<PAGE>   1
 
================================================================================

 
                       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, 1995

                                  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>
Common Stock, $1.00 Par Value.....................................  None
$2.50 Cumulative Preferred Stock, $1.00 Par Value.................  New York Stock Exchange
8 1/2% Sinking Fund Debentures Due April 1, 2008..................  New York Stock Exchange
                Securities registered pursuant to Section 12(g) of the Act:
$4.00 Cumulative Convertible Preferred Stock, $1.00 Par Value.....  Nasdaq Stock Market
</TABLE>
 
     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.  / /
 
     The aggregate market value of the voting stock held by non-affiliates of
the registrant as of March 1, 1996 was approximately $190,072,300.
 
     Shares of Common Stock outstanding at March 1, 1996 -- 135,609,772.
 
                      DOCUMENTS INCORPORATED BY REFERENCE
                                      None
 

================================================================================
<PAGE>   2
 
                                     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 in
Indonesia, Ecuador, Bolivia, Venezuela and certain other countries, 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.
 
     The Company's common stock, $1.00 par value ("Common Stock"), is wholly
owned by YPF Sociedad Anonima ("YPF"), an Argentine sociedad anonima. On March
6, 1995, a tender offer for the Company's Common Stock was commenced by YPF
Acquisition Corp. (the "Purchaser" or "YPFA Corp."), a wholly owned subsidiary
of YPF, at $5.50 per share. Pursuant to the tender offer, in April 1995, the
Purchaser acquired approximately 88.5% of the then-outstanding shares of Common
Stock. 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, the Purchaser and YPF. The holders of the Company's
Common Stock along with the holders of the Company's $4.00 Cumulative
Convertible Preferred Stock ("$4.00 Preferred Stock") approved the Merger
Agreement; the Purchaser was merged into the Company (the "Merger") on June 8,
1995; and, pursuant to the terms of the Merger Agreement, shares of the
Company's Common Stock outstanding on the date of the Merger were converted into
the right to receive $5.50 per share. The $4.00 Preferred Stock and the
Company's $2.50 Cumulative Preferred Stock ("$2.50 Preferred Stock") remain
outstanding, and the powers, preferences and rights of such preferred stock,
including conversion rights of the $4.00 Preferred Stock, were not affected by
the Merger.
 
     Effective April 1, 1995, the Company used the purchase method of accounting
to record the acquisition of the Company by YPF. In a purchase method
combination, the purchase price is allocated to 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 (years ending December 31, 1994 and 1993,
and the three-month period ending March 31, 1995) and post-Merger periods (nine
months ending December 31, 1995). The Company's sales or transfers between
geographic areas were not significant in each year in the period ended December
31, 1994 and 1993 and the three months ended March 31, 1995 and the nine months
ended December 31, 1995. Operating revenues from export sales to unaffiliated
customers located outside the United States were less than 10% of the Company's
consolidated sales and operating revenues in each year in the two-year period
ended December 31, 1994 and the three months ended March 31, 1995 and the nine
months ended December 31, 1995. Information concerning outside sales and
operating profit by geographic area for the nine months ended December 31, 1995
and identifiable assets by geographic area as of December 31, 1995 is presented
on page F-43 of this report. Information concerning outside sales and operating
profit by geographic area for the three months ended March 31, 1995 and for the
twelve months ended December 31, 1994 and 1993 and identifiable assets by
geographic area as of March 31, 1995 and December 31, 1994 and 1993 is presented
on pages F-9 and F-10 of this report.
 
  Exploration and Production -- International
 
  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 81% of the Company's total net
 
                                        2
<PAGE>   3
 
production of oil during 1995. 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, the
contractors currently receive 34% of the oil produced and 79.5% of the gas
produced before Indonesian taxes, the statutory rate for which is 56%. The
Southeast Sumatra and Northwest Java production sharing contracts extend to 2018
and 2017, respectively.
 
     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 255 million cubic feet per day ("mmcfpd") (gross) during 1995. 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 a gas sales contract to supply Jakarta or other markets. Although the
Company cannot give any assurance that a contract will ultimately be signed,
management currently believes that these negotiations will eventually lead to a
satisfactory gas sales contract and a profitable market for the Company's
Southeast Sumatra natural gas.
 
     During 1995, six exploration and 18 development wells were drilled in the
Northwest Java contract area, which added 28 million barrels (gross) of oil and
237 bcf (gross) of gas to proved reserves. During 1995, the Company drilled 14
exploration and 20 development wells in the Southeast Sumatra contract area
which added 19.4 million barrels (gross) of proved oil reserves.
 
     Exploration activities replaced 43% of net production of oil and gas for
the Southeast Sumatra and Northwest Java blocks in 1995. The Company plans to
drill fewer exploration wells (ten) in the Southeast Sumatra block in 1996 than
it did in 1995 (14), and will shift its emphasis and spending toward drilling
in-fill wells, increasing workovers, reducing lifting costs and securing
conditions to commercialize small oil fields discovered in previous years that
were considered uneconomic under then-prevailing operating cost and sales price
assumptions.
 
  Ecuador
 
     The Company is the operator of and has a 35% working interest in the Block
16 project in eastern Ecuador from which production began in 1994. During 1995,
the main access road to the northern and southern fields, the oil pipeline to
the southern fields and water disposal lines were completed, along with the
construction of wellpads for the following southern fields, as well as Water
Disposal Pad #1: Amo B, Iro A and Ginta B. This allowed continued development
drilling in these fields in the southern area which averaged 6,038 gross barrels
of oil production per day during 1995. Production from the Amo field was
recorded in November 1995, and production from the Iro and Ginta fields is
projected to be recorded in the first half of 1996. Production from the northern
fields averaged approximately 22,800 gross barrels of oil per day ("bpd") in
1995.
 
     Pipeline capacity available to the Company is sufficient to transport only
about 60% of the daily oil the Company expects to be able to produce in Ecuador,
and none of the various projects to increase transportation capacity that have
been considered has been approved by the government of Ecuador. In addition, the
Company is involved in a number of contract, auditing and certification disputes
with various government entities. Together, the lack of pipeline capacity and
the various disputes with government entities are retarding the Company's
ability to proceed with the economic development of Block 16. Although the
Company can give no assurances concerning the outcome of the discussions,
progress has recently been made on several important issues. The Company intends
to reduce program spending in Ecuador in 1996 to $19 million from $32 million in
1995.
 
                                        3
<PAGE>   4
 
  Bolivia
 
     In Bolivia, total daily oil production averaged approximately 6,400 gross
bpd during 1995 from ten wells located in the Surubi Field of the Mamore I
Block, a 1.6 million acre concession of which the Company is the operator and
owns a 50% interest. Production in the Mamore I Block increased to 9,500 gross
bpd at year-end 1995, as compared to 4,200 gross bpd at the end of 1994. The
Mamore I Block is currently the source of approximately 30% of Bolivia's liquid
hydrocarbon production; the majority of Bolivian fields produce primarily
natural gas and condensate. Proven Surubi area gross reserves were estimated at
28 million barrels of oil at January 1, 1996 by Gaffney, Cline & Associates
("Gaffney, Cline"), independent reserve engineers. In addition, the Company has
a 12.5% non-operating interest in the Secure Block which is adjacent to and west
of Mamore I. In 1995, the Company conducted a seismic program covering
approximately 450 kilometers of the Secure Block and plans to continue this
program in 1996. During 1995, the Company signed a contract to acquire a 25%
interest in the Caipipendi Block operated by Chevron Corporation.
 
  Venezuela
 
     Discovered in 1928, the Quiriquire field in Venezuela was produced through
1985. In 1993, it was offered as a reactivation field as part of the Venezuelan
second round of bids, at which time Maxus (95%) and Otepi Consultores, S.A.,
predecessor to Corporacion Energetica S.21, C.A., (5%) signed a contract for the
unit with Lagoven, an affiliate of Petroleos de Venezuela, S.A. In 1994, the
Company conveyed a 45% interest in the Quiriquire Unit to BP Exploracion de
Venezuela S.A., reducing its previous 95% interest in the unit to 50%. The
contract with Lagoven requires a $36 million investment in drilling and seismic
programs by mid-year 1997, the Company's share of which is $18 million. To date,
the Company has completed the performance of a three-dimensional seismic program
on the Quiriquire Unit. In addition, it has commenced the drilling of one of two
commitment exploratory wells and has begun a reactivation program, including the
drilling of one delineation well. The Quiriquire Unit currently produces
approximately 2,000 gross bpd of crude oil. In January 1996, the Company
acquired an interest in a second block, Guarapiche, adjacent to the Quiriquire
Unit. The Guarapiche block is operated by BP Exploration Orinoco Limited.
 
  Other Foreign Countries
 
     The Company is also undertaking exploration and production activities in
three other foreign areas. In the East China Sea, the Company operates two
blocks, one in which it has a 60% working interest and one in which it has a
100% working interest. Two and three dimensional seismic surveys on the blocks
have been completed. During 1995, a dry hole was drilled, and in the first
quarter of 1996 a second dry hole was drilled. The Company's exploration
commitment in the East China Sea is fulfilled and management does not intend to
continue activities in that area. In Tunisia, during 1995, the Company
relinquished its interest in the 1.1 million acre Djebel Oust Block. The Company
converted its seismic option on the Zembra permit, Tunisia, to an exploration
license during 1995. In Bulgaria, during 1995, the Company drilled its second
dry hole on a one million acre block which was subsequently relinquished.
 
     During December 1995, the Company sold its overriding royalty interest in
the Recetor Block, Colombia, to British Petroleum for $25 million.
 
     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, acts of war, guerrilla activities
and insurrection.
 
  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 two gas processing
 
                                        4
<PAGE>   5
 
plants in the area: its Sunray plant in Moore County, Texas and a plant in Roger
Mills County, Oklahoma. 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, 1996, was processing approximately 175 mmcfpd.
 
     In 1995, Midgard completed 75 net wells, as compared to 26 net wells
completed in 1994. The predominant portion of the wells drilled during 1995 were
completed during the second half of the year. At December 1995, net production
was 138 mmcfpd, an increase of 11% from the average for the first half of 1995
of 125 net mmcpd. Proved reserves of 70.4 bcf equivalent (net) were added during
1995, a significant increase from the 23 bcf equivalent (net) added in 1994.
Midgard acquired 26 bcf equivalent (net) of reserves through producing property
acquisitions in 1995. Twenty-two net wells were recompleted in 1995, an increase
of 14 (net) over 1994's recompletions. Proved reserves as of January 1, 1996
were 594 bcf equivalent (net), an increase of 16% over proved reserves of 513
bcf equivalent (net) as of January 1, 1995. The Company replaced 268% of its
production in 1995.
 
     In 1996, Midgard's development plans include the continuation of its
in-fill drilling program at a level comparable to 1995 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 exploration wells to complement its lower risk in-fill drilling
program.
 
     The Company has begun discussions with other companies concerning the
establishment of a joint venture or other alliance with regard to Midgard's
business and assets. The objective of such a joint venture or alliance would be
lowering unit costs, creating economies of scale and improving marketing
leverage. No joint venture or other partner has been selected and no assurances
can be given that attempts to establish a joint venture or other alliance will
be successful.
 
  Oil and Gas Operations
 
     Average sales prices and production costs of crude oil and natural gas
produced by geographic area for each year in the two-year period ended December
31, 1994, the three months ended March 31, 1995 and the nine months ended
December 31, 1995 were as follows:
 
<TABLE>
<CAPTION>
                                                    NINE MONTHS                        YEAR ENDED
                                                       ENDED         THREE MONTHS     DECEMBER 31,
                                                    DECEMBER 31,     ENDED MARCH    -----------------
                                                        1995           31, 1995      1994       1993
                                                    ------------     ------------   ------     ------
<S>                                                 <C>              <C>            <C>        <C>
United States
  Average Sales Price
     Crude Oil (per barrel).......................     $16.29           $16.07      $13.89     $16.99
     Natural Gas Liquids (per barrel).............     $10.42           $10.27      $10.02     $11.08
     Natural Gas Sold (per mcf)(a)................     $ 1.54           $ 1.42      $ 1.89     $ 2.13
     Natural Gas Produced (per mcf)(b)............     $ 1.97           $ 1.89      $ 2.10     $ 2.26
     Average Production Cost (per barrel)(c)......     $ 3.39           $ 3.74      $ 3.37     $ 3.61
Indonesia
  Average Sales Price
     Crude Oil (per barrel).......................     $17.01           $17.54      $15.61     $17.31
     Natural Gas Liquids (per barrel).............     $14.33           $19.19      $ 9.42     $10.57
     Natural Gas Sold (per mcf)(a)................     $ 2.62           $ 2.65      $ 2.24     $ 1.30
     Natural Gas Produced (per mcf)(b)............     $ 2.64           $ 2.73      $ 2.53     $ 2.35
     Average Production Cost (per barrel)(c)......     $ 6.44           $ 7.42      $ 6.18     $ 6.67
South America
  Average Sales Price
     Crude Oil (per barrel).......................     $12.79           $12.58      $12.58         NA
     Average Production Cost (per barrel)(c)......     $ 6.30           $ 8.99      $ 9.36         NA
</TABLE>
 
                                        5
<PAGE>   6
 
---------------
 
(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 crude oil and natural gas through price swap agreements and futures
contracts. A hedging program covered an average of 25% of the Company's United
States natural gas production during 1995 and covered up to 90% of such
production during the first quarter of 1996. Currently, the only remaining 1996
United States natural gas production which is hedged is approximately 30% of
April and June 1996 production; however, management intends to hedge up to 90%
of the remaining production for the year in the event that gas prices reach
certain targeted levels.
 
     Information regarding the Company's oil and gas producing activities for
the periods indicated is set forth on pages F-30 through F-34 and F-64 through
F-68 of this report. The Company's estimates of its net interests in proved
reserves at December 31, 1995 are based upon records regularly prepared and
maintained by its engineers. In 1995, the Company filed estimates of certain of
its proved reserves of crude oil and natural gas in the United States at
December 31, 1994 with the United States Department of Energy. The total reserve
estimates included therein do not differ by more than 5% from the total reserve
estimates for the comparable period for the same reserves included in the
Company's filings with the Securities and Exchange Commission.
 
     The following table shows the Company's average daily sales and net
production (after deducting royalty and operating interests of others) by
geographic area for the periods presented.
 
<TABLE>
<CAPTION>
                                                         NINE MONTHS     THREE MONTHS     YEAR ENDED
                                                            ENDED           ENDED        DECEMBER 31,
                                                         DECEMBER 31,     MARCH 31,      ------------
                                                             1995            1995        1994    1993
                                                         ------------    ------------    ----    ----
<S>                                                      <C>             <C>             <C>     <C>
United States
  Average Daily Production
     Crude Oil (m barrels).............................       1.1             1.0         2.4     4.9
     Natural Gas (mmcf)(a).............................       130             125         156     208
  Average Daily Sales
     Natural Gas Liquids (m barrels)...................       8.7             8.8         8.2     7.6
     Natural Gas (mmcf)(b).............................       104              98         131     181
Indonesia
  Average Daily Production
     Crude Oil (m barrels).............................      53.0            52.0        59.3    62.4
  Average Daily Sales
     Natural Gas Liquids (m barrels)...................       1.7             0.9         2.1     1.5
     Natural Gas (mmcf)(b).............................        61              45          44      13
South America
  Average Daily Production
     Crude Oil (m barrels).............................      12.4             8.5         4.6      NA
  Average Daily Sales
     Crude Oil (m barrels).............................      10.4             6.9         5.2      NA
</TABLE>
 
                                        6
<PAGE>   7
 
---------------
 
(a) Reflects the average amount of daily wellhead production.
 
(b) Average daily sales volumes for natural gas production, reduced, in those
    cases where the gas is processed for extraction of natural gas liquids, by
    the shrinkage resulting therefrom.
 
     In addition to gathering and processing a substantial part of the natural
gas produced by the Company, 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 facilities. 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          DECEMBER 31,
                                                     DECEMBER 31,     MARCH 31,      ----------------
                                                         1995            1995         1994      1993
                                                     ------------    ------------    ------    ------
<S>                                                  <C>             <C>             <C>       <C>
Average Sales Price
     Natural Gas Liquids (per barrel)..............     $10.57          $10.48       $10.12    $11.19
     Natural Gas (per mcf).........................     $ 1.42          $ 1.49       $ 1.90    $ 1.99
Average Daily Sales
     Natural Gas Liquids (m barrels)...............        8.9             9.6          9.7       9.8
     Natural Gas (mmcf)............................         68              69          144       184
</TABLE>
 
     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, 1995, 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.............................................    363    238.4     1467    1126.4
     Indonesia.................................................    708    269.8       12       2.9
     South America.............................................     38     15.4        0       0.0
          Total................................................   1109    523.6     1479    1129.3
Multiple Completions
     United States.............................................      0      0.0       35      18.2
     Indonesia.................................................     84     20.4        0         0
          Total................................................     84     20.4       35      18.2
</TABLE>
 
     At December 31, 1995, 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...........................  551,141       143,330        8,405          -0-
     Undeveloped Acres.........................  315,605     7,712,042     8,553,752    2,157,677
                                                 -------     ---------     ---------    ---------
          Total................................  866,746     7,855,372     8,562,157    2,157,677
Net Acres
     Developed Acres...........................  465,982        54,024        3,501          -0-
     Undeveloped Acres.........................  179,620     2,709,540     2,289,955    1,799,876
                                                 -------     ---------     ---------    ---------
          Total................................  645,602     2,763,564     2,293,456    1,799,876
</TABLE>
 
                                        7
<PAGE>   8
 
  Exploration and Development Activities
 
     Drilling activities of the Company for each year in the three-year period
ended December 31, 1995 are summarized by geographic area in the following
table:
 
<TABLE>
<CAPTION>
                                                                         FOR THE YEAR ENDED
                                                                            DECEMBER 31,
                                                                     --------------------------
                                                                     1995       1994       1993
                                                                     ----       ----       ----
<S>                                                                  <C>        <C>        <C>
Gross wells drilled(a)
  United States
     Exploratory
       Oil.........................................................     0          0          0
       Gas.........................................................     0          1          2
       Dry.........................................................     2          6          2
                                                                      ---        ---        ---
          Total....................................................     2          7          4
     Development
       Oil.........................................................     3          2         10
       Gas.........................................................    73         44         29
       Dry.........................................................     5          4          4
                                                                      ---        ---        ---
          Total....................................................    81         50         43
  Indonesia
     Exploratory
       Oil.........................................................     0          3          0
       Gas.........................................................     0          0          0
       Dry.........................................................    12          7          0
                                                                      ---        ---        ---
          Total....................................................    12         10          0
     Development
       Oil.........................................................    35         38         46
       Gas.........................................................     0          1         14
       Dry.........................................................     2          2         25
                                                                      ---        ---        ---
          Total....................................................    37         41         85
  South America
     Exploratory
       Oil.........................................................     1          1          2
       Gas.........................................................     0          0          0
       Dry.........................................................     1          0          3
                                                                      ---        ---        ---
          Total....................................................     2          1          5
     Development
       Oil.........................................................    17         13          2
       Gas.........................................................     0          0          0
       Dry.........................................................     0          0          0
                                                                      ---        ---        ---
          Total....................................................    17         13          2
  Other Foreign
     Exploratory
       Oil.........................................................     0          0          0
       Gas.........................................................     0          0          0
       Dry.........................................................     3          0          0
                                                                      ---        ---        ---
          Total....................................................     3          0          0
</TABLE>
 
                                        8
<PAGE>   9
 
<TABLE>
<CAPTION>
                                                                         FOR THE YEAR ENDED
                                                                            DECEMBER 31,
                                                                     1995       1994       1993
                                                                     ---        ---        ---
<S>                                                                  <C>        <C>        <C>
     Development
       Oil.........................................................     0          0          0
       Gas.........................................................     0          0          0
       Dry.........................................................     0          0          0
                                                                      ---        ---        ---
          Total....................................................     0          0          0
Net Wells Drilled (a)
  United States
     Exploratory
       Oil.........................................................   0.0        0.0        0.0
       Gas.........................................................   0.0        1.0        1.7
       Dry.........................................................   1.5        3.5        1.9
                                                                      ---        ---        ---
          Total....................................................   1.5        4.5        3.6
     Development
       Oil.........................................................   3.0        0.2        1.7
       Gas.........................................................  65.7       22.1       18.5
       Dry.........................................................   5.0        1.6        2.1
                                                                      ---        ---        ---
          Total....................................................  73.7       23.9       22.3
  Indonesia
     Exploratory
       Oil.........................................................   0.0        0.7        0.0
       Gas.........................................................   0.0        0.0        0.0
       Dry.........................................................   6.4        3.3        0.0
                                                                      ---        ---        ---
          Total....................................................   6.4        4.0        0.0
     Development
       Oil.........................................................  14.5       17.1       17.5
       Gas.........................................................   0.0        0.2        3.4
       Dry.........................................................   1.1        0.5        9.1
                                                                      ---        ---        ---
          Total....................................................  15.6       17.8       30.0
  South America
     Exploratory
       Oil.........................................................    .4        0.4        2.0
       Gas.........................................................   0.0        0.0        0.0
       Dry.........................................................    .6        0.0        2.1
                                                                      ---        ---        ---
          Total....................................................   1.0        0.4        4.1
     Development
       Oil.........................................................   7.2        4.6        2.0
       Gas.........................................................   0.0        0.0        0.0
       Dry.........................................................   0.0        0.0        0.0
                                                                      ---        ---        ---
          Total....................................................   7.2        4.6        2.0
  Other Foreign
     Exploratory
       Oil.........................................................   0.0        0.0        0.0
       Gas.........................................................   0.0        0.0        0.0
       Dry.........................................................   2.6        0.0        0.0
                                                                      ---        ---        ---
          Total....................................................   2.6        0.0        0.0
</TABLE>
 
                                        9
<PAGE>   10
 
<TABLE>
<CAPTION>
                                                                         FOR THE YEAR ENDED
                                                                            DECEMBER 31,
                                                                     1995       1994       1993
                                                                     ---        ---        ---
<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>
 
---------------
 
(a) "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, 1995, 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 2 gross and .8 net wells in areas outside the United States other
than Indonesia.
 
  Competition and Markets
 
     The primary markets for the Company's Indonesian oil production are the
Pacific Rim countries, including Japan, China and Indonesia. The increasing
environmental consciousness of this region has resulted in premium prices for
low sulfur oil such as that produced from the Southeast Sumatra and Northwest
Java areas. The Company has ongoing business relationships with government oil
companies, utilities, refiners and trading companies which are expected to
continue to facilitate sales in this area. The Company believes that the
long-term potential for growth in natural gas demand in North America remains
high due to environmental advantages of natural gas relative to other sources of
energy; however, market prices remain extremely volatile, with weather and
regional supply and demand imbalances causing the potential for large monthly
price swings. The Company has concentrated its domestic natural gas production
in its mid-continent division (Midgard), which encompasses the Texas Panhandle
and western Oklahoma. The Company's Sunray gas plant is located near the
intersection of three major interstate pipelines, giving the Company a choice of
markets for its gas sales, thereby enabling it to maximize prices. Approximately
25% of the Company's natural gas sales in 1995 were made directly to local gas
distribution companies and industrial and agricultural users through term
contracts, and the remaining 75% was sold on the spot market.
 
     The Company sells crude oil, natural gas and natural gas liquids to a wide
number of customers, including refineries, industrial consumers and utilities.
Oil and gas are essentially commodities, and the Company's production represents
only a small fraction of the total world markets for these products. As a
result, the prices the Company receives depend primarily on the relative balance
between supply and demand in these markets.
 
     The world oil market continues to be subject to uncertainty. Iraq has not
yet legally resumed oil sales due to its failure to agree to United Nations
imposed conditions on such sales, but the possibility of renewed Iraqi
production continues to overhang the market. Oil prices showed some positive
gains in 1995, but continue to be subject to volatile price swings due to the
maintenance of lower inventories by refining centers and increased competition
for the limited growth in demand in developed countries from additional
availabilities from non-OPEC countries and excessive OPEC production.
 
  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.
 
                                       10
<PAGE>   11
 
     Many of the Company's United States operations are subject to requirements
of the Safe Drinking Water Act, the Clean Water Act, the Clean Air Act (as
amended in 1990), the Occupational Safety and Health Act, the Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended
("CERCLA"), and other federal, as well as state, laws. Such laws address, among
other things, limits on the discharge of wastes associated with oil and gas
operations, investigation and clean-up of hazardous substances, and workplace
safety and health. In addition, these laws typically require compliance with
associated regulations and permits and provide for the imposition of penalties
for noncompliance. The Clean Air Act Amendments of 1990 may benefit the
Company's business by increasing the demand for natural gas as a clean fuel.
 
     The Company believes that its policies and procedures in the area of
pollution control, product safety and occupational health are adequate to
prevent unreasonable risk of environmental and other damage, and of resulting
financial liability, in connection with its business. Some risk of environmental
and other damage is, however, inherent in particular operations of the Company
and, as discussed below, the Company has certain potential liabilities
associated with former operations. The Company cannot predict what environmental
legislation or regulations will be enacted in the future or how existing or
future laws or regulations will be administered or enforced. Compliance with
more stringent laws or regulations, as well as more vigorous enforcement
policies of the regulatory agencies, could in the future require material
expenditures by the Company for the installation and operation of systems and
equipment for remedial measures and in certain other respects.
 
     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 sharing arrangement was about $39 million as of
December 31, 1995. Occidental Chemical Corporation ("OxyChem"), a subsidiary of
Occidental, and Henkel Corporation ("Henkel"), an assignee of certain of
Occidental's rights and obligations, have filed a declaratory judgment action in
Texas state court with respect to the Company's agreement in this regard. (See
"Item 3. Legal Proceedings.")
 
     In connection with the spin-off of Diamond Shamrock R&M, Inc., now known as
Diamond Shamrock, Inc. ("DSI"), in 1987, the Company and DSI agreed to share the
costs of losses (other than product liability) relating to businesses disposed
of prior to the spin-off, including Chemicals. Pursuant to this cost-sharing
agreement, the Company bore the first $75 million of such costs and DSI bore the
next $37.5 million. Under the arrangement, such ongoing costs are now borne
one-third by DSI and two-thirds by the Company. This arrangement will continue
until DSI has borne an additional $47.5 million, following which such costs will
be borne solely by the Company. As of December 31, 1995, DSI's remaining
responsibility is approximately $8 million.
 
     In 1995, the Company spent $6 million in environmental related expenditures
in its oil and gas operations. Expenditures in 1996 are expected to be
approximately $8 million.
 
     The Company's total expenditures for environmental compliance for disposed
of businesses, including Chemicals, were approximately $38 million in 1995, $12
million of which was recovered from DSI under the above described cost-sharing
agreement. Those expenditures are projected to be approximately $23 million in
1996 after recovery from DSI under such agreement.
 
                                       11
<PAGE>   12
 
     The insurance companies that wrote Chemicals' and the Company's primary and
excess insurance during the relevant periods have to date refused to provide
coverage for most of Chemicals' or the Company's cost of the personal injury and
property damage claims related to environmental claims, including remedial
activities at chemical plant sites and disposal sites. In two actions filed in
New Jersey state court, the Company has been conducting litigation against all
of these insurers for declaratory judgments that it is entitled to coverage for
certain of these claims. In 1989, the trial judge in one of the New Jersey
actions ruled that there is no insurance coverage with respect to the claims
related to the Newark plant (discussed below). The trial court's decision was
upheld on appeal and that action is now ended. The other suit, which is pending,
covers disputes with respect to insurance coverage related to certain other
environmental matters.
 
     Newark, New Jersey. A consent decree, previously agreed upon by the U.S.
Environmental Protection Agency (the "EPA"), the New Jersey Department of
Environmental Protection and Energy (the "DEP") and Occidental, as successor to
Chemicals, was entered in 1990 by the United States District Court of New Jersey
and requires implementation of a remedial action plan at Chemicals' former
Newark, New Jersey agricultural chemicals plant. Engineering for such plan,
which will include an engineering estimate of the cost of construction, is
progressing. Construction is expected to begin in 1997, cost approximately $22
million and take three to four years to complete. The work is being supervised
and paid for by the Company pursuant to its above-described indemnification
obligation to Occidental.
 
     Studies have indicated that sediments of the Newark Bay watershed,
including the Passaic River adjacent to the plant, are contaminated with
hazardous chemicals from many sources. Studies performed by the Company and
others suggest that contaminants historically discharged by the Newark plant are
buried under several feet of more recent sediment deposits and are not moving.
The Company, on behalf of Occidental, negotiated an agreement with the EPA under
which the Company is conducting further testing and studies to characterize
contaminated sediment in a six-mile portion of the Passaic River near the plant
site. The Company currently expects such testing and studies to be completed in
1999 and cost from $4 million to $6 million after December 31, 1995. The Company
has been conducting similar studies under its own auspices for several years.
Until these studies are completed and evaluated, the Company cannot reasonably
forecast what regulatory program, if any, will be proposed for the Passaic River
or the Newark Bay watershed.
 
     Hudson County, New Jersey. Until 1972, Chemicals operated a chromium ore
processing plant at Kearny, New Jersey. According to the DEP, wastes from these
ore processing operations were used as fill material at a number of sites in
Hudson County.
 
     As a result of negotiations between the Company (on behalf of Occidental)
and the DEP, Occidental signed an administrative consent order with the DEP in
1990 for investigation and remediation work at certain chromite ore residue
sites in Kearny and Secaucus, New Jersey. The work is being performed by the
Company on behalf of Occidental, and the Company is funding Occidental's share
of the cost of investigation and remediation of these sites and is currently
providing financial assurance for performance of the work in the form of a
self-guarantee in the amount of $20 million subject to the Company's continuing
ability to satisfy certain financial tests specified by the State. This
financial assurance may be reduced with the approval of the DEP following any
annual cost review. While the Company has participated in the cost of studies
and is implementing interim remedial actions and conducting remedial
investigations and feasibility studies, the ultimate cost of remediation is
uncertain. The Company anticipates submitting its investigation and feasibility
reports to the DEP in late 1996 or 1997. The results of the DEP's review of
these reports could impact the cost of any further remediation that may be
required. 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.
 
                                       12
<PAGE>   13
 
     Painesville, Ohio. From about 1912 through 1976, Chemicals operated
manufacturing facilities in Painesville, Ohio. The operations over the years
involved several discrete but contiguous plant sites over an area of about 1,300
acres. The primary area of concern historically has been Chemicals' former
chromite ore processing plant (the "Chrome Plant"). For many years, the site of
the Chrome Plant has been under the administrative control of the EPA pursuant
to an administrative consent order under which Chemicals is required to maintain
a clay cap over the site and to conduct certain ground water and surface water
monitoring. Many other sites have previously been clay-capped and one specific
site, which was a waste disposal site from the mid-1960s until the 1970s, has
been encapsulated and is being controlled and monitored. In September 1995, the
Ohio Environmental Protection Agency (the "OEPA") issued its Directors' Final
Findings and Order (the "Director's Order") by consent ordering that a remedial
investigation and feasibility study (the "RIFS") be conducted at the former
Painesville plant area. The Company has agreed to participate in the RIFS as
required by the Director's Order. It is estimated that the total cost of
performing the RIFS will be $3 million to $5 million over the next three years.
In spite of the many remedial, maintenance and monitoring activities performed,
the former Painesville plant sites have 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 scope and nature of any further
investigation or remediation that may be required cannot be determined at this
time.
 
     Other Former Plant Sites. Environmental remediation programs are in place
at all other former plant sites where material remediation is required in the
opinion of the Company. Former plant sites where remediation has been completed
are being maintained and monitored to insure continued compliance with
applicable laws and regulatory programs.
 
     Third Party Sites. Chemicals has also been designated as a potentially
responsible party ("PRP") by the EPA under CERCLA with respect to a number of
third party sites, primarily off of Chemicals' properties, where hazardous
substances from Chemicals' plant operations allegedly were disposed of or have
come to be located. Numerous PRPs have been named at substantially all of these
sites. At several of these, Chemicals has no known exposure. Although PRPs are
almost always jointly and severally liable for the cost of investigations,
cleanups and other response costs, each has the right of contribution from other
PRPs and, as a practical matter, cost sharing by PRPs is usually effected by
agreement among them. Accordingly, the ultimate cost of these sites and
Chemicals' share of the costs thereof cannot be estimated at this time, but are
not expected to be material except possibly as a result of the matters described
below.
 
     1. Fields Brook; Ashtabula, Ohio. At the time that Chemicals was sold to
Occidental, Chemicals operated a chemical plant at Ashtabula, Ohio which is
adjacent to Fields Brook. Occidental has continued to operate the Ashtabula
plant. In 1986, Chemicals was formally notified by the EPA that it was a PRP for
the Fields Brook site. The site is defined as Fields Brook, its tributaries and
surrounding areas within the Fields Brook watershed. At least 15 other parties
are presently considered to be financially responsible PRPs. In 1986, the EPA
estimated the cost of sediment remediation at the site would be $48 million. The
PRPs, including Occidental, have developed an allocation agreement for sharing
the costs of the work in Fields Brook ordered by the EPA. Under the allocation,
the Occidental share for Chemicals' ownership of the Ashtabula plant would be
about five percent of the total, assuming all viable PRPs were to participate.
 
     In 1990, the OEPA, as state trustee for natural resources under CERCLA,
advised previously identified PRPs, including Chemicals, that the OEPA intended
to conduct a Natural Resource Damage Assessment of the Fields Brook site to
calculate a monetary value for injury to surface water, groundwater, air, and
biological and geological resources at the site. Also, although Fields Brook
empties into the Ashtabula River which flows into Lake Erie, it is not known to
what extent, if any, the EPA will propose remedial action beyond Fields Brook
for which the Fields Brook PRPs might be asked to bear some share of the costs.
Until all preliminary studies and necessary governmental actions have been
completed and negotiated or judicial allocations have been made, it is not
possible for the Company to estimate what the response costs, response
activities or natural resource damages, if any, may be for Fields Brook or
related areas, the parties responsible therefor or their respective shares.
 
                                       13
<PAGE>   14
 
     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.
 
     2. French Limited Disposal Site; Crosby, Texas. The PRPs, including
Chemicals (represented by the Company), entered into a consent decree and a
related trust agreement with the EPA with respect to this disposal site. The
consent decree was entered by the federal court as a settlement of the EPA's
claim for remedial action. Chemical's share of the cost to complete remediation
at this site is expected to be approximately $500,000.
 
     3. SCP/Carlstadt Site; Carlstadt, New Jersey. Chemicals' share of
remediation costs at this CERCLA site would be approximately one percent, based
on relative volume of waste shipped to the site. An interim remedy has now been
implemented at the site by the PRPs but no estimate can be made at this time of
ultimate costs of remediation which may extend to certain off-site locations.
 
     4. Chemical Control Site; Elizabeth, New Jersey. The DEP has demanded of
PRPs (including Chemicals) reimbursement of the DEP's alleged $34 million
(including interest through December 31, 1995) in past costs for its partial
cleanup of this site. The PRPs and the EPA have settled the federal claims for
cost recovery and site remediation, and remediation is now complete. Based on
the previous allocation formula, it is expected that Chemicals' share of any
money paid to the DEP for its claim would be approximately two percent.
 
  Employees
 
     As of December 31, 1995, the Company had approximately 2,275 employees.
 
ITEM 3. LEGAL PROCEEDINGS.
 
     In connection with the tender offer by YPFA Corp. and Merger, a number of
holders of Common Stock sued in the Chancery Court of the State of Delaware. In
the various complaints, the plaintiffs purported to sue individually and on
behalf of classes comprised of the holders of shares of Common Stock,
stockholders of the Company or all holders of the Company's securities. The
complaints named as defendants the Company, the directors and certain of the
officers of the Company, a former director of the Company and, with respect to
some of the complaints, YPF, and alleged, among other things, that the defendant
directors and officers of the Company breached their fiduciary duties in
approving the Offer and the Merger and that YPF aided and abetted the alleged
breach of duties. The plaintiffs purported to seek orders enjoining the
consummation of the Offer and the Merger (or the rescission of those
transactions) or, in the alternative, an accounting for any damages to the
alleged classes, together with their attorneys' fees and other relief. These
lawsuits were consolidated into one action and, in September 1995, were settled
with no payment to the class members. However, as a part of the settlement, the
Company was ordered to pay $800,000 in attorneys' fees to the plaintiffs' class
counsel.
 
     In November 1995, OxyChem filed suit in Texas state court seeking a
declaration of certain of the parties' rights and obligations under the sales
agreement pursuant to which the Company sold Chemicals to Occidental. Henkel
joined in said lawsuit as a plaintiff in January 1996. Specifically, OxyChem and
Henkel are seeking a declaration that the Company is required to indemnify them
for 50% of certain environmental costs incurred on projects involving remedial
activities relating to chemical plant sites or other property used in connection
with the business of Chemicals on the Closing Date which relate to, result from
or arise out of conditions, events or circumstances discovered by OxyChem or
Henkel and as to which the Company is provided written notice by OxyChem or
Henkel prior to the expiration of ten years following the Closing Date,
irrespective of when OxyChem or Henkel incurs and gives notice of such costs,
subject to an aggregate $75 million cap. The Company believes that this lawsuit
is without merit and intends to defend same vigorously.
 
                                       14
<PAGE>   15
 
     As of December 31, 1995, the Company had paid OxyChem and Henkel a total of
approximately $39 million against said $75 million cap. The Company cannot
predict what portion of the approximately $36 million remaining as of that date
Occidental and Henkel may actually pay or incur prior to September 4, 1996, the
tenth anniversary of the Closing Date, if they accelerate spending with respect
to such environmental costs.
 
     See also the heading "Health, Safety and Environmental Controls" under
"Items 1 and 2. Business and Properties" of this report for a description of
certain other legal proceedings, which description is incorporated herein by
reference.
 
     The Company is involved in various other legal proceedings incidental to
its business, the outcome of any of which should not have a material adverse
effect on its financial position.
 
ITEM 4. 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, 1996, YPF was the sole holder of record of the Common Stock.
 
     Midgard and Maxus Indonesia, Inc., subsidiaries of the Company, are parties
to separate credit agreements which places certain restrictions on the ability
of these subsidiaries to make or declare certain payments, advances and loans
specified therein, including dividends to the Company. (For a further
description of these credit agreements, see "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations--Significant Events
1995"). While these restrictions could impact the ability of the Company to pay
dividends on its Common Stock, the Company has paid no such dividends since
1987, and cash flows are currently being dedicated to exploration and
development projects rather than to such payment. The Company intends to
continue paying regular quarterly dividends on its $4.00 Preferred Stock, $9.75
Cumulative Convertible Preferred Stock ("$9.75 Preferred Stock") and $2.50
Preferred Stock.
 
                                       15
<PAGE>   16
 
ITEM 6. SELECTED FINANCIAL DATA.
 
