions will result in settlements with such other
insurers.
 
  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 late 1997 or in 1998,
cost approximately $23 million and take three to four years to complete. The
work is being supervised and paid for by CLH, on behalf of the Company
pursuant to the Assumption and under the Company's above described
indemnification obligation to Occidental. The Company has 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. These studies suggest that the older and more
contaminated sediments located adjacent to the Newark plant generally are
buried under more recent sediment deposits. The Company, on behalf of
Occidental, negotiated an agreement with the EPA under which CLH, on the
Company's behalf, is conducting further testing and studies to characterize
contaminated sediment and biota in a six-mile portion of the Passaic River
near the plant site. The stability of the sediments in the entire six-mile
portion of the Passaic River study area is also being examined as a part of
CLH's studies. The Company currently expects the testing and studies to be
completed in 1999 and cost from $4 million to $6 million after December 31,
1996. The Company has reserved for the amount of its estimate of the remaining
costs to be incurred in performing these studies. The Company and later CLH
have been conducting similar studies under their 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. However, it is
possible that additional work, including interim remedial measures, may be
ordered with respect to the Passaic River.
 
                                     F-59
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
 
  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 and near 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 presently being
performed by CLH on behalf of the Company and Occidental, and CLH is funding
Occidental's share of the cost of investigation and remediation of these
sites. The Company 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 and
CLH have participated in the cost of studies and CLH is implementing interim
remedial actions and conducting remedial investigations and feasibility
studies, the ultimate cost of remediation is uncertain. The Company
anticipates CLH will submit its remedial investigation and feasibility study
report to the DEP in 1997. The results of the DEP's review of this report
could increase 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 approximately $47 million at
December 31, 1996. 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 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 $5 million to $8 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 reserved for the amount of its 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. The Company's obligations regarding the Chrome
Plant described above have been assumed by CLH pursuant to the Assumption.
 
  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
 
                                     F-60
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
been completed are being maintained and monitored to insure continued
compliance with applicable laws and regulatory programs. The Company has
reserved for its estimated costs related to these sites, none of which is
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. The matters described below are among those for
which CLH has assumed responsibility under the Assumption.
 
  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. 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.
 
  3. Chemical Control Site; Elizabeth, New Jersey. The PRPs and the EPA have
settled the federal claims for cost recovery and site remediation, and
remediation is now complete. The DEP has demanded of PRPs
 
                                     F-61
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
(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. 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 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 court denied the Company's motion for summary judgment and granted
OxyChem's and Henkel's joint motion for summary judgment, thereby granting
OxyChem and Henkel the declaration they sought. The Company believes the
court's orders are erroneous and has appealed.
 
  The Company has established reserves based on its 50% share of remaining
costs expected to be paid or incurred by OxyChem and Henkel prior to September
4, 1996, the tenth anniversary of the Closing Date. As of December 31, 1996,
the Company and CLH on its behalf had paid OxyChem and Henkel a total of
approximately $42 million against the $75 million cap and, based on OxyChem's
and Henkel's historical annual expenditures, the Company had approximately $4
million reserved. The Company cannot predict with any certainty what portion
of the approximately $29 million unreserved portion of the $33 million amount
remaining at December 31, 1996, OxyChem and Henkel may incur; however, OxyChem
and Henkel have asserted in court that the entire amount will be spent. In the
event that the Company does not prevail in its appeal, it could be required to
pay up to approximately $29 million in additional costs which have not been
reserved related to this indemnification. CLH has assumed, pursuant to the
Assumption, responsibility for this litigation.
 
  The Company has established reserves for legal contingencies in situations
where a loss is probable and can be reasonably estimated.
 
  On August 10, 1996, a new Government was inaugurated in Ecuador and on
August 20, 1996, the new Energy Minister announced his intention to cancel the
Company's risk service contract unless the Company and the other members of
its consortium for the Block 16 project ("Block 16") agreed to convert such
contract into a production sharing contract. Effective January 1, 1997, the
Company and the Government entered into a new contract governing Block 16. The
principal difference between the two contracts is the manner in which the
consortium's costs in the Block are recovered. Under the former contract, the
Company had the right to recover its investment before the Government began to
share in significant proceeds from the sale of production; under the new
contract, the Government receives a royalty, and the Company's recovery of its
investment is out of the proceeds after deducting such royalty. Previous
Governments had signaled their dissatisfaction with the former arrangement and
in recent years a series of auditing, contract administration and
certification of new field disputes had arisen that made it increasingly
difficult to develop Block 16. Partly in response to these difficulties, the
Company reduced its 1996 program spending on Block 16 to $17 million from $32
million in 1995.
 