                          FIVE-YEAR FINANCIAL SUMMARY
                (DOLLARS IN MILLIONS, EXCEPT FOR PER SHARE DATA)
 
<TABLE>
<CAPTION>
                                  NINE MONTHS     THREE MONTHS
                                     ENDED           ENDED
                                  DECEMBER 31,     MARCH 31,
                                      1995            1995        1994      1993      1992      1991
                                  ------------    ------------   -------   -------   -------   -------
<S>                               <C>             <C>            <C>       <C>       <C>       <C>
OPERATIONS
Sales and operating revenues......   $  463.8       $  142.5     $ 682.1   $ 786.7   $ 718.4   $ 790.8
Net income (loss) before
  extraordinary item and
  cumulative effect of change in
  accounting principle............      (73.7)         (56.9)      (22.7)    (37.9)     74.2     (11.2)
Extraordinary item................                                            (7.1)
Cumulative effect of change in
  accounting principle............                                            (4.4)
                                    --------        --------     --------  --------  --------
Net income (loss).................   $  (73.7)      $  (56.9)    $ (22.7)  $ (49.4)  $  74.2   $ (11.2)
FINANCIAL POSITION
Current assets....................   $  266.4       $  394.6     $ 441.9   $ 404.7   $ 391.2   $ 205.7
Current liabilities...............      306.4          224.3       171.0     263.4     327.9     249.3
Properties and equipment, less
  accumulated depreciation,
  depletion and amortization......    2,363.6        1,110.7     1,088.4   1,305.6   1,138.3   1,075.2
Total assets......................    2,716.8        1,692.1     1,706.7   1,987.4   1,811.6   1,451.5
Long-term debt, including current
  portion.........................    1,295.5          975.6       975.6   1,055.1     829.4     788.9
Deferred income taxes.............      551.2          199.7       199.3     198.3     152.9     142.9
Redeemable preferred stock........      125.0          125.0       125.0     250.0     250.0     250.0
Stockholders' equity (deficit)....      240.0           13.5        91.1     147.9     171.6     (55.9)
OTHER DATA
Expenditures for properties and
  equipment--including dry
  hole costs......................   $  137.4       $   53.6     $ 166.2   $ 340.0   $ 261.1   $ 272.3
Total exploration and development
  expenditures (whether
  capitalized or expensed)........      165.5           60.6       197.2     376.8     256.7     303.0
Preferred dividends paid..........       28.8            9.6        43.6      41.7      41.7      41.7
Depreciation, depletion and
  amortization....................      142.1           29.9       140.2     153.6     174.4     203.6
PER COMMON SHARE
Net income (loss) before
  extraordinary item and
  cumulative effect of change in
  accounting principle............   $   (.76)      $   (.49)    $  (.49)  $  (.60)  $   .27   $  (.52)
Extraordinary item................                                            (.05)
Cumulative effect of change in
  accounting principle............                                            (.03)
                                    --------        --------     --------  --------  --------
Net income (loss).................   $   (.76)      $   (.49)    $  (.49)  $  (.68)  $   .27   $  (.52)
</TABLE>
 
                                       16
<PAGE>   17
 
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
 
  Significant Events 1995
 
     On June 8, 1995, a special meeting of the stockholders of Maxus Energy
Corporation (the "Company" or "Maxus") was held to approve the Agreement of
Merger ("Merger Agreement") dated February 28, 1995, between the Company, YPF
Acquisition Corp. (the "Purchaser" or "YPFA Corp.") and YPF Sociedad Anonima
("YPF"). The holders of the Company's common stock, $1.00 par value per share
(the "Shares"), and $4.00 Cumulative Convertible Preferred Stock (the "$4.00
Preferred Stock" and together with the Shares, the "Voting Shares") approved the
Merger Agreement, and the Purchaser was merged into the Company (the "Merger")
on June 8, 1995 (the "Merger Date").
 
     Pursuant to the Merger Agreement, a tender offer (the "Offer") was
commenced on March 6, 1995 by the Purchaser for all the outstanding Shares at
$5.50 per Share. Pursuant to the Offer, in April 1995 the Purchaser acquired
120,000,613 Shares representing approximately 88.5% of the then-outstanding
Shares of the Company. As a result of the Merger, each outstanding Share (other
than Shares held by the Purchaser, YPF or any of their subsidiaries or in the
treasury of the Company, all of which were cancelled in the second quarter of
1995, and Shares of holders who perfected their appraisal rights under Section
262 of the Delaware General Corporation Law) was converted into the right to
receive $5.50 in cash, and YPF became the sole holder of all outstanding Shares.
The Company's preferred stock, consisting of the $4.00 Preferred Stock, $2.50
Cumulative Preferred Stock (the "$2.50 Preferred Stock") and $9.75 Cumulative
Convertible Preferred Stock (the "9.75 Preferred Stock"), remain outstanding.
YPF currently owns approximately 96.9% of the outstanding Voting Shares.
 
     The total amount of funds required by the Purchaser to acquire the entire
common equity interest in the Company, including the purchase of Shares pursuant
to the Offer and the payment for Shares converted into the right to receive cash
pursuant to the Merger, was approximately $762 million. On April 5, 1995, the
Purchaser entered into a credit agreement (the "Credit Agreement") with lenders
for which The Chase Manhattan Bank (National Association) ("Chase") acted as
agent, pursuant to which the lenders extended to the Purchaser a credit facility
for up to $550 million (the "Purchaser Facility"). On April 5, 1995, the
Purchaser borrowed $442 million under the Purchaser Facility and received a
capital contribution of $250 million from YPF. The Purchaser used borrowings
under the Purchaser Facility and the funds contributed to it by YPF to purchase
120,000,613 Shares pursuant to the Offer. Subsequent to the Merger, these Shares
and all other outstanding Shares vested in YPF.
 
     Following the Merger, Chase provided two additional credit facilities
aggregating $425 million: (i) a credit facility of $250 million extended to
Midgard Energy Company ("Midgard"), a wholly owned subsidiary of the Company,
and (ii) a credit facility of $175 million extended to Maxus Indonesia, Inc.
("Holdings"), a wholly owned subsidiary of the Company. The proceeds of the
loans made pursuant to these facilities were used to repay, in part, the
Purchaser Facility, which was assumed by the Company pursuant to the Merger. In
addition, the Company applied $8 million of its available cash to repayment of
the Purchaser Facility and used approximately $86 million of its available cash
to pay holders of Shares converted into the right to receive cash in the Merger.
 
     Effective April 1, 1995, the Company used the purchase method of accounting
to record the acquisition of the Company by YPF. In a purchase method
combination, the purchase price is allocated to the acquired assets and assumed
liabilities based on their fair values at the date of acquisition. As a result,
the assets and liabilities of the Company were revalued to reflect the
approximate $762 million cash purchase price paid by YPF to acquire the Company.
The Company's oil and gas properties were assigned carrying amounts based on
their relative fair market values. The Company's pre-Merger Consolidated Balance
Sheet as of March 31, 1995, together with the purchase method accounting
adjustments, became the Company's opening post-Merger Consolidated Balance Sheet
on April 1, 1995. Because of these purchase adjustments, which were effected
April 1, 1995, the Company's financial statements for the nine-month period
ended December 31, 1995, are not comparable to such statements for prior
periods. Accordingly, separate financial statements for periods prior to April
1, 1995 and for the nine-month period ended December 31, 1995 are presented.
 
                                       17
<PAGE>   18
 
  Significant Events 1994
 
     Maxus responded to many financial and operational challenges in 1994 which
culminated with the Company's agreement to merge with YPF in 1995.
 
     Financially, significant natural gas and crude oil price declines in 1994
contributed to Maxus' decision to streamline operations by decreasing overhead
and operating expenses, lowering program spending and redeeming certain
preferred stock. During the second quarter of 1994, the Company also sold its
interest in Diamond Shamrock Offshore Partners Limited Partnership ("Offshore
Partners") and certain producing oil and gas properties in Maxus' U.S. Southern
Division for $325 million net ("the Divested Properties"). Additionally, the
Company sold its geothermal subsidiary, Thermal Power Company, for approximately
$58 million net in cash and a note for $6.5 million. A portion of the proceeds
from these sales was used to reduce debt and redeem 625,000 shares of the $9.75
Preferred Stock for $63 million.
 
     Operationally, the Company initiated production from all three of Maxus'
South American operations--Ecuador, Bolivia and Venezuela. The Sunray gas plant
experienced its first full year of operation and achieved the operating
efficiencies and cost savings (approximately $14 million annually) that had been
anticipated. Additionally, net production from the Northwest Java gas project
averaged approximately 44 million cubic feet per day ("mmcfpd") during 1994,
resulting in $30 million of additional revenues.
 
  Results for the Nine Months Ended December 31, 1995
 
     For the nine months ended December 31, 1995, Maxus reported a net loss of
$74 million. Comparative information for the nine months ended December 31,
1994, is not presented due to the Merger with YPF which was effective April 1,
1995.
 
     Sales and Operating Revenues. Sales and operating revenues for the nine
months ended December 31, 1995, were $464 million composed of $298 million from
Maxus' Indonesian operations, $129 million from U.S. operations and $37 million
from South American operations.
 
     Maxus' net worldwide crude oil sales volumes were 64 thousand barrels per
day ("mbpd") during the nine-month period ended December 31, 1995, which were
comprised of 53 mbpd from Maxus' Indonesian operations, 10 mbpd from South
American operations and one mbpd from U.S. operations. Maxus' net worldwide
crude oil sales volumes increased from 60 mbpd in the third quarter of 1995 to
73 mbpd in the fourth quarter of 1995 due primarily to the recognition of
cumulative year-to-date production from the Southern Amo Field in Ecuador in the
fourth quarter of 1995, as this production had not previously been approved by
the Ecuadorian government, and the sole crude oil sale in Bolivia in October
1995. Despite natural declines in gross crude oil production in Indonesia over
the nine months ended December 31, 1995, Indonesian crude oil sales volumes
increased slightly due primarily to higher cost recovery. During the nine months
ended December 31, 1995, Maxus' average worldwide crude oil price was $16.31 per
barrel.
 
     During the nine-month period ended December 31, 1995, U.S. natural gas
sales volumes were 172 mmcfpd and U.S. natural gas prices averaged $1.49 per
thousand cubic feet ("mcf"). Although U.S. natural gas sales volumes remained
relatively flat over the nine months ended December 31, 1995, the success of the
1995 Midgard infill drilling program offset the natural declines from the area.
In the future, Maxus expects its Midgard infill drilling program to continue to
offset any natural declines. U.S. natural gas prices rose from $1.40 per mcf in
the third quarter of 1995 to $1.64 per mcf in the fourth quarter of 1995 which
favorably impacted revenues $4 million. During the nine-month period ended
December 31, 1995, Northwest Java natural gas sales volumes were 61 mmcfpd and
Northwest Java natural gas prices averaged $2.62 per mcf.
 
     Natural gas liquids sales volumes in the U.S. were 18 mbpd and U.S. natural
gas liquids prices averaged $10.49 per barrel.
 
     Costs and Expenses. Costs and expenses were $536 million during the nine
months ended December 31, 1995. Costs and expenses during this period included
operating expenses of $174 million; gas purchase costs of
 
                                       18
<PAGE>   19
 
$41 million; exploration expenses of $51 million; depreciation, depletion and
amortization ("DD&A") of $142 million; interest and debt expenses of $105
million and other costs and expenses totaling $23 million.
 
     DD&A of $142 million during the nine-month period ended December 31, 1995,
included $43 million of additional DD&A reflecting the impact of the purchase
price allocation which increased the book value of the Company's oil and gas
properties and equipment. The book value of oil and gas properties and equipment
increased approximately $1.3 billion as a result of the purchase price
allocation.
 
     In the nine-month period ended December 31, 1995, interest and debt
expenses of $105 million included $27 million of interest expense associated
with the Purchaser Facility and, Midgard and Holdings credit facilities. Also
included in interest and debt expenses during this period was $6 million of
interest associated with the accretion of discount on the Company's long-term
debt which was outstanding prior to the Merger. These borrowings were recorded
at their fair market value in the purchase method of accounting which resulted
in a reduction in their carrying value of $115 million. This reduction in
carrying value will be amortized to interest expense over the remaining term of
the borrowings.
 
     Other Revenues, Net. During the nine months ended December 31, 1995, other
revenues, net were $7 million which included $10 million of interest income, a
$2 million gain which represented the final settlement of the Company's sole
interest rate swap agreement prior to its termination and a $2 million gain
recognized on the sale of U.S. Treasury notes partially offset by a $3 million
production bonus payment stemming from the Company's Indonesian operations and
$5 million of accrued expenses. In the future, the Company anticipates
recognizing less interest income as a result of maintaining only minimal
balances of cash, cash equivalents and short-term investments to cover working
capital fluctuations. Capital contributions from YPF are expected to cover any
additional funding needs.
 
     Income Taxes. Income tax expense of $9 million for the nine-month period
ended December 31, 1995, included $63 million of current foreign income tax
expense primarily from Indonesian operations partially offset by a $49 million
deferred tax benefit due primarily to the higher DD&A associated with the
increase in book value of the Company's oil and gas properties and equipment as
a result of the purchase price allocation. In addition, the Company received $5
million of interest income on U.S. federal income tax refunds. This interest
income was not previously accrued in prior periods. In the future, the Company
expects to realize additional deferred tax benefits as a result of the higher
DD&A.
 
  Comparison of Results
 
  Three Months Ended March 31, 1995 vs. Three Months Ended March 31, 1994
 
     Maxus reported a net loss of $57 million for the first quarter of 1995
compared to a net loss of $11 million for the first quarter of 1994. The first
quarter 1995 results reflect $42 million of pre-Merger costs incurred by the
Company prior to the Merger. Such costs included expenses associated with
financial consulting and legal services, severance payments pursuant to change
of control agreements and payments for surrender of stock options and restricted
stock.
 
     Sales and Operating Revenues. Sales and operating revenues for the first
quarter of 1995 were $143 million, compared to $187 million for the same 1994
period. The loss of production from the Divested Properties which were sold in
the second quarter of 1994 and lower volumes of purchased gas accounted for $45
million of the revenue decline. Additionally, U.S. natural gas prices fell,
which also unfavorably impacted revenues $12 million for the three months ended
March 31, 1995. These declines were partially offset by first quarter 1995
revenue of $8 million from South America. Initial sales from the Company's South
American operations were recorded in the third quarter 1994.
 
     Net worldwide crude oil production was 60 mbpd in the first quarter 1995,
compared to 69 mbpd in the same quarter a year ago. Domestic crude oil volumes
declined four mbpd during the period due to the loss of production from the
Divested Properties resulting in lower revenues of $5 million. Crude oil sales
from the Company's Indonesian operations were also down 12 mbpd during the
period primarily as a result of lower entitlements due to higher crude oil sales
prices and lower production. Offsetting these declines, production from South
America of seven mbpd provided an additional $8 million of revenues in 1995.
 
                                       19
<PAGE>   20
 
     U. S. natural gas sales for the first quarter of 1995 were 167 mmcfpd, a
decrease of 208 mmcfpd as compared to the first quarter 1994 resulting in lower
revenues of $42 million. The decline was driven by the loss of production from
the Divested Properties and lower volumes of gas purchased for resale. The
average gas price received in the U. S. was $1.45 per mcf in the first quarter
1995 as compared to $2.24 per mcf in the same 1994 period.
 
     Northwest Java natural gas volumes of 40 mmcfpd in the first quarter 1995
were eight mmcfpd higher than the first quarter 1994. Natural gas sales prices
improved to an average of $2.65 per mcf during the first quarter 1995 from $1.81
per mcf during the same period last year due to the change in contract terms
which increased the price received for "old" gas production from $0.20 per mcf
to $2.65 per mcf effective January 1, 1995. The higher Northwest Java natural
gas volumes coupled with the higher average natural gas price resulted in
increased revenues of $4 million in the first quarter of 1995.
 
     Natural gas liquids sales in the U. S. for the first quarter 1995 were 18
mbpd, a slight decrease over first quarter last year. The average sales price
for U.S. natural gas liquids in the first quarter of 1995 was $10.38 per barrel,
an increase of $1.15 per barrel from 1994.
 
     Costs and Expenses. Costs and expenses for the first quarter of 1995 were
$190 million which were relatively flat compared to the first quarter of 1994.
Costs and expenses for the first quarter of 1995 included Maxus pre-Merger costs
of $42 million which were partially offset by lower gas purchase costs of $31
million when compared to the first quarter of 1994.
 
     Gas purchase costs were $31 million lower in the first quarter of 1995 as
compared to first quarter 1994 due to the lower volumes of gas purchased to
aggregate with the production from the Divested Properties, the reduction in
volumes of gas purchased for resale and lower natural gas prices.
 
     DD&A of $30 million for the first quarter 1995 was $8 million lower than
the same period of the prior year. Approximately $11 million of this decline
represents DD&A from the Divested Properties included in the first quarter of
1994. Partially offsetting this decline was $4 million of DD&A in the first
quarter of 1995 associated with South American operations which did not go into
production until late 1994.
 
     Income Taxes. Income tax expense was $19 million and $16 million in the
first quarters of 1995 and 1994, respectively. The increase in income tax
expense was primarily due to higher Indonesian taxes as a result of increased
taxable income from the Company's Indonesian operations.
 
  Comparison of Results
 
  Twelve Months Ended December 31, 1994 vs. Twelve Months Ended December 31,
1993
 
     Maxus reported a net loss of $23 million in 1994 compared to a net loss of
$49 million in 1993.
 
     Sales and Operating Revenues. Sales and operating revenues dropped 13%, or
$105 million, during 1994 when compared to 1993. The loss of production from the
Divested Properties and lower volumes of purchased gas which were aggregated and
sold with the production from the Divested Properties accounted for $86 million
of the revenue decline. Additionally, worldwide oil and gas prices fell, which
further compounded the loss of revenues. However, initial production from South
America and new gas production from Northwest Java added $54 million to revenues
during 1994, partially offsetting the overall negative revenue variances.
 
     The Company's total net crude oil production was 67 mbpd in 1994,
essentially flat compared to 1993. Production from South American operations
added five mbpd during 1994 and favorably impacted revenues by $24 million.
Crude oil volumes in the United States declined three mbpd, resulting in a $15
million negative volume variance, primarily from the loss of production from the
Divested Properties. Crude oil sales from the Company's Indonesian operations
were also down approximately three mbpd ($20 million negative volume variance),
primarily in Northwest Java. A portion of the 1994 decline was the result of
temporary production problems, which were corrected. Also, the 1993 volumes in
Northwest Java reflected additional barrels received through cost recovery due
to the substantial capital outlay for the gas project, which was completed in
late 1993. Maxus' 1994 average worldwide crude price hit a five-year low of
$15.31 per barrel, negatively impacting income by $39 million.
 
                                       20
<PAGE>   21
 
     United States natural gas sales volumes fell from 365 mmcfpd to 275 mmcfpd
in 1994 with the decline attributable to the loss of production from the
Divested Properties and the decrease in purchased gas volumes which were
aggregated and sold with the production from the Divested Properties. The
decline was partially offset by increased sales volumes of nine mmcfpd from
Midgard. United States natural gas revenues declined approximately $83 million
during 1994, with $68 million occurring as a result of the Divested Properties
and $14 million attributable to declining prices. Maxus' United States natural
gas prices averaged $1.95 per mcf in 1994 and $2.08 per mcf in 1993.
 
     Northwest Java gas volumes increased from 13 mmcfpd in 1993 to 44 mmcfpd
during 1994. The Company realized an additional $30 million of revenues during
1994 from the Northwest Java gas project, which came on stream in fourth quarter
1993.
 
     Natural gas liquids sales in the United States increased slightly from 17.4
mbpd to 17.9 mbpd in 1994 but average prices received declined from $11.14 per
barrel in 1993 to $10.07 per barrel. Overall, liquids revenues were down $5
million compared to 1993 due to the price declines.
 
     Costs and Expenses. Costs and expenses, excluding restructuring, were $728
million in 1994 compared to $781 million in 1993. The decline was primarily due
to the elimination of expenses related to the Divested Properties.
 
     Overall, operating expenses were down $21 million, of which approximately
$15 million related to the Divested Properties. Operating expenses declined in
Indonesia as well as in the United States, but were partially offset by the
additional operating expenses incurred in South America due to the start-up of
production in Ecuador, Bolivia and Venezuela.
 
     Gas purchase costs were $39 million lower than 1993 primarily as a result
of lower purchased gas prices and the reduction in volumes of purchased gas
which were previously aggregated and sold with the production from the Divested
Properties.
 
     Exploration expenses were $24 million lower than 1993 due to management's
decision to curtail exploratory spending in new frontiers during 1994. The
Company had previously announced its decision to concentrate spending in its
core areas of the United States and Indonesia and its emerging areas in South
America.
 
     DD&A declined $13 million in 1994. The Divested Properties created a $32
million favorable variance. Partially offsetting this favorable variance was a
$7 million increase in DD&A in South America due to the start-up of production
in Ecuador, Bolivia and Venezuela. DD&A in Indonesia was also up $13 million as
a result of higher DD&A rates and additional depreciation from the Northwest
Java gas project, which came on-stream in fourth quarter 1993.
 
     The Company increased its reserve for environmental liabilities in 1994 by
$60 million, primarily in response to the EPA's recently proposed chromium
clean-up standards and for additional costs expected to be incurred at the
Company's former Newark, New Jersey plant site. The 1993 environmental accrual
of $18 million related to expected costs of engineering studies for the Passaic
River in New Jersey and the Newark plant site.
 
     Restructuring. The 1994 results reflect a $101 million pre-tax net benefit
from the Company's restructuring activities, which included a pre-tax gain of
$202 million from the Divested Properties. This gain was partially offset by
restructuring costs, including a non-cash, pre-tax $70 million write-off
associated with the Company's undeveloped Alaska coal leases. The restructuring
also included costs associated with staff reductions and the write-off of
non-producing assets outside the Company's core areas.
 
     Other Revenues, Net. Other revenues, net were approximately $31 million
lower in 1994 compared to 1993. This decline was due primarily to a loss of $13
million stemming from the sale of the Company's geothermal subsidiary in the
third quarter of 1994 and to gains recorded on the sale of investments in U.S.
Treasury notes and other securities of $12 million during 1993.
 
                                       21
<PAGE>   22
 
     Income Taxes. The Company's provision for income taxes in 1994 was
comprised primarily of Indonesian income tax. The 1994 Indonesian tax was $12
million less than that of 1993 as a result of lower operating profit. United
States federal and state taxes increased $9 million in 1994 compared to 1993.
This increase was the result of tax on asset sales, which was offset by tax
benefit from the write-off of undeveloped Alaska coal leases and the favorable
resolution of a federal tax refund suit.
 
     Change in Accounting Principle. In 1993, Maxus adopted Statement of
Financial Accounting Standards No. 112, "Employers' Accounting for
Postemployment Benefits," which requires an accrual method of recognizing
postemployment benefits. The Company recognized a one-time charge of $4 million
to recognize the cumulative effect of the change in accounting for
postemployment benefits.
 
     Extraordinary Item. During 1993, the Company recorded an extraordinary loss
of $7 million after tax, representing call premium and unamortized issuance
costs for the early retirement of debt. Approximately $115 million of
outstanding 11 1/4% sinking fund debentures were redeemed at 105.329% of the
principal amount.
 
  Liquidity and Capital Resources
 
     Liquidity refers to the ability of an enterprise to generate adequate
amounts of cash to satisfy its financial needs. Maxus' primary needs for cash
are to fund its exploration and development program, service debt, pay existing
trade obligations, meet redemption obligations on redeemable preferred stock and
pay dividends to preferred stockholders. The Company's primary sources of
liquidity have been from operating activities, asset sales, debt financing and
equity issuances.
 
     Pursuant to the Merger Agreement, in the event that the Company is unable
to meet its obligations as they come due, whether at maturity or otherwise,
including, solely for the purposes of this undertaking, dividend and redemption
payments with respect to the $9.75 Preferred Stock, the $4.00 Preferred Stock
and the $2.50 Preferred Stock, YPF has agreed to capitalize the Company in an
amount necessary to permit the Company to meet such obligations; provided that
YPF's aggregate obligation will be: (i) limited to the amount of debt service
obligations under the Purchaser Facility, the Midgard credit facility and the
Holdings credit facility and (ii) reduced by the amount, if any, of capital
contributions by YPF to the Company after the Merger Date and by the amount of
the net proceeds of any sale by the Company of common stock or non-redeemable
preferred stock after the Merger Date. The foregoing obligations of YPF (the
"Keepwell Covenant") will survive until June 8, 2004. In addition, YPF has
guaranteed the Company's outstanding debt as of the Merger Date, the principal
amount of which was approximately $976 million. The debt covered by the YPF
guarantee includes the Company's outstanding 11 1/4%, 11 1/2% and 8 1/2% Sinking
Fund Debentures, its outstanding 9 7/8%, 9 1/2% and 9 3/8% Notes, and its
outstanding medium-term notes. YPF has also guaranteed the payment and
performance of the Company's obligations to the holders of its $9.75 Preferred
Stock.
 
     Each of the Midgard facility and the Holdings facility contains restrictive
covenants including limitations upon the sale of assets, mergers and
consolidations, the creation of liens and additional indebtedness, investments,
dividends, the purchase or repayment of subordinated indebtedness, transactions
with affiliates and modifications to certain material contracts. The obligors
under the Midgard facility and the Holdings facility may not permit (a)
consolidated tangible net worth to be less than $200 million, in the case of the
Midgard facility, or $350 million, in the case of the Holdings facility, plus
(or minus), in the case of Midgard, the amount of any adjustment in the book
value of assets or, in the case of Holdings, 70% of the amount of any adjustment
to net worth, resulting from the merger of YPFA Corp. into the Company, (b) the
ratio of consolidated cash flow to consolidated debt service to be less than 1.1
to 1.0 at the end of any fiscal quarter and (c) the ratio of consolidated cash
flow to consolidated interest expense to be less than 1.25 to 1.0 at the end of
any fiscal quarter. In addition, mandatory prepayments of the loans under the
Midgard facility and the Holdings facility may be required in connection with
certain asset sales and casualty losses, upon the issuance of subordinated
indebtedness and in 1996 and in each year thereafter if, after semi-annual
review, the agent and the lenders determine that a borrowing base deficiency
exists. No borrowing base deficiencies existed at December 31, 1995.
 
                                       22
<PAGE>   23
 
     Maxus has guaranteed the obligation under the Midgard facility (the
"Midgard Guaranty") and under the Holdings facility (the "Subsidiaries
Guaranty"). The Midgard Guaranty and the Subsidiaries Guaranty contain
restrictions upon mergers and consolidations, the creation of liens and the
business activities in which Maxus and its subsidiaries may engage. In addition,
Midgard, in the case of the Midgard Guaranty, and Holdings and its subsidiaries,
in the case of the Subsidiaries Guaranty, are required to be wholly owned
subsidiaries of Maxus, except to the extent YPF or a subsidiary of YPF (other
than Maxus or a subsidiary of Maxus) makes capital contributions to Midgard or
Holdings or one of Holdings subsidiaries, as the case may be.
 
     In management's opinion, cash on hand and cash from operations will be
inadequate to fund the 1996 program spending budget, service debt, meet
redemption obligations on redeemable preferred stock and pay preferred stock
dividends and trade obligations. During 1996 through the date of this report,
YPF has made capital contributions to the Company in the aggregate amount of $64
million pursuant to the terms of the Keepwell Covenant. It is anticipated that
YPF could be required to make capital contributions in 1996 totaling
approximately $200 million to $250 million to fund the Company's obligations.
Actual capital contributions made by YPF could vary significantly depending on,
among other circumstances, oil and gas prices and program spending commitments.
Such capital contributions will be credited to YPF's obligations under the
Keepwell Covenant and will entitle YPF to shares of Common Stock.
 
     Operating Activities. During the nine months ended December 31, 1995, net
cash provided by operating activities was $57 million. Excluding the change in
working capital requirements, net cash from operating activities was $44 million
during this period. Working capital requirements provided an additional $13
million primarily as a result of U.S. federal income tax refunds of
approximately $60 million. These tax refunds were partially offset by lower
accrued liabilities of $32 million due primarily to payment of Maxus pre-Merger
costs coupled with higher inventories of $13 million.
 
     Net cash provided by operating activities during the three months ended
March 31, 1995, was $62 million of which $18 million was provided by operating
activities and $44 million was from working capital. Working capital was
favorably impacted by higher accrued liabilities of $26 million of which $11
million was due to higher accrued interest, lower oil and gas receivables of $24
million and a U.S. federal income tax refund of $9 million partially offset by
lower accounts payable of $15 million.
 
     Net cash provided by operating activities totaled $70 million and $137
million in 1994 and 1993, respectively. Excluding the change in working capital
requirements, net cash from operating activities was $58 million lower in 1994
than in 1993. Cash flow from operations was negatively impacted by lower crude
oil and natural gas prices, the loss of production from the Divested Properties
and costs associated with staff reductions, but was partially offset by
additional gas volumes from Northwest Java ($30 million). Net working capital
requirements of $42 million for 1994 were $9 million higher than 1993 due to
lower accounts payable primarily as a result of timing of expenditures in
Ecuador.
 
     Investing Activities. During 1995, the Company continued to concentrate its
capital spending in core areas of the United States, Indonesia and Ecuador plus
development of the emerging areas: the Mamore Block in Bolivia and the
Quiriquire Block in Venezuela. Spending in 1995 increased modestly compared to
1994, with the largest increase occurring in the U.S. due to the implementation
of an aggressive program of infill drilling designed to increase production and
cash flow. Only Ecuador experienced lower capital spending in 1995 as spending
for major infrastructure and facilities was completed in 1994. Approximately 45%
of the 1994 capital spending was for development of oil reserves in South
America. Initial production began in the third quarter of 1994 in Ecuador,
Bolivia and Venezuela. Spending in Ecuador in 1994 was $31 million below 1993 as
spending for major infrastructure and facilities was being completed. In 1993,
the development of gas reserves in Northwest Java and development of Block 16 in
Ecuador alone accounted for $167 million of spending. The Northwest Java gas
project was completed on time and within budget in the fourth quarter of 1993.
Additionally, construction of the Sunray gas plant in the Texas Panhandle, which
was started in mid-1991, was completed during the first quarter of 1993.
 
     In December 1995, the Company sold its overriding royalty interest in the
Recetor Block in Colombia for $25 million. There was no gain or loss recognized
on this transaction.
 
                                       23
<PAGE>   24
 
     On April 25, 1994, Offshore Partners sold its interests in Main Pass Blocks
72, 73 and 74. On April 26, 1994, Maxus and its subsidiaries sold all of their
partnership interests in Offshore Partners. In the second quarter of 1994, Maxus
also sold the McFarlan Field and Grand Isle Block 25, both producing oil and gas
properties. In total, the Company received $325 million of proceeds and recorded
a pre-tax gain of $202 million from these transactions. A portion of the
proceeds from these sales was used to reduce senior debt by $70 million net and
to redeem $63 million of the $9.75 Preferred Stock due in February 1995.
 
     During the second quarter of 1994, Maxus Bolivia, Inc., a subsidiary of
Maxus, signed an agreement to take BHP Petroleum as a partner in its Bolivian
oil development project. The Company received $10 million from BHP in exchange
for a 50% interest in the project. Also during the second quarter of 1994, Maxus
Venezuela (C.I.) Ltd. ("Maxus Venezuela"), a subsidiary of Maxus, signed an
agreement with BP Exploracion de Venezuela S.A., granting BP a 45% interest in
the Quiriquire Unit in eastern Venezuela. Maxus Venezuela remains the operator
with a 50% interest and Corporacion Energetica S. 21, C.A., a Venezuelan
company, holds the remaining 5%.
 
     The Company sold its geothermal subsidiary, Thermal Power Company, in
September 1994. The sale was for $58 million net in cash and a $7 million
promissory note due from the purchaser in 1997. The Company recorded a loss of
$13 million on the transaction.
 
     In 1993, the Company purchased $52 million of U.S. Treasury notes. To
partially fund the 1993 capital program budget and cover working capital
fluctuations, the Company subsequently sold $142 million of U.S. Treasury notes
realizing a gain of $8 million. Additionally, during 1993, Maxus received stock
and other securities from The LTV Corporation ("LTV") in settlement of its
bankruptcy claims against LTV. The Company sold these securities for
approximately $22 million, realizing a $2 million gain. During 1994, the Company
purchased an additional $112 million of short-term investments with the proceeds
from the sales of assets. To partially fund the capital program budget and pay
Merger-related costs in 1995, the Company liquidated all its short-term
investments. Additionally, the Company sold its remaining long-term investment
in U.S. Treasury notes for $31 million realizing a gain on the sale of $2
million. In the future, the Company anticipates maintaining only minimal
balances of cash, cash equivalents and short-term investments to cover working
capital fluctuations.
 
     During 1995, the Company was able to release a significant portion of its
restricted cash, of which $48 million supporting letters of credit were released
and $17 million of assets held in trust as required by certain insurance
policies were released due to YPF's guarantees. Additionally, in 1995, the
Company restricted $8 million as required by the Holdings credit agreement.
During 1993, the Company restricted $36 million backing its spending commitment
in Venezuela. The $36 million in restricted cash backing the letters of credit
in Venezuela were released in 1994 when the Company took on a partner and
reduced its interest to 50%.
 
     Financing Activities. During 1995, most of Maxus' financing activity was
impacted by the Merger. The Company received $851 million from the issuance of
debt under the Purchaser Facility and the Midgard and Holdings credit facilities
and a $250 million capital infusion from YPF to partially fund the Merger. In
connection with the Merger, the Company also paid $14 million to redeem rights
attached to Shares, repaid the Purchaser Facility, and, pursuant to the Merger,
either assumed or paid $746 million of purchase consideration for the Shares
outstanding plus transaction costs. Of the approximate $762 million purchase
price paid by YPF to acquire the Company, as of December 31, 1995, $16 million
remained to be paid in respect of Shares and Merger costs. This liability was
recorded in accrued liabilities.
 
     At December 31, 1995, the Company had $7 million of advances outstanding
from YPF. The Company and YPF intend to enter into a loan agreement during 1996
to facilitate short-term loans by YPF to the Company and short-term loans by the
Company to YPF of excess cash balances. It is expected that loans will be made
by the parties under the loan agreement during 1996; however, the number and
amounts thereof are not presently known.
 
     The Company's only derivative financial instruments are an interest rate
swap agreement, natural gas price swap agreements and natural gas and crude oil
futures contracts, which are not used for trading purposes. During the third
quarter of 1995 the Company recorded a $2 million gain which represented the
final
 
                                       24
<PAGE>   25
 
settlement of the Company's sole interest rate swap agreement prior to its
termination. This gain was recorded in other revenues, net. The Company also
received a $5 million termination payment, which has been deferred.
 
     Over the two-year period from January 1, 1993, to December 31, 1994, Maxus
took steps to restructure its debt and equity position. The overall intent was
to provide immediate funding for its major development and construction projects
(the Sunray gas plant, the Northwest Java gas project and the development of
Block 16 in Ecuador) and to match the repayment schedules of the debt with the
future cash flow expected from these projects while maintaining necessary
working capital balances required for flexibility. The Company was able to take
advantage of lower interest rates and, at the same time, to extend the average
debt maturities.
 
     Debt rose significantly in 1993 due to the completion of two of the
Company's major projects and the near completion of the initial phase of the
Ecuador project. These projects contributed to substantial capital spending in
1993. To cover the shortfall between cash from operations and the cash used in
investing activities, incremental new debt was issued. Of the $412 million
proceeds received in 1993 from the issuance of long-term debt, $204 million was
used to refinance currently maturing debt and to fund the early retirement of a
portion of the Company's 11 1/4% sinking fund debentures, with the remainder
partially funding the 1993 capital spending program.
 
     During 1994, the Company issued $101 million of additional long-term debt.
Debt issuances, along with a portion of the proceeds from asset sales, were used
to repay approximately $170 million of debt obligations due 1994 and beyond and
to prepay $63 million of $9.75 Preferred Stock due in February 1995.
 
     In 1993, Maxus issued a new class of preferred stock, the $2.50 Preferred
Stock. Of the $85 million in net proceeds received from the offering, $63
million was used to redeem 625,000 shares of $9.75 Preferred Stock as required
in February 1994.
 
  Accounting Standards
 
     Effective April 1, 1995, the Company used the purchase method of accounting
to record the acquisition of the Company by YPF. In a purchase method
combination, the purchase price is allocated to the assets acquired and
liabilities assumed based on their fair values at the date of acquisition. In
connection with the purchase price allocation, the Company adopted Statement of
Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of,"
which requires a review of long-lived assets for impairment whenever events or
changes in circumstance indicate that the carrying amount of the asset may not
be recoverable. Under SFAS 121, if the expected future cash flow of a long-lived
asset is less than the carrying amount of the asset, an impairment loss shall be
recognized to value the asset at its fair value. Maxus revalued its assets and
liabilities to fair value in the purchase price allocation effective April 1,
1995. There was no impact on the Company's results of operations resulting from
the adoption of SFAS 121 during the nine months ended December 31, 1995.
 
  Environmental Matters
 
     Federal, state and local laws and regulations relating to health and
environmental quality in the United States, as well as environmental laws and
regulations of other countries in which the Company operates, affect nearly all
of the operations of the Company. These laws and regulations set various
standards regulating certain aspects of health and environmental quality,
provide for penalties and other liabilities for the violation of such standards
and establish in certain circumstances remedial obligations. In addition,
especially stringent measures and special provisions may be appropriate or
required in environmentally sensitive foreign areas of operation, such as those
in Ecuador.
 
     Many of the Company's United States operations are subject to requirements
of the Safe Drinking Water Act, the Clean Water Act, the Clean Air Act (as
amended in 1990), the Occupational Safety and Health Act, the Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended
("CERCLA"), and other federal, as well as state, laws. Such laws address, among
other things, limits on the discharge of wastes associated with oil and gas
operations, investigation and clean-up of hazardous substances,
 
                                       25
<PAGE>   26
 
and workplace safety and health. In addition, these laws typically require
compliance with associated regulations and permits and provide for the
imposition of penalties for noncompliance. The Clean Air Act Amendments of 1990
may benefit the Company's business by increasing the demand for natural gas as a
clean fuel.
 
     The Company believes that its policies and procedures in the area of
pollution control, product safety and occupational health are adequate to
prevent unreasonable risk of environmental and other damage, and of resulting
financial liability, in connection with its business. Some risk of environmental
and other damage is, however, inherent in particular operations of the Company
and, as discussed below, the Company has certain potential liabilities
associated with former operations. The Company cannot predict what environmental
legislation or regulations will be enacted in the future or how existing or
future laws or regulations will be administered or enforced. Compliance with
more stringent laws or regulations, as well as more vigorous enforcement
policies of the regulatory agencies, could in the future require material
expenditures by the Company for the installation and operation of systems and
equipment for remedial measures and in certain other respects. Such potential
expenditures cannot be reasonably estimated.
 
     In connection with the sale of the Company's former chemical subsidiary,
Diamond Shamrock Chemicals Company ("Chemicals"), to Occidental Petroleum
Corporation ("Occidental") in 1986, the Company agreed to indemnify Chemicals
and Occidental from and against certain liabilities relating to the business or
activities of Chemicals prior to the September 4, 1986 closing date (the
"Closing Date"), including certain environmental liabilities relating to certain
chemical plants and waste disposal sites used by Chemicals prior to the Closing
Date.
 
     In addition, the Company agreed to indemnify Chemicals and Occidental for
50% of certain environmental costs incurred by Chemicals for which notice is
given to the Company within 10 years after the Closing Date on projects
involving remedial activities relating to chemical plant sites or other property
used in the conduct of the business of Chemicals as of the Closing Date and for
any period of time following the Closing Date, with the Company's aggregate
exposure for this cost sharing being limited to $75 million. The total expended
by the Company under this cost sharing arrangement was about $39 million as of
December 31, 1995. Occidental Chemical Corporation ("OxyChem"), a subsidiary of
Occidental, and Henkel Corporation ("Henkel"), an assignee of certain of
Occidental's rights and obligations, have filed a declaratory judgment action in
Texas state court with respect to the Company's agreement in this regard (see
"Legal Proceedings").
 
     In connection with the spin-off of Diamond Shamrock R&M, Inc., now known as
Diamond Shamrock, Inc. ("DSI"), in 1987, the Company and DSI agreed to share the
costs of losses (other than product liability) relating to businesses disposed
of prior to the spin-off, including Chemicals. Pursuant to this cost-sharing
agreement, the Company bore the first $75 million of such costs and DSI bore the
next $37.5 million. Under the arrangement, such ongoing costs are now borne
one-third by DSI and two-thirds by the Company. This arrangement will continue
until DSI has borne an additional $47.5 million, following which such costs will
be borne solely by the Company. As of December 31, 1995, DSI's remaining
responsibility is approximately $8 million and is included in accounts
receivable in the accompanying balance sheet.
 
     For the year ended December 31, 1995, the Company spent $6 million in
environmental related expenditures in its oil and gas operations. Expenditures
in 1996 are expected to be approximately $8 million.
 
     The Company's total expenditures for environmental compliance for disposed
of businesses, including Chemicals, were approximately $38 million in 1995, $12
million of which were recovered from DSI under the above described cost-sharing
agreement. Those expenditures are projected to be approximately $23 million in
1996 after recovery from DSI under such agreement.
 
     At December 31, 1995, reserves for the environmental contingencies
discussed herein totaled $119 million. Management believes it has adequately
reserved for all environmental contingencies which are probable and can be
reasonably estimated; however, changes in circumstances could result in changes,
including additions, to such reserves in the future.
 
     The insurance companies that wrote Chemicals' and the Company's primary and
excess insurance during the relevant periods have to date refused to provide
coverage for most of Chemicals' or the Company's cost of
 
                                       26
<PAGE>   27
 
the personal injury and property damage claims related to environmental claims,
including remedial activities at chemical plant sites and disposal sites. In two
actions filed in New Jersey state court, the Company has been conducting
litigation against all of these insurers for declaratory judgments that it is
entitled to coverage for certain of these claims. In 1989, the trial judge in
one of the New Jersey actions ruled that there is no insurance coverage with
respect to the claims related to the Newark plant (discussed below). The trial
court's decision was upheld on appeal and that action is now ended. The other
suit, which is pending, covers disputes with respect to insurance coverage
related to certain other environmental matters.
 
     Newark, New Jersey. A consent decree, previously agreed upon by the U.S.
Environmental Protection Agency (the "EPA"), the New Jersey Department of
Environmental Protection and Energy (the "DEP") and Occidental, as successor to
Chemicals, was entered in 1990 by the United States District Court of New Jersey
and requires implementation of a remedial action plan at Chemicals' former
Newark, New Jersey agricultural chemicals plant. Engineering for such plan,
which will include an engineering estimate of the cost of construction, is
progressing. Construction is expected to begin in 1997, cost approximately $22
million and take three to four years to complete. The work is being supervised
and paid for by the Company pursuant to its above described indemnification
obligation to Occidental. The Company has fully reserved the estimated costs of
performing the remedial action plan and required ongoing maintenance costs.
 
     Studies have indicated that sediments of the Newark Bay watershed,
including the Passaic River adjacent to the plant, are contaminated with
hazardous chemicals from many sources. Studies performed by the Company and
others suggest that contaminants historically discharged by the Newark plant are
buried under several feet of more recent sediment deposits and are not moving.
The Company, on behalf of Occidental, negotiated an agreement with the EPA under
which the Company is conducting further testing and studies to characterize
contaminated sediment in a six-mile portion of the Passaic River near the plant
site. The Company currently expects such testing and studies to be completed in
1999 and cost from $4 million to $6 million after December 31, 1995. The Company
has reserved its estimate of the remaining costs to be incurred in performing
these studies as of December 31, 1995. The Company has been conducting similar
studies under its own auspices for several years. Until these studies are
completed and evaluated, the Company cannot reasonably forecast what regulatory
program, if any, will be proposed for the Passaic River or the Newark Bay
watershed and therefore cannot estimate what additional costs, if any, will be
required to be incurred.
 
     Hudson County, New Jersey. Until 1972, Chemicals operated a chromium ore
processing plant at Kearny, New Jersey. According to the DEP, wastes from these
ore processing operations were used as fill material at a number of sites in
Hudson County.
 
     As a result of negotiations between the Company (on behalf of Occidental)
and the DEP, Occidental signed an administrative consent order with the DEP in
1990 for investigation and remediation work at certain chromite ore residue
sites in Kearny and Secaucus, New Jersey. The work is being performed by the
Company on behalf of Occidental, and the Company is funding Occidental's share
of the cost of investigation and remediation of these sites and is currently
providing financial assurance for performance of the work in the form of a
self-guarantee in the amount of $20 million subject to the Company's continuing
ability to satisfy certain financial tests specified by the State. This
financial assurance may be reduced with the approval of the DEP following any
annual cost review. While the Company has participated in the cost of studies
and is implementing interim remedial actions and conducting remedial
investigations and feasibility studies, the ultimate cost of remediation is
uncertain. The Company anticipates submitting its investigation and feasibility
reports to the DEP in late 1996 or 1997. The results of the DEP's review of
these reports could impact the cost of any further remediation that may be
required. The Company has reserved its best estimate of the remaining cost to
perform the investigations and remedial work as being $50 million at December
31, 1995. In addition, the DEP has indicated that it expects Occidental and the
Company to participate with the other chromium manufacturers in the funding of
certain remedial activities with respect to a number of so-called "orphan"
chrome sites located in Hudson County, New Jersey. Occidental and the Company
have declined participation as to those sites for which there is no evidence of
the presence of residue generated by Chemicals. The Governor of New Jersey
issued an Executive Order requiring state agencies to provide specific
justification for
 
                                       27
<PAGE>   28
 
any state requirements more stringent than federal requirements. The DEP has
indicated that it may be revising its soil action level upwards towards the
higher soil screening levels proposed by the EPA in 1994.
 
     Painesville, Ohio. From about 1912 through 1976, Chemicals operated
manufacturing facilities in Painesville, Ohio. The operations over the years
involved several discrete but contiguous plant sites over an area of about 1,300
acres. The primary area of concern historically has been Chemicals' former
chromite ore processing plant (the "Chrome Plant"). For many years, the site of
the Chrome Plant has been under the administrative control of the EPA pursuant
to an administrative consent order under which Chemicals is required to maintain
a clay cap over the site and to conduct certain ground water and surface water
monitoring. Many other sites have previously been clay-capped and one specific
site, which was a waste disposal site from the mid-1960s until the 1970s, has
been encapsulated and is being controlled and monitored. In September 1995, the
Ohio Environmental Protection Agency (the "OEPA") issued its Directors' Final
Findings and Order (the "Director's Order") by consent ordering that a remedial
investigation and feasibility study (the "RIFS") be conducted at the former
Painesville plant area. The Company has agreed to participate in the RIFS as
required by the Director's Order. It is estimated that the total cost of
performing the RIFS will be $3 million to $5 million over the next three years.
In spite of the many remedial, maintenance and monitoring activities performed,
the former Painesville plant site has been proposed for listing on the National
Priority List under CERCLA; however, the EPA has stated that the site will not
be listed so long as it is satisfactorily addressed pursuant to the Director's
Order and OEPA's programs. The Company has accrued the estimate of its share of
the cost to perform the RIFS. The scope and nature of any further investigation
or remediation that may be required cannot be determined at this time; however,
as the RIFS progresses, the Company will continuously assess the condition of
the Painesville plant site and make any changes, including additions, to its
reserve as may be required.
 
     Other Former Plant Sites. Environmental remediation programs are in place
at all other former plant sites where material remediation is required in the
opinion of the Company. Former plant sites where remediation has been completed
are being maintained and monitored to insure continued compliance with
applicable laws and regulatory programs. The Company has reserved $6 million at
December 31, 1995, related to these sites, none of which are individually
material.
 
     Third Party Sites. Chemicals has also been designated as a potentially
responsible party ("PRP") by the EPA under CERCLA with respect to a number of
third party sites, primarily off of Chemicals' properties, where hazardous
substances from Chemicals' plant operations allegedly were disposed of or have
come to be located. Numerous PRPs have been named at substantially all of these
sites. At several of these, Chemicals has no known exposure. Although PRPs are
almost always jointly and severally liable for the cost of investigations,
cleanups and other response costs, each has the right of contribution from other
PRPs and, as a practical matter, cost sharing by PRPs is usually effected by
agreement among them. Accordingly, the ultimate cost of these sites and
Chemicals' share of the costs thereof cannot be estimated at this time, but are
not expected to be material except possibly as a result of the matters described
below.
 
     1. Fields Brook; Ashtabula, Ohio. At the time that Chemicals was sold to
Occidental, Chemicals operated a chemical plant at Ashtabula, Ohio which is
adjacent to Fields Brook. Occidental has continued to operate the Ashtabula
plant. In 1986, Chemicals was formally notified by the EPA that it was a PRP for
the Fields Brook site. The site is defined as Fields Brook, its tributaries and
surrounding areas within the Fields Brook watershed. At least 15 other parties
are presently considered to be financially responsible PRPs. In 1986, the EPA
estimated the cost of sediment remediation at the site would be $48 million. The
PRPs, including Occidental, have developed an allocation agreement for sharing
the costs of the work in Fields Brook ordered by the EPA. Under the allocation,
the Occidental share for Chemicals' ownership of the Ashtabula plant would be
about five percent of the total, assuming all viable PRPs were to participate.
 
     In 1990, the OEPA, as state trustee for natural resources under CERCLA,
advised previously identified PRPs, including Chemicals, that the OEPA intended
to conduct a Natural Resource Damage Assessment of the Fields Brook site to
calculate a monetary value for injury to surface water, groundwater, air, and
biological and geological resources at the site. Also, although Fields Brook
empties into the Ashtabula River which flows into Lake Erie, it is not known to
what extent, if any, the EPA will propose remedial action beyond Fields
 
                                       28
<PAGE>   29
 
Brook for which the Fields Brook PRPs might be asked to bear some share of the
costs. Until all preliminary studies and necessary governmental actions have
been completed and negotiated or judicial allocations have been made, it is not
possible for the Company to estimate what the response costs, response
activities or natural resource damages, if any, may be for Fields Brook or
related areas, the parties responsible therefore or their respective shares.
 
     It is the Company's position that costs attributable to the Ashtabula plant
fall under the Company's above-described cost sharing arrangement with
Occidental under which the Company bears one-half of certain costs up to an
aggregate dollar cap. Occidental, however, has contended that it is entitled to
full indemnification from the Company for such costs, and the outcome of this
dispute cannot be predicted. The Company has reserved its estimate of its share
of potential cleanup costs based on the assumption that this site falls under
the Occidental cost sharing arrangement.
 
     2. French Limited Disposal Site; Crosby, Texas. The PRPs, including
Chemicals (represented by the Company), entered into a consent decree and a
related trust agreement with the EPA with respect to this disposal site. The
consent decree was entered by the federal court as a settlement of the EPA's
claim for remedial action. Chemical's share of the cost to complete remediation
at this site at December 31, 1995 is expected to be approximately $500,000 and
such amount is fully accrued.
 
     3. SCP/Carlstadt Site; Carlstadt, New Jersey. Chemicals' share of
remediation costs at this CERCLA site would be approximately one percent, based
on relative volume of waste shipped to the site. An interim remedy has now been
implemented at the site by the PRPs but no estimate can be made at this time of
ultimate costs of remediation which may extend to certain off-site locations.
 
     4. Chemical Control Site; Elizabeth, New Jersey. The DEP has demanded of
PRPs (including Chemicals) reimbursement of the DEP's alleged $34 million
(including interest through December 31, 1995) in past costs for its partial
cleanup of this site. The PRPs and the EPA have settled the federal claims for
cost recovery and site remediation, and remediation is now complete. Based on
the previous allocation formula, it is expected that Chemicals' share of any
money paid to the DEP for its claim would be approximately two percent. The
Company has fully reserved its estimated liability for this site.
 
  Legal Proceedings
 
     In November 1995, OxyChem filed suit in Texas state court seeking a
declaration of certain of the parties' rights and obligations under the sales
agreement pursuant to which the Company sold Chemicals to Occidental. Henkel
joined in said lawsuit as a plaintiff in January 1996. Specifically, OxyChem and
Henkel are seeking a declaration that the Company is required to indemnify them
for 50% of certain environmental costs incurred on projects involving remedial
activities relating to chemical plant sites or other property used in connection
with the business of Chemicals on the Closing Date which relate to, result from
or arise out of conditions, events or circumstances discovered by OxyChem or
Henkel and as to which the Company is provided written notice by OxyChem or
Henkel prior to the expiration of ten years following the Closing Date,
irrespective of when OxyChem or Henkel incurs and gives notice of such costs,
subject to an aggregate $75 million cap. The Company believes that this lawsuit
is without merit and intends to defend same vigorously. The Company has
established reserves based on its 50% share of costs expected to be paid or
incurred by OxyChem and Henkel prior to September 1996.
 
     As of December 31, 1995, the Company had paid OxyChem and Henkel a total of
approximately $39 million against said $75 million cap. The Company cannot
predict what portion of the approximately $36 million remaining as of that date
Occidental and Henkel may actually pay or incur prior to September 4, 1996, the
tenth anniversary of the Closing Date if they accelerate spending with regard to
such environmental costs; however, the Company has approximately $7 million
reserved at December 31, 1995, based on 50% of OxyChem's and Henkel's historical
annual expenditures. In the event OxyChem and Henkel prevail in this lawsuit,
the Company could be required to provide up to approximately $29 million in
additional reserves related to this indemnification.
 
                                       29
<PAGE>   30
 
     The Company has established reserves for legal contingencies in situations
where a loss is probable and can be reasonably estimated.
 
  Future Outlook
 
     In addition to maintaining and developing its core and emerging areas, it
is expected that, beginning in 1996, the Company will acquire or assume
responsibility for certain YPF exploration interests in South America (outside
Argentina) and the United States Gulf of Mexico. The Company will continue to
focus on maximizing the value of its core producing assets and seek new
investment opportunities in associated ventures.
 
     Maxus currently projects total program spending (capital expenditures plus
exploration expenses) for 1996 to be approximately $249 million, compared to
$231 million in 1995. Indonesia will receive nearly $79 million, Midgard (U.S.)
$72 million, South America $62 million and exploration interests outside
Argentina acquired or assumed from YPF $25 million. The remaining $11 million
will be allocated to domestic and overseas new ventures. Funding for the 1996
spending program is expected to be provided through cash and cash equivalents on
hand at the beginning of the year, expected cash from operations and capital
contributions from YPF as necessary. In addition to the 1996 program, Maxus has
financial and/or performance commitments for exploration and development
activities in 1997 and beyond none of which are material except for the recently
acquired Guarapiche block in Venezuela discussed below.
 
     In January 1996, the Company and its partners were successful in acquiring
the highly prospective Guarapiche block in Venezuela's first auction awards for
equity production in over 20 years. Guarapiche is located on the same trend as
the five billion barrel El Furrial field in northeastern Venezuela. The Company,
together with its partners, paid $109 million (approximately $27 million net to
the Company) to the Venezuelan government for rights to explore the Guarapiche
block. BP Exploration Orinoco Limited is the operator with a 37.5% working
interest while Amoco Production Company and the Company hold 37.5% and 25%
working interests, respectively. The Company's net exploration commitment is
anticipated to total approximately $15 million over the next five years.
 
     The Company has begun discussions with other companies concerning the
establishment of a joint venture or other alliance with regard to Midgard's
business and assets. The objectives of such a joint venture or alliance would be
lowering unit costs, creating economies of scale and improving marketing
leverage. No joint venture or other partner has been selected and no assurances
can be given that the attempts to establish a joint venture or other alliance
will be successful. In addition, Maxus is considering a number of possible
capital and business restructuring alternatives; however, no decisions have been
made to take any specific action nor can there be any assurance that any
specific action will be taken.
 
     By the end of 1995, management had streamlined the Maxus organizational
structure, reduced Maxus' overhead costs and improved communications and
decision making. In addition, a "management by objectives" program was
introduced to make each business unit and staff group directly responsible for
their accomplishments. These actions are expected to result in significant cost
savings.
 
     The Company's foreign petroleum exploration, development and production
activities are subject to political and economic uncertainties, expropriation of
property and cancellation or modification of contract rights, foreign exchange
restrictions and other risks arising out of foreign governmental sovereignty
over the areas in which the Company's operations are conducted, as well as risks
of loss in some countries due to civil strife, guerrilla activities and
insurrection. Areas in which the Company has significant operations include the
United States, Indonesia, Ecuador, Bolivia and Venezuela.
 
     In Ecuador, pipeline capacity available to the Company is sufficient to
transport only about 60% of the oil the Company expected to be able to produce
daily, and none of the various projects to increase transportation capacity that
have been considered has been approved by the government of Ecuador. In
addition, the Company is involved in a number of contract, auditing and
certification disputes with various government entities. Together, the lack of
pipeline capacity and the various disputes with government entities are
retarding the Company's ability to proceed with the economic development of
Block 16. Although the Company can
 
                                       30
<PAGE>   31
 
give no assurances concerning the outcome of these discussions, progress has
recently been made on several important issues. The Company intends to reduce
program spending in Ecuador in 1996 to $19 million from $32 million in 1995.
 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
 
     The information required by this item appears on pages F-1 to F-69 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, 1996
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     57        1995
W. Mark Miller................  Executive Vice President and Treasurer    42        1995
Michael C. Forrest............  Senior Vice President                     62        1992
David A. Wadsworth............  Vice President, Legal                     46        1995
Linda R. Engelbrecht..........  Controller                                40        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, except that Mr. Monti received $120,000 from YPF in
respect of the period from August 21, 1995, when he was elected President, Chief
Executive Officer and a director of the Company, until October 9, 1995, when he
became an employee of the Company. Certain information regarding the principal
occupations and employment of each of the officers named above during the prior
five years is set forth below.
 
     Mr. Monti was elected President and Chief Executive Officer and a director
of the Company effective August 21, 1995 and became an employee of the Company
on October 9, 1995. Prior to joining Maxus, Mr. Monti served as the President of
Dowell, a division of Schlumberger Limited. Since joining the oilfield services
company in 1963, Mr. Monti has held various positions with Schlumberger,
including president and vice president of various divisions or subsidiaries.
 
     Mr. Miller was elected Executive Vice President and Treasurer of the
Company in November 1995. Mr. Miller joined a former subsidiary of Maxus in 1981
as Manager, Taxes and has held various positions with the Company since such
time, including Director, Exploration and Production Taxes; Director, Operations
Auditing; General Manager, Indonesia; and Vice President of the Company.
 
     Mr. Forrest joined the Company in 1992 as special assistant to the Chairman
and later that year was elected Vice Chairman and Chief Operating Officer. Prior
to 1992, he was with Shell U.S.A. for more than five years, last serving as
President of its subsidiary, Pecten International Company. Mr. Forrest was named
Senior Vice President, Business Development of the Company in 1994. Mr. Forrest
has been a Senior Vice President of the Company since 1994.
 
     Mr. Wadsworth was elected Vice President, Legal of the Company in June
1995. Mr. Wadsworth joined Natomas Company, a former subsidiary of Maxus, in
1979. He has served in various positions with the Company, including Associate
General Counsel and Corporate Secretary, since such time.
 
                                       31
<PAGE>   32
 
     Mrs. Engelbrecht was elected Controller of the Company in November 1995.
She joined a former subsidiary of the Company in 1978 as a financial associate
and has held various positions with the Company, including Director of Financial
Reporting and Assistant Controller, since such time.
 
  Directors of the Company
 
     Certain information regarding each director, including his age, is set
forth below. Each director is elected at the annual meeting of stockholders for
a term of one year.
 
     CHARLES L. BLACKBURN: 68, a director of the Company since 1986. For more
than five years prior to his retirement in April 1995, he was also the Chairman,
President and Chief Executive Officer of Maxus. He is currently an international
consultant for the Company. Mr. Blackburn also serves as a director of Lone Star
Technologies, Inc. and Landmark Graphics Corporation.
 
     CEDRIC BRIDGER: 60, a director of the Company since April 1995. Mr. Bridger
has been Vice President, Finance and Corporate Development of YPF since 1992.
From 1989 to 1992, he was employed by CBV Industrias Mecanicas in Brazil, last
serving as Marketing Manager. Previously, he was associated with Hughes Tool
Company from 1964 to 1989.
 
     GEORGE L. JACKSON: 67, a director of the Company since 1987. Mr. Jackson
has been an oil field service consultant for more than five years.
 
     NELLS LEON: 69, a director of the Company since June 1995. Mr. Leon has
been a director of YPF since 1991, and was elected President of YPF in May 1995.
Mr. Leon held various positions with YPF from 1956 to 1977 and from 1983 to
1987. Since 1990, he has served as Executive Vice President. He was Vice
President of Operations of Sol Petroleo S.A. from 1987 to 1990.
 
     JAMES R. LESCH: 74, a director of the Company since April 1995. Mr. Lesch
has been a director of YPF since 1993. He is currently retired, having retired
from Hughes Tool Company in 1986. He was Chief Executive Officer (1979-1986) and
Chairman of the Board (1981-1986) of Hughes Tool Company and also served as
Commissioner, State of Texas Department of Commerce (1988-1992). Previously, he
served as Director of the American Petroleum Institute. Mr. Lesch also serves as
a director of TransTexas Gas Corporation.
 
     ROBERTO MONTI: 57, a director, President and Chief Executive Officer of the
Company since August 1995. Prior to such time, Mr. Monti had been employed since
1963 by Schlumberger Limited, an oil field services company, in various
capacities. He most recently served as President of Dowell, a division of
Schlumberger Limited.
 
     P. DEXTER PEACOCK: 54, a director of the Company since April 1995. Mr.
Peacock has been a partner of the law firm of Andrews & Kurth L.L.P. since 1975.
He is a member of the firm's Management Committee. He currently serves as a
director of Texas Commerce Bank National Association and as an alternate
director of YPF.
 
     R. A. WALKER: 39, a director of the Company since 1994. He is a Managing
Director of Prudential Capital Group and a Vice President of The Prudential
Insurance Company of America ("Prudential"). Mr. Walker has held similar
positions with Prudential Capital Group for the past five years. He was elected
to the Board of Directors of Maxus by Prudential pursuant to the terms of the
$9.75 Preferred Stock.
 
ITEM 11. EXECUTIVE COMPENSATION.
 
DIRECTOR COMPENSATION
 
     The Company pays each director who is not an employee of the Company or YPF
(other than Mr. Blackburn) an annual retainer of $20,000 and a fee of $1,000 for
each meeting of the Board attended and for each committee meeting attended. For
so long as Mr. Blackburn is an international consultant to the Company, he will
not be entitled to such compensation paid to other non-employee Directors.
See--"Employment Contracts and Termination of Employment and Change in Control
Agreements."
 
                                       32
<PAGE>   33
 
EXECUTIVE OFFICER COMPENSATION
 
     The following tables set forth compensation awarded to, earned by or paid
to the executive officers named below in 1993, 1994 and 1995.
 
                           SUMMARY COMPENSATION TABLE
 
<TABLE>
<CAPTION>
                                                                           LONG TERM
                                                                          COMPENSATION
                                                                          ------------
                                                  ANNUAL COMPENSATION      SECURITIES
                                                  -------------------      UNDERLYING     ALL OTHER
                 NAME AND                         SALARY       BONUS      OPTIONS/SARS   COMPENSATION
            PRINCIPAL POSITION             YEAR     ($)         ($)           (#)            ($)
------------------------------------------ ----   -------     -------     ------------   ------------
<S>                                        <C>    <C>         <C>         <C>            <C>
Roberto Monti............................. 1995   302,052(1)   30,000(2)           0         10,923(3)
  President and Chief Executive Officer    1994       N/A         N/A            N/A            N/A
                                           1993       N/A         N/A            N/A            N/A
W. Mark Miller............................ 1995   174,900      60,000              0         87,086(4)
  Executive Vice President and Treasurer   1994       N/A         N/A            N/A            N/A
                                           1993       N/A         N/A            N/A            N/A
Michael C. Forrest........................ 1995   261,016      60,000              0      1,291,032(5)
  Senior Vice President                    1994   304,020     100,000         65,000         18,241(3)
                                           1993   298,020      75,000              0         17,881(3)
David A. Wadsworth........................ 1995   155,640      52,000              0          9,338(3)
  Vice President, Legal                    1994       N/A         N/A            N/A            N/A
                                           1993       N/A         N/A            N/A            N/A
Linda R. Engelbrecht...................... 1995   119,910      36,000              0          7,195(3)
  Controller                               1994       N/A         N/A            N/A            N/A
                                           1993       N/A         N/A            N/A            N/A
Charles L. Blackburn...................... 1995   209,331           0              0      4,996,344(6)
  Chairman, President and Chief            1994   519,996     200,000        185,000         31,200(3)
     Executive Officer                     1993   512,496     100,000              0         30,750(3)
     (executive officer through April 21,
       1995)
Peter Gaffney............................. 1995   300,000(7)        0              0              0
  President and Chief Executive Officer    1994       N/A         N/A            N/A            N/A
     (executive officer from April 21,
       1995                                1993       N/A         N/A            N/A            N/A
     through August 21, 1995)
G. W. Pasley.............................. 1995   167,703           0              0      1,007,245(8)
  Senior Vice President                    1994   208,440     100,000         65,000         12,506(3)
     (executive officer through            1993   198,840      45,000              0         11,930(3)
     August 31, 1995)
Glen R. Brown............................. 1995   189,582           0              0        942,434(9)
  Vice President and Controller            1994   174,420      55,000         28,000         10,465(3)
     (executive officer through            1993   165,375      25,000              0          9,923(3)
     December 15, 1995)
</TABLE>
 
                                       33
<PAGE>   34
 
---------------
 
(1) Mr. Monti became a consultant, officer and director of the Company on August
    21, 1995, and an employee of the Company on October 9, 1995. He received
    $120,000 of this amount from YPF in respect of his serving as President and
    Chief Executive Officer of the Company prior to the date on which he became
    an employee.
(2) Mr. Monti was paid this amount as a signing bonus upon commencement of his
    employment with the Company.
(3) These payments represent the Company's matching contributions to this
    individual's qualified and non-qualified savings plans' accounts.
(4) $76,592 of this amount represents a payment made in accordance with Mr.
    Miller's employment agreement (see--"Employment Contracts, Termination of
    Employment and Change in Control Agreements"), and $10,494 of such amount
    represents the Company's matching contributions to Mr. Miller's qualified
    and non-qualified savings plan accounts.
(5) $1,075,383 of this amount represents a payment made in accordance with Mr.
    Forrest's change in control agreement (see--"Employment Contracts,
    Termination of Employment and Change in Control Agreements"); $199,988
    represents payment in respect of the surrender pursuant to the terms of the
    Merger Agreement of options and stock appreciation rights ("SARs") held by
    Mr. Forrest (see table below entitled "Aggregated Option/SAR Exercises in
    the Last Fiscal Year and FY-End Option/SAR Values"); and $15,661 of such
    amount represents the Company's matching contributions to Mr. Forrest's
    qualified and non-qualified savings plan accounts.
(6) $120,000 of this amount represents payments in connection with Mr.
    Blackburn's consulting agreement with the Company (see--"Employment
    Contracts and Termination of Employment and Change in Control Agreements"),
    $2,662,070 of such amount represents a severance payment made in accordance
    with Mr. Blackburn's change in control agreement (see "-- Employment
    Contracts, Termination of Employment and Change in Control Agreements");
    $1,943,632 of such amount represents a lump sum payment to Mr. Blackburn in
    respect of the Company's retirement plans, including the Supplemental
    Executive Retirement Plan; $298,396 represents a distribution from Mr.
    Blackburn's savings plan accounts; $104,588 represents payment in respect of
    restricted shares of Common Stock, the restrictions on which lapsed on May
    1, 1995 in accordance with their terms; and $10,400 of such amount
    represents the Company's matching contributions to Mr. Blackburn's qualified
    and non-qualified savings plan accounts.
(7) Mr. Gaffney became a consultant and an officer of the Company on April 21,
    1995 and an employee of the Company on June 6, 1995. Pursuant to an
    agreement between Mr. Gaffney and the Company, he received a total of
    $300,000, $195,721 of which was paid with respect of the period during which
    he was an employee of the Company.
(8) $835,893 of this amount represents a severance payment made in accordance
    with Mr. Pasley's change in control agreement (see--"Employment Contracts,
    Termination of Employment and Change in Control Agreements"); $162,774
    represents a distribution or rights to a distribution from Mr. Pasley's
    savings plan accounts; and $8,578 of such amount represents the Company's
    matching contributions to Mr. Pasley's qualified and non-qualified savings
    plan accounts.
(9) $619,877 of this amount represents a severance payment made in accordance
    with Mr. Brown's change in control agreement (see--"Employment Contracts,
    Termination of Employment and Change in Control Agreements"); $84,999
    represents payment in respect of the surrender pursuant to the terms of the
    Merger Agreement of options and SARs held by Mr. Brown (see table below
    entitled "Aggregated Option/SAR Exercises in the Last Fiscal Year and FY-End
    Option/SAR Values"); $13,772 represents payment in respect of restricted
    shares of Common Stock, the restrictions on which lapsed on May 1, 1995 in
    accordance with their terms; $213,560 represents a distribution or rights to
    a distribution from Mr. Brown's savings plan accounts; and $10,226
    represents the Company's matching contributions to Mr. Brown's qualified and
    non-qualified savings plan accounts.
 
            AGGREGATED OPTION/SAR EXERCISES IN THE LAST FISCAL YEAR
                          AND FY-END OPTION/SAR VALUES
 
<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 ($)
                                               EXERCISE   REALIZED    EXERCISABLE/     EXERCISABLE/
                      NAME                       (#)       ($)(1)     UNEXERCISABLE    UNEXERCISABLE
    -----------------------------------------  --------   --------   ---------------   -------------
    <S>                                        <C>        <C>        <C>               <C>
    Roberto Monti............................      0             0          0               0/0
    W. Mark Miller...........................      0       138,532          0               0/0
    Michael C. Forrest.......................      0       199,998(2)       0               0/0
    David A. Wadsworth.......................      0        10,930          0               0/0
    Linda R. Engelbrecht.....................      0           740          0               0/0
    Charles L. Blackburn.....................      0             0(2)       0               0/0
    Peter Gaffney............................      0             0          0               0/0
    G. W. Pasley.............................      0        25,000(2)       0               0/0
    Glen R. Brown............................      0        84,999(2)       0               0/0
</TABLE>
 
                                       34
<PAGE>   35
 
---------------
 
(1) These payments were made in respect of the surrender of options and any SARs
    held by the named executive officers as contemplated by the terms of the
    Merger Agreement. No shares of stock were acquired in these transactions.
 
(2) Although each of these named executive officers surrendered all of his
    options and SARs in 1995, payment was not made in 1995 by the Company in
    respect of a certain number of such options and SARs due to then pending tax
    and other questions. Such questions have been resolved and these named
    officers received the following amounts in 1996 for their surrendered
    options and SARs: Mr. Monti--0; Mr. Miller--0; Mr. Forrest--$182,102; Mr.
    Wadsworth--0; Mrs. Engelbrecht--0; Mr. Blackburn--$939,256; Mr. Gaffney--0;
    Mr. Pasley--$307,173; and Mr. Brown--$87,502.
 
EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND CHANGE IN CONTROL
AGREEMENTS
 
     Employment Contracts. On April 5, 1995, the Company entered into an
agreement with Mr. Gaffney, a director and the President and Chief Executive
Officer of the Company from April 21, 1995 to August 21, 1995, whereby Mr.
Gaffney served in the capacity of chief executive officer of the Company in
consideration of payment of $50,000 a month from the date of such agreement
through September 30, 1995. A total of $300,000 was paid to Mr. Gaffney under
this agreement, $195,721 during the period he was an employee. In addition,
Gaffney, Cline, an oil and gas technical and management consulting firm of which
Mr. Gaffney is a Senior Partner, entered into an agreement with the Company
obligating the Company to pay Gaffney, Cline $500,000 in consideration of
Gaffney, Cline granting Mr. Gaffney a leave of absence to enable him to serve as
the Company's chief executive officer.
 
     The Company entered into an agreement effective July 1, 1995 in replacement
of a change in control agreement dated November 1, 1991 with Mr. Miller,
Executive Vice President and Treasurer of the Company, under which Mr. Miller is
to be employed for a term of four years at not less than his then current
salary, plus an annual bonus not less than the amount of the largest bonus paid
to Mr. Miller in respect of the years 1992, 1993 or 1994, and a "sign-on" bonus
in the amount of $76,592. In addition, a "stay on" bonus in the amount of
$76,592 is payable under this agreement on each of July 1, 1996, 1997 and 1998
provided, as to each such "stay on" bonus, that Mr. Miller continues to be an
employee of the Company on the respective payment date. Under the agreement, in
the event that Mr. Miller's employment is terminated under certain
circumstances, severance compensation will be paid to Mr. Miller as specified
therein.
 
     On December 27, 1995, the Company entered an agreement with Mr. Monti, a
director and the President and Chief Executive Officer of the Company, pursuant
to which his Foreign Service Pay, as defined in such agreement, payable with
respect to services rendered from and after January 1, 1996 will be credited by
the Company to a deferral account which will bear interest at a specified rate
and the balance of which will be paid to Mr. Monti under certain circumstances,
including termination of his employment with the Company.
 
     Mr. Blackburn, a director and formerly the Chairman, President and Chief
Executive Officer of the Company, became an international consultant during 1995
to YPF pursuant to a consulting agreement which was subsequently assigned to
Maxus. Under the two-year contract, Mr. Blackburn will be available to render
consulting services for a minimum of 60 days per year and be paid a retainer of
$180,000 per year. Mr. Blackburn will be paid $3,000 per day for each day of
consulting provided in excess of 60 days per year. Office space is made
available to him in Dallas and Buenos Aires. During 1995, Mr. Blackburn was paid
a total of $120,000 under the terms of this contract.
 
     Termination of Employment Agreements. On August 3, 1995, the Company
entered into an agreement with Mr. Monti under which he will receive a severance
payment from the Company in the amount of $3 million in the event that his
employment with the Company is terminated (i) by Mr. Monti or the Company for
reason of death or disability; (ii) by the Company other than for cause; (iii)
by Mr. Monti for any reason within six months following a take-over (other than
to accept employment with YPF); and (iv) by Mr. Monti for any reason after
reaching age 65.
 
     Separation Pay Plan. Under the Separation Pay Plan, most employees (other
than non-resident aliens), excluding Mr. Monti (who has waived any rights
thereunder) but including the other named executive
 
                                       35
<PAGE>   36
 
officers, are eligible for separation pay if their employment is terminated for
any reason other than death, voluntary termination of employment, voluntary
retirement or discharge for reasons of criminal activity, willful misconduct,
gross negligence in the performance of duties or violation of Company policy.
The payment to be received under the plan by a particular employee depends on
his job classification and length of service and whether termination occurs
after the elimination of the employee's position or a change in control of the
Company (as defined in the plan). In the case of the named executive officers,
the plan provides in most cases for separation pay in an amount equal to
two-weeks' base pay for each year of service with the Company, plus three
months' base pay, not to exceed a maximum of 12 months' base pay; and, in the
case of a change in control of the Company, separation pay in an amount equal to
one month's base pay for each year of service with the Company, but not less
than 12 months' base pay nor more than 24 months' base pay. The plan requires
that employees sign releases as a condition of receiving separation pay.
Executive officers are not entitled to separation pay under the plan to the
extent they receive severance payments under the change in control agreements
discussed below or employment contracts discussed above. The acquisition of the
Company by YPF constitutes a change in control under the Separation Pay Plan,
thereby triggering the post-change in control separation formula until April 5,
1997.
 
     Change in Control Agreements. In 1987 or thereafter, the Company entered
into agreements with certain executives including Messrs. Blackburn, Forrest,
Brown, Pasley and Miller which were binding upon execution but were to become
operative on a change of control of the Company. Pursuant to the terms of said
agreements, they became operative when YPF acquired control of the Company.
 
     Under these agreements, the executive officer is entitled to continue in
the employ of the Company until the earlier of the expiration of the third
anniversary of the occurrence of a "change in control" or the executive's death
at an annual base salary of not less than the rate in effect upon the occurrence
of a change in control plus an incentive award of not less than the highest such
award received by the executive for any year in the three calendar years
immediately preceding the change in control. Under the agreements, a "change of
control" includes the following: (i) the merger, consolidation or reorganization
of the Company after which a majority of voting power of the Company is held by
persons other than the holders thereof prior to such event; (ii) the sale of all
or substantially all of the assets of the Company to an entity, the majority of
the voting power of which is not held by holders of the voting power of the
Company before such sale; (iii) a report is filed on Schedule 13D or Schedule
14D-1 showing that a person is the beneficial owner of 25% or more of the voting
power of the Company; (iv) the Company files a Form 8-K or proxy statement
disclosing that a change in control has or may occur; or (v) a change in the
composition of the majority of the Board under certain circumstances occurs
during any period of two consecutive years. In the event the Company terminates
the executive's employment during such term without cause, the executive will be
entitled to receive as severance compensation a lump-sum payment equal to the
present value of the cash compensation payable under the agreement in the
absence of such termination, not to exceed 299% of his "base amount" as defined
in the Internal Revenue Code of 1986, as amended (the "Code"), without any
reduction for subsequent earnings.
 
     Under these agreements, continuation of benefits under employee benefit
plans of the Company is provided after termination during the remainder of the
original term of employment. The agreements include provisions which limit the
amounts payable under them in certain circumstances in which the net after-tax
amount received by the officer would be reduced as a result of the applicability
of the 20% excise tax imposed in respect of certain change in control payments
under the Code. The Company has assumed the obligation to pay certain fees and
expenses of counsel incurred by the executive officers if legal action is
required to enforce their rights under the agreements and has secured such
obligation by obtaining a letter of credit issued by a commercial bank.
 
     On April 7, 1995, all of the Company's then executive officers, including
Messrs. Blackburn, Forrest, Pasley and Brown, gave notice of their intent to
resign under circumstances in which they had the right to receive severance
payments under the change in control agreements. In order to facilitate the
transition following the acquisition by YPF, the Company and the eight executive
officers who were parties to such agreements (Messrs. Blackburn, Forrest,
Pasley, Brown, S. G. Crowell, M. J. Barron, M. J. Gentry and M. Middlebrook)
agreed that such executive officers would continue to work for the Company in
their then present positions at their then current levels of compensation until
June 30, 1995 or such date as otherwise
 
                                       36
<PAGE>   37
 
mutually agreed. The Company also agreed to pay such executive officers' said
severance payments no later than April 15, 1995. Mr. Blackburn resigned as
Chairman, Chief Executive Officer and President of the Company on April 21, 1995
and retired as an employee of the Company on April 30, 1995. Messrs. Brown and
Pasley resigned effective December 15, 1995 and August 31, 1995, respectively.
All of such other executive officers resigned on June 30, 1995, except Mr.
Forrest who agreed to continue in the employment of the Company at a reduced
salary and as an "at will" employee. Pursuant to said agreements and the change
in control agreements, the named executive officers and all of the executive
officers as a group (including said former executive officers) received
"severance" payments in the following amounts: Mr. Monti--$0; Mr. Miller--$0;
Mr. Forrest--$1.0 million; Mr. Wadsworth--$0; Mrs. Engelbrecht--$0; Mr.
Blackburn--$2.7 million; Mr. Gaffney--$0; Mr. Pasley--$0.9 million; and Mr.
Brown--$0.6 million and the executive officers (including said former executive
officers) as a group, $7.9 million.
 
RETIREMENT PROGRAM
 
     Effective February 1, 1987, the Company adopted a new retirement income
plan (the "New Retirement Income Plan") applicable to most of its employees to
replace the Company's former retirement income plans under which such employees
ceased to accrue benefits on January 31, 1987. Under the New Retirement Income
Plan, a covered employee acquires a right upon retirement to a yearly amount
equal to 2% of the employee's earnings during each year from February 1, 1987
forward (rather than on final compensation or average final compensation)
without offset for social security benefits. Benefits under the New Retirement
Income Plan become vested after five years of service. Benefits may be paid in
equal monthly installments, starting on the date of retirement and continuing
until death, or employees may select one of a number of optional forms of
payment having equal actuarial value as provided in the plan. The benefits
payable under the New Retirement Income Plan are subject to maximum limitations
under the Employee Retirement Income Security Act of 1974, as amended ("ERISA"),
and the Code. In the case of the named executives, if benefits at the time of
retirement exceed the then permissible limits of such statutes, the excess would
be paid by the Company from the "SERP" described below.
 