  The new contract also resolves certain outstanding disputes and amends the
prior agreement in various other ways, some of which are expected to
significantly improve the Company's current and future operating costs. The
Company believes that the new contract permits the Company to go forward with
the development of Block 16 and permits it to do so on a more cost-effective
basis, subject to the eventual permanent increase of
 
                                     F-62
<PAGE>
 
                           MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
pipeline capacity discussed below. Based on the terms of the newly approved
contract and events which have transpired since such approval, no write down
of carrying value of the Block is required. During 1996, pipeline capacity
available to the Company was sufficient to transport only about 60 to 80% of
the oil which the Company produced daily in Ecuador. Due to the decreased
usage by PetroEcuador, however, pipeline capacity has presently been available
to transport close to 100% of the oil which the Company produces daily. It is
not known whether this availability is temporary and, if permanent, whether it
will be adequate to accommodate expected increased production in mid-1997.
Additionally, the Ecuadorian Government has announced its intention to solicit
bids in early 1997 for the construction of a new pipeline system and expects
completion of the pipeline within 18 to 24 months from the date of execution
of a contract. It is unknown what impact, if any, a recent change in the
country's political leadership will have on these plans to solicit such bids.
 
  The Company has entered 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 changes in governments, civil
strife, acts of war, guerrilla activities and insurrection. Areas in which the
Company has significant operations include the United States, Indonesia and
Ecuador.
 
NOTE TWENTY-THREE--SUBSEQUENT EVENTS
 
  Midgard has signed a letter of intent with Amoco Production Company
("Amoco") concerning the establishment of a partnership with regard to
Midgard's business and assets. It is anticipated that Midgard and Amoco will
each contribute to the partnership oil and gas properties in the Texas
Panhandle and western Oklahoma and that Amoco will contribute certain other
assets. Midgard and Amoco have commenced negotiations of definitive agreements
covering the partnership. However, no definitive agreements have been entered
into, and consequently no assurances can be given that the attempts to
establish the partnership will be successful.
 
                                     F-63
<PAGE>
 
                      FINANCIAL SUPPLEMENTARY INFORMATION
                                  (UNAUDITED)
  (Data is for the twelve months ended December 31, 1996 and 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 twelve months ended December 31, 1996 and 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.
 
<TABLE>
<CAPTION>
                                      TWELVE MONTHS ENDED DECEMBER 31, 1996
                          -------------------------------------------------------------
                          UNITED STATES INDONESIA SOUTH AMERICA OTHER FOREIGN WORLDWIDE
                          ------------- --------- ------------- ------------- ---------
<S>                       <C>           <C>       <C>           <C>           <C>
Sales...................     $131.6      $403.9       $81.3                    $616.8
                             ------      ------       -----         -----      ------
Production costs........       32.2       147.0        20.6                     199.8
Exploration costs.......        8.8        14.6         4.0         $ 7.7        35.1
Depreciation, depletion
 and amortization.......       51.5        87.0        25.8            .2       164.5
Loss on sale of assets..         .2                     1.5                       1.7
Other...................       13.3(a)     (2.4)        (.1)          (.1)       10.7
                             ------      ------       -----         -----      ------
                              106.0       246.2        51.8           7.8       411.8
                             ------      ------       -----         -----      ------
Income (loss) before tax
 provision..............       25.6       157.7        29.5          (7.8)      205.0
Provision (benefit) for
 income taxes...........         .5        89.9        12.3           (.2)      102.5
                             ------      ------       -----         -----      ------
Results of operations...     $ 25.1      $ 67.8       $17.2         $(7.6)     $102.5
                             ======      ======       =====         =====      ======
</TABLE>
 