     The Company has an unfunded Supplemental Executive Retirement Plan that
provides additional benefits to the Company's highest ranking officer, the other
named executives and to certain executive employees designated by the highest
ranking officer. Under the SERP, a participant acquires the right to a lump sum
amount upon retirement which is the actuarial equivalent of a straight life or,
if married, a 50% joint and survivor annuity payable monthly in an amount equal
to (a) the sum of (i) 1.6% of the participant's average monthly compensation in
1986 times the years of service through January 31, 1987, plus (ii) 2% of the
participant's average monthly compensation after January 31, 1987 times the
years of service after January 31, 1987 plus an additional five years less (b)
the amount of the benefits calculated for such participant under the Company's
other retirement plans. The maximum benefit payable is 60% of the participant's
high three-year average pay. The amounts calculated under the SERP are not
subject to any reduction for Social Security and are not determined primarily by
final compensation or average final compensation and years of service. If a
participant dies while still employed by the Company and is survived by an
eligible spouse, the surviving spouse will receive a lump-sum payment equal to
the present value of one-half of the benefit which would have been payable to
the participant at his normal retirement age under the SERP assuming the
participant had terminated employment with the Company at the time of death with
a vested interest under the SERP and that the participant survived to the normal
retirement age. In the case of retirement after age 55 but before age 60, the
supplemental retirement benefits generally will be reduced by 5% for each year
that the employee's actual retirement date precedes age 60. The benefits
provided under the plan will vest upon completion of five years of service or
attainment of age 55.
 
     The estimated annual benefits payable upon retirement at normal retirement
age (or January 1, 1996 in those cases where the participant's age on that date
was greater than normal retirement age) under the Company's retirement plans as
supplemented by the SERP based on service and compensation through December 31,
1995 for the executive officers named in the compensation table are as follows:
Mr. Monti-- $82,668, Mr. Miller--$46,751, Mr. Forrest--$64,502, Mr.
Wadsworth--$52,900, Mrs. Engelbrecht--$33,863 and Mr. Gaffney--$0. The annual
benefits payable under the Company's retirement plans as supplemented by
 
                                       37
<PAGE>   38
 
the SERP to Mr. Blackburn who retired on April 30, 1995 (and received a lump sum
distribution of his retirement benefits) were $193,006. The annual benefits
payable at normal retirement age to Mr. Brown who resigned from the Company
effective December 15, 1995 are $61,207 and to Mr. Pasley who resigned from the
Company effective August 31, 1995 are $58,002.
 
     Whether any amounts actually become payable in whole or in part depends on
the contingencies and conditions governing the applicable retirement plan.
 
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
 
     From January 1, 1995 to April 21, 1995, the Compensation Committee of the
Board of Directors consisted of J. David Barnes, B. Clark Burchfiel, Charles W.
Hall, George L. Jackson and Richard W. Murphy. From April 21, 1995 to June 7,
1995, the Compensation Committee consisted of Jose Estenssoro, Cedric Bridger
and James R. Lesch. On June 7, 1995, Nells Leon replaced Mr. Estenssoro.
 
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 
     Except as provided in the next succeeding sentence, the following table
sets forth the beneficial ownership (as defined in the rules of the Securities
and Exchange Commission) as of February 1, 1996 of the equity securities of the
Company and YPF by the directors, the named executive officers and all directors
and executive officers as a group. At such date, none of the directors or
executive officers beneficially owned any $4.00 Preferred Stock, $9.75 Preferred
Stock or $2.50 Preferred Stock.
 
<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
Glen R. Brown..........................    Common Stock.......................           -0-
                                           YPF Class "D"......................           -0-
Linda Engelbrecht......................    Common Stock.......................           -0-
                                           YPF Class "D"......................           -0-
Michael C. Forrest.....................    Common Stock.......................           -0-
                                           YPF Class "D"......................         3,000
Peter Gaffney..........................    Common Stock.......................           -0-
                                           YPF Class "D"......................           -0-
George L. Jackson......................    Common Stock.......................           -0-
                                           YPF Class "D"......................           -0-
Nells Leon.............................    Common Stock.......................           -0-(1)(2)
                                           YPF Class "D"......................           -0-
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-
                                           YPF Class "D"......................           -0-
George W. Pasley.......................    Common Stock.......................           -0-
                                           YPF Class "D"......................           -0-
P. Dexter Peacock......................    Common Stock.......................           -0-(1)
                                           YPF Class "D"......................         3,000
David A. Wadsworth.....................    Common Stock.......................           -0-
                                           YPF Class "D"......................           -0-
</TABLE>
 
                                       38
<PAGE>   39
 
<TABLE>
<CAPTION>
                                                                                AMOUNT AND NATURE
                                                                                  OF SECURITIES
                                                                                  BENEFICIALLY
       NAME OF BENEFICIAL OWNER                     TITLE OF SECURITY                 OWNED
---------------------------------------    -----------------------------------  -----------------
<S>                                        <C>                                  <C>
R. A. Walker...........................    Common Stock.......................           -0-(3)
                                           YPF Class "D"......................           -0-
Directors and Executive Officers.......    Common Stock.......................           -0-(1)(3)
  as a group...........................    YPF Class "D"......................        11,942(2)(4)
</TABLE>
 
---------------
 
(1) Does not include Common Stock owned by YPF, as to which each of Messrs.
    Bridger, Leon, Lesch and Peacock disclaim any beneficial ownership.
 
(2) Does not include 347 YPF Class "D" shares owned by Mr. Leon's wife, as to
    which Mr. Leon disclaims any beneficial ownership.
 
(3) Does not include equity securities owned by Prudential, as to which Mr.
    Walker disclaims beneficial ownership.
 
(4) Directors and executive officers individually and as a group did not own
    more than 1% of the Common Stock or YPF Class D shares.
 
     To the knowledge of the Company, as of February 1, 1996, no person
beneficially owned more than 5% of any class of the Company's voting securities
except as set forth below:
 
<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      135,609,772        100%
  Avenida Pte. Roque
  Saenz Pena 777
  1364 Buenos Aires
  Argentina
The Prudential Insurance Company of America........  Common Stock        7,910,000(1)     5.6%
                                                     $9.75
  Prudential Plaza                                   Preferred           1,250,000(2)   100.0%
  Newark, New Jersey 07102-3777                      Stock
Kidder, Peabody Group Inc..........................  Common Stock        8,000,000(3)     5.6%
  10 Hanover Square
  New York, New York 10005
</TABLE>
 
---------------
 
(1) Prudential reported on Amendment No. 7 to Schedule 13G, dated February 12,
    1996, in connection with beneficial ownership at December 31, 1995, that it
    had sole voting and dispositive power with respect to all 7,910,000 shares
    of Common Stock indicated above as beneficially owned by it. The information
    herein regarding such shares assumes that Prudential's ownership had not
    changed as of February 1, 1996 and is included in reliance on such Amendment
    No. 7, except that the percent of class is based upon the Company's
    calculations made in reliance upon the information regarding such shares
    contained in such Amendment No. 7.
 
(2) On February 28, 1995, the Company and Prudential entered into an agreement
    pursuant to which Prudential waived certain rights, including conversion
    rights and registration rights. See "Item 13. Certain Relationships and
    Related Transactions."
 
(3) 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, 1996
    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.
 
                                       39
<PAGE>   40
 
     Gaffney, Cline, an oil and gas technical and management consulting firm of
which Mr. Gaffney, the President and Chief Executive Officer and a director of
the Company from April 21, 1995 to August 21, 1995, is a Senior Partner, has
provided oil and gas technical and management consulting services to the Company
for which the Company paid Gaffney, Cline approximately $490,000 during 1995.
The Company and Gaffney, Cline have agreed that Gaffney, Cline will continue to
provide such services in 1996 and it is anticipated that the fees for such
services will be lower.
 
     During 1996 through the date of this report, YPF has made capital
contributions to the Company in the aggregate amount of $64 million pursuant to
the terms of the Keepwell Covenant (see "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and Capital
Resources"). It is anticipated that YPF could be required to make capital
contributions in 1996 totaling approximately $200 million to $250 million to
fund the Company's obligations. Actual capital contributions made by YPF could
vary significantly depending on, among other circumstances, oil and gas prices
and program spending commitments. Such capital contributions will be credited to
YPF's obligations under the Keepwell Covenant and will entitle YPF to shares of
Common Stock.
 
     During 1995, YPF made an advance to the Company in the amount of $7
million. The Company and YPF intend to enter into a loan agreement during 1996
to facilitate short-term loans by YPF to the Company and short-term loans by the
Company to YPF of excess cash balances. It is expected that loans will be made
by the parties under the loan agreement during 1996, and while the number and
amounts thereof are not presently known, it is expected that they will aggregate
in excess of $60,000.
 
     Mr. Peacock, a director of the Company, is a partner in the law firm of
Andrews & Kurth L.L.P. Andrews & Kurth provided certain legal services to the
Company (including services rendered to YPFA Corp. in connection with the
Merger), the fees for which the Company paid Andrews & Kurth approximately
$3,180,000 in 1995. It is anticipated that Andrews & Kurth will continue to
provide legal services to the Company during 1996 and that the fees for such
services will be significantly lower.
 
     The Company and YPF intend to enter into a services agreement whereby the
Company would render or arrange for services to be rendered to or for the
benefit of YPF and YPF would render or arrange for services to be rendered to or
for the benefit of the Company, and each party would be compensated on the basis
of the cost to them of such services. It is not presently known what the cost of
these services will be to either party but it is expected that it will exceed
$60,000.
 
     During 1995, Prudential was the record or beneficial owner of more than 5%
of one or more of the classes of the Company's voting securities. Mr. Walker, an
officer of Prudential, was elected as a director of the Company by Prudential as
holder of all of the $9.75 Preferred Stock and pursuant to the terms thereof.
The Company offers its employees the opportunity to participate in medical
programs administered by Prudential. In addition, Prudential provides services
and coverages relating to pension and life insurance programs for retired
employees of Gateway Coal Company, a partnership owned by the Company. During
1995, the Company paid Prudential approximately $238,000 for these services. The
Company and Prudential have agreed that Prudential will continue to perform such
services during 1996 and anticipate that the fees for the year will be somewhat
higher.
 
     Also during 1995, Prudential and the Company entered into an agreement to
induce Prudential, as the holder of the $9.75 Preferred Stock, to consent to the
Merger as required by the terms of the Company's Restated Certificate of
Incorporation. Under the agreement, the Company and Prudential agreed to waive
certain rights and covenants with respect to the $9.75 Preferred Stock and the
Company paid Prudential a restructuring fee of $250,000.
 
COMPLIANCE WITH SECTION 16(A) OF THE SECURITIES EXCHANGE ACT OF 1934
 
     During 1995, a former director of the Company, Raymond A. Hay, filed a Form
4 reporting a sale of Common Stock in the month following the date upon which
such filing was due.
 
                                       40
<PAGE>   41
 
                                    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-26 and F-30 through F-69 of this report.
 
           Consolidated Statement of Operations for the years ended December 31,
           1994 and 1993, the three months ended March 31, 1995 and nine months
           ended December 31, 1995.
 
           Consolidated Balance Sheet at December 31, 1995 and 1994.
 
           Consolidated Statement of Cash Flows for the years ended December 31,
           1994 and 1993, the three months ended March 31, 1995 and nine months
           ended December 31, 1995.
 
           Notes to Consolidated Financial Statements.
 
           Report of Independent Public Accountants.
 
           Supplementary Financial Information (unaudited).
 
           Quarterly Data (unaudited).
 
        (2) Financial Statement Schedules.
 
             None
 
     Condensed parent company financial information has been omitted, since the
amount of restricted net assets of consolidated subsidiaries does not exceed 25%
of total consolidated net assets. Also, footnote disclosure regarding
restrictions on the ability of both consolidated and unconsolidated subsidiaries
to transfer funds to the parent company has been omitted since the amount of
such restrictions does not exceed 25% of total consolidated net assets.
 
        (3) Exhibits.
 
     Each document marked by an asterisk is incorporated herein by reference to
the designated document previously filed with the Securities and Exchange
Commission (the "Commission"). Each of Exhibits Nos. 10.1 through 10.10 and
10.15 through 10.25 is a management contract or compensatory plan, contract or
arrangement required to be filed as an exhibit hereto by Item 14(c) of Form
10-K.
 
<TABLE>
<C>                  <S>
          3(i)       --Restated Certificate of Incorporation of the Company (Exhibit 3(i).2
                       to the Company's Quarterly Report on Form 10-Q for the quarter ended
                       June 30, 1995).*
          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).*
</TABLE>
 
                                       41
<PAGE>   42
 
<TABLE>
<C>                  <S>
          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).*
          4.11       --Indenture dated as of April 1, 1988 between the Company and Chemical
                       Bank relating to unspecified debt securities of the Company (Exhibit
                       4.11 to the 1992 Form 10-K).*
          4.12       --Officers' Certificate dated June 1, 1988 establishing a series of debt
                       securities ($150,000,000 Medium-Term Notes, Series A) to be issued
                       under the Indenture described in Exhibit 4.11 above (Exhibit 4.12 to
                       the 1992 Form 10-K).*
          4.13       --Indenture dated as of November 1, 1990 between the Company and
                       Chemical Bank relating to unspecified debt securities of the Company
                       (Exhibit 4.13 to the 1992 Form 10-K).*
          4.14       --Officers' Certificate dated February 13, 1991 establishing a series of
                       debt securities ($150,000,000 Medium-Term Notes, Series B) to be
                       issued under the Indenture described in Exhibit 4.13 above (Exhibit
                       4.14 to the 1992 Form 10-K).*
          4.15       --Officers' Certificate dated September 28, 1992 establishing a series
                       of debt securities ($250,000,000 9 7/8% Notes Due 2002) to be issued
                       under the Indenture described in Exhibit 4.13 above (Exhibit 4.15 to
                       the 1992 Form 10-K).*
          4.16       --Officers' Certificate dated January 26, 1993 establishing a series of
                       debt securities ($100,000,000 9 1/2% Notes Due 2003) to be issued
                       under the Indenture described in Exhibit 4.13 above (Exhibit 4.16 to
                       the 1992 Form 10-K).*
</TABLE>
 
                                       42
<PAGE>   43
 
<TABLE>
<C>                  <S>
          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       --Preferred Stock Purchase Agreement dated February 1, 1987 (the
                       "Preferred Stock Purchase Agreement") between the Company and The
                       Prudential Insurance Company of America ("Prudential") (Exhibit 4.17
                       to the 1992 Form 10-K).*
          4.21       --Amendment dated February 8, 1987 to the Preferred Stock Purchase
                       Agreement (Exhibit 4.18 to the 1992 Form 10-K).*
          4.22       --Registration Rights Agreement dated as of February 1, 1987 between the
                       Company and Prudential (Exhibit 4.19 to the 1992 Form 10-K).*
          4.23       --Agreement dated April 12, 1990 amending the Preferred Stock Purchase
                       Agreement (Exhibit 4.20 to the 1992 Form 10-K).*
          4.24       --Waiver of Certain Rights Relating to $9.75 Preferred Stock dated June
                       5, 1990 between the Company and Prudential (Exhibit 4.21 to the 1992
                       Form 10-K).*
          4.25       --Waiver of Certain Equity Offering Rights dated April 12, 1990 between
                       the Company and Prudential amending the Preferred Stock Purchase
                       Agreement (Exhibit 4.22 to the 1992 Form 10-K).*
          4.26       --Agreement dated February 28, 1995 between Prudential and the Company
                       (Exhibit 2 to the Company's Schedule 14D-9 dated March 3, 1995 [the
                       "Schedule 14D-9"]).*
          4.27       --Waiver of Certain Rights Relating to $9.75 Preferred Stock dated June
                       8, 1995 between Prudential and the Company, filed herewith.
          4.28       --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).*
          4.29       --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).*
          4.30       --Agreement of Merger, dated February 28, 1995, among the Company, YPF
                       Sociedad Anonima ("YPF") and YPF Acquisition Corp. ("YPFA") (Exhibit 3
                       to the Schedule 14D-9).*
          4.31       --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"]).*
          4.32       --Credit Agreement dated as of June 16, 1995, between Maxus Indonesia,
                       Inc., Maxus Northwest Java Inc., Maxus Southeast Sumatra, Inc., the
                       lenders signatory thereto and Chase, as agent (Exhibit 4.2 to the June
                       8, 1995 Form 8-K).*
</TABLE>
 
                                       43
<PAGE>   44
 
<TABLE>
<C>                  <S>
         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 its executive officers (Exhibit 10.7 to the 1992
                       Form 10-K).*
         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), filed herewith.
         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 1993 Form 10-K).*
         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       --Rights Agreement dated as of September 2, 1988 between the Company and
                       AmeriTrust Company National Association (Exhibit 10.24 to the 1992
                       Form 10-K).*
         10.13       --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).*
         10.14       --Agreement of Merger dated as of February 28, 1995 among YPF, YPFA
                       Corp. and the Company (Exhibit 3 to the Schedule 14D-9).*
         10.15       --International Consulting Agreement, dated May 1, 1995 between C. L.
                       Blackburn and YPF, filed herewith.
         10.16       --Assignment of International Consulting Agreement, dated November 2,
                       1995 between C. L. Blackburn, YPF, and the Company, filed herewith.
         10.17       --Maxus Severance Agreement dated August 3, 1995 between the Company and
                       Roberto Luis Monti, filed herewith.
         10.18       --Compensation Agreement dated December 27, 1995 between the Company and
                       Roberto L. Monti, filed herewith.
         10.19       --Services Agreement dated April 5, 1995 between the Company and Peter
                       D. Gaffney, filed herewith.
         10.20       --Secondment Agreement dated April 5, 1995 between the Company, YPF and
                       Gaffney, Cline & Associates, Inc., filed herewith.
         10.21       --Amendment to Change in Control Agreement dated May 11, 1995 between
                       the Company and W. Mark Miller, filed herewith.
         10.22       --Employment Agreement effective as of July 1, 1995 between the Company
                       and W. Mark Miller, filed herewith.
</TABLE>
 
                                       44
<PAGE>   45
 
<TABLE>
<C>                  <S>
         10.23       --Specimen copy of a letter agreement regarding Change in Control
                       Agreement dated April 7, 1995 between the Company and certain of its
                       executive officers, filed herewith.
         10.24       --Letter Agreement regarding Change in Control Agreement dated April 13,
                       1995 between the Company and Michael C. Forrest, filed herewith.
         10.25       --Specimen copy of a letter agreement regarding Change in Control
                       Agreement dated ------------, 1995 between the Company and certain of
                       its executive officers, 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.
</TABLE>
 
     (b) Reports on Form 8-K.
 
        None.
 
                                       45
<PAGE>   46
 
                                   SIGNATURES
 
     PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
 
                                            MAXUS ENERGY CORPORATION
 
                                            By         ROBERTO MONTI*
                                                       Roberto Monti
                                                       President and
                                                  Chief Executive Officer
 
     March 21, 1996
 
     Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
 
<TABLE>
<CAPTION>
                  SIGNATURE                                          TITLE
---------------------------------------------     --------------------------------------------
<C>                                               <S>
                                                  President and Chief Executive Officer and
                ROBERTO MONTI*                       Director
                Roberto Monti
                                                  Executive Vice President and Treasurer
               W. MARK MILLER*                       (principal financial officer)
               W. Mark Miller

            LINDA R. ENGELBRECHT*                 Controller
            Linda R. Engelbrecht                     (principal accounting officer)

            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

</TABLE>
 
     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.
 
<TABLE>
<C>                                               <S>
          *By      LYNNE P. CIUBA                March 21, 1996
                   Lynne P. Ciuba
                  Attorney-in-fact
</TABLE>
 
                                       46
<PAGE>   47
 
                            MAXUS ENERGY CORPORATION
 
                      CONSOLIDATED STATEMENT OF OPERATIONS
 
<TABLE>
<CAPTION>
                                                                  THREE MONTHS      YEAR ENDED
                                                                     ENDED         DECEMBER 31,
                                                                   MARCH 31,     ----------------
                                                                      1995        1994      1993
                                                                  ------------   ------    ------
                                                                  (IN MILLIONS, EXCEPT PER SHARE)
<S>                                                               <C>            <C>       <C>
Revenues
     Sales and operating revenues.................................    $142.5     $682.1    $786.7
     Other revenues, net..........................................       9.6        9.0      40.4
                                                                      ------     ------    ------
                                                                       152.1      691.1     827.1
Costs and Expenses
     Operating expenses...........................................      64.6      242.8     263.9
     Gas purchase costs...........................................      12.7      116.9     155.6
     Exploration, including exploratory dry holes.................       8.9       35.5      59.8
     Depreciation, depletion and amortization.....................      29.9      140.2     153.6
     General and administrative expenses..........................       4.2       22.4      25.7
     Taxes other than income taxes................................       3.1       12.9      15.9
     Interest and debt expenses...................................      24.1       96.7      88.4
     Pre-merger costs.............................................      42.4
     Environmental studies and remediation........................                 60.5      17.9
     Restructuring:
          Gain on sale of assets..................................               (201.9)
          Restructuring costs.....................................                100.9
                                                                      ------     ------    ------
                                                                       189.9      626.9     780.8
                                                                      ------     ------    ------
Income (Loss) Before Income Taxes, Extraordinary Item and
  Cumulative Effect of Change in Accounting Principle.............     (37.8)      64.2      46.3
     Income Taxes.................................................      19.1       86.9      84.2
                                                                      ------     ------    ------
Net Loss Before Extraordinary Item and
  Cumulative Effect of Change in Accounting Principle.............     (56.9)     (22.7)    (37.9)
     Extraordinary item, net of tax benefit of $.1................                           (7.1)
     Cumulative effect of change in accounting principle..........                           (4.4)
                                                                      ------      ------    ------
Net Loss..........................................................     (56.9)     (22.7)    (49.4)
     Dividend requirement on Preferred Stock......................      (9.6)     (43.6)    (41.7)
                                                                      ------     ------    ------
Net Loss Applicable to Common Shares..............................    $(66.5)    $(66.3)   $(91.1)
                                                                      ======     ======    ======
Net Loss Per Common Share Before Extraordinary Item and
  Cumulative Effect of Change in Accounting Principle.............    $ (.49)    $ (.49)   $ (.60)
     Extraordinary item...........................................                           (.05)
     Cumulative effect of change in accounting principle..........                           (.03)
                                                                      ------     ------    ------
Net Loss Per Common Share.........................................    $ (.49)    $ (.49)   $ (.68)
                                                                      ======     ======    ======
Average Common Shares Outstanding.................................     135.5      134.7     133.9
</TABLE>
 
                See Notes to Consolidated Financial Statements.
 
                                       F-1
<PAGE>   48
 
                            MAXUS ENERGY CORPORATION
 
                           CONSOLIDATED BALANCE SHEET
 
<TABLE>
<CAPTION>
                                                                        MARCH 31,    DECEMBER 31,
                               ASSETS                                     1995           1994
                             ----------                                ---------    -------------
                                                                      (IN MILLIONS, EXCEPT SHARES)
<S>                                                                   <C>           <C>
Current Assets
     Cash and cash equivalents....................................... $    91.6     $     40.6
     Short-term investments..........................................      65.0          103.8
     Receivables, less allowance for doubtful accounts...............     127.8          152.4
     Taxes receivable................................................      13.7           23.8
     Inventories.....................................................      28.6           27.9
     Restricted cash.................................................      48.5           46.4
     Prepaids and other current assets...............................      19.4           18.7
                                                                      ---------     ----------
          Total Current Assets.......................................     394.6          413.6
Properties and Equipment, less accumulated depreciation, depletion
  and amortization...................................................   1,110.7        1,088.4
Investments and Long-Term Receivables................................      41.5           40.2
Restricted Cash......................................................      79.9           94.2
Intangible Assets, less accumulated amortization.....................      35.5           35.8
Deferred Income Taxes................................................       9.4            9.4
Deferred Charges.....................................................      20.5           25.1
                                                                      ---------     ----------
                                                                      $ 1,692.1     $  1,706.7
                                                                      =========     ==========
                LIABILITIES AND STOCKHOLDERS' EQUITY
   ---------------------------------------------------------------
Current Liabilities
     Long-term debt.................................................. $     4.7     $      4.7
     Accounts payable................................................      49.8           65.1
     Accrued liabilities.............................................     169.8          101.2
                                                                      ---------     ----------
          Total Current Liabilities..................................     224.3          171.0
Long-Term Debt.......................................................     970.9          970.9
Deferred Income Taxes................................................     199.7          199.3
Other Liabilities and Deferred Credits...............................     158.7          149.4
$9.75 Redeemable Preferred Stock, $1.00 par value
  Authorized and issued shares--1,250,000............................     125.0          125.0
Stockholders' Equity
     $2.50 Preferred Stock, $1.00 par value
       Authorized shares--5,000,000
       Issued shares--3,500,000......................................       3.5            3.5
     $4.00 Preferred Stock, $1.00 par value
       Authorized shares--5,915,017
       Issued shares--4,356,958 and 4,358,658........................       4.4            4.4
     Common Stock, $1.00 par value
       Authorized shares--300,000,000
       Issued shares--135,897,899 and 135,694,722....................     135.9          135.7
     Paid-in capital.................................................     966.2          988.1
     Accumulated deficit.............................................  (1,073.3)      (1,016.4)
     Minimum pension liability.......................................     (18.3)         (18.3)
     Unrealized loss on marketable securities........................      (1.3)          (2.4)
     Common Treasury Stock, at cost--310,535 and 295,995.............      (3.6)          (3.5)
                                                                      ---------     ----------
          Total Stockholders' Equity.................................      13.5           91.1
                                                                      ---------     ----------
                                                                      $ 1,692.1     $  1,706.7
                                                                      =========     ==========
</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>   49
 
                            MAXUS ENERGY CORPORATION
 
                      CONSOLIDATED STATEMENT OF CASH FLOWS
 
<TABLE>
<CAPTION>
                                                                                  TWELVE MONTHS
                                                                  THREE MONTHS   ENDED DECEMBER
                                                                      ENDED            31,
                                                                    MARCH 31,   -----------------
                                                                      1995       1994      1993
                                                                  ------------- -------   -------
<S>                                                                  <C>        <C>       <C>
                                                                           (IN MILLIONS)
Cash Flows From Operating Activities:
     Net loss...................................................     $ (56.9)   $ (22.7)  $ (49.4)
     Adjustments to reconcile net loss to net cash provided by
       operating activities:
          Extraordinary item....................................                              7.1
          Cumulative effect of change in accounting principle...                              4.4
          Depreciation, depletion and amortization..............        29.9      140.2     153.6
          Dry hole costs........................................         1.0        2.8       5.7
          Deferred income taxes.................................         0.4       (9.3)     22.3
          Net gain on sale of assets and investments............        (1.7)    (166.7)    (13.8)
          Postretirement benefits...............................         1.4        6.2       6.6
          Pre-merger costs......................................        42.4
          Restructuring costs...................................                   91.0
          Environmental studies and remediation.................                   60.5      17.9
          Other.................................................         1.3        9.2      15.1
          Changes in components of working capital:
               Receivables......................................        23.8       (1.8)    (21.5)
               Inventories, prepaids and other current assets...        (1.4)      (2.3)     (6.4)
               Accounts payable.................................       (15.1)     (22.3)      9.0
               Accrued liabilities..............................        26.3      (12.5)     (5.2)
               Taxes payable/receivable.........................        10.1       (2.8)     (8.8)
                                                                     -------    -------   -------
                    Net Cash Provided by Operating Activities...        61.5       69.5     136.6
                                                                     -------    -------   -------
Cash Flows From Investing Activities:
     Expenditures for properties and equipment--including dry
       hole costs...............................................       (53.6)    (166.2)   (340.0)
     Expenditures for investments...............................                  (20.1)    (20.4)
     Proceeds from sales of assets..............................         2.1      377.0      20.4
     Proceeds from sale/maturity of short-term investments......        63.4       10.9     171.3
     Purchases of short-term investments........................       (24.6)    (111.8)    (53.1)
     Restricted cash............................................        12.2       19.6     (35.5)
     Other......................................................         9.8      (10.8)    (20.4)
                                                                     -------    -------   -------
                    Net Cash Provided by (Used in) Investing
                      Activities................................         9.3       98.6    (277.7)
                                                                     -------    -------   -------
Cash Flows From Financing Activities:
     Net borrowings from joint venture partners.................                   (4.4)      4.4
     Interest rate swap.........................................         3.4       (7.9)      5.8
     Proceeds from issuance of short-term debt..................                   30.0      32.7
     Repayment of short-term debt...............................                  (69.1)    (32.7)
     Proceeds from issuance of long-term debt...................                  101.3     412.5
     Repayment of long-term debt................................                 (137.5)   (203.7)
     Stock rights redemption....................................       (13.6)
     Proceeds from issuance of Preferred Stock..................                             85.7
     Redemption of Preferred Stock..............................                 (125.0)
     Dividends paid on Preferred Stock..........................        (9.6)     (43.6)    (41.7)
                                                                     -------    -------   -------
                    Net Cash Provided by (Used in) Financing
                      Activities................................       (19.8)    (256.2)    263.0
                                                                     -------    -------   -------
Net Increase (Decrease) in Cash and Cash Equivalents............        51.0      (88.1)    121.9
Cash and Cash Equivalents at Beginning of Year..................        40.6      128.7       6.8
                                                                     -------    -------   -------
Cash and Cash Equivalents at End of Year........................     $  91.6    $  40.6   $ 128.7
                                                                     =======    =======   =======
</TABLE>
 
                See Notes to Consolidated Financial Statements.
 
                                       F-3
<PAGE>   50
 
                            MAXUS ENERGY CORPORATION
 
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
PRESENTATION
 
     On June 8, 1995, a special meeting of the stockholders of Maxus Energy
Corporation (together with its foreign and domestic subsidiaries, the "Company"
or "Maxus") was held to approve the Agreement of Merger ("Merger Agreement")
dated February 28, 1995, between the Company, YPF Acquisition Corp. (the
"Purchaser") and YPF Sociedad Anonima ("YPF"). The holders of the Company's
common stock, $1.00 par value per share, and $4.00 Cumulative Convertible
Preferred Stock approved the Merger Agreement, and the Purchaser was merged into
the Company (the "Merger") on June 8, 1995.
 
     Effective April 1, 1995, the Company used the purchase method of accounting
to record the acquisition of the Company by YPF. In a purchase method
combination, the purchase price is allocated to acquired assets and assumed
liabilities based on their fair values at the date of acquisition. As a result,
the Company's assets and liabilities were revalued to reflect the approximate
$762 million cash purchase price paid by YPF to acquire the Company. The
Company's pre-Merger Consolidated Balance Sheet as of March 31, 1995, together
with the purchase method accounting adjustments became the Company's opening
post-Merger Consolidated Balance Sheet on April 1, 1995.
 
     The following pre-Merger data is for the three months ended March 31, 1995,
and the years ended December 31, 1994 and 1993 and dollar amounts in tables are
in millions, except per share amounts. The financial statements for the
three-month period ended March 31, 1995, and the years ended December 31, 1994
and 1993 are presented separately as pre-Merger and post-Merger financial
information are not comparable. Certain data for 1994 and 1993 has been
reclassified to conform with the 1995 presentation.
 
NOTE ONE--SIGNIFICANT ACCOUNTING POLICIES
 
     The Consolidated Financial Statements have been prepared in conformity with
generally accepted accounting principles, the most significant of which are
described below.
 
  Consolidation and Equity Accounting
 
     The Consolidated Financial Statements include the accounts of Maxus Energy
Corporation and all domestic and foreign subsidiaries. The Company used the
equity method to account for its less than majority owned investments in
affiliates and joint ventures ("Associated Companies"). Under the equity method,
the Company recognizes its proportionate share of the net income or loss of
Associated Companies currently, rather than when realized through dividends or
disposal. The Company used the proportionate consolidation method to account for
its investment in Diamond Shamrock Offshore Partners Limited Partnership
("Offshore Partners"). The Company sold its investment in Offshore Partners in
the second quarter of 1994 (See Note Four). All significant intercompany
accounts and transactions have been eliminated.
 
  Statement of Cash Flows
 
     Investments with original maturities of three months or less at the time of
original purchase are considered cash equivalents for purposes of the
accompanying Consolidated Statement of Cash Flows. Short-term investments
include investments with maturities over three months but less than one year.
 
                                       F-4
<PAGE>   51
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     Net cash provided by operating activities reflects cash receipts for
interest income and cash payments for interest expense and income taxes as
follows:
 
<TABLE>
<CAPTION>
                                                                           TWELVE MONTHS
                                                            THREE MONTHS   ENDED DECEMBER
                                                               ENDED            31,
                                                             MARCH 31,     --------------
                                                                1995       1994     1993
                                                            ------------   -----    -----
        <S>                                                 <C>            <C>      <C>
        Interest receipts...................................    $  7.0     $12.4    $13.5
        Interest payments...................................      12.2      98.7     82.0
        Income tax payments.................................      18.6      98.1     73.4
</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.
 
     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.
 
                                       F-5
<PAGE>   52
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  Deferred Charges
 
     Deferred charges are primarily comprised of debt issuance costs and are
amortized over the terms of the related debt agreements.
 
  Revenue Recognition
 
     Oil and gas sales are recorded on the entitlements method. Differences
between the Company's actual production and entitlements result in a receivable
when underproduction occurs and a payable when overproduction occurs. These
underproduced or overproduced volumes are valued based on the weighted average
sales price for each respective property. The Company's gross underproduced and
overproduced values at March 31, 1995, are not material.
 
  Pensions
 
     The Company has a number of trusteed noncontributory pension plans covering
substantially all full-time employees. The Company's funding policy is to
contribute amounts to the plans sufficient to meet the minimum funding
requirements under governmental regulations, plus such additional amounts as
management may determine to be appropriate. The benefits related to the plans
are based on years of service and compensation earned during years of
employment. The Company also has a noncontributory supplemental retirement plan
for executive officers.
 
  Other Postretirement and Postemployment Benefits
 
     The Company provides certain health care and life insurance benefits for
retired employees and certain insurance and other postemployment benefits for
individuals whose employment is terminated by the Company prior to their normal
retirement. The Company accrues the estimated cost of retiree benefit payments,
other than pensions, during employees' active service period. Employees become
eligible for these benefits if they meet minimum age and service requirements.
The Company accounts for benefits provided after employment but before
retirement by accruing the estimated cost of postemployment benefits when the
minimum service period is met, payment of the benefit is probable and the amount
of the benefit can be reasonably estimated. The Company's policy is to fund
other postretirement and postemployment benefits as claims are incurred.
 
  Environmental Expenditures
 
     Environmental liabilities are recorded when environmental assessments
and/or remediation are probable and material and such costs to the Company can
be reasonably estimated. The Company's estimate of environmental assessment
and/or remediation costs to be incurred are based on either 1) detailed
feasibility studies of remediation approach and cost for individual sites or 2)
the Company's estimate of costs to be incurred based on historical experience
and publicly available information, based on the stage of assessment and/or
remediation of each site. As additional information becomes available regarding
each site or as environmental remediation standards change, the Company revises
its estimate of costs to be incurred in environmental assessment and/or
remediation.
 
  Income Taxes
 
     The Company reports income taxes in accordance with Statement of Financial
Accounting Standards No. 109 ("SFAS 109"), Accounting for Income Taxes. SFAS 109
requires the use of an asset and liability approach to measure deferred tax
assets and liabilities resulting from all expected future tax consequences of
events that have been recognized in the Company's financial statements or tax
returns. Additionally, SFAS 109 requires that annual taxes are to be allocated
to interim periods on the basis of the requirements of
 
                                       F-6
<PAGE>   53
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
Accounting Principles Board Opinion No. 28 ("APB 28"), Interim Financial
Reporting. The reporting requirements of APB 28 are based on the view that each
interim period is an integral part of the related annual period.
 
     Because the tax year of the Company did not close in any relevant
jurisdiction on March 31, 1995, taxes were not measured on deferred tax
liabilities and assets at that time. In accordance with APB 28 and SFAS 109,
taxes were allocated to the period based on the estimated annual effective tax
rate for the period ended December 31, 1995.
 
  Earnings per Share
 
     Primary earnings per share are based on the weighted average number of
shares of common stock and common stock equivalents outstanding, unless the
inclusion of common stock equivalents has an antidilutive effect on earnings per
share. Fully diluted earnings per share are not presented due to the
antidilutive effect of including all potentially dilutive common stock
equivalents.
 
  Financial Instruments with Off-Balance-Sheet Risk and Concentrations of Credit
Risk
 
     The Company's financial instruments that are exposed to concentrations of
credit risk consist primarily of cash equivalents, short-term investments,
restricted cash and trade receivables.
 
     The Company's cash equivalents, short-term investments and restricted cash
represent high-quality securities placed with various high investment grade
institutions. This investment practice limits the Company's exposure to
concentrations of credit risk.
 
     The Company's trade receivables are dispersed among a broad domestic and
international customer base; therefore, concentrations of credit risk are
limited. The Company carefully assesses the financial strength of its customers.
Letters of credit are the primary security obtained to support lines of credit.
 
     The Company has minimal exposure to credit losses in the event of
nonperformance by the counterparties to its interest rate swap agreement,
natural gas price swap agreements and nonderivative financial assets. The
Company does not obtain collateral or other security to support financial
instruments subject to credit risk but restricts such arrangements to
investment-grade counterparties.
 
  Investments in Marketable Securities
 
     Effective January 1, 1994, the Company adopted Statement of Financial
Accounting Standards No. 115, ("SFAS 115") "Accounting for Certain Investments
in Debt and Equity Securities." SFAS 115 requires that investments in debt and
equity securities be reported at fair value except for those investments in debt
securities which management has the intent and the ability to hold to maturity.
Investments in debt securities which are held-for-sale are classified based on
the stated maturity and management's intent to sell the securities. Unrealized
gains and losses on investments in marketable securities, except for debt
securities classified as "held-to-maturity", are reported as a separate
component of stockholders' equity. The cumulative effect of adopting SFAS 115 of
$2.4 million was recorded as a valuation reserve in shareholders' equity. The
Company's gross unrealized loss on its involvement in marketable securities
which are included in long-term investments at March 31, 1995, was $1.3 million
which was entirely comprised of unrealized losses on the Company's investment in
U. S. Treasury Notes. Prior to the adoption of SFAS 115, the Company accounted
for its investments in debt securities at amortized cost and classified such
investments according to the stated maturity of the underlying securities.
 
                                       F-7
<PAGE>   54
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  Derivatives
 
     The Company periodically hedges the effects of fluctuations in the price of
crude oil and natural gas through price swap agreements and futures contracts.
The Company historically has hedged no more than 50% of its U. S. gas
production. Gains and losses on these hedges are deferred until the related
sales are recognized and are recorded as a component of sales and operating
revenues. The Company periodically enters into interest rate swap agreements to
hedge interest on long-term debt. The gain or loss on interest rate swaps is
recognized monthly as a decrease or increase to interest expense.
 
  Take-or-Pay Obligations
 
     The Company records payments received for take-or-pay obligations for
unpurchased contract volumes as deferred revenue, which is included in Other
Liabilities in the consolidated balance sheet. The deferred revenue is
recognized in the income statement as quantities are delivered which fulfill the
take-or-pay obligation. At March 31, 1995, the Company had $13.6 million in
deferred revenue as a result of a take-or-pay payment received related to its
Indonesian operations.
 
NOTE TWO--MASTER LIMITED PARTNERSHIP
 
     In 1994, the Company sold its interests in Offshore Partners, a master
limited partnership, which explored for and produced natural gas and crude oil
on federal offshore leases in the Gulf of Mexico (See Note Four). Maxus Offshore
Exploration Company, a wholly owned subsidiary of the Company, and the Company
had a combined 1% general partner's interest in Offshore Partners and were the
managing general partner and special general partner, respectively. The Company
had an aggregate interest in Offshore Partners of approximately 87.1% at
December 31, 1993.
 
NOTE THREE--PRE-MERGER COSTS
 
     In March 1995, the Company recorded $42.4 million of pre-merger costs
associated with the Merger. Such costs, which included expenses associated with
financial consulting and legal services, severance payments pursuant to change
of control agreements and payments for surrender of stock options and restricted
stock, were recorded in accrued liabilities in the consolidated balance sheet.
 
NOTE FOUR--RESTRUCTURING
 
  Asset Sales
 
     On April 25, 1994, Offshore Partners sold its interests in Main Pass Blocks
72, 73 and 74. On April 26, 1994, Maxus and its subsidiaries sold all of their
partnership interests in Offshore Partners. On June 22, 1994, Maxus also sold
the McFarlan Field and Grand Isle Block 25, both producing oil and gas
properties. In total, the Company received $324.6 million of proceeds and
recorded a net gain of $201.9 million from these transactions.
 