<TABLE>
<CAPTION>
                                       NINE MONTHS ENDED DECEMBER 31, 1995
                          -------------------------------------------------------------
                          UNITED STATES INDONESIA SOUTH AMERICA OTHER FOREIGN WORLDWIDE
                          ------------- --------- ------------- ------------- ---------
<S>                       <C>           <C>       <C>           <C>           <C>
Sales...................     $ 75.4      $298.3      $ 36.5                    $410.2
                             ------      ------      ------        ------      ------
Production costs........       21.2       114.5        21.5                     157.2
Exploration costs.......       10.8        18.0         6.9        $ 15.5        51.2
Depreciation, depletion
 and amortization.......       48.8        67.7        20.8            .2       137.5
Gain on sale of assets..        (.1)                                              (.1)
Other...................        8.5(a)      9.4        (1.2)          (.1)       16.6
                             ------      ------      ------        ------      ------
                               89.2       209.6        48.0          15.6       362.4
                             ------      ------      ------        ------      ------
Income (loss) before tax
 provision..............      (13.8)       88.7       (11.5)        (15.6)       47.8
Provision (benefit) for
 income taxes...........                   43.5       (12.7)                     30.8
                             ------      ------      ------        ------      ------
Results of operations...     $(13.8)     $ 45.2      $  1.2        $(15.6)     $ 17.0
                             ======      ======      ======        ======      ======
</TABLE>
--------
(a) Includes United States gathering and processing costs related to sales.
    Such costs were $13.8 million for the twelve months ended December 31,
    1996 and $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
 
                                     F-64
<PAGE>
 
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 56% 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, 1996 and 1995
were:
 
<TABLE>
<CAPTION>
                                                UNITED STATES     INDONESIA
                                                ------------- -----------------
                                                 1996   1995    1996     1995
                                                ------ ------ -------- --------
<S>                                             <C>    <C>    <C>      <C>
Proved properties:
  Wells and related equipment and facilities... $591.9 $501.6 $  761.7 $  704.0
  Support equipment and facilities.............  176.5  128.7
  Uncompleted well, equipment and facilities...   17.9   11.0     17.2     18.6
  Unproved properties..........................    4.1   79.9    445.1    435.3
                                                ------ ------ -------- --------
                                                 790.4  721.2  1,224.0  1,157.9
                                                ------ ------ -------- --------
Less--Accumulated depreciation, depletion and
 amortization..................................  104.4   50.4    154.7     67.7
                                                ------ ------ -------- --------
                                                $686.0 $670.8 $1,069.3 $1,090.2
                                                ====== ====== ======== ========
</TABLE>
 
<TABLE>
<CAPTION>
                                  SOUTH AMERICA OTHER FOREIGN     WORLDWIDE
                                  ------------- ------------- -----------------
                                   1996   1995   1996   1995    1996     1995
                                  ------ ------ ------ ------ -------- --------
<S>                               <C>    <C>    <C>    <C>    <C>      <C>
Proved properties:
  Wells and related equipment and
   facilities.................... $264.5 $307.0               $1,618.1 $1,512.6
  Support equipment and
   facilities....................                                176.5    128.7
  Uncompleted well, equipment and
   facilities....................   33.0   50.5                   68.1     80.1
  Unproved properties............         252.3 $  4.2 $  1.3    453.4    768.8
                                  ------ ------ ------ ------ -------- --------
                                   297.5  609.8    4.2    1.3  2,316.1  2,490.2
                                  ------ ------ ------ ------ -------- --------
Less--Accumulated depreciation,
 depletion and amortization......   38.7   20.9     .4     .2    298.2    139.2
                                  ------ ------ ------ ------ -------- --------
                                  $258.8 $588.9 $  3.8 $  1.1 $2,017.9 $2,351.0
                                  ====== ====== ====== ====== ======== ========
</TABLE>
 
COSTS INCURRED
 
  Costs incurred by the Company in its oil and gas producing activities for
the twelve months ended December 31, 1996 and the nine months ended December
31, 1995 (whether capitalized or charged against earnings) were as follows:
 
<TABLE>
<CAPTION>
                                                      UNITED STATES  INDONESIA
                                                      ------------- -----------
                                                       1996   1995  1996  1995
                                                      ------ ------ ----- -----
<S>                                                   <C>    <C>    <C>   <C>
Property acquisition costs........................... $  3.2 $  2.1
Exploration costs....................................    9.9   10.1 $14.9 $19.8
Development costs....................................   55.1   37.5  67.3  44.2
                                                      ------ ------ ----- -----
                                                      $ 68.2 $ 49.7 $82.2 $64.0
                                                      ====== ====== ===== =====
</TABLE>
 