  Restructuring Costs
 
     In June 1994, the Company recorded a $100.9 million restructuring charge.
The charge included a $69.8 million write-off associated with undeveloped Alaska
coal leases, the development of which does not fit within the Company's strategy
to commit funds only to oil and gas exploration and production. The charge also
included costs associated with staff reductions and the write-off of
non-producing assets outside the Company's core areas.
 
                                       F-8
<PAGE>   55
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
NOTE FIVE--ASSET ACQUISITIONS AND DIVESTITURES
 
     In September of 1994, the Company sold its geothermal subsidiary, Thermal
Power Company, for approximately $58 million net in cash and a $6.5 million
promissory note due from the purchaser in 1997. A $12.6 million loss on the sale
of these assets was recognized.
 
     In November of 1993, the Company transferred its working interest in the
Recetor Block in Colombia to its partner for partial recoupment of its
investment. Maxus received $10 million and retained an overriding royalty
interest ("ORI"). There was no gain or loss recognized on this transaction. In
December 1995, the Company sold its ORI to the same party for $25 million.
 
     In October 1993, the Company and its Venezuelan partner, Otepi Consultores,
S.A., were awarded an operating service agreement to reactivate Venezuelan oil
fields with Lagoven, S.A., an affiliate of the national oil company, Petroleos
de Venezuela, S.A. Under the terms of the operating service agreement, Maxus
will be a contractor for Lagoven and will be responsible for overall operations
of the Quiriquire Unit, including all necessary investments to reactivate the
fields comprising the unit. Maxus will receive a fixed fee in U.S. dollars for
each barrel of crude oil produced based on an average international crude oil
price. Maxus is reimbursed in U.S. dollars for its capital expenditures,
provided that such fee and expense reimbursement cannot exceed the maximum
dollar amount per barrel set forth in the agreement. The Venezuelan government
will retain full ownership of all hydrocarbons in the field.
 
     During the second quarter of 1994, Maxus Venezuela (C.I.) Ltd., a
subsidiary of Maxus, signed an agreement with BP Exploracion de Venezuela S.A.,
granting BP a 45% interest in the Quiriquire Unit in eastern Venezuela. Maxus
Venezuela remained the operator with a 50% interest and Otepi Consultores, a
Venezuelan company, holds the remaining 5%. Also, during the second quarter of
1994, Maxus Bolivia, Inc., a subsidiary of Maxus, signed an agreement to take
BHP Petroleum as a partner in its Bolivian oil development project. The Company
received $10 million from BHP in exchange for a 50% interest in the project.
 
NOTE SIX--GEOGRAPHIC DATA
 
     The Company is engaged primarily in the exploration for and the production
and sale of crude oil and natural gas. Sales, operating profit and identifiable
assets by geographic area were as follows:
 
<TABLE>
<CAPTION>
                                                          SALES AND OPERATING REVENUES
                                                       ----------------------------------
                                                       THREE MONTHS        YEAR ENDED
                                                          ENDED           DECEMBER 31,
                                                        MARCH 31,       -----------------
                                                           1995          1994       1993
                                                       ------------     ------     ------
        <S>                                            <C>              <C>        <C>
        United States..................................    $ 41.6       $276.9     $380.7
        Indonesia......................................      93.1        381.2      406.0
        South America..................................       7.8         24.0
                                                           ------       ------     ------
                                                           $142.5       $682.1     $786.7
                                                           ======       ======     ======
</TABLE>
 
                                       F-9
<PAGE>   56
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
<TABLE>
<CAPTION>
                                                            OPERATING PROFIT (LOSS)
                                                       ----------------------------------
                                                       THREE MONTHS        YEAR ENDED
                                                          ENDED           DECEMBER 31,
                                                        MARCH 31,       -----------------
                                                           1995          1994       1993
                                                       ------------     ------     ------
        <S>                                            <C>              <C>        <C>
        United States..................................    $  2.9       $ 35.0     $ 26.3
        Indonesia......................................      36.8        138.5      169.1
        South America..................................      (3.7)        (2.6)     (13.0)
        Other foreign..................................      (1.7)       (11.6)     (20.4)
                                                           ------       ------     ------
                                                             34.3        159.3      162.0
        Equity earnings................................                    5.2       10.2
        General corporate expenses.....................      (5.6)      (104.6)     (37.5)
        Interest and debt expenses.....................     (24.1)       (96.7)     (88.4)
        Pre-merger costs...............................     (42.4)
        Restructuring costs............................                  101.0
                                                           ------        ------     ------
                                                           $(37.8)       $ 64.2     $ 46.3
                                                           ======        ======     ======
</TABLE>
 
<TABLE>
<CAPTION>
                                                             IDENTIFIABLE ASSETS
                                                     -----------------------------------
                                                                       DECEMBER 31,
                                                     MARCH 31,     ---------------------
                                                       1995          1994         1993
                                                     ---------     --------     --------
        <S>                                          <C>           <C>          <C>
        United States............................... $   295.7     $  327.0     $  521.1
        Indonesia...................................     639.0        647.5        665.5
        South America...............................     317.2        304.2        218.9
        Other foreign...............................      15.3         11.4          3.9
                                                      --------     --------     --------
                                                       1,267.2      1,290.1      1,409.4
        Corporate assets............................     424.9        416.6        489.7
        Investments in Associated Companies.........                                88.3
                                                      --------     --------     --------
                                                     $ 1,692.1     $1,706.7     $1,987.4
                                                      ========     ========     ========
</TABLE>
 
     Net foreign assets were $685.5 million at March 31, 1995, $701.4 million at
December 31, 1994 and $673.5 million at December 31, 1993.
 
     Income from foreign operations, after applicable local income taxes, was
$16.7 million for the three months ended March 31, 1995 and $63.9 million and
$77.8 million for the years ended December 31, 1994 and 1993, respectively.
 
     Sales to three customers for the three months ended March 31, 1995 and the
year ended December 31, 1994 and 1993 each represented 10% or more of
consolidated sales:
 
<TABLE>
<CAPTION>
                                                  THREE MONTHS          TWELVE MONTHS
                                                     ENDED            ENDED DECEMBER 31,
                                                   MARCH 31,       ------------------------
                                                      1995          1994          1993
                                                  ------------     ------     -------------
        <S>                                       <C>              <C>        <C>
        Phillips Petroleum Company................    $ 14.3       $ 56.4        $  41.1
        Mitsubishi Corporation....................      23.4         66.5           83.3
        Indonesian Government.....................      36.4        145.8          148.0
</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
 
                                      F-10
<PAGE>   57
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
production sharing contracts between the Company's Indonesian operations and the
Indonesian Government. The Indonesian Government is required to purchase a
specified amount of the Company's oil and gas production throughout the life of
its operations in Indonesia based on these contracts.
 
NOTE SEVEN--TAXES
 
     The Company reports income taxes in accordance with SFAS 109 (See Note
One). The standard was adopted in January 1993. Adoption, which was made
prospectively, had no impact on 1993 earnings or cash flow; however, $21.0
million of deferred tax liabilities which were considered current under SFAS 96
were reclassified as noncurrent and $4.1 million of deferred tax assets were
reclassified as current assets.
 
     Income before income taxes, extraordinary item and cumulative effect of
change in accounting principle was comprised of income (loss) from:
 
<TABLE>
<CAPTION>
                                                       THREE MONTHS        YEAR ENDED
                                                          ENDED           DECEMBER 31,
                                                        MARCH 31,       -----------------
                                                           1995          1994       1993
                                                       ------------     ------     ------
        <S>                                            <C>              <C>        <C>
        United States..................................    $(69.2)      $(60.1)    $(89.4)
        Foreign........................................      31.4        124.3      135.7
                                                           ------       ------     ------
                                                           $(37.8)      $ 64.2     $ 46.3
                                                           ======       ======     ======
</TABLE>
 
     The Company's provision for income taxes was comprised of the following:
 
<TABLE>
<CAPTION>
                                                        THREE MONTHS        YEAR ENDED
                                                           ENDED           DECEMBER 31,
                                                         MARCH 31,       ----------------
                                                            1995          1994      1993
                                                        ------------     ------     -----
        <S>                                             <C>              <C>        <C>
        Current
             Federal....................................                 $(20.1)    $  .4
             Foreign....................................    $ 18.7         73.7      60.9
             State and local............................                    5.5        .6
                                                             -----       ------     -----
                                                              18.7         59.1      61.9
        Deferred
             Federal....................................                   24.7
             Foreign....................................        .4          3.1      22.3
                                                             -----       ------     -----
                                                                .4         27.8      22.3
                                                             -----       ------     -----
        Provision for income taxes......................    $ 19.1       $ 86.9     $84.2
                                                             =====       ======     =====
</TABLE>
 
                                      F-11
<PAGE>   58
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     The principal reasons for the difference between tax expense at the
statutory federal income tax rate of 35% and the Company's provision for income
taxes were:
 
<TABLE>
<CAPTION>
                                                          THREE MONTHS      YEAR ENDED
                                                             ENDED         DECEMBER 31,
                                                           MARCH 31,     ----------------
                                                              1995        1994      1993
                                                          ------------   ------    ------
        <S>                                               <C>            <C>       <C>
        Tax expense at statutory federal rate.............    $(13.2)    $ 22.5    $ 16.2
        Increase (reduction) resulting from:
             Taxes on foreign income......................      12.4       49.5      53.7
             Excess statutory depletion...................                  (.7)     (1.0)
             Asset sales..................................                 20.5
             Alternative minimum tax......................                  (.3)       .3
             Settlement of claims relating to Natomas
               acquisition................................                  (.3)     (2.4)
             Nondeductible pre-Merger costs...............       4.4
             Valuation allowance..........................      13.9       24.9      30.0
             Items not related to current year earnings...       1.5      (33.4)    (13.7)
             Other, net...................................        .1        4.2       1.1
                                                             ------      ------    ------
             Provision for income taxes...................    $ 19.1     $ 86.9    $ 84.2
                                                             ======      ======    ======
</TABLE>
 
     "Items not related to current year earnings" in 1994 includes tax benefit
from the favorable resolution of a federal tax refund suit.
 
     The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities for the three
months ended March 31, 1995, December 31, 1994 and 1993 were as follows:
 
<TABLE>
<CAPTION>
                                                                 MARCH 31,   DECEMBER 31,
                                                                   1995          1994
                                                                 ---------   ------------
        <S>                                                      <C>         <C>
        U. S. deferred tax liabilities
             Properties and equipment..........................   $   5.1      $    5.0
             Other.............................................        .2
                                                                  -------       -------
                  Deferred U. S. tax liabilities...............       5.3           5.0
                                                                  -------       -------
        U. S. deferred tax assets
             Foreign deferred taxes............................     (69.9)        (69.7)
             Book accruals.....................................     (34.4)        (35.1)
             Loss carryforwards................................     (50.8)        (36.3)
             Credit carryforwards..............................     (23.2)        (23.2)
             Other.............................................       (.6)          (.4)
                                                                  -------       -------
                  Gross deferred U. S. tax assets..............    (178.9)       (164.7)
                                                                  -------       -------
        Valuation allowance....................................     163.9         150.0
                                                                  -------       -------
        Net deferred U. S. tax assets..........................     (15.0)        (14.7)
                                                                  -------       -------
        Net deferred U. S. taxes...............................      (9.7)         (9.7)
                                                                  -------       -------
        Foreign deferred tax liabilities
             Properties and equipment..........................     199.7         199.4
                                                                  -------       -------
                  Net deferred foreign taxes...................     199.7         199.4
                                                                  -------       -------
        Net deferred taxes.....................................   $ 190.0      $  189.7
                                                                  =======       =======
</TABLE>
 
                                      F-12
<PAGE>   59
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     The valuation allowance was $92.6 million upon adoption of SFAS 109. The
valuation allowance was increased $23.4 million during 1994 and $13.9 million
during the first three months of 1995, primarily due to the increase in loss
carryforwards.
 
     Because the tax year of the Company did not close on March 31, 1995, tax
carryovers are not measured at that date. At December 31, 1994, the Company had
$13.1 million of general business credit carryforwards that expire between 1996
and 2002; $103.8 million of U.S. net operating loss carryforwards that expire in
2003, 2005 and 2008; and $10.1 million of minimum tax credit that can be carried
forward indefinitely.
 
     As a result of the Merger, effective April 1, 1995, the Company's ability
to utilize its existing net operating loss carryforwards will be limited by
statute to approximately $92.0 million each year until exhausted. To the extent
certain gains are recognized in the future, the annual limitation may be
increased to the extent that the gains are built-in gains within the meaning of
the U.S. Internal Revenue Code.
 
     There are accumulated undistributed earnings after applicable local taxes
of foreign subsidiaries of $6.4 million at March 31, 1995 for which no provision
was necessary for foreign withholding or other income taxes because that amount
had been reinvested in properties and equipment and working capital in the
foreign jurisdictions.
 
     Taxes other than income taxes were comprised of the following:
 
<TABLE>
<CAPTION>
                                                            THREE MONTHS     YEAR ENDED
                                                               ENDED        DECEMBER 31,
                                                             MARCH 31,     --------------
                                                                1995       1994     1993
                                                            ------------   -----    -----
        <S>                                                 <C>            <C>      <C>
        Gross production....................................     $1.2      $ 6.5    $ 8.0
        Real and personal property..........................      1.8        5.5      7.4
        Other...............................................       .1         .9       .5
                                                                 ----      -----    -----
                                                                 $3.1      $12.9    $15.9
                                                                 ====      =====    =====
</TABLE>
 
NOTE EIGHT--POSTEMPLOYMENT BENEFITS
 
  Pensions
 
     The components of net periodic pension expense are as follows:
 
<TABLE>
<CAPTION>
                                                           THREE MONTHS     YEAR ENDED
                                                              ENDED        DECEMBER 31,
                                                            MARCH 31,     ---------------
                                                               1995       1994      1993
                                                           ------------   -----    ------
        <S>                                                <C>            <C>      <C>
        Service cost for benefits earned during the
          period...........................................    $   .5     $ 2.9    $  2.1
        Interest cost on projected benefit obligation......       2.2       8.7       9.3
        Actual return on plan assets.......................      (4.5)     (2.5)    (10.4)
        Net amortization and deferrals.....................       2.5      (5.4)       .6
                                                                -----     -----    ------
                                                               $   .7     $ 3.7    $  1.6
                                                                =====     =====    ======
</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.
 
                                      F-13
<PAGE>   60
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     Plan assets are primarily invested in short-term investments and stocks and
bonds. The principal assumptions used to estimate the benefit obligations of the
plans on the measurement date, October 1, 1994 were as follows:
 
<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 and December 31, 1994 were
as follows:
 
<TABLE>
<CAPTION>
                                                                  PLANS WITH
                                           --------------------------------------------------------
                                           ACCUMULATED      ASSETS       ACCUMULATED      ASSETS
                                            BENEFITS       EXCEEDING      BENEFITS       EXCEEDING
                                            EXCEEDING     ACCUMULATED     EXCEEDING     ACCUMULATED
                                             ASSETS        BENEFITS        ASSETS        BENEFITS
                                             3/31/95        3/31/95       12/31/94       12/31/94
                                           -----------    -----------    -----------    -----------
    <S>                                    <C>            <C>            <C>            <C>
    Actuarial present value of:
         Vested benefit obligation.........   $  86.3        $ 9.8         $  87.6         $ 9.4
                                              -------        -----          ------         -----
         Accumulated benefit obligation....   $  90.6        $11.9         $  91.9         $11.5
                                              -------        -----          ------         -----
         Projected benefit obligation......   $  91.4        $15.0         $  92.7         $14.6
    Plan assets at fair value..............      76.2         14.5            78.0          14.2
                                              -------        -----          ------         -----
    Plan assets less than projected benefit
      obligation...........................   $ (15.2)       $ (.5)        $ (14.7)          (.4)
    Unrecognized net loss..................      24.1          1.0            24.1           1.0
    Unrecognized net transition obligation
      (asset)..............................      (3.8)          .1            (3.8)           .1
    Unrecognized prior service cost........       (.3)         (.9)            (.3)          (.9)
    Adjustment required to recognize
      minimum liability....................     (18.3)                       (18.3)
                                              -------        -----          ------         -----
    Prepaid (accrued) pension cost.........   $ (13.5)       $ (.3)        $ (13.0)        $ (.2)
                                              =======        =====          ======         =====
</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.
 
     In addition to the defined benefit plans, the Company has a defined
contribution plan which covers Indonesian nationals. Employee contributions of
2% of each covered employee's compensation are matched by the Company with a
contribution of 6% of compensation by the Company. Contributions to the plan
were $.1 million in the first quarter of 1995 and $.4 million in 1994.
 
  Other Postretirement Benefits
 
     Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 106 ("SFAS 106"), "Employers' Accounting for
Postretirement Benefits Other Than Pensions," for its retiree health and welfare
benefits plan. Under SFAS 106, the Company is required to accrue the estimated
cost of retiree benefit payments, other than pensions, during employees' active
service period. The Company previously expensed the cost of these benefits,
which are principally medical benefits, as claims were incurred. The Company
currently administers several unfunded postretirement medical and life insurance
plans covering primarily U. S. employees which are, depending on the type of
plan, either contributory or noncontributory. Employees become eligible for
these benefits if they meet minimum age and service
 
                                      F-14
<PAGE>   61
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
requirements. At January 1, 1993, the estimated APBO was $46.1 million, which
the Company elected to amortize over a 20-year period.
 
     During 1994, the Company's postretirement medical and life insurance plans
experienced a partial curtailment due to the Company's decision to reduce staff.
The effect of the curtailment was a $6.6 million charge to earnings in 1994,
which was included as a component of the restructuring costs (See Note Four),
primarily due to accelerated recognition of the transition obligation.
 
     The components of net periodic postretirement benefit expense for the three
months ended March 31, 1995 and for the years ended December 31, 1994 and 1993
are as follows:
 
<TABLE>
<CAPTION>
                                                           THREE MONTHS      YEAR ENDED
                                                              ENDED         DECEMBER 31,
                                                            MARCH 31,       -------------
                                                               1995         1994     1993
                                                           ------------     ----     ----
        <S>                                                <C>              <C>      <C>
        Service cost for benefits earned during the
          period...........................................     $ .1        $ .5     $ .4
        Interest cost on accumulated postretirement
          benefit obligation...............................       .9         3.4      3.9
        Amortization of transition obligation..............       .5         2.3      2.3
                                                                ----         ----     ----
                                                                $1.5        $6.2     $6.6
                                                                ====        ====     ====
</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 and December 31,
1994 is as follows:
 
<TABLE>
<CAPTION>
                                                               MARCH 31,     DECEMBER 31,
                                                                 1995            1994
                                                               ---------     ------------
        <S>                                                    <C>           <C>
        Retirees..............................................  $  39.0         $ 39.0
        Fully eligible active employees.......................      1.8            1.8
        Other active employees................................      3.6            3.6
                                                                 ------          -----
        Total.................................................     44.4           44.4
        Unrecognized transition obligation....................    (33.7)         (34.2)
        Unrecognized net gain.................................      2.1            2.0
                                                                 ------          -----
                                                                $  12.8         $ 12.2
                                                                =======         ======
</TABLE>
 
     A discount rate of 8.5% was used in determining the APBO for the three
months ended March 31, 1995 and the year ended December 31, 1994. The APBO was
based on a 10.4% increase in the medical cost trend rate, with the rate trending
downward .6% per year to 5% in 2003 and remaining at 5% thereafter. This
assumption has a significant effect on annual expense, as it is estimated that a
1% increase in the medical trend rate would increase the APBO by $4.2 million
and increase the net periodic postretirement benefit cost by $.4 million per
year.
 
  Other Postemployment Benefits
 
     In 1993 the Company adopted, Statement of Financial Accounting Standards
No. 112 ("SFAS 112"), "Employers' Accounting for Postemployment Benefits," to
account for benefits provided after employment but before retirement. SFAS 112
requires an accrual method of recognizing the cost of providing postemployment
benefits. Prior to 1993, postemployment benefit expenses were recognized as
paid. The Company recognized the cumulative effect of the change in accounting
for postemployment benefits in 1993, which resulted in a charge of $4.4 million.
This liability primarily represents medical benefits for long-term disability
recipients. Future annual costs are expected to be immaterial. Net periodic
postemployment benefit expense
 
                                      F-15
<PAGE>   62
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
was insignificant for the three months ended March 31, 1995 and for the years
ended December 31, 1994 and 1993.
 
NOTE NINE--FINANCIAL INSTRUMENTS
 
     The fair value of financial instruments is determined by reference to
various market data and other valuation techniques as appropriate. Unless
otherwise disclosed, the fair value of financial instruments approximates their
recorded values.
 
  Restricted Cash
 
     The fair value of the Company's restricted cash, which is invested
primarily in U. S. Treasury notes, marketable securities and trust accounts is
based on the quoted market prices for the same or similar securities at the
reporting date.
 
  Long-Term Investments
 
     The fair value of the Company's long-term investments, which are primarily
U. S. Treasury notes and long-term notes receivable, is based on the quoted
market prices for the same or similar investments at the reporting date.
 
  Long-Term Debt
 
     The fair value of the Company's long-term debt is estimated based on the
quoted market prices for the same or similar issues or on the current rates
offered to the Company for debt of the same remaining maturities.
 
     The estimated fair value of the Company's financial instruments are as
follows:
 
<TABLE>
<CAPTION>
                                                                      MARCH 31, 1995
                                                                    -------------------
                                                                    CARRYING      FAIR
                                                                     AMOUNT      VALUE
                                                                    --------     ------
        <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>
 
<TABLE>
<CAPTION>
                                                                     DECEMBER 31, 1994
                                                                    -------------------
                                                                    CARRYING      FAIR
                                                                     AMOUNT      VALUE
                                                                    --------     ------
        <S>                                                         <C>          <C>
        Liabilities
             Long-term debt, including current portion.............  $975.6      $857.8
</TABLE>
 
     For information on the Company's derivative financial instruments, see Note
Seventeen.
 
NOTE TEN--RECEIVABLES
 
<TABLE>
<CAPTION>
                                                               MARCH 31,     DECEMBER 31,
                                                                 1995            1994
                                                               ---------     ------------
        <S>                                                    <C>           <C>
        Trade receivables.....................................  $  97.0         $110.8
        Notes and other receivables...........................     32.0           42.3
        Less--Allowance for doubtful receivables..............      1.2             .7
                                                               ---------     ------------
                                                                $ 127.8         $152.4
                                                                =======      ==========
</TABLE>
 
                                      F-16
<PAGE>   63
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
NOTE ELEVEN--PROPERTIES AND EQUIPMENT
 
<TABLE>
<CAPTION>
                                                               MARCH 31,     DECEMBER 31,
                                                                 1995            1994
                                                               ---------     ------------
        <S>                                                    <C>           <C>
        Proved properties..................................... $2,445.5        $2,397.7
        Unproved properties...................................     31.7            29.1
        Gas plants and other..................................    220.0           219.1
                                                               --------        --------
                  Total Oil and Gas...........................  2,697.2         2,645.9
        Corporate.............................................     51.5            53.5
                                                               --------        --------
                                                                2,748.7         2,699.4
        Less--Accumulated depreciation, depletion and
          amortization........................................  1,638.0         1,611.0
                                                               --------        --------
                                                               $1,110.7        $1,088.4
                                                               ========        ========
</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 and $152.3 million for the years ended December 31,
1994 and 1993, respectively. The charge against earnings for maintenance and
repairs was $7.4 million for the three months ended March 31, 1995, and $38.9
million and $35.0 million for the years ended December 31, 1994 and 1993,
respectively.
 
NOTE TWELVE--INVESTMENTS AND LONG-TERM RECEIVABLES
 
<TABLE>
<CAPTION>
                                                               MARCH 31,     DECEMBER 31,
                                                                 1995            1994
                                                               ---------     ------------
        <S>                                                      <C>            <C>
        Investments, at cost, and long-term receivables........  $12.0          $ 11.9
        U. S. Treasury notes...................................   29.5            28.3
                                                                 -----          ------
                                                                 $41.5          $ 40.2
                                                                 =====          ======
</TABLE>
 
     In September 1994, the Company sold its geothermal subsidiary, Thermal
Power Company, which owned Union-Magma-Thermal Tax Partnership ("UMT") (See Note
Five). The investment in UMT was carried on the equity method prior to the sale
of Thermal Power Company. The following schedule presents certain summarized
financial information of UMT:
 
<TABLE>
<CAPTION>
                                                             DECEMBER 31,     DECEMBER 31,
                                                                 1994             1993
                                                             ------------     ------------
        <S>                                                  <C>              <C>
        Summarized Statement of Income:
             Sales...........................................    $ 50.0          $ 93.1
             Gross profit....................................      24.8            50.3
             Net income......................................      24.8            50.3
</TABLE>
 
     The Company's equity earnings are principally from UMT and were $5.2
million in 1994 and $10.2 million in 1993.
 
NOTE THIRTEEN--RESTRICTED CASH
 
     At March 31, 1995 and December 31, 1994, the Company had $128.4 million and
$140.6 million, respectively, in restricted cash, of which $64.0 million in 1995
and $78.5 million in 1994 represented collateral for outstanding letters of
credit. Assets held in trust as required by certain insurance policies were
$64.4 million in 1995 and $62.1 million in 1994. Approximately $48.5 million and
$46.4 million of collateral for outstanding letters of credit at March 31, 1995
and December 31, 1994, respectively, was classified as a current asset.
 
                                      F-17
<PAGE>   64
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
NOTE FOURTEEN--INTANGIBLE ASSETS
 
     Intangibles, primarily the excess of cost over fair market value of net
assets acquired, were $50.0 million at March 31, 1995 and December 31, 1994.
Accumulated amortization at March 31, 1995 and December 31, 1994 was $14.5
million and $14.2 million, respectively. The charge against earnings for
amortization of intangible assets was $0.3 million for the three months ended
March 31, 1995 and $1.3 million for the years ended December 31, 1994 and 1993.
 
NOTE FIFTEEN--ACCRUED LIABILITIES
 
<TABLE>
<CAPTION>
                                                                 MARCH 31,   DECEMBER 31,
                                                                   1995          1994
                                                                 ---------   ------------
        <S>                                                      <C>         <C>
        Accrued interest payable...............................   $  34.8       $ 23.3
        Joint interest billings for international operations...      32.3         25.9
        Merger reserve.........................................      41.0
        Environmental reserve..................................      14.9         14.9
        Overlift payable.......................................      12.2          9.1
        Postretirement and postemployment benefits.............       4.5          4.5
        Accrued compensation, benefits and withholdings........       5.0          6.4
        Other..................................................      25.1         17.1
                                                                   ------       ------
                                                                  $ 169.8       $101.2
                                                                   ======       ======
</TABLE>
 
NOTE SIXTEEN--LONG-TERM DEBT AND CREDIT ARRANGEMENTS
 
<TABLE>
<CAPTION>
                                                                 MARCH 31,   DECEMBER 31,
                                                                   1995          1994
                                                                 ---------   ------------
        <S>                                                      <C>         <C>
        Senior Indebtedness
             Sinking Fund Debentures
                  11 1/4% due 2013.............................   $  16.9       $ 16.9
                  11 1/2% due 2001-2015........................     109.0        109.0
                  8 1/2% due 1998-2008.........................      93.4         93.4
        Notes
             9 7/8% due 2002...................................     247.3        247.3
             9 1/2% due 2003...................................      99.5         99.5
             9 3/8% due 2003...................................     260.0        260.0
        Medium-term notes......................................     149.3        149.3
        Bank and other loans...................................        .2           .2
                                                                   ------       ------
             Total senior indebtedness.........................     975.6        975.6
        Less--current portion..................................       4.7          4.7
                                                                   ------       ------
                                                                  $ 970.9       $970.9
                                                                   ======       ======
</TABLE>
 
     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>
 
                                      F-18
<PAGE>   65
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     At March 31, 1995 and December 31, 1994, the Company had $149.3 million of
medium-term notes outstanding, which were issued in prior years, with maturities
from 1995 to 2004 and annual interest rates ranging from 7.57% to 11.08%.
 
     The Company maintains a $25.0 million uncommitted credit facility (the
"credit facility") which is used for the issuance of documentary or standby
letters of credit and/or the payment of shipping documents. The credit facility
can be secured by cash or the accounts receivable which are financed through the
letters of credit. At March 31, 1995, there were $24.5 million of cash
collateralized letters of credit outstanding under this credit facility.
 
     Total interest and debt expenses incurred, including capitalized interest,
were as follows:
 
<TABLE>
<CAPTION>
                                                            THREE MONTHS     YEAR ENDED
                                                               ENDED        DECEMBER 31,
                                                             MARCH 31,     --------------
                                                                1995       1994     1993
                                                            ------------   -----    -----
        <S>                                                   <C>          <C>      <C>
        Interest and debt expenses..........................   $ 24.1      $96.7    $88.4
        Capitalized interest................................       .1        3.2      7.5
                                                                -----      -----    -----
                                                               $ 24.2      $99.9    $95.9
                                                                =====      =====    =====
</TABLE>
 
NOTE SEVENTEEN--DERIVATIVE FINANCIAL INSTRUMENTS
 
     The Company's only derivative financial instruments are an interest rate
swap agreement with an investment broker, natural gas price swap agreements and
crude oil and natural gas futures contracts, which are not used for trading
purposes.
 
  Interest Rate Swap Agreement
 
     Effective January 27, 1993, the Company entered into an interest rate swap
agreement under which it pays the counterparty interest at a variable rate based
on the London Interbank Offering Rate (LIBOR) and the counterparty pays the
Company interest at 6.73% on the notional principal of $100.0 million. This
agreement is effective through January 27, 2003. The Company is not required to
collateralize its obligation under this agreement unless it is in an unfavorable
position. At December 31, 1993, the Company had borrowings of $5.8 million
against its then favorable position in this interest rate swap agreement. Due to
higher interest rates in 1994, the Company's position in the interest rate swap
became unfavorable. As a result, the Company was required to collateralize $7.9
million, which was recorded in deferred charges at December 31, 1994. As
interest rates declined during the first three months of 1995, the Company
reduced its collateralized position by $3.4 million, leaving a balance of $4.5
million recorded in deferred charges at March 31, 1995.
 
  Natural Gas Price Swap Agreements
 
     Under the price swap agreements used to hedge fluctuations in the price of
natural gas, the Company receives or makes payments based on the differential
between the Company's specified price and the counterparty's specified price of
natural gas. Depending on the agreement, the Company pays a fixed or variable
price per million British Thermal Units ("Mmbtu") and receives a fixed or
variable price per Mmbtu. During the three months ended March 31, 1995, the
Company had swap agreements with other companies to exchange payments on 0.8
million Mmbtu of gas. Under these swap agreements, the Company paid fixed or
variable prices averaging $1.61 per Mmbtu and received fixed or variable prices
averaging $1.58 per Mmbtu. Gross gains and gross losses realized on these swap
agreements were immaterial.
 
                                      F-19
<PAGE>   66
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  Natural Gas and Crude Oil Futures Contracts
 
     Under the natural gas futures contracts used to hedge fluctuations in the
price of natural gas, the Company receives or makes payments based on the
differential between the selling price and the settlement price per Mmbtu.
During the three months ended March 31, 1995, the Company settled futures
contracts with other companies on 1.2 million Mmbtu of gas. Under these futures
contracts, the Company received selling prices averaging $1.65 per Mmbtu and
paid settlement prices averaging $1.46 per Mmbtu. Realized gross gains on these
futures contracts were $0.2 million.
 
     Under the crude oil futures contracts used to hedge fluctuations in the
price of crude oil, the Company receives or makes payments based on the
differential between the selling price and the settlement price per barrel.
During the three-month period ended March 31, 1995, crude oil volumes hedged
under these futures contracts were insignificant as were gross unrealized gains
and losses.
 
NOTE EIGHTEEN--PREFERRED STOCK
 
     The Company has the authority to issue 100,000,000 shares of Preferred
Stock, $1.00 par value. The rights and preferences of shares of authorized but
unissued Preferred Stock are established by the Company's Board of Directors at
the time of issuance.
 
  $9.75 Cumulative Convertible Preferred Stock
 
     In 1987, the Company sold 3,000,000 shares of $9.75 Cumulative Convertible
Preferred Stock (the "$9.75 Preferred Stock"). Since such time, the Company has
entered into various agreements, most recently on June 8, 1995, with the sole
holder of the $9.75 Preferred Stock pursuant to which, among other things, the
Company has repurchased 500,000 shares and the parties have waived or amended
various covenants, agreements and restrictions relating to such stock.
Currently, 1,250,000 shares of $9.75 Preferred Stock are outstanding, each
receiving an annual cash dividend of $9.75. In addition, 375,000 of such shares
(the "Conversion Waiver Shares") each receive an additional quarterly cash
payment of $.25 ($.50 in certain circumstances). For the 12-month period
commencing February 1, 1995, each share of the $9.75 Preferred Stock has a
liquidation value of $101.0836 ($126.4 million in the aggregate) which reduces
to $100 at February 1, 1996, in each case plus accrued dividends. Since February
1, 1994, the stock has been subject to mandatory redemption at the rate of
625,000 shares per year. The $9.75 Preferred Stock currently is neither
convertible by the holder nor redeemable at the Company's option and has no
associated registration rights. The $9.75 Preferred Stock entitles the holder to
vote only on certain matters separately affecting such holder, and the $9.75
Preferred Stock other than the Conversion Waiver Shares entitles the holder to
elect one individual to the Board of Directors of the Company. In addition,
pursuant to the June 8, 1995 agreement, the holder of the $9.75 Preferred Stock
waived previously granted rights to approve certain "self-dealing" transactions
and certain financial covenants pertaining to the Company, and the Company
waived its right of first offer with respect to the transfer of the $9.75
Preferred Stock and certain transfer restrictions on such stock.
 
  $4.00 Cumulative Convertible Preferred Stock
 
     Each outstanding share of $4.00 Cumulative Convertible Preferred Stock (the
"$4.00 Preferred Stock") is entitled to one vote, is convertible at any time
into shares of the Company's Common Stock (2.29751 shares at March 31, 1995), is
entitled to receive annual cash dividends of $4.00 per share, is callable at and
has a liquidation value of $50.00 per share ($217.8 million in the aggregate at
March 31, 1995) plus accrued but unpaid dividends, if any.
 
                                      F-20
<PAGE>   67
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  $2.50 Cumulative Preferred Stock
 
     Each outstanding share of the $2.50 Preferred is entitled to shall receive
annual cash dividends of $2.50 per share, is callable after December 1, 1998 at
and has a liquidation value of $25.00 per share ($87.5 million in the aggregate
at March 31, 1995) plus accrued but unpaid dividends, if any.
 
     The holders of the shares are entitled to limited voting rights under
certain conditions. In the event the Company is in arrears in the payment of six
quarterly dividends, the holders of the $2.50 Preferred Stock have the right to
elect two members to the Board of Directors until such time as the dividends in
arrears are current and a provision is made for the current dividends due.
 
NOTE NINETEEN--COMMON STOCK
 
<TABLE>
<CAPTION>
                                                                    SHARES      AMOUNT
                                                                  -----------   ------
        <S>                                                       <C>           <C>
        January 1, 1993.........................................  133,567,300   $133.6
             Employee Shareholding and Investment Plan..........      475,852       .5
             Restricted stock...................................      312,690       .3
             Exercise of stock options..........................       17,683
             Fractional shares exchanged for cash...............           (2)
                                                                  -----------   ------
        January 1, 1994.........................................  134,373,523    134.4
             Employee Shareholding and Investment Plan..........      830,798       .8
             Restricted stock...................................      490,430       .5
             Exercise of stock options..........................
             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>
 
     On July 30, 1991, the Company's Dividend Reinvestment and Stock Purchase
Plan (the "Plan") became effective. The Plan allowed holders of Common Stock to
purchase additional shares at a 3% discount from the current market prices
without paying brokerage commissions or other charges. In addition, if the
Company paid a dividend on its Common Stock in the future, common stockholders
could reinvest the amount of those dividends in additional shares also at a 3%
discount from the current market prices. In November 1992, the Company
effectively suspended the Plan by raising the threshold price.
 
     At March 31, 1995 and December 31, 1994, respectively, there were 32.4
million and 35.8 million shares of Common Stock reserved for issuance upon
conversion of Preferred Stock, exercises of stock options or issuance under
certain employee benefit plans.
 
     In 1992, Kidder, Peabody & Co. Incorporated purchased eight million
warrants from the Company. Each warrant represents the right to purchase one
share of the Company's Common Stock at $13.00 per share at any time prior to the
expiration of the warrants on October 10, 1997.
 
     The Company has an Employee Shareholding and Investment Plan ("ESIP") which
allows eligible participating employees to contribute a certain percentage of
their salaries (1%-10%) to a trust for investment in any of six funds, one of
which consists of the Company's Common Stock. The Company matches the
participating employee's contribution to the ESIP (up to 6% of base pay); such
matching contribution is charged against earnings and invested in the ESIP fund
which consists of the Company's Common Stock. The charge against earnings for
the Company's contribution to the ESIP was $0.6 million, $2.8 million and
 
                                      F-21
<PAGE>   68
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
$2.6 million at March 31, 1995, December 31, 1994, and December 31, 1993,
respectively. Subsequent to the Merger, contributions can no longer be invested
in the Company's Common Stock.
 
     In 1988, the Company adopted a Preferred Share Purchase Rights Plan. The
plan issued one right for each share of Common Stock and 7.92 rights for each
share of $9.75 Cumulative Convertible Preferred Stock outstanding as of the
close of business on September 12, 1988. The rights, which entitle the holder to
purchase from the Company one one-hundredth of a share of a new series of junior
preferred stock at $23.00 per share, become exercisable if a person becomes the
beneficial owner of 20% or more of the Company's Common Stock or of an amount
that the Board of Directors determines is intended to cause the Company to take
certain actions not in the best long-term interests of the Company and its
stockholders. The rights also become exercisable if a person makes a tender
offer or exchange offer for 30% or more of the Company's outstanding Common
Stock. The rights may be redeemed at $.10 per right under certain circumstances.
In the Merger Agreement, the Company agreed to redeem the rights. On February
28, 1995, the Board of Directors of the Company took action to redeem the
rights, effective as of March 22, 1995. Holders of Common Stock on the close of
business on that date received the redemption price of $0.10 per right. Under a
separate agreement with the sole holder of the $9.75 Preferred Stock, such
holder waived its right to receive the redemption price with respect to the
rights associated with the $9.75 Preferred Stock, subject to consummation of the
Merger.
 
NOTE TWENTY--PAID-IN CAPITAL AND ACCUMULATED DEFICIT
 
<TABLE>
<CAPTION>
                                                                  PAID-IN    ACCUMULATED
                                                                  CAPITAL      DEFICIT
                                                                  --------   -----------
        <S>                                                       <C>        <C>
        January 1, 1993.........................................  $  980.1    $  (944.3)
             Net loss...........................................                  (49.4)
             Dividends on Preferred Stock.......................     (41.7)
             Issuance of $4.00 Preferred Stock..................       1.1
             Issuance of $2.50 Preferred Stock..................      81.1
             Employee Shareholding and Investment Plan..........       3.1
             Restricted stock...................................       2.5
                                                                  --------    ---------
        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>
 
                                      F-22
<PAGE>   69
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
NOTE TWENTY-ONE--UNREALIZED LOSS ON INVESTMENT IN MARKETABLE SECURITIES
 
     The amortized cost and estimated fair value of marketable securities at
March 31, 1995 are as follows:
 
<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>
 
     At March 31, 1995, securities categorized as held-to-maturity are included
in cash equivalents, short-term investments and short- and long-term restricted
cash. The securities held-for-sale consist of U. S. Treasury notes which mature
in August, 2002 and are classified as long-term investments (See Note Twelve).
 
     The amortized cost and estimated fair value of marketable securities at
December 31, 1994 are as follows:
 
<TABLE>
<CAPTION>
                                                                 DECEMBER 31, 1994
                                                        -----------------------------------
                                                                        GROSS
                                                        AMORTIZED     UNREALIZED     MARKET
                                                          COST           LOSS        VALUE
                                                        ---------     ----------     ------
        <S>                                             <C>           <C>            <C>
        Held-to-maturity:
             Corporate and other debt securities.......  $ 139.4                     $139.4
        Held-for-sale:
             Corporate and other debt securities.......     30.7         $2.4          28.3
</TABLE>
 
     At December 31, 1994, securities categorized as held-to-maturity with
maturities of 90 days or less are classified as cash equivalents and those with
maturities greater than ninety days are classified as short-term investments.
The securities held-for-sale consist of U. S. Treasury notes which mature in
August, 2002 and are classified as long-term investments (See Note Twelve).
 
NOTE TWENTY-TWO--COMMON TREASURY STOCK
 
<TABLE>
<CAPTION>
                                                                     SHARES     AMOUNT
                                                                    --------    ------
        <S>                                                         <C>         <C>
        January 1, 1993...........................................  (135,751)   $(2.1)
             Restricted Stock.....................................   (38,212)     (.4)
                                                                    --------    -----
        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-THREE--STOCK OPTIONS
 
     Two plans, a Long-Term Incentive Plan and a Director Stock Option Plan,
were approved by the stockholders in 1992. The Company's 1986 and 1992 Long-Term
Incentive Plans (the "Incentive Plans"), administered by the Compensation
Committee of the Board of Directors, permit the grant to officers and certain
key employees of stock options, stock appreciation rights ("SARs"), performance
units and awards of Common Stock or other securities of the Company on terms and
conditions determined by the Compensation Committee of the Board of Directors.
 
                                      F-23
<PAGE>   70
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     The Director Stock Option Plan became effective on September 1, 1992. Under
this plan, non-employee directors received options to purchase shares of Common
Stock on the effective date of the plan. Thereafter, upon initial election or
re-election of a non-employee director at an annual meeting, the non-employee
directors automatically receive options to purchase shares of Common Stock. The
plan terminated on June 7, 1995.
 
     The grant or exercise of an option does not result in a charge against the
Company's earnings because all options have been granted at exercise prices
approximating the market value of the stock at the date of grant. However, any
excess of Common Stock market price over the option price of options, which
includes SARs, does result in a charge against the Company's earnings; a
subsequent decline in market price results in a credit to earnings, but only to
a maximum of the earnings charges incurred in prior years on SARs.
 
     Stock option activity was as follows:
 
<TABLE>
<CAPTION>
                                                                    DECEMBER 31,
                                              MARCH 31,    ------------------------------
                                                1995           1994             1993
                                              ---------    ------------     -------------
        <S>                                   <C>          <C>              <C>
        Outstanding at January 1............  2,268,068       1,694,445         1,855,695
             Granted........................                    758,000            20,000
             Exercised......................                                      (17,683)
             Cancelled......................    (77,495)       (184,377)         (163,567)
                                              ---------    ------------     -------------
        Outstanding at end of period........  2,190,573       2,268,068         1,694,445
             Grant price....................               $5.00-$8.625            $8.625
             Exercise price.................                                $6.625-$8.506
        Available for future grants at end
          of period.........................  2,496,936       2,419,441         3,492,787
        Restricted stock held for vesting at
          end
          of period.........................    936,066         951,410           874,602
        Performance units held for vesting
          at
          end of period.....................    653,355         653,355           653,355
</TABLE>
 
     Exercise prices of stock options outstanding at March 31, 1995 ranged from
$5.00 to $13.75 per share. There was a credit to earnings for SARs in 1993 of
$.1 million. There was no earnings activity related to SARs in 1994 or for the
period ended March 31, 1995. Effective upon the Merger, all stock options and
restricted stock outstanding under Company-sponsored incentive plans were
surrendered to the Company.
 
     Under the 1986 Long-Term Incentive Plan, the Company granted Restricted
Stock. The amount of the grant price is amortized over the vesting period of the
grant as a charge against earnings. The charge against earnings was $0.5 million
for the period ended March 31, 1995, $1.4 million in 1994 and $2.4 million in
1993.
 
     In 1993, the Company issued performance units under the Long-Term Incentive
Plan. The performance unit entitles the grantee to the value of a share of
Common Stock contingent upon the performance of the Company compared to a
selected group of peer companies. The value of the performance unit is amortized
over the vesting period based on a weighted probability of expected payout
levels. The charge against earnings was $0.6 million in 1993. There was no
earnings activity related to performance units in 1994. For the period ended
March 31, 1995, there was a credit to earnings of $0.6 million.
 
     Effective upon the Merger, all stock options and restricted stock
outstanding under Company-sponsored incentive plans were surrendered to the
Company. In March 1995, the Company recorded a $9.9 million charge to earnings
to record the estimated cost to redeem all outstanding options and restricted
stock. This charge was included in pre-Merger costs in the Company's
consolidated statement of operations (See Note Three).
 
                                      F-24
<PAGE>   71
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
NOTE TWENTY-FOUR--LEASES
 
     The Company leases certain machinery and equipment, facilities and office
space under cancelable and noncancelable operating leases, most of which expire
within 20 years and may be renewed.
 
     Minimum annual rentals for non-cancelable operating leases at March 31,
1995, were as follows:
 
<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          DECEMBER 31,
                                                          MARCH 31,       ---------------
                                                             1995         1994      1993
                                                         ------------     -----     -----
        <S>                                              <C>              <C>       <C>
        Total rentals....................................    $ 14.0       $60.1     $67.7
        Less--Sublease rental income.....................        .9         2.9       3.4
                                                             ------       -----     -----
        Rental expense...................................    $ 13.1       $57.2     $64.3
                                                             ======       =====     =====
</TABLE>
 
NOTE TWENTY-FIVE--COMMITMENTS AND CONTINGENCIES
 
     Like other energy companies, Maxus' operations are subject to various laws
related to the handling and disposal of hazardous substances which require the
cleanup of deposits and spills. Compliance with the laws and protection of the
environment worldwide is of the highest priority to Maxus management. In the
first quarter of 1995, the Company spent $1.4 million in environmental related
expenditures for its oil and gas operations.
 
     In addition, the Company is implementing certain environmental projects
related to its former chemicals business ("Chemicals") sold to an affiliate of
Occidental Petroleum Corporation (collectively, "Occidental") in 1986 and
certain other disposed of businesses. The environmental projects discussed below
relating to Chemicals' business are being conducted on behalf of Occidental
pursuant to the sale agreement.
 
     The Company has agreed to remediate the site of the former agricultural
chemical plant in Newark, New Jersey as required by a consent decree entered
into in 1990 by Occidental, the United States Environmental Protection Agency
(the "EPA") and the New Jersey Department of Environmental Protection and Energy
(the "DEP"). Pursuant to an agreement with the EPA, the Company is conducting
further testing and studies to characterize contaminated sediment in a portion
of the Passaic River near the plant site. The Company has been conducting
similar studies under its own auspices for several years.
 
     Under an Administrative Consent Order issued by the DEP in 1990, covering
sites primarily in Kearny and Secaucus, New Jersey, the Company will continue to
implement interim remedial measures and to perform remedial investigations and
feasibility studies and, if necessary, will implement additional remedial
actions at various locations where chromite ore residue, allegedly from the
former Kearny plant, was utilized, as well as at the plant site.
 
                                      F-25
<PAGE>   72
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     Until 1976, Chemicals operated manufacturing facilities in Painesville,
Ohio. The Company has heretofore conducted many remedial, maintenance and
monitoring activities at this site. The former Painesville plant area has been
proposed for listing on the national priority list of Superfund sites. The scope
and nature of further investigation or remediation which may be required cannot
be determined at this time.
 
     The Company also has responsibility for Chemicals' share of the remediation
cost for a number of other non-plant sites where wastes from plant operations by
Chemicals were allegedly disposed of or have come to be located, including
several commercial waste disposal sites.
 
     At the time of the spin-off by the Company of Diamond Shamrock, Inc.
("DSI") in 1987, the Company executed a cost-sharing agreement for the partial
reimbursement by DSI of environmental expenses related to the Company's disposed
of businesses, including Chemicals. DSI is expected to reach its total
reimbursement obligation in 1996.
 
     The Company's total expenditures for environmental compliance for disposed
of businesses, including Chemicals, were $7.9 million in the first quarter of
1995, $2.6 million of which was recovered from DSI under the cost-sharing
agreement.
 
     Reserves have been established for environmental liabilities where they are
material and probable and can be reasonably estimated. At March 31, 1995 and
December 31, 1994, reserves for the above environmental contingencies totaled
$84.7 million and $87.1 million, respectively. During 1994, the Company
increased its reserve for future environmental liabilities by $60.5 million,
primarily in response to the EPA's proposal of chromium clean-up standards and
for additional costs expected to be incurred at Chemicals' former Newark, New
Jersey plant site.
 
     The Company enters into various operating agreements and capital
commitments associated with the exploration and development of its oil and gas
properties. Such contractual financial and/or performance commitments are not
material.
 
     The Company's foreign petroleum exploration, development and production
activities are subject to political and economic uncertainties, expropriation of
property and cancellation or modification of contract rights, foreign exchange
restrictions and other risks arising out of foreign governmental sovereignty
over the areas in which the Company's operations are conducted, as well as risks
of loss in some countries due to civil strife, guerrilla activities and
insurrection. Areas in which the Company has significant operations include the
United States, Indonesia, Ecuador, Bolivia and Venezuela.
 
     The Company has begun discussions with various government entities in
Ecuador regarding a number of issues related to Block 16 and the Tivacuno area,
including the Company's cost recovery claims, the approval of budgets, contract
terms and other operating matters. The Company believes these matters will be
satisfactorily resolved.
 
                                      F-26
<PAGE>   73
 
                              REPORT OF MANAGEMENT
 
To the Stockholders of Maxus Energy Corporation
 
     The Consolidated Financial Statements have been prepared in conformity with
generally accepted accounting principles and have been audited by Arthur
Andersen LLP, independent accountants, for the three months ended March 31, 1995
and the nine months ended December 31, 1995 and have been audited by Price
Waterhouse LLP, independent accountants, for the two years in the period ended
December 31, 1994.
 
     In meeting its responsibility for the reliability of the Consolidated
Financial Statements, the Company depends on its accounting and control systems.
These systems are designed to provide reasonable assurance that assets are
safeguarded against loss from unauthorized use and that transactions are
executed in accordance with the Company's authorizations and are recorded
properly. The Company believes that its accounting and control systems provide
reasonable assurance that errors or irregularities that could be material to the
Consolidated Financial Statements are prevented or would be detected within a
timely period. The Company also requires that all officers and other employees
adhere to a written business conduct policy.
 
     The independent accountants provide an objective review as to the Company's
reported operating results and financial position. The Company also has an
active operations auditing program which monitors the functioning of the
Company's accounting and control systems and provides additional assurance that
the Company's operations are conducted in a manner which is consistent with
applicable laws.
 
     The Board of Directors pursues its oversight role for the Consolidated
Financial Statements through the Audit Review Committee which is composed solely
of directors who are not employees of the Company. The Audit Review Committee
meets with the Company's financial management and operations auditors
periodically to review the work of each and to monitor the discharge of their
responsibilities. The Audit Review Committee also meets periodically with the
Company's independent accountants without representatives of the Company
present, to discuss accounting, control, auditing and financial reporting
matters.
 
                                            /s/  W. MARK MILLER
                                            W. Mark Miller
                                            Executive Vice President and
                                            Treasurer
                                            (Principal Financial Officer)
 
                                            /s/  LINDA R. ENGELBRECHT
                                            Linda R. Engelbrecht
                                            Controller
                                            (Principal Accounting Officer)
 
Dallas, Texas
February 2, 1996
 
                                      F-27
<PAGE>   74
 
                       REPORT OF INDEPENDENT ACCOUNTANTS
 
To the Stockholders and Board of Directors of
  Maxus Energy Corporation
 
     We have audited the accompanying consolidated balance sheets of Maxus
Energy Corporation (a Delaware corporation) and subsidiaries as of March 31,
1995 and December 31, 1995, and the related consolidated statements of
operations and cash flows for the three months ended March 31, 1995 and the nine
months ended December 31, 1995. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
 
     We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provides a reasonable basis for our opinion.
 
     In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
Maxus Energy Corporation and its subsidiaries as of March 31, 1995 and December
31, 1995, and the results of its operations and its cash flows for the three
months ended March 31, 1995 and the nine months ended December 31,1995, in
conformity with generally accepted accounting principles.
 
/s/  ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
 
Dallas, Texas
February 2, 1996
 
                                      F-28
<PAGE>   75
 
                       REPORT OF INDEPENDENT ACCOUNTANTS
 
To the Stockholders and Board of Directors of
  Maxus Energy Corporation
 
     In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of operations and of cash flows present fairly, in all
material respects, the financial position of Maxus Energy Corporation and its
subsidiaries at December 31, 1994 and the results of their operations and their
cash flows for each of the two years in the period ended December 31, 1994, in
conformity with generally accepted accounting principles. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
 
     As discussed in Notes 1, 7 and 8 to the Consolidated Financial Statements,
the Company changed its methods of accounting for income taxes, postretirement
benefits and postemployment benefits in 1993.
 
/s/  PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
 
Dallas, Texas
February 28, 1995
 
                                      F-29
<PAGE>   76
 
                FINANCIAL SUPPLEMENTARY INFORMATION (Unaudited)
 
(DATA IS AS OF DECEMBER 31 FOR THE YEARS ENDED 1993 AND 1994 AND AS OF MARCH 31
                             FOR THE FIRST QUARTER
THEN ENDED 1995. THE DOLLAR AMOUNTS IN TABLES ARE IN MILLIONS, EXCEPT PER SHARE)
 
OIL AND GAS PRODUCING ACTIVITIES
 
     The following are disclosures about the oil and gas producing activities of
the Company as required by Statement of Financial Accounting Standards No. 69
("SFAS 69").
 
  Results of Operations
 
     Results of operations from all oil and gas producing activities are shown
below. These results exclude revenues and expenses related to the purchase of
natural gas and the subsequent processing and resale of such natural gas plus
the sale of natural gas liquids extracted therefrom.
 
<TABLE>
<CAPTION>
                                 UNITED STATES                         INDONESIA
                        -------------------------------     ------------------------------
                         MARCH 31,                           MARCH 31,
                          1995       1994(B)    1993(B)       1995        1994       1993
                        ---------   -------     -------     ---------    ------     ------
<S>                       <C>       <C>         <C>           <C>          <C>        <C>         
Sales..................   $22.7     $ 132.3     $202.0        $93.1      $381.2     $405.9
                          -----     -------     ------        -----      ------     ------
Production costs.......     7.4        35.0       52.1         39.7       151.5      157.5
Exploration costs......     3.7        12.2       17.6          2.7        13.8       16.5
Depreciation, depletion
  and amortization.....     7.0        45.3       77.9         16.9        75.6       63.0
(Gain) loss on sale of
  assets...............     (.1)     (201.8)       3.0
Other..................     2.9(a)     10.8(a)    19.0 (a)     (3.0)        1.8        (.2)
                          -----     -------     ------        -----      ------     ------
                           20.9       (98.5)     169.6         56.3       242.7      236.8
                          -----     -------     ------        -----      ------     ------
Income (loss) before
  tax provision........     1.8       230.8       32.4         36.8       138.5      169.1
Provision (benefit) for
  income taxes.........                 4.6         .6         18.7        74.4       86.7
                          -----     -------     ------        -----      ------     ------
Results of
  operations...........   $ 1.8      $226.2     $ 31.8        $18.1      $ 64.1     $ 82.4
                          =====      ======     ======        =====      ======     ======
</TABLE>
 
<TABLE>
<CAPTION>
                                SOUTH AMERICA                       OTHER FOREIGN                         WORLDWIDE
                       -----------------------------     -------------------------------     -------------------------------
                       MARCH 31,                          MARCH 31,                           MARCH 31,
                         1995        1994     1993         1995        1994       1993         1995       1994(B)    1993(B)
                       --------    -------   -------     ---------    -------    -------     ---------    -------    -------
<S>                    <C>          <C>      <C>         <C>          <C>        <C>         <C>          <C>        <C>
Sales..................   $ 7.8     $24.0                                                    $   123.6    $ 537.5    $ 607.9
                       ---------    -----    -------     --------     -------    -------     ---------    -------    -------
Production costs.......     6.8      17.8        1.7                                              53.9      204.3      211.3
Exploration costs......      .4       2.4       10.5     $    2.2     $   7.2    $  15.2           9.0       35.6       59.8
Depreciation, depletion
  and amortization.....     3.9       7.5         .6           .4         2.7        1.7          28.2      131.1      143.2
(Gain) loss on sale of
  assets...............                .2                    (1.1)                                (1.2)    (201.6)       3.0
Other..................      .4      (1.4)        .2                      (.3)       (.1)           .3       10.9       18.9
                       --------    ------    -------     --------     -------    -------     ---------    -------    -------
                           11.5      26.5       13.0          1.5         9.6       16.8          90.2      180.3      436.2
                       --------    ------    -------     --------     -------    -------     ---------    -------    -------
Income (loss) before
  tax provision........    (3.7)     (2.5)     (13.0)        (1.5)       (9.6)     (16.8)         33.4      357.2      171.7
Provision (benefit) for
  income taxes.........      .5       5.2        (.3)                     (.2)       (.3)         19.2       84.0       86.7
                       --------    ------    -------     --------     -------    -------     ---------    -------    -------
Results of
  operations...........   $(4.2)   $ (7.7)   $(12.7)     $   (1.5)    $  (9.4)   $(16.5)     $    14.2    $ 273.2    $  85.0
                       ========    ======    =======     ========     =======    =======     =========    =======    =======
</TABLE>
 
---------------
 
(a) Includes United States gathering and processing costs related to sales. Such
     costs were $3.1 million, $11.8 million and $15.1 million for March 31,
     1995, December 31, 1994 and 1993, respectively.
 
(b) Production costs, Exploration costs and Other have been restated for the
     years ended December 31, 1994 and 1993 to be consistent with current period
     presentation.
 
                                      F-30
<PAGE>   77
 
  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,                          MARCH 31,
                          1995        1994      1993         1995        1994       1993
                        ---------    ------    -------     ---------    -------    -------
<S>                     <C>          <C>       <C>         <C>          <C>        <C>
Proved properties.......    605.4     584.0    1,214.6      1,588.1     1,572.9    1,514.3
Unproved properties.....     10.7       7.8       51.2           .7          .7         .8
                          ------     ------    --------    --------     --------   --------
                           616.1      591.8    1,265.8      1,588.8     1,573.6    1,515.1
                          ------     ------    --------    --------     --------   --------
Less-Accumulated
  depreciation,
  depletion and
  amortization..........    422.6     416.8      931.9      1,060.6     1,043.7      968.1
                          ------     ------    --------    --------     --------   --------
                         $ 193.5     $175.0    $ 333.9     $  528.2     $ 529.9    $ 547.0
                          ======     ======    ========    ========     ========   ========
</TABLE>
 
<TABLE>
<CAPTION>
                                SOUTH AMERICA                       OTHER FOREIGN                         WORLDWIDE
                        ------------------------------     -------------------------------     -------------------------------
                        MARCH 31,                          MARCH 31,                           MARCH 31,
                          1995        1994      1993         1995        1994       1993         1995        1994       1993
                        ---------    ------    -------     ---------    -------    -------     ---------    -------    -------
<S>                     <C>          <C>       <C>         <C>          <C>        <C>         <C>          <C>        <C>
Proved properties.......  $ 252.1    $240.8    $ 173.2                                         $2,445.6     $2,397.7   $2,902.1
Unproved properties.....     15.2      15.2       14.9     $    5.0     $   5.4    $   5.4         31.6        29.1       72.3
                          ------     ------    --------    --------     --------   --------    --------     --------   --------
                           267.3      256.0      188.1          5.0         5.4        5.4      2,477.2     2,426.8    2,974.4
                          ------     ------    --------    --------     --------   --------    --------     --------   --------
Less-Accumulated
  depreciation,
  depletion and
  amortization..........     12.3       8.5        1.0          4.2         4.0        2.6      1,499.7     1,473.0    1,903.6
                          ------     ------    --------    --------     --------   --------    --------     --------   --------
                         $ 255.0     $247.5    $ 187.1     $     .8     $   1.4    $   2.8     $  977.5     $ 953.8    $1,070.8
                          ======     ======    ========    ========     ========   ========    ========     ========   ========
</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,                           MARCH 31,
                         1995       1994(A)    1993(A)       1995        1994       1993
                       ---------    -------    -------     ---------    -------    -------
<S>                    <C>          <C>        <C>         <C>          <C>        <C>
Property acquisition
  costs................   $13.6      $ 2.4     $ 13.5
Exploration costs......     7.0       12.8       25.6        $ 7.0       $13.8     $ 16.4
Development costs......     8.2       20.9       35.6         10.9        58.7      120.8
                         -----       -----     ------        -----       -----     ------
                         $28.8       $36.1     $ 74.7        $17.9       $72.5     $137.2
                         =====       =====     ======        =====       =====     ======
</TABLE>
 
<TABLE>
<CAPTION>
                                SOUTH AMERICA                       OTHER FOREIGN                         WORLDWIDE
                       -------------------------------     -------------------------------     -------------------------------
                       MARCH 31,                           MARCH 31,                           MARCH 31,
                         1995        1994       1993         1995        1994       1993         1995       1994(A)    1993(A)
                       ---------    -------    -------     ---------    -------    -------     ---------    -------    -------
<S>                    <C>          <C>        <C>         <C>          <C>        <C>         <C>          <C>        <C>
Property acquisition
  costs................                                                            $   .5        $13.6      $  2.4     $ 14.0
Exploration costs......   $  .4      $ 3.4     $ 25.3        $ 2.2       $ 7.4       15.5         16.6        37.4       82.8
Development costs......    11.3       77.7      123.6                                             30.4       157.3      280.0
                         -----       -----     ------        -----       -----     ------        -----      ------     ------
                         $11.7       $81.1     $148.9        $ 2.2       $ 7.4     $ 16.0        $60.6      $197.1     $376.8
                         =====       =====     ======        =====       =====     ======        =====      ======     ======
</TABLE>
 
---------------
 
(a) Exploration costs have been restated for the years ended December 31, 1994
     and 1993 to be consistent with current period presentation.
 
                                      F-31
<PAGE>   78
 
  Oil and Gas Reserves
 
     The following table represents the Company's net interest in estimated
quantities of developed and undeveloped reserves of crude oil, condensate,
natural gas liquids and natural gas and changes in such quantities at
quarter-end March 31, 1995 and at year-end 1994 and 1993. Net proved reserves
are the estimated quantities of crude oil and natural gas which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Proved developed reserves are proved reserve volumes that can be
expected to be recovered through existing wells with existing equipment and
operating methods. Proved undeveloped reserves are proved reserve volumes that
are expected to be recovered from new wells on undrilled acreage or from
existing wells where a significant expenditure is required for recompletion.
 
     Estimates of reserves were prepared by the Company using standard
geological and engineering methods generally accepted by the petroleum industry
and in accordance with the rules and regulations of the Securities and Exchange
Commission ("SEC"). The choice of method or combination of methods employed in
the analysis of each reservoir was determined by experience in the area, stage
of development, quality and completeness of basic data, and production history.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the producer. Reserve
engineering is a subjective process of estimating underground accumulations of
crude oil and natural gas that cannot be measured in an exact manner, and the
accuracy of any reserve estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment. As a result,
estimates of different engineers often vary. In addition, results of drilling,
testing and production subsequent to the date of an estimate may justify
revision of such estimate. Accordingly, reserve estimates are often different
from the quantities of crude oil and natural gas that are ultimately recovered.
The meaningfulness of such estimates is highly dependent upon the accuracy of
the assumption upon which they were based. The reserve estimates were subjected
to economic tests to determine economic limits. The estimates may change as a
result of numerous factors including, but not limited to, additional development
activity, evolving production history, and continued reassessment of the
viability of production under varying economic conditions.
<TABLE>
<CAPTION>
                                                       MARCH 31, 1995(D)                             1994                     1993
                                              ------------------------------------   -------------------------------------   ------
                                              UNITED                SOUTH            UNITED                SOUTH             UNITED
                  CRUDE OIL                   STATES   INDONESIA   AMERICA   TOTAL   STATES   INDONESIA   AMERICA    TOTAL   STATES
----------------------------------------------------   ---------   -------   -----   ------   ---------   -------    -----   ------
                                                                              (MILLIONS OF BARRELS)
<S>                                           <C>      <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    12.2
   Revisions of previous estimates............                                          .2       (3.2)(a)    5.1       2.1      .4
   Purchase of reserves in place..............    .3                            .3                                              .2
   Extensions, discoveries and other
     additions................................                                          .1        3.5(a)               3.6     1.3
   Production.................................   (.1)     (4.7)       (.8)    (5.6)    (.9)     (21.6)      (1.8)(c) (24.3)   (1.8)
   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    12.3
                                                 ---     -----     -------   -----   -----      ------      ----     -----   -----
Net Proved Developed Reserves
   Beginning of period........................   2.9     141.5       14.8    159.2    11.0      161.1       14.1     186.2    11.3
   End of period..............................   2.8     136.8       14.0    153.6     2.9      141.5       14.8     159.2    11.0
 
<CAPTION>
 
                                                             SOUTH
                  CRUDE OIL                     INDONESIA   AMERICA   TOTAL
----------------------------------------------  ---------   -------   -----
 
<S>                                               <C>         <C>     <C>
Net Proved Developed and Undeveloped Reserves
Beginning of period...........................    155.2       53.1    220.5
   Revisions of previous estimates............     39.6(a)     1.2     41.2
   Purchase of reserves in place..............                           .2
   Extensions, discoveries and other
     additions................................      8.1(a)    17.3     26.7
   Production.................................    (22.8)              (24.6)
   Sales of reserves in place.................
 
                                                  -----       ----    -----
End of period.................................    180.1       71.6    264.0
 
                                                  -----       ----    -----
Net Proved Developed Reserves
   Beginning of period........................    128.9               140.2
   End of period..............................    161.1       14.1    186.2
</TABLE>
 
                                      F-32
<PAGE>   79
 
<TABLE>
<CAPTION>
                                                MARCH 31, 1995(D)                   1994                          1993
                                            --------------------------   ---------------------------   --------------------------
                                            UNITED                       UNITED                        UNITED
               NATURAL GAS(B)               STATES   INDONESIA   TOTAL   STATES   INDONESIA    TOTAL   STATES   INDONESIA   TOTAL
--------------------------------------------------   ---------   -----   ------   ---------    -----   ------   ---------   -----
                                                                          (BILLIONS OF CUBIC FEET)
<S>                                         <C>      <C>         <C>     <C>      <C>          <C>     <C>      <C>         <C>
Net Proved Developed and Undeveloped
  Reserves
Beginning of period.........................   492      304       796      679        262       941      584        245      829
    Revisions of previous estimates.........                                21          1        22        3        (23)     (20 )
    Purchase of reserves in place...........    24                 24                                     17                  17
    Extensions, discoveries and other
      additions.............................                                13         58        71      152         45      197
    Production..............................   (11)      (4)      (15)     (57)       (17)      (74)     (76)        (5)     (81)
    Sales of reserves in place..............                              (164)                (164)      (1)                 (1)
                                             ----       ---      ----     ----       ----      ----     ----       ----     ----
End of period...............................   505      300       805      492        304       796      679        262      941
                                             ----       ---      ----     ----       ----      ----     ----       ----     ----
Net Proved Developed Reserves
    Beginning of period.....................   384      107       491      507         85       592      515         22      537
    End of period...........................   373      103       476      384        107       491      507         85      592
</TABLE>
 
<TABLE>
<CAPTION>
                                                MARCH 31, 1995(D)                   1994                          1993
                                            --------------------------   ---------------------------   --------------------------
                                            UNITED                       UNITED                        UNITED
            NATURAL GAS LIQUIDS             STATES   INDONESIA   TOTAL   STATES   INDONESIA    TOTAL   STATES   INDONESIA   TOTAL
--------------------------------------------------   ---------   -----   ------   ---------    -----   ------   ---------   -----
                                                                            (MILLIONS OF BARRELS)
<S>                                         <C>      <C>         <C>     <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     30.8        9.3     40.1
    Revisions of previous estimates.........                               2.0        (.7)      1.3      1.9        (.3)     1.6
    Purchase of reserves in place...........    .4                 .4
    Extensions, discoveries and other
      additions.............................                                .4         .7       1.1      7.2        1.7      8.9
    Production..............................   (.8)     (.1)      (.9)    (3.0)       (.8)     (3.8)    (2.8)       (.5)    (3.3)
                                             ----       ---      ----     ----       ----      ----     ----       ----     ----
End of period...............................  36.1      9.3      45.4     36.5        9.4      45.9     37.1       10.2     47.3
                                             ----       ---      ----     ----       ----      ----     ----       ----     ----
Net Proved Developed Reserves
    Beginning of period.....................  29.7      3.2      32.9     29.5        3.3      32.8     27.0        5.1     32.1
    End of period...........................  28.9      3.1      32.0     29.7        3.2      32.9     29.5        3.3     32.8
</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. Decreasing prices resulted in an increase of 24.3 million barrels
     in 1993.
 
(b) Natural gas is reported on the basis of actual or calculated volumes which
     remain after removal, by lease or field separation facilities, of
     liquefiable hydrocarbons and of non-hydrocarbons where they occur in
     sufficient quantities to render the gas unmarketable. Natural gas reserve
     volumes include liquefiable hydrocarbons approximating 11% of total gas
     reserves in the United States and 5% in Indonesia which are recoverable at
     natural gas processing plants downstream from the lease or field separation
     facilities. Such recoverable liquids also have been included in natural gas
     liquids reserve volumes.
 
(c) Reserves in Venezuela attributable to an operating service agreement under
     which all hydrocarbons are owned by the Venezuelan government have not been
     included. Production reported in Oil and Gas reserves does not include
     Venezuela production but it is included in net oil sales reported in
     Exploration and Production Statistics. The SFAS 69 Results of Operations,
     Capitalized Costs and Costs Incurred disclosures include costs related to
     Venezuela.
 
(d) Reserves are estimated at year end only. Reserves at March 31, 1995 are
     December 31, 1994 reserves adjusted only for the production for the first
     quarter of 1995 and purchase of properties in the United States.
 
  Future Net Cash Flows
 
     The standardized measure of discounted future net cash flows relating to
the Company's proved oil and gas reserves is calculated and presented in
accordance with Statement of Financial Accounting Standards
 
                                      F-33
<PAGE>   80
 
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>
                                            UNITED STATES            INDONESIA           SOUTH AMERICA           WORLDWIDE
                                          ------------------   ---------------------   -----------------   ---------------------
                                           1994       1993       1994        1993       1994      1993       1994        1993
                                          -------   --------   ---------   ---------   -------   -------   ---------   ---------
<S>                                       <C>       <C>        <C>         <C>         <C>       <C>       <C>         <C>
Future cash flows.......................  $ 967.3   $1,781.2   $ 3,389.0   $ 3,269.8   $ 831.9   $ 700.9   $ 5,188.2   $ 5,751.9
Future production and development
  costs.................................   (324.7)    (521.6)   (2,246.8)   (2,258.1)   (371.8)   (500.9)   (2,943.3)   (3,280.6)
Future income tax expenses..............    (92.8)    (152.4)     (503.1)     (438.5)    (53.6)    (81.9)     (649.5)     (672.8)
                                          -------   --------   ---------   ---------   -------   -------   ---------   ---------
Future net cash flows...................    549.8    1,107.2       639.1       573.2     406.5     118.1     1,595.4     1,798.5
Annual discount at 10% rate.............   (241.1)    (414.0)     (261.7)     (238.2)   (162.8)    (85.0)     (665.6)     (737.2)
                                          -------   --------   ---------   ---------   -------   -------   ---------   ---------
Standardized measure of discounted
  future net cash flows.................  $ 308.7   $  693.2   $   377.4   $   335.0   $ 243.7   $  33.1   $   929.8   $ 1,061.3
                                          =======   ========   =========   =========   =======   =======   =========   =========
</TABLE>
 
     The following are the principal sources for change in the standardized
measure:
 
<TABLE>
<CAPTION>
                                                                            1994         1993
                                                                          --------     --------
<S>                                                                       <C>          <C>
Beginning of year.......................................................  $1,061.3     $1,169.6
     Sales and transfers of oil and gas produced, net of production
      costs.............................................................    (333.2)      (396.6)
     Net changes in prices and production costs.........................     103.4       (443.6)
     Extensions, discoveries and improved recovery, less related
      costs.............................................................      68.0        229.9
     Development costs incurred during the year that reduced future
      development costs.................................................     123.2        217.4
     Revisions of previous quantity estimates...........................      56.6         13.6
     Purchase of reserves in place......................................        .4         18.8
     Sale of reserves in place..........................................    (275.7)         (.9)
     Net change in income taxes.........................................     (22.6)       170.5
     Accretion of discount..............................................     132.4        172.3
     Other..............................................................      16.0        (89.7)
                                                                          --------     --------
End of year.............................................................  $  929.8     $1,061.3
                                                                          ========     ========
</TABLE>
 
                                      F-34
<PAGE>   81
 
                            MAXUS ENERGY CORPORATION
 
                      CONSOLIDATED STATEMENT OF OPERATIONS
 
<TABLE>
<CAPTION>
                                                                              NINE MONTHS ENDED
                                                                              DECEMBER 31, 1995
                                                                              -----------------
                                                                              (IN MILLIONS, EXCEPT
                                                                                 PER SHARE)
<S>                                                                           <C>
Revenues
     Sales and operating revenues.............................................      $ 463.8
     Other revenues, net......................................................          7.1
                                                                                    -------
                                                                                      470.9
Costs and Expenses
     Operating expenses.......................................................        173.5
     Gas purchase costs.......................................................         41.4
     Exploration, including exploratory dry holes.............................         51.2
     Depreciation, depletion and amortization.................................        142.1
     General and administrative expenses......................................         12.7
     Taxes other than income taxes............................................          9.7
     Interest and debt expenses...............................................        104.9
                                                                                    -------
                                                                                      535.5
                                                                                    -------
Loss Before Income Taxes......................................................        (64.6)
     Income Taxes.............................................................          9.1
                                                                                    -------
Net Loss......................................................................        (73.7)
     Dividend requirement on Preferred Stock..................................        (28.8)
                                                                                    -------
Net Loss Applicable to Common Shares..........................................      $(102.5)
                                                                                    =======
Net Loss Per Common Share.....................................................      $  (.76)
                                                                                    =======
Average Common Shares Outstanding.............................................        135.6
</TABLE>
 
                See Notes to Consolidated Financial Statements.
 
                                      F-35
<PAGE>   82
 
                            MAXUS ENERGY CORPORATION
 
                           CONSOLIDATED BALANCE SHEET
 
<TABLE>
<CAPTION>
                                                                                                   
                                                                                                   
                                                                      DECEMBER 31,      APRIL 1,   
                               ASSETS                                     1995            1995     
                                                                      ------------     ----------- 
                                                                              (UNAUDITED)
                                                                      (IN MILLIONS, EXCEPT SHARES)
<S>                                                                   <C>              <C>
Current Assets
     Cash and cash equivalents.......................................   $   38.3        $    92.1
     Short-term investments..........................................                        65.0
     Receivables, less allowance for doubtful accounts...............      141.8            127.8
     Taxes receivable................................................                        13.7
     Inventories.....................................................       40.8             28.6
     Restricted cash.................................................       19.0             48.5
     Prepaids and other current assets...............................       26.5             26.5
                                                                        --------         --------
            Total Current Assets.....................................      266.4            402.2
Properties and Equipment, less accumulated depreciation, depletion
  and amortization...................................................    2,363.6          2,404.7
Investments and Long-Term Receivables................................        7.1             36.7
Restricted Cash......................................................       61.4             77.1
Deferred Charges.....................................................       18.3             15.5
                                                                        --------         --------
                                                                        $2,716.8        $ 2,936.2
                                                                        ========         ========
                LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
     Long-term debt..................................................   $   34.3        $    12.7
     Accounts payable................................................       59.0             49.8
     Taxes payable...................................................       39.7
     Accrued liabilities.............................................      173.4            263.2
                                                                        --------         --------
            Total Current Liabilities................................      306.4            325.7
Long-Term Debt.......................................................    1,261.2          1,282.7
Deferred Income Taxes................................................      551.2            593.5
Other Liabilities and Deferred Credits...............................      233.0            260.9
$9.75 Redeemable Preferred Stock, $1.00 par value Authorized and
  issued shares--1,250,000...........................................      125.0            125.0
Stockholders' Equity
     $2.50 Preferred Stock, $1.00 par value
       Authorized shares--5,000,000
       Issued shares--3,500,000......................................       66.5             73.1
     $4.00 Preferred Stock, $1.00 par value
       Authorized shares--5,915,017
       Issued shares--4,356,958......................................       11.7             24.8
     Common Stock, $1.00 par value
       Authorized shares--300,000,000
       Issued shares--135,609,772 and 135,897,899....................      135.6            135.9
     Paid-in capital.................................................      105.8            118.2
     Accumulated deficit.............................................      (73.7)
     Minimum pension liability.......................................       (5.9)
     Common Treasury Stock, at cost--0 and 310,535...................                        (3.6)
            Total Stockholders' Equity...............................      240.0            348.4
                                                                        --------         --------
                                                                        $2,716.8        $ 2,936.2
                                                                        ========         ========
</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.
  The Consolidated Balance Sheet at April 1, 1995 which represents the opening
              post-merger consolidated balance sheet is unaudited.
 
                                      F-36
<PAGE>   83
 
                            MAXUS ENERGY CORPORATION
 
                      CONSOLIDATED STATEMENT OF CASH FLOWS
 
<TABLE>
<CAPTION>
                                                                                  NINE MONTHS
                                                                                     ENDED
                                                                                  DECEMBER 31,
                                                                                      1995
                                                                                  ------------
                                                                                      (IN
                                                                                  MILLIONS)
<S>                                                                               <C>
Cash Flows From Operating Activities:
     Net loss.....................................................................   $  (73.7)
     Adjustments to reconcile net loss to net cash provided by operating
      activities:
          Depreciation, depletion and amortization................................      142.1
          Dry hole costs..........................................................       18.8
          Deferred income taxes...................................................      (49.2)
          Net gain on sale of assets and investments..............................       (5.9)
          Postretirement benefits.................................................        3.1
          Accretion of discount on long-term debt.................................        7.3
          Other...................................................................        1.4
          Changes in components of working capital:
               Receivables........................................................       (5.4)
               Inventories, prepaids and other current assets.....................      (12.8)
               Accounts payable...................................................        9.2
               Accrued liabilities................................................      (31.5)
               Taxes payable/receivable...........................................       53.4
                                                                                     --------
                    Net Cash Provided by Operating Activities.....................       56.8
                                                                                     --------
Cash Flows From Investing Activities:
     Expenditures for properties and equipment--including dry hole costs..........     (137.4)
     Proceeds from sales of assets................................................       27.4
     Proceeds from sale/maturity of short- and long-term investments..............       96.3
     Restricted cash..............................................................       45.3
     Other........................................................................      (34.3)
                                                                                     --------
                    Net Cash Used in Investing Activities.........................       (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.................................................      (21.8)
     Net proceeds from issuance of long-term debt.................................      839.8
     Repayment of long-term debt..................................................     (425.1)
     Acquisition of common stock, including payment of merger costs...............     (746.6)
     Capital contribution from parent.............................................      250.5
     Dividends paid on Preferred Stock............................................      (28.8)
                                                                                     --------
                    Net Cash Used in Financing Activities.........................     (107.9)
                                                                                     --------
Net Decrease in Cash and Cash Equivalents.........................................      (53.8)
Cash and Cash Equivalents at Beginning of Period..................................       92.1
                                                                                     --------
Cash and Cash Equivalents at End of Period........................................   $   38.3
                                                                                     ========
</TABLE>
 
                See Notes to Consolidated Financial Statements.
 