<TABLE>
<CAPTION>
                                       SOUTH AMERICA OTHER FOREIGN   WORLDWIDE
                                       ------------- ------------- -------------
                                        1996   1995   1996   1995   1996   1995
                                       ------ ------ ------ ------ ------ ------
<S>                                    <C>    <C>    <C>    <C>    <C>    <C>
Property acquisition costs............ $ 27.3                      $ 30.5 $  2.1
Exploration costs.....................   11.2 $  7.6 $ 10.3 $ 15.7   46.3   53.2
Development costs.....................   19.2   28.2     .6     .3  142.2  110.2
                                       ------ ------ ------ ------ ------ ------
                                       $ 57.7 $ 35.8 $ 10.9 $ 16.0 $219.0 $165.5
                                       ====== ====== ====== ====== ====== ======
</TABLE>
 
                                     F-65
<PAGE>
 
OIL AND GAS RESERVES
 
  The following table represents the Company's net interest in estimated
quantities of developed and undeveloped reserves of crude oil, condensate,
natural gas liquids and natural gas and changes in such quantities for the
twelve months ended December 31, 1996 and 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, 1996 and 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.
 
<TABLE>
<CAPTION>
                                DECEMBER 31, 1996                    DECEMBER 31, 1995
                          -----------------------------------  -----------------------------------
                          UNITED              SOUTH            UNITED              SOUTH
       CRUDE OIL          STATES INDONESIA   AMERICA    TOTAL  STATES INDONESIA   AMERICA    TOTAL
       ---------          ------ ---------   -------    -----  ------ ---------   -------    -----
                                              (MILLIONS OF BARRELS)
<S>                       <C>    <C>         <C>        <C>    <C>    <C>         <C>        <C>
Net Proved Developed and
 Undeveloped Reserves
Beginning of period,
 April 1, 1995 or
 January 1, 1996........   4.1     144.1       61.1     209.3   3.7     154.1      66.3      224.1
  Revisions of previous
   estimates............    .6     (15.6)(a)    5.4      (9.6)   .2      (2.6)(a)  (4.5)      (6.9)
  Purchase of reserves
   in place.............
  Extensions,
   discoveries and other
   additions............   1.0       8.4 (a)   12.0      21.4    .5       7.1 (a)   2.7       10.3
  Production............   (.5)    (15.9)      (4.4)(c) (20.8)  (.3)    (14.5)     (3.4)(c)  (18.2)
  Sales of reserves in
   place................                      (12.1)    (12.1)
                           ---     -----      -----     -----   ---     -----      ----      -----
End of period...........   5.2     121.0       62.0     188.2   4.1     144.1      61.1      209.3
                           ---     -----      -----     -----   ---     -----      ----      -----
Net Proved Developed
 Reserves
Beginning of period.....   3.6     128.1       32.8     164.5   2.8     136.8      14.0      153.6
End of period...........   4.9      99.1       25.1     129.1   3.6     128.1      32.8      164.5
                           ===     =====      =====     =====   ===     =====      ====      =====
</TABLE>
 
 
                                     F-66
<PAGE>
 
<TABLE>
<CAPTION>
                                   DECEMBER 31, 1996       DECEMBER 31, 1995
                                 ----------------------  ----------------------
                                 UNITED                  UNITED
         NATURAL GAS(B)          STATES INDONESIA TOTAL  STATES INDONESIA TOTAL
         --------------          ------ --------- -----  ------ --------- -----
                                           (BILLIONS OF CUBIC FEET)
<S>                              <C>    <C>       <C>    <C>    <C>       <C>
Net Proved Developed and
 Undeveloped Reserves
Beginning of period,
 April 1, 1995 or January 1,
 1996...........................  570      313      883   505      300     805
  Revisions of previous
   estimates....................   83       15       98     7       18      25
  Purchase of reserves in
   place........................    2                 2
  Extensions, discoveries and
   other additions..............   91       12      103    94       14     108
  Production....................  (53)     (30)     (83)  (36)     (19)    (55)
  Sales of reserves in place
                                  ---      ---    -----   ---      ---     ---
End of period...................  693      310    1,003   570      313     883
                                  ---      ---    -----   ---      ---     ---
Net Proved Developed Reserves
Beginning of period.............  449      138      587   373      103     476
End of period...................  573      136      709   449      138     587
                                  ===      ===    =====   ===      ===     ===
</TABLE>
 