                                      F-37
<PAGE>   84
 
                            MAXUS ENERGY CORPORATION
 
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
PRESENTATION
 
     On June 8, 1995, a special meeting of the stockholders of Maxus Energy
Corporation (together with its foreign and domestic subsidiaries, the "Company"
or "Maxus") was held to approve the Agreement of Merger ("Merger Agreement")
dated February 28, 1995, between the Company, YPF Acquisition Corp. (the
"Purchaser") and YPF Sociedad Anonima ("YPF"). The holders of the Company's
common stock, $1.00 par value per share, and $4.00 Cumulative Convertible
Preferred Stock approved the Merger Agreement, and the Purchaser was merged into
the Company (the "Merger") on June 8, 1995.
 
     Effective April 1, 1995, the Company used the purchase method of accounting
to record the acquisition of the Company by YPF. In a purchase method
combination, the purchase price is allocated to acquired assets and assumed
liabilities based on their fair values at the date of acquisition. As a result,
the Company's assets and liabilities were revalued to reflect the approximate
$762 million cash purchase price paid by YPF to acquire the Company. The
Company's pre-Merger Consolidated Balance Sheet as of March 31, 1995, together
with the purchase method accounting adjustments, became the Company's opening
unaudited post-Merger Consolidated Balance Sheet on April 1, 1995, which is
included in the accompanying balance sheet.
 
     The following post-Merger data is for the nine months ended December 31,
1995 and dollar amounts in tables are in millions, except per share amounts.
Post-Merger financial information is not comparable to prior periods due to the
application of purchase accounting effective April 1, 1995.
 
NOTE ONE--SIGNIFICANT ACCOUNTING POLICIES
 
     The Consolidated Financial Statements have been prepared in conformity with
generally accepted accounting principles, the most significant of which are
described below.
 
  Consolidation Accounting
 
     The Consolidated Financial Statements include the accounts of Maxus Energy
Corporation and all domestic and foreign subsidiaries. All significant
intercompany accounts and transactions have been eliminated.
 
  Statement of Cash Flows
 
     Investments with original maturities of three months or less at the time of
original purchase are considered cash equivalents for purposes of the
accompanying Consolidated Statement of Cash Flows. Short-term investments
include investments with maturities over three months but less than one year.
 
     Net cash provided by operating activities reflects cash receipts for
interest income and cash payments for interest expense and income taxes as
follows:
 
<TABLE>
<CAPTION>
                                                                          NINE MONTHS
                                                                             ENDED
                                                                          DECEMBER 31,
                                                                              1995
                                                                          ------------
        <S>                                                               <C>
        Interest receipts...............................................     $ 11.8
        Interest payments...............................................      107.9
        Income tax payments.............................................       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.
 
                                      F-38
<PAGE>   85
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  Properties and Equipment
 
     Properties and equipment are carried at cost. Major additions are
capitalized; expenditures for repairs and maintenance are charged against
earnings.
 
     The Company uses the successful efforts method to account for costs
incurred in the acquisition, exploration, development and production of oil and
gas reserves. Under this method, all geological and geophysical costs are
expensed; all development costs, whether or not successful, are capitalized as
costs of proved properties; exploratory drilling costs are initially
capitalized, but if the effort is determined to be unsuccessful, the costs are
then charged against earnings; depletion is computed based on an aggregation of
properties with common geologic structural features or stratigraphic conditions,
such as reservoirs or fields.
 
     For investment in unproved properties in the United States, a valuation
allowance (included as an element of depletion) is provided by a charge against
earnings to reflect the impairment of unproven acreage. Investment in
international non-producing leasehold costs are reviewed periodically by
management to insure the carrying value is recoverable based upon the geological
and engineering estimates of total possible and probable reserves expected to be
added over the remaining life of each concession. Based upon increases to proved
reserves determined by reserve reports, a portion of the investment in
international non-producing leasehold costs will be periodically transferred to
investment in proved properties.
 
     Depreciation and depletion related to the costs of all development
drilling, successful exploratory drilling and related production equipment is
calculated using the unit of production ("UOP") method based upon estimated
proved developed reserves. Leasehold costs are amortized using the UOP method
based on estimated total proved reserves. Other properties and equipment are
depreciated generally on the straight-line method over their estimated useful
lives. Estimated future dismantlement, restoration and abandonment costs for
major facilities, net of salvage value, are taken into account in determining
depreciation, depletion and amortization.
 
     The Company capitalizes the interest cost associated with major property
additions and mineral development projects while in progress, such amounts being
amortized over the useful lives, and applying the same depreciation method, as
that used for the related assets.
 
     When complete units of depreciable property are retired or sold, the asset
cost and related accumulated depreciation are eliminated with any gain or loss
reflected in other revenues, net. When less than complete units of depreciable
property are disposed of or retired, the difference between asset cost and
salvage or sales value is charged or credited to accumulated depreciation and
depletion.
 
  Deferred Charges
 
     Deferred charges are primarily comprised of debt issuance costs and are
amortized over the terms of the related debt agreements.
 
  Revenue Recognition
 
     Oil and gas sales are recorded on the entitlements method. Differences
between the Company's actual production and entitlements result in a receivable
when underproduction occurs and a payable when overproduction occurs. These
underproduced or overproduced volumes are valued based on the weighted average
sales price for each respective property. The Company's gross underproduced and
overproduced volumes at December 31, 1995, are not material.
 
  Pensions
 
     The Company has a number of trusteed noncontributory pension plans covering
substantially all full-time employees. The Company's funding policy is to
contribute amounts to the plans sufficient to meet the
 
                                      F-39
<PAGE>   86
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
minimum funding requirements under governmental regulations, plus such
additional amounts as management may determine to be appropriate. The benefits
related to the plans are based on years of service and compensation earned
during years of employment. The Company also has a noncontributory supplemental
retirement plan for executive officers.
 
  Other Postretirement and Postemployment Benefits
 
     The Company provides certain health care and life insurance benefits for
retired employees and certain insurance and other postemployment benefits for
individuals whose employment is terminated by the Company prior to their normal
retirement. The Company accrues the estimated cost of retiree benefit payments,
other than pensions, during employees' active service period. Employees become
eligible for these benefits if they meet minimum age and service requirements.
The Company accounts for benefits provided after employment but before
retirement by accruing the estimated cost of postemployment benefits when the
minimum service period is met, payment of the benefit is probable and the amount
of the benefit can be reasonably estimated. The Company's policy is to fund
other postretirement and postemployment benefits as claims are incurred.
 
  Environmental Expenditures
 
     Environmental liabilities are recorded when environmental assessments
and/or remediation are probable and material and such costs to the Company can
be reasonably estimated. The Company's estimate of environmental assessment
and/or remediation costs to be incurred are based on either 1) detailed
feasibility studies of remediation approach and cost for individual sites or 2)
the Company's estimate of costs to be incurred based on historical experience
and publicly available information, based on the stage of assessment and/or
remediation of each site. As additional information becomes available regarding
each site or as environmental remediation standards change, the Company revises
its estimate of costs to be incurred in environmental assessment and/or
remediation.
 
  Income Taxes
 
     The Company reports income taxes in accordance with Statement of Financial
Accounting Standards No. 109 ("SFAS 109"), Accounting for Income Taxes. SFAS 109
requires the use of an asset and liability approach to measure deferred tax
assets and liabilities resulting from all expected future tax consequences of
events that have been recognized in the Company's financial statements or tax
returns. Additionally, SFAS 109 requires that annual taxes are to be allocated
to interim periods on the basis of the requirements of Accounting Principles
Board Opinion No. 28 ("APB 28"), Interim Financial Reporting. The reporting
requirements of APB 28 are based on the view that each interim period is an
integral part of the annual period.
 
     Because the tax year of the Company did not close in any relevant
jurisdiction on March 31, 1995, taxes were not measured on deferred tax
liabilities and assets at that time. Thus, taxes were allocated to the nine
month period ended December 31, 1995 based on an allocation of taxes for the
annual period ended December 31, 1995, in accordance with APB 28 and SFAS 109.
Deferred tax assets and liabilities were measured at December 31, 1995.
 
  Earnings per Share
 
     Primary earnings per share are based on the weighted average number of
shares of common stock and common stock equivalents outstanding, unless the
inclusion of common stock equivalents has an antidilutive effect on earnings per
share. Fully diluted earnings per share are not presented due to the
antidilutive effect of including all potentially dilutive common stock
equivalents.
 
                                      F-40
<PAGE>   87
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  Financial Instruments with Off-Balance-Sheet Risk and Concentrations of Credit
Risk
 
     The Company's financial instruments that are exposed to concentrations of
credit risk consist primarily of cash equivalents, short-term investments and
trade receivables.
 
     The Company's cash equivalents, short-term investments and restricted cash
represent high-quality securities placed with various high investment grade
institutions. This investment practice limits the Company's exposure to
concentrations of credit risk.
 
     The Company's trade receivables are dispersed among a broad domestic and
international customer base; therefore, concentrations of credit risk are
limited. The Company carefully assesses the financial strength of its customers.
Letters of credit are the primary security obtained to support lines of credit.
 
     The Company has minimal exposure to credit losses in the event of
nonperformance by the counterparties to its interest rate swap agreement,
natural gas price swap agreements and nonderivative financial assets. The
Company does not obtain collateral or other security to support financial
instruments subject to credit risk but restricts such arrangements to
investment-grade counterparties.
 
  Investments in Marketable Securities
 
     Investments in debt and equity securities are reported at fair value except
for those investments in debt securities which management has the intent and the
ability to hold to maturity. Investments in debt securities which are
held-for-sale are classified based on the stated maturity and management's
intent to sell the securities. Unrealized gains and losses on investments in
marketable securities, except for debt securities classified as
"held-to-maturity", are reported as a separate component of stockholders'
equity.
 
  Derivatives
 
     The Company periodically hedges the effects of fluctuations in the price of
crude oil and natural gas through price swap agreements and futures contracts.
The Company historically has hedged no more than 50% of its U. S. gas production
although the Company anticipates it may hedge up to 90% of its U. S. gas
production during 1996. Gains and losses on these hedges are deferred until the
related sales are recognized and are recorded as a component of sales and
operating revenues. The Company periodically enters into interest rate swap
agreements to hedge interest on long-term debt. The gain or loss on interest
rate swaps is recognized monthly as a decrease or increase to interest expense.
 
  Take-or-Pay Obligations
 
     The Company records payments received for take-or-pay obligations for
unpurchased contract volumes as deferred revenue, which is included in Other
Liabilities in the consolidated balance sheet. The deferred revenue is
recognized in the income statement as quantities are delivered which fulfill the
take-or-pay obligation. At December 31, 1995, the Company had $12.4 million in
deferred revenue as a result of a take-or-pay payment received related to its
Indonesian operations.
 
NOTE TWO--MERGER
 
     On June 8, 1995, a special meeting of the stockholders of the Company was
held to approve the Agreement of Merger ("Merger Agreement") dated February 28,
1995, between the Company, YPF Acquisition Corp. (the "Purchaser") and YPF
Sociedad Anonima ("YPF"). The holders of the Company's common stock, $1.00 par
value per share (the "Shares"), and $4.00 Cumulative Convertible Preferred Stock
(the "$4.00 Preferred Stock") and together with the Shares, the ("Voting
Shares") approved the Merger Agreement, and the Purchaser was merged into the
Company (the "Merger") on June 8, 1995 (the "Merger Date").
 
                                      F-41
<PAGE>   88
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     The Merger was the consummation of all transactions contemplated by the
Merger Agreement. Pursuant to the Merger Agreement, a tender offer (the "Offer")
was commenced on March 6, 1995 by the Purchaser for all the outstanding Shares
at $5.50 per Share. Pursuant to the Offer, in April 1995 the Purchaser acquired
120,000,613 Shares representing approximately 88.5% of the then-outstanding
Shares of the Company. As a result of the Merger, each outstanding Share (other
than Shares held by the Purchaser, YPF or any of their subsidiaries or in the
treasury of the Company (all of which were cancelled in the second quarter of
1995) and Shares of holders who perfected their appraisal rights under Section
262 of the Delaware General Corporation Law) was converted into the right to
receive $5.50 in cash, and YPF became the sole holder of all outstanding Shares.
The Company's preferred stock, consisting of the $4.00 Preferred Stock, $2.50
Cumulative Preferred Stock ("$2.50 Preferred Stock") and $9.75 Cumulative
Convertible Preferred Stock (the "$9.75 Preferred Stock") remain outstanding.
YPF currently owns approximately 96.9% of the outstanding Voting Shares.
 
     The total amount of funds required by the Purchaser to acquire the entire
common equity interest in the Company, including the purchase of Shares pursuant
to the Offer and the payment for Shares converted into the right to receive cash
pursuant to the Merger, was approximately $762 million. On April 5, 1995 the
Purchaser entered into a credit agreement (the "Credit Agreement") with lenders
for which The Chase Manhattan Bank (National Association) ("Chase") acted as
agent, pursuant to which the lenders extended to the Purchaser a credit facility
for up to $550 million (the "Purchaser Facility"). On April 5, 1995, the
Purchaser borrowed $442 million under the Purchaser Facility and received a
capital contribution of $250 million from YPF. The Purchaser used borrowings
under the Purchaser Facility and the funds contributed to it by YPF to purchase
120,000,613 Shares pursuant to the Offer. Subsequent to the Merger, these Shares
and all other outstanding Shares vested in YPF.
 
     During the second quarter of 1995, the Company used the purchase method to
record the acquisition of the Company by YPF. In a purchase method combination,
the purchase price is allocated to the acquired assets and assumed liabilities
based on their fair values at the date of acquisition. As a result, the assets
and liabilities of the Company were revalued to reflect the approximate $762
million cash purchase price paid by YPF plus all liabilities assumed to acquire
the Company. The Company's oil and gas properties were assigned carrying amounts
based on their relative fair market values. In connection with the purchase
price allocation, the Company adopted Statement of Financial Accounting
Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of," which requires a review of
long-lived assets for impairment whenever events or changes in circumstance
indicate that the carrying amount of the asset may not be recoverable. Under
SFAS 121, if the expected future cash flow of a long-lived asset is less than
the carrying amount of the asset, an impairment loss shall be recognized to
value the asset at its fair value. Maxus revalued its assets and liabilities on
April 1, 1995 following the provisions of SFAS 121. There was no impact on the
Company's results of operations due to the adoption of SFAS 121 during the nine
months ended December 31, 1995.
 
     Following the Merger, Chase provided two additional credit facilities
aggregating $425 million: (i) a credit facility of $250 million extended to
Midgard Energy Company ("Midgard"), a wholly owned subsidiary of the Company,
and (ii) a credit facility of $175 million extended to Maxus Indonesia, Inc.
("Holdings"), a wholly owned subsidiary of the Company. The proceeds of the
loans made pursuant to these facilities were used to repay, in part, the
Purchaser Facility, which was assumed by the Company pursuant to the Merger. In
addition, the Company applied $8 million of its available cash to repay the
Purchaser Facility and used approximately $86 million of its available cash to
pay holders of Shares converted into the right to receive cash in the Merger.
 
                                      F-42
<PAGE>   89
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
NOTE THREE--ASSET DIVESTITURES
 
     In December 1995, the Company sold its overriding royalty interest in the
Recetor Block in Colombia for $25 million. There was no gain or loss recognized
on this transaction as the sales price approximated the carrying value of the
investment in the Recetor Block.
 
NOTE FOUR--GEOGRAPHIC DATA
 
     The Company is engaged primarily in the exploration for and the production
and sale of crude oil and natural gas.
 
     Sales, operating profit and identifiable assets by geographic area were as
follows:
 
<TABLE>
<CAPTION>
                                                                           SALES AND
                                                                           OPERATING
                                                                           REVENUES
                                                                          -----------
                                                                          NINE MONTHS
                                                                             ENDED
                                                                           DECEMBER
                                                                              31,
                                                                             1995
                                                                          ----------
        <S>                                                                <C>
        United States...................................................   $   128.9
        Indonesia.......................................................       298.3
        South America...................................................        36.6
                                                                            --------
                                                                           $   463.8
                                                                           =========
</TABLE>
 
<TABLE>
<CAPTION>
                                                                           OPERATING
                                                                             LOSS
                                                                          -----------
                                                                          NINE MONTHS
                                                                             ENDED
                                                                           DECEMBER
                                                                              31,
                                                                             1995
                                                                           ---------
        <S>                                                                <C>
        United States...................................................   $   (15.1)
        Indonesia.......................................................        88.7
        South America...................................................       (11.5)
        Other Foreign...................................................       (15.9)
                                                                           ----------
                                                                                46.2
        General corporate expenses......................................        (5.9)
        Interest and debt expenses......................................      (104.9)
                                                                           ----------
                                                                           $   (64.6)
                                                                           =========
</TABLE>
 
<TABLE>
<CAPTION>
                                                                          IDENTIFIABLE
                                                                            ASSETS
                                                                          -----------
                                                                           DECEMBER
                                                                              31,
                                                                             1995
                                                                          -----------
        <S>                                                                <C>
        United States...................................................   $   715.9
        Indonesia.......................................................     1,157.1
        South America...................................................       666.6
        Other Foreign...................................................        24.3
                                                                           ---------
                                                                             2,563.9
        Corporate assets................................................       152.9
                                                                           ---------
                                                                           $ 2,716.8
                                                                           =========
</TABLE>
 
     Net foreign assets were $1,296.7 million at December 31, 1995. Income from
foreign operations, after applicable local taxes, was $6.9 million for the nine
months ended December 31, 1995.
 
                                      F-43
<PAGE>   90
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     Sales to two customers for the nine months ended December 31, 1995 each
represented 10% or more of consolidated sales:
 
<TABLE>
<CAPTION>
                                                                           NINE MONTHS
                                                                              ENDED
                                                                            DECEMBER
                                                                               31,
                                                                              1995
                                                                           -----------
        <S>                                                                <C>
        Mitsubishi Corporation.............................................   $  49.6
        Indonesian Government..............................................     102.4
</TABLE>
 
     The Company does not believe that the loss of Mitsubishi Corporation as a
customer would adversely affect the Company's ability to market its oil and gas
production. Sales to the Company's largest customer, the Indonesian Government,
are made primarily pursuant to long-term production sharing contracts between
the Company's Indonesian operations and the Indonesian Government. The
Indonesian Government is required to purchase a specified amount of the
Company's oil and gas production throughout the life of its operations in
Indonesia based on these contracts.
 
NOTE FIVE--TAXES
 
     Income before income taxes was comprised of income (loss) from:
 
<TABLE>
<CAPTION>
                                                                           NINE MONTHS
                                                                              ENDED
                                                                            DECEMBER
                                                                               31,
                                                                              1995
                                                                           -----------
        <S>                                                                <C>
        United States......................................................   $(125.9)
        Foreign............................................................      61.3
                                                                              -------
                                                                              $ (64.6)
                                                                              =======
</TABLE>
 
     The Company's provision for income taxes was comprised of the following:
 
<TABLE>
<CAPTION>
                                                                           NINE MONTHS
                                                                              ENDED
                                                                            DECEMBER
                                                                               31,
                                                                              1995
                                                                           -----------
        <S>                                                                <C>
        Current
             Federal.......................................................   $  (7.9)
             Foreign.......................................................      64.9
             State and local...............................................       1.3
                                                                              -------
                                                                                 58.3
        Deferred
             Federal.......................................................     (15.2)
             Foreign.......................................................     (34.0)
                                                                              -------
                                                                                (49.2)
                                                                              -------
        Provision for income taxes.........................................   $   9.1
                                                                              =======
</TABLE>
 
                                      F-44
<PAGE>   91
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     The principal reasons for the difference between tax expense at the
statutory federal income tax rate of 35% and the Company's provision for income
taxes were:
 
<TABLE>
<CAPTION>
                                                                            NINE MONTHS
                                                                               ENDED
                                                                             DECEMBER
                                                                                31,
                                                                               1995
                                                                            -----------
        <S>                                                                   <C>
        Tax expense (benefit) at statutory federal rate....................   $ (22.6)
        Increase (reduction) resulting from:
             Taxes on foreign income.......................................      19.8
             Asset sales...................................................       1.5
             Non-deductible depreciation and amortization of net purchase
              price adjustments............................................       4.4
             Valuation allowance...........................................      11.7
             Audit settlements and other changes in tax position...........      (5.0)
             Other, net....................................................       (.7)
                                                                              -------
             Provision for income taxes....................................   $   9.1
                                                                              =======
</TABLE>
 
     The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities as of and for
the nine months ended December 31, 1995 were as follows:
 
<TABLE>
<CAPTION>
                                                                            NINE MONTHS
                                                                               ENDED
                                                                             DECEMBER
                                                                                31,
                                                                               1995
                                                                             -----------
        <S>                                                                   <C>
        U. S. deferred tax liabilities
             Properties and equipment......................................   $ 269.1
             Other.........................................................      18.6
                                                                              -------
                  Deferred U. S. tax liabilities...........................     287.7
                                                                              -------
        U. S. deferred tax assets
             Foreign deferred taxes........................................    (139.8)
             Book accruals.................................................     (28.0)
             Interest limitation carryforwards.............................     (16.4)
             Loss carryforwards............................................     (72.7)
             Credit carryforwards..........................................     (19.9)
             Other.........................................................       (.2)
                                                                              -------
                  Gross deferred U. S. tax assets..........................    (277.0)
                                                                              -------
             Valuation allowance...........................................      87.1
                                                                              -------
                  Net deferred U. S. tax assets............................    (189.9)
                                                                              -------
                  Net deferred U. S. taxes.................................      97.8
                                                                              -------
        Foreign deferred tax liabilities
             Properties and equipment......................................     446.5
                                                                              -------
                  Net deferred foreign taxes...............................     446.5
                                                                              -------
        Net deferred taxes.................................................   $ 544.3
                                                                              =======
</TABLE>
 
     As a result of an increase in U. S. net operating loss carryforwards, the
valuation allowance was increased $11.7 million during the nine months ended
December 31, 1995.
 
                                      F-45
<PAGE>   92
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     At December 31, 1995, the Company had $14.4 million of general business
credit carryforwards that expire between 1996 and 2002; $207.7 million of U.S.
net operating loss carryforwards that expire from 2003 to 2010; and $5.5 million
of minimum tax credit that can be carried forward indefinitely.
 
     As a result of the Merger, effective April 1, 1995, the Company's ability
to utilize its existing net operating loss carryforwards will be limited by
statute to approximately $92.0 million each year until exhausted. To the extent
certain gains are recognized in the future, the annual limitation may be
increased to the extent that the gains are built-in gains within the meaning of
the U.S. Internal Revenue Code.
 
     There are accumulated undistributed earnings after applicable local taxes
of foreign subsidiaries of $5.7 million at December 31, 1995 for which no
provision was necessary for foreign withholding or other income taxes because
that amount had been reinvested in properties and equipment and working capital
in the foreign jurisdictions.
 
     Taxes other than income taxes were comprised of the following:
 
<TABLE>
<CAPTION>
                                                                           NINE MONTHS
                                                                              ENDED
                                                                            DECEMBER
                                                                               31,
                                                                              1995
                                                                           -----------
        <S>                                                                <C>
        Gross production...................................................    $ 4.1
        Real and personal property.........................................      5.2
        Other..............................................................       .4
                                                                              ------
                                                                              $  9.7
                                                                              ======
</TABLE>
 
NOTE SIX--POSTEMPLOYMENT BENEFITS
 
  Pensions
 
     The components of net periodic pension expense are as follows:
 
<TABLE>
<CAPTION>
                                                                           NINE MONTHS
                                                                              ENDED
                                                                            DECEMBER
                                                                               31,
                                                                              1995
                                                                           -----------
        <S>                                                                <C>
        Service cost for benefits earned during the period.................   $   1.4
        Interest cost on projected benefit obligation......................       6.5
        Actual return on plan assets.......................................     (13.4)
        Net amortization and deferrals.....................................       7.4
                                                                             --------
                                                                             $    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 date, October 1, 1995, were as follows:
 
<TABLE>
        <S>                                                                     <C>
        Discount rate.........................................................   7.5%
        Expected long-term rate of return on assets...........................   9.0%
        Rate of increase in compensation levels...............................   4.5%
</TABLE>
 
                                      F-46
<PAGE>   93
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     The funded status of the plans at December 31, 1995 were as follows:
 
<TABLE>
<CAPTION>
                                                                      PLANS WITH
                                                              ---------------------------
                                                              ACCUMULATED       ASSETS
                                                               BENEFITS        EXCEEDING
                                                               EXCEEDING      ACCUMULATED
                                                                ASSETS         BENEFITS
                                                              -----------     -----------
        <S>                                                   <C>             <C>
        Actuarial present value of:
             Vested benefit obligation......................    $ 111.7          $ 1.1
                                                                -------          -----
             Accumulated benefit obligation.................    $ 117.6          $ 1.1
                                                                -------          -----
             Projected benefit obligation...................    $ 122.6          $ 1.1
        Plan assets at fair value...........................      102.8            1.3
                                                                -------          -----
        Plan assets (less)more than projected benefit
          obligation........................................    $ (19.8)         $  .2
        Unrecognized net loss...............................       10.1
        Adjustment required to recognize minimum
          liability.........................................       (5.9)
                                                                -------          -----
        Prepaid (accrued) pension cost......................    $ (15.6)         $  .2
                                                                =======          =====
</TABLE>
 
     As a result of the Merger, the Company was required to fully accrue its
obligation for pension benefits in purchase accounting (See Note Two).
Therefore, effective April 1, 1995, the Company increased its balance sheet
liability to reflect any previously unrecognized gains and losses, transition
obligations and prior service costs. Additionally, several of the Company's
pension plans experienced a partial curtailment due to workforce reductions
following the Merger. The impact of the partial curtailment, which had no impact
on the Company's net periodic pension expense, reduced the Company's projected
benefit obligation by $1.1 million.
 
     At December 31, 1995, the Company's accumulated postretirement benefit
obligation ("APBO") exceeded the plan assets. In accordance with Statement of
Financial Accounting Standards No. 87, "Employers' Accounting for Pensions," the
Company recorded a minimum pension liability of $5.9 million and a charge to
equity of $5.9 million.
 
     In addition to the defined benefit plans, the Company has a defined
contribution plan which covers the Indonesian nationals. Employee contributions
of 2% of each covered employee's compensation are matched by the Company with a
contribution of 6% of compensation. Contributions to the plan were $.4 million
for the nine months ended December 31, 1995.
 
  Other Postretirement Benefits
 
     As a result of the Merger, the Company was required to fully accrue its
obligation for postretirement benefits other than pensions in purchase
accounting (See Note Two). Therefore, effective April 1, 1995, the Company
increased its balance sheet liability by $31.7 million to reflect any previously
unrecognized gains and unrecognized transition obligation at March 31, 1995.
 
     The components of net periodic postretirement benefit expense for the nine
months ended December 31, 1995 are as follows:
 
<TABLE>
<CAPTION>
                                                                          NINE MONTHS
                                                                             ENDED
                                                                           DECEMBER
                                                                              31,
                                                                             1995
                                                                          -----------
        <S>                                                               <C>
        Service cost for benefits earned during the period..............     $  .3
        Interest cost on accumulated postretirement benefit
          obligation....................................................       2.6
                                                                             -----
                                                                             $ 2.9
                                                                             =====
</TABLE>
 
                                      F-47
<PAGE>   94
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     The APBO as of December 31, 1995 was $46.6 million. The amount recognized
in the Company's statement of financial position at December 31, 1995 is as
follows:
 
<TABLE>
<CAPTION>
                                                                          DECEMBER 31,
                                                                              1995
                                                                          ------------
        <S>                                                               <C>
        Retirees..........................................................    $ 39.9
        Fully eligible active employees...................................       2.3
        Other active employees............................................       4.4
                                                                              ------
        Total.............................................................      46.6
        Unrecognized net loss.............................................      (1.6)
                                                                              ------
                                                                             $  45.0
                                                                              ======
</TABLE>
 
     A discount rate of 7.5% was used in determining the APBO at December 31
1995. The APBO was based on a 9% increase in the medical cost trend rate, with
the rate trending downward .5% per year to 5% in 2003 and remaining at 5%
thereafter. This assumption has a significant effect on annual expense, as it is
estimated that a 1% increase in the medical trend rate would increase the APBO
at December 31, 1995 by $4.6 million and increase the net periodic
postretirement benefit cost by $.4 million per year.
 
NOTE SEVEN--FINANCIAL INSTRUMENTS
 
     The fair value of financial instruments is determined by reference to
various market data and other valuation techniques as appropriate. Unless
otherwise disclosed, the fair value of financial instruments approximates their
recorded values.
 
  Restricted Cash
 
     The fair value of the Company's restricted cash, which is invested
primarily in U. S. Treasury notes, marketable securities and trust accounts, is
based on the quoted market prices for the same or similar securities at the
reporting date. The Company's gross unrealized gain on its restricted cash was
$2.3 million at December 31, 1995.
 
  Long-Term Debt
 
     The fair value of the Company's long-term debt is estimated based on the
quoted market prices for the same or similar issues or on the current rates
offered to the Company for debt of the same remaining maturities.
 
     The estimated fair value of the Company's financial instruments are as
follows:
 
<TABLE>
<CAPTION>
                                                                    DECEMBER 31, 1995
                                                                  ---------------------
                                                                  CARRYING       FAIR
                                                                   AMOUNT       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
Thirteen.
 
                                      F-48
<PAGE>   95
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
NOTE EIGHT--RECEIVABLES
 
<TABLE>
<CAPTION>
                                                                          DECEMBER 31,
                                                                              1995
                                                                          ------------
        <S>                                                               <C>
        Trade receivables.................................................   $ 101.4
        Notes and other receivables.......................................      41.3
        Less--Allowance for doubtful receivables..........................        .9
                                                                             -------
                                                                             $ 141.8
                                                                             =======
</TABLE>
 
NOTE NINE--PROPERTIES AND EQUIPMENT
 
<TABLE>
<CAPTION>
                                                                          DECEMBER 31,
                                                                              1995
                                                                          ------------
        <S>                                                                  <C>
        Proved properties.................................................  $ 1,597.1
        Unproved properties...............................................      763.1
        Gas plants and other..............................................      130.0
                                                                            ---------
                  Total Oil and Gas.......................................    2,490.2
        Corporate.........................................................       13.3
                                                                            ---------
                                                                              2,503.5
        Less--Accumulated depreciation, depletion and amortization........      139.9
                                                                             --------
                                                                             $2,363.6
                                                                             ========
</TABLE>
 
     The charge against earnings for depreciation, depletion and amortization of
property and equipment was $142.1 million for the nine months ended December 31,
1995 and the charge against earnings for maintenance and repairs, which is
included in operating expenses, was $25 million.
 
NOTE TEN--RESTRICTED CASH
 
     At December 31, 1995 the Company had $80.4 million in restricted cash, of
which $30.7 million represented collateral for outstanding letters of credit and
$7.4 million represented six months of interest on outstanding borrowings as
required by the Holdings credit agreement. Assets held in trust as required by
certain insurance policies were $42.3 million. Approximately $19.0 million of
collateral for outstanding letters of credit at December 31, 1995, was
classified as a current asset as these amounts are expected to be released
during 1996.
 
NOTE ELEVEN--ACCRUED LIABILITIES
 
<TABLE>
<CAPTION>
                                                                          DECEMBER 31,
                                                                              1995
                                                                          ------------
        <S>                                                               <C>
        Accrued interest payable..........................................   $  24.2
        Joint interest billings for international operations..............      41.7
        Merger reserve....................................................      31.4
        Environmental reserve.............................................      28.5
        Overlift payable..................................................       6.6
        Postretirement and postemployment benefits........................       4.5
        Accrued compensation, benefits and withholdings...................       8.1
        Other.............................................................      28.4
                                                                             -------
                                                                             $ 173.4
                                                                             =======
</TABLE>
 
                                      F-49
<PAGE>   96
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
NOTE TWELVE--LONG-TERM DEBT AND CREDIT ARRANGEMENTS
 
<TABLE>
<CAPTION>
                                                                 DECEMBER 31, 1995
                                                         ---------------------------------
                                                           FACE     UNAMORTIZED   CARRYING
                                                          VALUE      DISCOUNT      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 Credit Facility........................     250.0                    250.0
        Holdings Credit 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. Total debt outstanding at April 1, 1995 of $1,295.4 million, as
included in the accompanying unaudited balance sheet, reflected the unamortized
discount. For the nine months ended December 31, 1995 $5.9 million of discount
amortization was included as a component of interest expense.
 
     The aggregate maturities of long-term debt outstanding at December 31,
1995, for the next five years will be as follows:
 
<TABLE>
        <S>                                                                    <C>
        1996.................................................................  $34.3
        1997.................................................................   89.1
        1998.................................................................   95.5
        1999.................................................................   76.5
        2000.................................................................   74.0
</TABLE>
 
     At December 31, 1995, the Company had $144.8 million of medium-term notes
outstanding, which were issued in prior years, with maturities from 1996 to 2004
and annual interest rates ranging from 7.57% to 11.08%.
 
     The Company maintains a $25.0 million uncommitted credit facility (the
"credit facility"), which is used for the issuance of documentary or standby
letters of credit and/or the payment of shipping documents. The credit facility
can be secured by cash or the accounts receivable which are financed through the
letters of credit. At December 31, 1995, there were $13.8 million of cash
collateralized letters of credit outstanding under this credit facility.
 
                                      F-50
<PAGE>   97
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     Total interest and debt expenses incurred, including capitalized interest,
were as follows:
 
<TABLE>
<CAPTION>
                                                                           NINE MONTHS
                                                                              ENDED
                                                                            DECEMBER
                                                                               31,
                                                                              1995
                                                                           -----------
        <S>                                                                <C>
        Interest and debt expenses.........................................  $ 104.9
        Capitalized interest...............................................      1.4
                                                                              ------
                                                                             $ 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. ("Holdings"), a wholly owned subsidiary of the Company.
The proceeds of these loans were used to repay in part, the Purchaser Facility,
which was assumed by the Company. In addition, the Company applied $8 million of
its available cash to repayment of the Purchaser Facility. The Company
capitalized $16.8 million of debt issue costs during 1995 in connection with the
Midgard and Holdings credit facilities. These costs are recorded as deferred
charges and amortized over the terms of the related borrowings. For the nine
months ended December 31, 1995 $1.2 million of debt issue costs amortization was
included as a component of interest expense.
 
     Midgard Facility. Approximately $250 million of the loans under the
Purchaser Facility were repaid on June 8, 1995 with funds provided to the
Company by Midgard. Midgard provided these funds from the proceeds of a $250
million loan (the "Midgard Loan") extended to it pursuant to a credit agreement
(the "Midgard Facility") entered into on such date. In addition, approximately
$8 million of the loans outstanding under the Purchaser Facility, including
accrued interest on the Purchaser Facility loans, were repaid on June 8, 1995
utilizing cash held by the Company.
 
     The Midgard Loan, which was made in a single drawing, will mature on
December 31, 2003 and will be repaid in up to 28 consecutive equal quarterly
installments commencing on March 31, 1997, subject to semi-annual borrowing base
redeterminations. At December 31, 1995, the borrowing base for the Midgard
Facility was $250 million. The borrowing base is subject to redetermination on
April 1, 1996. At Midgard's option, the interest rate applicable to the Midgard
Loan will be, until March 31, 1997, either (i) the one-, two- or three-month
London Interbank Offered Rate ("LIBOR") plus a margin of 1 3/4% or (ii) the Base
Rate (as defined in the Midgard Facility) plus a margin of  3/4% and,
thereafter, either (iii) the one-, two- or three-month LIBOR plus a margin of
2 1/4% or (iv) the Base Rate plus a margin of 1 1/4%. At December 31, 1995, the
interest rate on the Midgard Facility based on the one-month LIBOR plus 1 3/4%
was 7.6875%. The Midgard Loan is not secured but is guaranteed by YPF and the
Company. The agreement evidencing the Midgard Loan contains, among other things,
a negative pledge on all assets of Midgard, subject to customary exceptions. It
is anticipated that the Midgard Loan will be repaid with funds generated by
Midgard's business operations.
 
     Holdings Facility. Approximately $175 million of the Purchaser Facility was
repaid with funds provided on June 16, 1995 to the Company by Holdings. Holdings
provided these funds from the proceeds of a $175 million loan (the "Subsidiaries
Loan") extended to it pursuant to a credit agreement (the "Holdings Facility")
entered into on such date.
 
                                      F-51
<PAGE>   98
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     The Subsidiaries Loan, which was made in a single drawing on June 16, 1995,
will mature on December 31, 2002 and will be repaid in up to 24 consecutive
equal quarterly installments commencing on March 31, 1997, subject to
semi-annual borrowing base redeterminations. At December 31, 1995, the borrowing
base for the Holdings Facility was $175 million. The borrowing base is subject
to redetermination on April 1, 1996. At the option of Holdings, the interest
rates applicable to the Subsidiaries Loan will be, until March 31, 1997, either
(i) the one-, two- or three-month LIBOR plus a margin of 2 1/4% or (ii) the Base
Rate (as defined in the Holdings Facility) plus a margin of 1 1/4% and,
thereafter, either (iii) the one-, two- or three-month LIBOR plus a margin of
2 3/4% or (iv) the Base Rate plus a margin of 1 3/4%. At December 31, 1995, the
interest rate on the Holdings Facility based on the one-month LIBOR plus 2 1/4%
was 8.125%. The Subsidiaries Loan to Holdings is secured by the stock of Maxus
Northwest Java, Inc. ("Java") and Maxus Southeast Sumatra, Inc. ("Sumatra")
(collectively, the "Holdings Subsidiaries") and by the interest of Holdings,
Java and Sumatra in certain accounts maintained at Chase into which the proceeds
of sales of hydrocarbons are to be deposited, and is guaranteed by Java,
Sumatra, YPF and the Company. The agreement evidencing the Subsidiaries Loan
contains a negative pledge on all of the other assets of Holdings, subject to
customary exceptions. It is anticipated that the Subsidiaries Loan will be
repaid with funds generated by the Holdings Subsidiaries' business operations.
 
     Each of the Midgard Facility and the Holdings Facility contains restrictive
covenants including limitations upon the sale of assets, mergers and
consolidations, the creation of liens and additional indebtedness, investments,
dividends, the purchase or repayment of subordinated indebtedness, transactions
with affiliates and modifications to certain material contracts. The obligors
under the Midgard Facility and the Holdings Facility may not permit (a)
consolidated tangible net worth to be less than $200 million, in the case of the
Midgard Facility, or $350 million, in the case of the Holdings Facility, plus
(or minus), in the case of Midgard, the amount of any adjustment in the book
value of assets or, in the case of Holdings, 70% of the amount of any adjustment
to net worth, resulting from the merger of YPF Acquisition Corp. into the
Company, (b) the ratio of consolidated cash flow to consolidated debt service to
be less than 1.1 to 1.0 at the end of any fiscal quarter and (c) the ratio of
consolidated cash flow to consolidated interest expense to be less than 1.25 to
1.0 at the end of any fiscal quarter. In addition, mandatory prepayments of the
loans under the Midgard Facility and the Holdings Facility may be required in
connection with certain asset sales and casualty losses, upon the issuance of
subordinated indebtedness and in 1996 and in each year thereafter if, after
semi-annual review, the agent and the lenders determine that a borrowing base
deficiency exists. No borrowing base deficiencies existed at December 31, 1995.
 
     The guaranty by Maxus of the obligation under the Midgard Facility (the
"Midgard Guaranty") and under the Holdings Facility (the "Subsidiaries
Guaranty") contains restrictions upon mergers and consolidations, the creation
of liens and the business activities in which Maxus and its subsidiaries may
engage. In addition, Midgard, in the case of the Midgard Guaranty, and Holdings
and its subsidiaries, in the case of the Subsidiaries Guaranty, are required to
be wholly owned subsidiaries of Maxus, except to the extent YPF or a subsidiary
of YPF (other than Maxus or a subsidiary of Maxus) makes capital contributions
to Midgard or Holdings or one of Holdings subsidiaries, as the case may be.
 