<TABLE>
<CAPTION>
                                    DECEMBER 31, 1996       DECEMBER 31, 1995
                                  ----------------------  ----------------------
                                  UNITED                  UNITED
       NATURAL GAS LIQUIDS        STATES INDONESIA TOTAL  STATES INDONESIA TOTAL
       -------------------        ------ --------- -----  ------ --------- -----
                                              (MILLIONS OF BARRELS)
<S>                               <C>    <C>       <C>    <C>    <C>       <C>
Net Proved Developed and
 Undeveloped Reserves
Beginning of period,
 April 1, 1995 or January 1,
 1996............................  42.6     9.0    51.6    36.1     9.3    45.4
  Revisions of previous
   estimates.....................   8.6     (.1)    8.5     1.5      .1     1.6
  Purchase of reserves in place..
  Extensions, discoveries and
   other additions...............   6.0      .1     6.1     7.4             7.4
  Production.....................  (3.1)    (.9)   (4.0)   (2.4)    (.4)   (2.8)
                                   ----     ---    ----    ----     ---    ----
End of period....................  54.1     8.1    62.2    42.6     9.0    51.6
                                   ----     ---    ----    ----     ---    ----
Net Proved Developed Reserves
Beginning of period..............  33.4     4.3    37.7    28.9     3.1    32.0
End of period....................  44.5     3.5    48.0    33.4     4.3    37.7
                                   ====     ===    ====    ====     ===    ====
</TABLE>
--------
(a) The changes reflect the impact of the change in the price of crude oil on
    the barrels to which the Company is entitled under the terms of the
    Indonesian production sharing contracts. The Indonesian production sharing
    contracts allow the Company to recover tangible 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 15.9 million barrels in 1996
    and 9.9 million barrels in 1995.
(b) Natural gas liquids reserve volumes are presented separately for
    information purposes only. Natural gas liquids are extracted from the
    Company's natural gas volumes and are recoverable at natural gas
    processing plants downstream from the lease or field separation facility.
    The volumes presented for natural gas reserves are prior to the extraction
    of natural gas liquids.
(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. During 1996, the Company sold
    Maxus Venezuela to YPF.
 
                                     F-67
<PAGE>
 
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, 1996 and 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.
 
<TABLE>
<CAPTION>
                           UNITED STATES           INDONESIA         SOUTH AMERICA          WORLDWIDE
                         -------------------  --------------------  -----------------  --------------------
                           1996       1995      1996       1995       1996     1995      1996       1995
                         ---------  --------  ---------  ---------  --------  -------  ---------  ---------
<S>                      <C>        <C>       <C>        <C>        <C>       <C>      <C>        <C>
Future cash flows....... $ 2,826.9  $1,161.0  $ 3,604.6  $ 3,461.9  $1,030.3  $ 822.5  $ 7,461.8  $ 5,445.4
Future production
 costs..................    (543.2)   (331.2)  (1,843.0)  (2,004.7)   (317.4)  (221.3)  (2,703.6)  (2,557.2)
Future development
 costs..................     (77.0)    (70.6)    (293.2)    (288.2)   (104.2)  (122.3)    (474.4)    (481.1)
                         ---------  --------  ---------  ---------  --------  -------  ---------  ---------
Future net cash flows,
 before income taxes....   2,206.7     759.2    1,468.4    1,169.0     608.7    478.9    4,283.8    2,407.1
Discount for estimated
 timing of future cash
 flows..................  (1,101.9)   (342.9)    (578.7)    (459.4)   (246.6)  (200.0)  (1,927.2)  (1,002.3)
                         ---------  --------  ---------  ---------  --------  -------  ---------  ---------
Present value of future
 net cash flows, before
 income taxes...........   1,104.8     416.3      889.7      709.6     362.1    278.9    2,356.6    1,404.8
Future income taxes,
 discounted at 10%(a)...    (172.0)    (67.8)    (388.9)    (321.7)    (99.6)   (34.3)    (660.5)    (423.8)
                         ---------  --------  ---------  ---------  --------  -------  ---------  ---------
Standardized measure of
 discounted future net
 cash flows............. $   932.8  $  348.5  $   500.8  $   387.9  $  262.5  $ 244.6  $ 1,696.1  $   981.0
                         =========  ========  =========  =========  ========  =======  =========  =========
</TABLE>
--------
(a) Future income taxes undiscounted are $491.6 for the United States, $618.4
    for Indonesia and $168.3 for South America at December 31, 1996 and $161.6
    for the United States, $508.2 for Indonesia and $57.1 for South America at
    December 31, 1995.
 
                                     F-68
<PAGE>
 
  The following are the principal sources for change in the standardized
measure:
 
<TABLE>
<CAPTION>
                                                               1996    1995(A)
                                                             --------  -------
<S>                                                          <C>       <C>
January 1................................................... $  981.0  $ 929.8
  Sales and transfers of oil and gas produced, net of
   production costs.........................................   (417.0)  (322.7)
  Net changes in prices and production costs, net of future
   production and development costs.........................    994.6     99.6
  Extensions, discoveries and improved recovery, less
   related costs............................................    264.3     79.5
  Development costs incurred during the year that reduced
   future development costs.................................    142.2    140.6
  Revisions of previous quantity estimates..................    108.5     51.5
  Purchase of reserves in place.............................       .1     16.3
  Sale of reserves in place.................................    (65.6)     (.1)
  Net change in income taxes................................   (236.7)   (42.8)
  Accretion of discount.....................................    136.5    131.1
  Changes in production rates (timing) and other............   (211.8)  (101.8)
                                                             --------  -------
December 31................................................. $1,696.1  $ 981.0
                                                             ========  =======
</TABLE>
--------
(a) 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.
 
                                     F-69
<PAGE>
 
 Quarterly Data
 
<TABLE>
<CAPTION>
                                                     1996
                          ------------------------------------------------------------------
                          MARCH 31,     JUNE 30,   SEPTEMBER 30,   DECEMBER 31, FOR THE YEAR
                          ---------     --------   -------------   ------------ ------------
<S>                       <C>           <C>        <C>             <C>          <C>
Sales and operating
 revenues...............   $174.0        $172.1       $174.4          $197.5       $718.0
Gross profit (a)........     64.5          58.6         59.1            91.0        273.2
Net income (loss) before
 extraordinary item          (0.5)         (2.7)        11.3            12.5         20.6
Extraordinary item (b)..                                                (5.6)        (5.6)
  Net income (loss).....     (0.5)         (2.7)        11.3             6.9         15.0
Market price per share:
  $4.00 Preferred(c)
    High................       46            50          50 3/4
    Low.................       42            41 1/4      49 3/4
  $2.50 Preferred
    High................       26 1/2        26          26 11/32        26 1/2       26 1/2
    Low.................       25 1/8        25          25 1/4          25 3/4       25
 
<CAPTION>
                                                     1995
                          ------------------------------------------------------------------
                                                                                NINE MONTHS
                                                                                   ENDED
                          MARCH 31,     JUNE 30,   SEPTEMBER 30,   DECEMBER 31, DECEMBER 31,
                          ---------     --------   -------------   ------------ ------------
<S>                       <C>           <C>        <C>             <C>          <C>
Sales and operating
 revenues...............   $142.5        $150.7       $141.8          $171.3       $463.8
Gross profit (a)........     35.2          34.3         24.5            48.0        106.8
Net loss................    (56.9)        (23.0)       (28.1)          (22.6)       (73.7)
Per Common Share
  Net loss..............     (.49)
Market price per share:
  Common
    High................        5 29/32      5 1/2
    Low.................        3            5 3/8
  $4.00 Preferred
    High................       38 1/4       41            40 1/2          44 3/4      44 3/4
    Low.................       30           32 1/2        38              38          32 1/2
  $2.50 Preferred
    High................       21 3/4       24 1/4        25 5/8          26 1/8      26 1/8
    Low.................       17 45/64     19 1/8        23 5/8          17 5/8      17 5/8
</TABLE>
--------
(a) Gross profit is sales and operating revenues less purchases and operating
    expenses, gas purchase costs and depreciation, depletion and amortization.
(b) In December 1996, the Company repaid the $175.0 million Indonesian
    Facility due 1997-2002. Unamortized issuance costs associated with this
    early retirement were recorded as an extraordinary loss of $5.6 million.
    The tax impact of this transaction was less than $.1 million.
(c) As part of the Company's reorganization, the Company redeemed on August
    13, 1996, all of its outstanding shares of $4.00 Preferred Stock.
 
                                     F-70