  Keepwell Covenant
 
     Pursuant to the Merger Agreement, in the event that the Company is unable
to meet its obligations as they come due, whether at maturity or otherwise,
including, solely for the purposes of this undertaking, dividend and redemption
payments with respect to the $9.75 Preferred Stock, the $2.50 Preferred Stock
and the $4.00 Preferred Stock, YPF has agreed to capitalize the Company in an
amount necessary to permit the Company to meet such obligations; provided that
YPF's aggregate obligation will be: (i) limited to the amount of debt service
obligations under the Purchaser Facility, the Midgard Facility and the Holdings
Facility and (ii) reduced by the amount, if any, of capital contributions by YPF
to the Company after the Merger Date and by the amount of the net proceeds of
any sale by the Company of common stock or
 
                                      F-52
<PAGE>   99
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
nonredeemable preferred stock after the Merger Date. The foregoing obligations
of YPF (the "Keepwell Covenant") will survive until June 8, 2004. YPF has made
no capital contributions under the Keepwell Covenant as of December 31, 1995. In
addition, YPF has guaranteed the Company's outstanding debt as of the Merger
Date, the principal amount of which was approximately $976 million. The debt
covered by the YPF guarantee includes the Company's outstanding 11 1/4%, 11 1/2%
and 8 1/2% Sinking Fund Debentures, its outstanding 9 7/8%, 9 1/2% and 9 3/8%
Notes, and its outstanding medium-term notes. YPF has also guaranteed the
payment and performance of the Company's obligations to the holders of its $9.75
Preferred Stock.
 
  Advances from Parent
 
     Based on 1996 projections, the Company anticipates that YPF will make
capital contributions of approximately $200 million to $250 million under the
Keepwell Covenant during 1996. At December 31, 1995, the Company had $6.6
million outstanding of advances from its parent, YPF, which is included in long-
term debt.
 
     The Company and YPF intend to enter into a loan agreement during 1996 to
facilitate short-term loans by YPF to the Company and short-term loans by the
Company to YPF of excess cash balances. It is expected that loans will be made
by the parties under the loan agreement during 1996; however, the number and
amounts thereof are not presently known.
 
NOTE THIRTEEN--DERIVATIVE FINANCIAL INSTRUMENTS
 
     The Company's only derivative financial instruments are natural gas price
swap agreements and crude oil and natural gas futures contracts, which are not
used for trading purposes. During the nine-month period ended December 31, 1995,
the Company unwound its sole interest rate swap agreement and recorded a $2.4
million final settlement gain in other revenues. The Company also received a
$4.5 million termination payment, which has been deferred.
 
  Natural Gas Price Swap Agreements
 
     Under the price swap agreements used to hedge fluctuations in the price of
natural gas, the Company receives or makes payments based on the differential
between the Company's specified price and the counterparty's specified price of
natural gas. Depending on the agreement, the Company pays a fixed or variable
price per million British Thermal Units ("Mmbtu") and receives a fixed or
variable price per Mmbtu. During the nine months ended December 31, 1995, the
Company had swap agreements with other companies to exchange payments on 10.7
million Mmbtu of gas. Under these swap agreements, the Company paid fixed or
variable prices averaging $1.68 per Mmbtu and received fixed or variable prices
averaging $1.53 per Mmbtu. Gross losses realized on these swap agreements of
$2.1 million were partially offset by gross gains of $0.5 million resulting in a
net loss of $1.6 million during the nine months ended December 31, 1995.
 
     As of December 31, 1995, the Company has outstanding price swap agreements
with other companies to exchange payments on 5.5 million Mmbtu of gas during the
first quarter of 1996. Under these swap agreements, the Company will pay
variable prices averaging $2.00 per Mmbtu and receive fixed prices averaging
$1.74 per Mmbtu resulting in gross unrealized losses of $1.4 million based on
gas sales prices at period end. Actual gains and losses realized upon settlement
of these price swap agreements will depend upon the variable prices received at
the time of settlement.
 
  Natural Gas and Crude Oil Futures Contracts
 
     Under the natural gas futures contracts used to hedge fluctuations in the
price of natural gas, the Company receives or makes payments based on the
differential between the selling price and the settlement price per Mmbtu.
During the nine months ended December 31, 1995, the Company settled futures
contracts
 
                                      F-53
<PAGE>   100
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
with other companies on 4.9 million Mmbtu of gas. Under these futures contracts,
the Company received selling prices averaging $1.71 per Mmbtu and paid
settlement prices averaging $1.70 per Mmbtu. Realized gross gains and losses on
these futures contracts were immaterial.
 
     As of December 31, 1995, the Company had outstanding futures contracts with
other companies to sell 3.6 million Mmbtu of gas. Under these futures contracts,
the Company will receive selling prices averaging $2.01 per Mmbtu and pay
settlement prices averaging $2.76 per Mmbtu resulting in gross unrealized losses
of $2.7 million based on gas prices at period end. Actual gains and losses
realized upon expiration of these futures contracts will depend upon the
settlement prices.
 
     Under the crude oil futures contracts used to hedge fluctuations in the
price of crude oil, the Company receives or makes payments based on the
differential between the selling price and the settlement price per barrel.
During the nine-month period ended December 31, 1995, crude oil volumes hedged
under these futures contracts were insignificant as were gross unrealized gains
and losses. The Company had no open crude oil futures contracts at December 31,
1995.
 
NOTE FOURTEEN--PREFERRED STOCK
 
     The Company has the authority to issue 100,000,000 shares of Preferred
Stock, $1.00 par value. The rights and preferences of shares of authorized but
unissued Preferred Stock are established by the Company's Board of Directors at
the time of issuance.
 
  $9.75 Cumulative Convertible Preferred Stock
 
     In 1987, the Company sold 3,000,000 shares of $9.75 Preferred Stock. Since
such time, the Company has entered into various agreements, most recently on
June 8, 1995, with the sole holder of the $9.75 Preferred Stock pursuant to
which, among other things, the Company has repurchased 500,000 shares and the
parties have waived or amended various covenants, agreements and restrictions
relating to such stock. Currently, 1,250,000 shares of $9.75 Preferred Stock are
outstanding, each receiving an annual cash dividend of $9.75. In addition,
375,000 of such shares (the "Conversion Waiver Shares") each receive an
additional quarterly cash payment of $.25 ($.50 in certain circumstances). For
the twelve month period commencing February 1, 1996, each share of the $9.75
Preferred Stock has a liquidation value of $100.00 ($125.0 million in the
aggregate) plus accrued dividends. Since February 1, 1994, the stock has been
subject to mandatory redemption at the rate of 625,000 shares per year. The
$9.75 Preferred Stock currently is neither convertible by the holder nor
redeemable at the Company's option and has no associated registration rights.
The $9.75 Preferred Stock entitles the holder to vote only on certain matters
separately affecting such holder, and the $9.75 Preferred Stock other than the
Conversion Waiver Shares entitles the holder to elect one individual to the
Board of Directors of the Company. In addition, pursuant to the June 8, 1995
agreement, the holder of the $9.75 Preferred Stock waived previously granted
rights to approve certain "self-dealing" transactions and certain financial
covenants pertaining to the Company, and the Company waived its right of first
offer with respect to the transfer of the $9.75 Preferred Stock and certain
transfer restrictions on such stock.
 
  $4.00 Cumulative Convertible Preferred Stock
 
     Each outstanding share of $4.00 Preferred Stock is entitled to one vote, is
convertible at any time into shares of the Company's Common Stock (2.29751
shares at December 31, 1995), is entitled to receive annual cash dividends of
$4.00 per share, is callable at and has a liquidation value of $50.00 per share
($217.8 million in the aggregate at December 31, 1995) plus accrued but unpaid
dividends, if any.
 
                                      F-54
<PAGE>   101
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
  $2.50 Cumulative Preferred Stock
 
     Each outstanding share of the $2.50 Preferred Stock is entitled to receive
annual cash dividends of $2.50 per share, is callable after December 1, 1998 at
and has a liquidation value of $25.00 per share ($87.5 million in the aggregate
at December 31, 1995) plus accrued but unpaid dividends, if any.
 
     The holders of the shares are entitled to limited voting rights under
certain conditions. In the event the Company is in arrears in the payment of six
quarterly dividends, the holders of the $2.50 Preferred Stock have the right to
elect two members to the Board of Directors until such time as the dividends in
arrears are current and a provision is made for the current dividends due.
 
NOTE FIFTEEN--COMMON STOCK
 
<TABLE>
<CAPTION>
                                                                      SHARES       AMOUNT
                                                                    ----------     ------
    <S>                                                             <C>            <C>
    April 1, 1995.................................................. 135,897,899    $135.9
         Employee Shareholding and Investment Plan.................      18,182
         Cancellation of treasury shares...........................   (306,307)       (.3)
         Fractional shares exchanged for cash......................         (2)
                                                                    -----------    ------
    December 31, 1995.............................................. 135,609,772    $135.6
                                                                    ===========    ======
</TABLE>
 
     Pursuant to the offer in April 1995, YPF acquired 120,000,613 shares of
Maxus Common Stock at $5.50 per Share representing 88.5% of the then-outstanding
Shares of the Company. As a result of the Merger, each outstanding Share (other
than Shares held by YPF or any of their subsidiaries or in the treasury of the
Company, all of which were cancelled in the second quarter of 1995, and Shares
of holders who perfected their appraisal rights under Section 262 of the
Delaware General Corporation Law) was converted into the right to receive $5.50,
and accordingly, the Company's common stock ceased to be publicly traded. (See
Note Two).
 
     At December 31, 1995, there were 10.0 million shares of Common Stock
reserved for issuance upon conversion of Preferred Stock. However, since the
Company's Common Stock is not publicly traded, there would be no market for the
common shares.
 
     In 1992, Kidder, Peabody & Co. Incorporated purchased eight million
warrants from the Company. Each warrant represents the right to purchase one
share of the Company's Common Stock at $13.00 per share at any time prior to the
expiration of the warrants on October 10, 1997.
 
     The Company has an Employee Shareholding and Investment Plan ("ESIP") which
allows eligible participating employees to contribute a certain percentage of
their salaries (1%-10%) to a trust for investment in any of five funds. Prior to
the Merger employees could also invest in a fund consisting of the Company's
Common Stock. However, the Maxus Energy Stock Fund was eliminated from the ESIP
plan effective April 19, 1995. The Company matches the participating employees
contributions to the ESIP (up to 6% of base pay). Such matching contribution is
charged against earnings and prior to April 19, 1995, was invested in the ESIP
fund which consisted of the Company's Common Stock. Subsequent to April 19,
1995, the Company's matching contribution is invested in any of five funds as
directed by the employee. For the nine months ended December 31, 1995, the
charge against earnings for the Company's contribution was $1.7 million.
 
                                      F-55
<PAGE>   102
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
NOTE SIXTEEN--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)
                                                                 -------       -------
        December 1, 1995........................................ $ 105.8       $ (73.7)
                                                                 =======       =======
</TABLE>
 
NOTE SEVENTEEN--UNREALIZED GAIN ON INVESTMENT IN MARKETABLE SECURITIES
 
     The amortized cost and estimated fair value of marketable securities at
December 31, 1995 are as follows:
 
<TABLE>
<CAPTION>
                                                                         GROSS
                                                          AMORTIZED    UNREALIZED    MARKET
                                                            COST         GAINS       VALUE
                                                          ---------    ----------    ------
        <S>                                               <C>          <C>           <C>
        Held-to-maturity:
             Corporate and other debt securities..........  $ 108.4       $2.3       $110.7
</TABLE>
 
     At December 31, 1995, securities categorized as held-to-maturity are
included in cash equivalents, short-term investments and short- and long-term
restricted cash.
 
NOTE EIGHTEEN--COMMON TREASURY STOCK
 
<TABLE>
<CAPTION>
                                                                    SHARES      AMOUNT
                                                                   --------     ------
        <S>                                                        <C>          <C>
        April 1, 1995............................................. (310,535)    $(3.6)
             Restricted Stock.....................................   (5,660)
             Director Stock Compensation Plan.....................    9,888        .1
             Cancellation of Treasury Shares......................  306,307       3.5
                                                                   --------     -----
        December 31, 1995.........................................       --        --
                                                                   ========     =====
</TABLE>
 
     See Note Two.
 
NOTE NINETEEN--STOCK OPTIONS
 
     Two plans, a Long-Term Incentive Plan and a Director Stock Option Plan,
were approved by the stockholders in 1992. The Company's 1986 and 1992 Long-Term
Incentive Plans (the "Incentive Plans"), administered by the Compensation
Committee of the Board of Directors, permit the grant to officers and certain
key employees of stock options, stock appreciation rights ("SARs"), performance
units and awards of Common Stock or other securities of the Company on terms and
conditions determined by the Compensation Committee of the Board of Directors.
 
     The Director Stock Option Plan became effective on September 1, 1992. Under
this plan, non-employee directors received options to purchase shares of Common
Stock on the effective date of the plan. Thereafter, upon initial election or
re-election of a non-employee director at an annual meeting, the non-employee
directors automatically received options to purchase shares of Common Stock. The
plan terminated on June 7, 1995.
 
                                      F-56
<PAGE>   103
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     The grant or exercise of an option does not result in a charge against the
Company's earnings because all options have been granted at exercise prices
approximating the market value of the stock at the date of grant. However, any
excess of Common Stock market price over the option price of options, which
includes SARs, does result in a charge against the Company's earnings; a
subsequent decline in market price results in a credit to earnings, but only to
a maximum of the earnings charges incurred in prior years on SARs.
 
     Stock option activity was as follows:
 
<TABLE>
<CAPTION>
                                                                          DECEMBER 31,
                                                                              1995
                                                                          ------------
        <S>                                                               <C>
        Outstanding at April 1..........................................    2,190,573
             Cancelled..................................................      (16,133)
             Surrendered................................................   (2,174,440)
                                                                           ----------
        Outstanding at December 31......................................           --
                                                                           ----------
        Available for future grants at December 31......................    3,789,124
                                                                           ----------
        Performance units held for vesting at December 31...............       27,640
                                                                           ----------
</TABLE>
 
     There will be no further grants of stock options, restricted stock or
performance units subsequent to April 1, 1995 under the Company's Long-Term
Incentive Plans. Effective upon the Merger, all stock options and restricted
stock outstanding under Company-sponsored incentive plans were surrendered to
the Company. The Company anticipates replacing the Long-Term Incentive Plans in
1996.
 
     In 1993, the Company issued performance units under the 1992 Long-Term
Incentive Plan. The performance unit entitles the grantee to the value of a
share of Common Stock contingent upon the performance of the Company compared to
a selected group of peer companies. The value of the performance unit is
amortized over the vesting period based on a weighted probability of expected
payout levels. There was no earnings activity related to performance units for
the nine months period ended December 31, 1995 as outstanding performance units
had no value.
 
NOTE TWENTY--LEASES
 
     The Company leases certain machinery and equipment, facilities and office
space under cancelable and noncancelable operating leases, most of which expire
within 20 years and may be renewed.
 
     Minimum annual rentals for non-cancelable operating leases at December 31,
1995, were as follows:
 
<TABLE>
        <S>                                                                   <C>
        1996................................................................  $ 39.9
        1997................................................................    27.9
        1998................................................................    18.9
        1999................................................................    15.7
        2000................................................................    11.3
        December 31, 2001 and thereafter....................................    63.2
                                                                              ------
                                                                              $176.9
                                                                              ======
</TABLE>
 
     Minimum annual rentals have not been reduced by minimum sublease rentals of
$36.9 million due in the future under noncancelable subleases.
 
                                      F-57
<PAGE>   104
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
     Rental expense for operating leases was as follows:
 
<TABLE>
<CAPTION>
                                                                           NINE MONTHS
                                                                              ENDED
                                                                            DECEMBER
                                                                               31,
                                                                              1995
                                                                           -----------
        <S>                                                                    <C>
        Total rentals......................................................    $44.1
        Less--Sublease rental income.......................................      2.1
                                                                               -----
        Rental expense.....................................................    $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 $3.2 million during 1995.
Additionally, the Company has $6.6 million outstanding in advances from its
parent, YPF.
 
NOTE TWENTY-TWO--COMMITMENTS AND CONTINGENCIES
 
     Federal, state and local laws and regulations relating to health and
environmental quality in the United States, as well as environmental laws and
regulations of other countries in which the Company operates, affect nearly all
of the operations of the Company. These laws and regulations set various
standards regulating certain aspects of health and environmental quality,
provide for penalties and other liabilities for the violation of such standards
and establish in certain circumstances remedial obligations. In addition,
especially stringent measures and special provisions may be appropriate or
required in environmentally sensitive foreign areas of operation, such as those
in Ecuador.
 
     Many of the Company's United States operations are subject to requirements
of the Safe Drinking Water Act, the Clean Water Act, the Clean Air Act (as
amended in 1990), the Occupational Safety and Health Act, the Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended
("CERCLA"), and other federal, as well as state, laws. Such laws address, among
other things, limits on the discharge of wastes associated with oil and gas
operations, investigation and clean-up of hazardous substances, and workplace
safety and health. In addition, these laws typically require compliance with
associated regulations and permits and provide for the imposition of penalties
for noncompliance. The Clean Air Act Amendments of 1990 may benefit the
Company's business by increasing the demand for natural gas as a clean fuel.
 
     The Company believes that its policies and procedures in the area of
pollution control, product safety and occupational health are adequate to
prevent unreasonable risk of environmental and other damage, and of resulting
financial liability, in connection with its business. Some risk of environmental
and other damage is, however, inherent in particular operations of the Company
and, as discussed below, the Company has certain potential liabilities
associated with former operations. The Company cannot predict what environmental
legislation or regulations will be enacted in the future or how existing or
future laws or regulations will be administered or enforced. Compliance with
more stringent laws or regulations, as well as more vigorous enforcement
policies of the regulatory agencies, could in the future require material
expenditures by the Company for the installation and operation of systems and
equipment for remedial measures and in certain other respects. Such potential
expenditures cannot be reasonably estimated.
 
     In connection with the sale of the Company's former chemical subsidiary,
Diamond Shamrock Chemicals Company ("Chemicals"), to Occidental Petroleum
Corporation ("Occidental") in 1986, the Company agreed to indemnify Chemicals
and Occidental from and against certain liabilities relating to the business or
activities of Chemicals prior to the September 4, 1986 closing date (the
"Closing Date"),
 
                                      F-58
<PAGE>   105
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
including certain environmental liabilities relating to certain chemical plants
and waste disposal sites used by Chemicals prior to the Closing Date.
 
     In addition, the Company agreed to indemnify Chemicals and Occidental for
50% of certain environmental costs incurred by Chemicals for which notice is
given to the Company within 10 years after the Closing Date on projects
involving remedial activities relating to chemical plant sites or other property
used in the conduct of the business of Chemicals as of the Closing Date and for
any period of time following the Closing Date, with the Company's aggregate
exposure for this cost sharing being limited to $75 million. The total expended
by the Company under this cost sharing arrangement was about $39 million as of
December 31, 1995. Occidental Chemical Corporation ("OxyChem"), a subsidiary of
Occidental, and Henkel Corporation ("Henkel"), an assignee of certain of
Occidental's rights and obligations, have filed a declaratory judgment action in
Texas state court with respect to the Company's agreement in this regard (see
"Legal Proceedings").
 
     In connection with the spin-off of Diamond Shamrock R&M, Inc., now known as
Diamond Shamrock, Inc. ("DSI"), in 1987, the Company and DSI agreed to share the
costs of losses (other than product liability) relating to businesses disposed
of prior to the spin-off, including Chemicals. Pursuant to this cost-sharing
agreement, the Company bore the first $75 million of such costs and DSI bore the
next $37.5 million. Under the arrangement, such ongoing costs are now borne
onethird by DSI and two-thirds by the Company. This arrangement will continue
until DSI has borne an additional $47.5 million, following which such costs will
be borne solely by the Company. As of December 31, 1995, DSI's remaining
responsibility is approximately $8 million and is included in accounts
receivable in the accompanying balance sheet.
 
     During the nine months ended December 31, 1995, the Company spent $5
million in environmental related expenditures in its oil and gas operations.
Expenditures for the full year 1996 are expected to be approximately $8 million.
 
     For the nine months ended December 31, 1995, the Company's total
expenditures for environmental compliance for disposed of businesses, including
Chemicals, were approximately $30 million, $9 million of which was recovered
from DSI under the above described cost-sharing agreement. Those expenditures
are projected to be approximately $23 million for the full year 1996 after
recovery from DSI under such agreement.
 
     At December 31, 1995, reserves for the environmental contingencies
discussed herein totaled $119 million. Management believes it has adequately
reserved for all environmental contingencies which are probable and can be
reasonably estimated; however, changes in circumstances could result in changes,
including additions, to such reserves in the future.
 
     The insurance companies that wrote Chemicals' and the Company's primary and
excess insurance during the relevant periods have to date refused to provide
coverage for most of Chemicals' or the Company's cost of the personal injury and
property damage claims related to environmental claims, including remedial
activities at chemical plant sites and disposal sites. In two actions filed in
New Jersey state court, the Company has been conducting litigation against all
of these insurers for declaratory judgments that it is entitled to coverage for
certain of these claims. In 1989, the trial judge in one of the New Jersey
actions ruled that there is no insurance coverage with respect to the claims
related to the Newark plant (discussed below). The trial court's decision was
upheld on appeal and that action is now ended. The other suit, which is pending,
covers disputes with respect to insurance coverage related to certain other
environmental matters.
 
     Newark, New Jersey. A consent decree, previously agreed upon by the U.S.
Environmental Protection Agency (the "EPA"), the New Jersey Department of
Environmental Protection and Energy (the "DEP") and Occidental, as successor to
Chemicals, was entered in 1990 by the United States District Court of New Jersey
and requires implementation of a remedial action plan at Chemicals' former
Newark, New Jersey agricultural chemicals plant. Engineering for such plan,
which will include an engineering estimate of the cost of construction, is
progressing. Construction is expected to begin in 1997, cost approximately $22
million and
 
                                      F-59
<PAGE>   106
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
take three to four years to complete. The work is being supervised and paid for
by the Company pursuant to its above described indemnification obligation to
Occidental. The Company has fully reserved the estimated costs of performing the
remedial action plan and required ongoing maintenance costs.
 
     Studies have indicated that sediments of the Newark Bay watershed,
including the Passaic River adjacent to the plant, are contaminated with
hazardous chemicals from many sources. Studies performed by the Company and
others suggest that contaminants historically discharged by the Newark plant are
buried under several feet of more recent sediment deposits and are not moving.
The Company, on behalf of Occidental, negotiated an agreement with the EPA under
which the Company is conducting further testing and studies to characterize
contaminated sediment in a six-mile portion of the Passaic River near the plant
site. The Company currently expects such testing and studies to be completed in
1999 and cost from $4 million to $6 million after December 31, 1995. The Company
has reserved its estimate of the remaining costs to be incurred in performing
these studies as of December 31, 1995. The Company has been conducting similar
studies under its own auspices for several years. Until these studies are
completed and evaluated, the Company cannot reasonably forecast what regulatory
program, if any, will be proposed for the Passaic River or the Newark Bay
watershed and therefore cannot estimate what additional costs, if any, will be
required to be incurred.
 
     Hudson County, New Jersey. Until 1972, Chemicals operated a chromium ore
processing plant at Kearny, New Jersey. According to the DEP, wastes from these
ore processing operations were used as fill material at a number of sites in
Hudson County.
 
     As a result of negotiations between the Company (on behalf of Occidental)
and the DEP, Occidental signed an administrative consent order with the DEP in
1990 for investigation and remediation work at certain chromite ore residue
sites in Kearny and Secaucus, New Jersey. The work is being performed by the
Company on behalf of Occidental, and the Company is funding Occidental's share
of the cost of investigation and remediation of these sites and is currently
providing financial assurance for performance of the work in the form of a
self-guarantee in the amount of $20 million subject to the Company's continuing
ability to satisfy certain financial tests specified by the State. This
financial assurance may be reduced with the approval of the DEP following any
annual cost review. While the Company has participated in the cost of studies
and is implementing interim remedial actions and conducting remedial
investigations and feasibility studies, the ultimate cost of remediation is
uncertain. The Company anticipates submitting its investigation and feasibility
reports to the DEP in late 1996 or 1997. The results of the DEP's review of
these reports could impact the cost of any further remediation that may be
required. The Company has reserved its best estimate of the remaining cost to
perform the investigations and remedial work as being $50 million at December
31, 1995. In addition, the DEP has indicated that it expects Occidental and the
Company to participate with the other chromium manufacturers in the funding of
certain remedial activities with respect to a number of so-called "orphan"
chrome sites located in Hudson County, New Jersey. Occidental and the Company
have declined participation as to those sites for which there is no evidence of
the presence of residue generated by Chemicals. The Governor of New Jersey
issued an Executive Order requiring state agencies to provide specific
justification for any state requirements more stringent than federal
requirements. The DEP has indicated that it may be revising its soil action
level upwards towards the higher soil screening levels proposed by the EPA in
1994.
 
     Painesville, Ohio. From about 1912 through 1976, Chemicals operated
manufacturing facilities in Painesville, Ohio. The operations over the years
involved several discrete but contiguous plant sites over an area of about 1,300
acres. The primary area of concern historically has been Chemicals' former
chromite ore processing plant (the "Chrome Plant"). For many years, the site of
the Chrome Plant has been under the administrative control of the EPA pursuant
to an administrative consent order under which Chemicals is required to maintain
a clay cap over the site and to conduct certain ground water and surface water
monitoring. Many other sites have previously been clay-capped and one specific
site, which was a waste disposal site from the mid-1960s until the 1970s, has
been encapsulated and is being controlled and monitored.
 
                                      F-60
<PAGE>   107
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
In September 1995, the Ohio Environmental Protection Agency (the "OEPA") issued
its Directors' Final Findings and Order (the "Director's Order") by consent
ordering that a remedial investigation and feasibility study (the "RIFS") be
conducted at the former Painesville plant area. The Company has agreed to
participate in the RIFS as required by the Director's Order. It is estimated
that the total cost of performing the RIFS will be $3 million to $5 million over
the next three years. In spite of the many remedial, maintenance and monitoring
activities performed, the former Painesville plant site has been proposed for
listing on the National Priority List under CERCLA; however, the EPA has stated
that the site will not be listed so long as it is satisfactorily addressed
pursuant to the Director's Order and OEPA's programs. The Company has accrued
the estimate of its share of the cost to perform the RIFS. The scope and nature
of any further investigation or remediation that may be required cannot be
determined at this time; however, as the RIFS progresses, the Company will
continuously assess the condition of the Painesville plant site and make any
changes, including additions, to its reserve as may be required.
 
     Other Former Plant Sites. Environmental remediation programs are in place
at all other former plant sites where material remediation is required in the
opinion of the Company. Former plant sites where remediation has been completed
are being maintained and monitored to insure continued compliance with
applicable laws and regulatory programs. The Company has reserved $6 million at
December 31, 1995, related to these sites, none of which are individually
material.
 
     Third Party Sites. Chemicals has also been designated as a potentially
responsible party ("PRP") by the EPA under CERCLA with respect to a number of
third party sites, primarily off of Chemicals' properties, where hazardous
substances from Chemicals' plant operations allegedly were disposed of or have
come to be located. Numerous PRPs have been named at substantially all of these
sites. At several of these, Chemicals has no known exposure. Although PRPs are
almost always jointly and severally liable for the cost of investigations,
cleanups and other response costs, each has the right of contribution from other
PRPs and, as a practical matter, cost sharing by PRPs is usually effected by
agreement among them. Accordingly, the ultimate cost of these sites and
Chemicals' share of the costs thereof cannot be estimated at this time, but are
not expected to be material except possibly as a result of the matters described
below.
 
     1. Fields Brook; Ashtabula, Ohio. At the time that Chemicals was sold to
Occidental, Chemicals operated a chemical plant at Ashtabula, Ohio which is
adjacent to Fields Brook. Occidental has continued to operate the Ashtabula
plant. In 1986, Chemicals was formally notified by the EPA that it was a PRP for
the Fields Brook site. The site is defined as Fields Brook, its tributaries and
surrounding areas within the Fields Brook watershed. At least 15 other parties
are presently considered to be financially responsible PRPs. In 1986, the EPA
estimated the cost of sediment remediation at the site would be $48 million. The
PRPs, including Occidental, have developed an allocation agreement for sharing
the costs of the work in Fields Brook ordered by the EPA. Under the allocation,
the Occidental share for Chemicals' ownership of the Ashtabula plant would be
about five percent of the total, assuming all viable PRPs were to participate.
 
     In 1990, the OEPA, as state trustee for natural resources under CERCLA,
advised previously identified PRPs, including Chemicals, that the OEPA intended
to conduct a Natural Resource Damage Assessment of the Fields Brook site to
calculate a monetary value for injury to surface water, groundwater, air, and
biological and geological resources at the site. Also, although Fields Brook
empties into the Ashtabula River which flows into Lake Erie, it is not known to
what extent, if any, the EPA will propose remedial action beyond Fields Brook
for which the Fields Brook PRPs might be asked to bear some share of the costs.
Until all preliminary studies and necessary governmental actions have been
completed and negotiated or judicial allocations have been made, it is not
possible for the Company to estimate what the response costs, response
activities or natural resource damages, if any, may be for Fields Brook or
related areas, the parties responsible therefore or their respective shares.
 
     It is the Company's position that costs attributable to the Ashtabula plant
fall under the Company's above-described cost sharing arrangement with
Occidental under which the Company bears one-half of
 
                                      F-61
<PAGE>   108
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
certain costs up to an aggregate dollar cap. Occidental, however, has contended
that it is entitled to full indemnification from the Company for such costs, and
the outcome of this dispute cannot be predicted. The Company has reserved its
estimate of its share of potential cleanup costs based on the assumption that
this site falls under the Occidental cost sharing arrangement.
 
     2. French Limited Disposal Site; Crosby, Texas. The PRPs, including
Chemicals (represented by the Company), entered into a consent decree and a
related trust agreement with the EPA with respect to this disposal site. The
consent decree was entered by the federal court as a settlement of the EPA's
claim for remedial action. Chemical's share of the cost to complete remediation
at this site at December 31, 1995, is expected to be approximately $500,000 and
such amount is fully accrued.
 
     3. SCP/Carlstadt Site; Carlstadt, New Jersey. Chemicals' share of
remediation costs at this CERCLA site would be approximately one percent, based
on relative volume of waste shipped to the site. An interim remedy has now been
implemented at the site by the PRPs but no estimate can be made at this time of
ultimate costs of remediation which may extend to certain off-site locations.
 
     4. Chemical Control Site; Elizabeth, New Jersey. The DEP has demanded of
PRPs (including Chemicals) reimbursement of the DEP's alleged $34 million
(including interest through December 31, 1995) in past costs for its partial
cleanup of this site. The PRPs and the EPA have settled the federal claims for
cost recovery and site remediation, and remediation is now complete. Based on
the previous allocation formula, it is expected that Chemicals' share of any
money paid to the DEP for its claim would be approximately two percent. The
Company has fully reserved its estimated liability for this site.
 
     Legal Proceedings. In November 1995, OxyChem filed suit in Texas state
court seeking a declaration of certain of the parties' rights and obligations
under the sales agreement pursuant to which the Company sold Chemicals to
Occidental. Henkel joined in said lawsuit as a plaintiff in January 1996.
Specifically, OxyChem and Henkel are seeking a declaration that the Company is
required to indemnify them for 50% of certain environmental costs incurred on
projects involving remedial activities relating to chemical plant sites or other
property used in connection with the business of Chemicals on the Closing Date
which relate to, result from or arise out of conditions, events or circumstances
discovered by OxyChem or Henkel and as to which the Company is provided written
notice by OxyChem or Henkel prior to the expiration of ten years following the
Closing Date, irrespective of when OxyChem or Henkel incurs and gives notice of
such costs, subject to an aggregate $75 million cap. The Company believes that
this lawsuit is without merit and intends to defend same vigorously. The Company
has established reserves based on its 50% share of costs expected to be paid or
incurred by OxyChem and Henkel prior to September 1996.
 
     As of December 31, 1995, the Company had paid OxyChem and Henkel a total of
approximately $39 million against said $75 million cap. The Company cannot
predict what portion of the approximately $36 million remaining as of that date
Occidental and Henkel may actually pay or incur prior to September 4, 1996, the
tenth anniversary of the Closing Date if they accelerate spending with regard to
such environmental costs; however, the Company has approximately $7 million
reserved at December 31, 1995, based on 50% of OxyChem's and Henkel's historical
annual expenditures. In the event OxyChem and Henkel prevail in this lawsuit,
the Company could be required to provide up to approximately $29 million in
additional reserves related to this indemnification.
 
     The Company has established reserves for legal contingencies in situations
where a loss is probable and can be reasonably estimated.
 
     In Ecuador, pipeline capacity available to the Company is sufficient to
transport only about 60% of the oil the Company expects to be able to produce
daily, and none of the various projects to increase transportation capacity that
have been considered has been approved by the government of Ecuador. In
addition, the Company is involved in a number of contract, auditing and
certification disputes with various government entities. Together, the lack of
pipeline capacity and the various disputes with government entities are
retarding
 
                                      F-62
<PAGE>   109
 
                            MAXUS ENERGY CORPORATION
 
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
 
the Company's ability to proceed with the economic development of Block 16.
Although the Company can give no assurances concerning the outcome of these
discussions, progress has recently been made on several important issues. The
Company intends to reduce program spending in Ecuador in 1996 to $19 million
from $32 million in 1995.
 
NOTE TWENTY-THREE--SUBSEQUENT EVENTS
 
     In January 1996, the Company and its partners were successful in acquiring
the highly prospective Guarapiche block in Venezuela's first auction awards for
equity production in over 20 years. Guarapiche is located on the same trend as
the five billion barrel El Furrial field in northeastern Venezuela. The Company,
together with its partners, paid $109 million ($27 million net to Maxus) to the
Venezuelan government for rights to explore the Guarapiche block. BP Exploration
Orinoco Limited is the operator with a 37.5% working interest while Amoco
Production Company and the Company hold the remaining 37.5% and 25%,
respectively. The Company's net exploration commitment for this block is
anticipated to total approximately $15 million over the next five years.
 
                                      F-63
<PAGE>   110
 
                FINANCIAL SUPPLEMENTARY INFORMATION (Unaudited)
 
        DATA IS FOR THE NINE MONTHS ENDED DECEMBER 31, 1995. THE DOLLAR
              AMOUNTS IN TABLES ARE IN MILLIONS, EXCEPT PER SHARE)
 
OIL AND GAS PRODUCING ACTIVITIES
 
     The following are disclosures about the oil and gas producing activities of
the Company as required by Statement of Financial Accounting Standards No. 69
("SFAS 69").
 
  Results of Operations
 
     Results of operations for the nine months ended December 31, 1995 from all
oil and gas producing activities are shown below. These results exclude revenues
and expenses related to the purchase of natural gas and the subsequent
processing and resale of such natural gas plus the sale of natural gas liquids
extracted therefrom.
 
<TABLE>
<CAPTION>
                                             UNITED                SOUTH     OTHER
                                             STATES   INDONESIA   AMERICA   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 $9.1 million for the nine months ended December 31, 1995.
 
                                      F-64
<PAGE>   111
 
CAPITALIZED COSTS
 
     Included in properties and equipment are capitalized amounts applicable to
the Company's oil and gas producing activities. Such capitalized amounts include
the cost of mineral interests in properties, completed and incomplete wells and
related support equipment. In addition, the Company's gas plants that process
not only the Company's gas but also third party gas, has been included in
capitalized costs. Approximately 52% of the volumes processed through the
Company's gas plants is the Company's gas. Only the revenue and cost related to
the Company's produced gas is included in results of operations and costs
incurred. Capitalized costs at December 31, 1995 were:
 
<TABLE>
<CAPTION>
                                         UNITED                  SOUTH      OTHER
                                         STATES    INDONESIA    AMERICA    FOREIGN    WORLDWIDE
                                         ------    ---------    -------    -------    ---------
        <S>                              <C>       <C>          <C>        <C>        <C>
        Proved properties:
             Wells and related equipment
               and facilities........... $501.6     $  704.0    $307.0                 $1,512.6
             Support equipment and
               facilities...............  128.7                                           128.7
             Uncompleted well, equipment
               and facilities...........   11.0         18.6      50.5                     80.1
        Unproved properties.............   79.9        435.3     252.3      $ 1.3         768.8
                                         ------      -------    ------      -----      --------
                                          721.2      1,157.9     609.8        1.3       2,490.2
                                         ------      -------    ------      -----      --------
        Less-Accumulated depreciation,
          depletion and amortization....   50.4         67.7      20.9         .2         139.2
                                         ------      -------    ------      -----      --------
                                         $670.8     $1,090.2    $588.9      $ 1.1      $2,351.0
                                         ======      =======    ======      =====      ========
</TABLE>
 
COSTS INCURRED
 
     Costs incurred by the Company in its oil and gas producing activities for
the nine months ended December 31, 1995 (whether capitalized or charged against
earnings) were as follows:
 
<TABLE>
<CAPTION>
                                         UNITED                  SOUTH      OTHER
                                         STATES    INDONESIA    AMERICA    FOREIGN    WORLDWIDE
                                         ------    ---------    -------    -------    ---------
        <S>                              <C>       <C>          <C>        <C>        <C>
        Property acquisition costs...... $  2.1                                        $   2.1
        Exploration costs...............   10.1     $   19.8    $  7.6      $15.7         53.2
        Development costs...............   37.5         44.2      28.2         .3        110.2
                                         ------     --------    ------      -----      -------
                                         $ 49.7     $   64.0    $ 35.8      $16.0      $ 165.5
                                         ======     ========    ======      =====      =======
</TABLE>
 
  Oil and Gas Reserves
 
     The following table represents the Company's net interest in estimated
quantities of developed and undeveloped reserves of crude oil, condensate,
natural gas liquids and natural gas and changes in such quantities for the nine
months ended December 31, 1995. Net proved reserves are the estimated quantities
of crude oil and natural gas which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved developed
reserves are proved reserve volumes that can be expected to be recovered through
existing wells with existing equipment and operating methods. Proved undeveloped
reserves are proved reserve volumes that are expected to be recovered from new
wells on undrilled acreage or from existing wells where a significant
expenditure is required for recompletion.
 
     Estimates of reserves for December 31, 1995 were prepared by Gaffney, Cline
& Associates, petroleum engineers, using standard geological and engineering
methods generally accepted by the petroleum industry and in accordance with the
rules and regulations of the Securities and Exchange Commission ("SEC"). The
choice of method or combination of methods employed in the analysis of each
reservoir was determined by experience in the area, stage of development,
quality and completeness of basic data, and production history.
 
                                      F-65
<PAGE>   112
 
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, 1995
                                                  ------------------------------------------
                                                  UNITED                    SOUTH
                        CRUDE OIL                 STATES     INDONESIA     AMERICA     TOTAL
        ----------------------------------------- ------     ---------     -------     -----
                                                            (MILLIONS OF BARRELS)
        <S>                                       <C>        <C>           <C>         <C>
        Net Proved Developed and Undeveloped
          Reserves
        Beginning of period, March 31, 1995......   3.7        154.1         66.3      224.1
             Revisions of previous estimates.....    .2         (2.6)(a)     (4.5)      (6.9)
             Purchase of reserves in place.......
             Extensions, discoveries and other
               additions.........................    .5        7.1(a)         2.7       10.3
             Production..........................   (.3)       (14.5)        (3.4)(c)  (18.2)
             Sales of reserves in place..........
                                                  ------     ---------     -------     -----
        End of period............................   4.1        144.1         61.1      209.3
                                                  ------     ---------     -------     -----
        Net Proved Developed Reserves
        Beginning of period......................   2.8        136.8         14.0      153.6
        End of period............................   3.6        128.1         32.8      164.5
</TABLE>
 
<TABLE>
<CAPTION>
                                                                       DECEMBER 31, 1995
                                                                 ------------------------------
                                                                 UNITED
                           NATURAL GAS(B)                        STATES     INDONESIA     TOTAL
    ------------------------------------------------------------ ------     ---------     -----
                                                                    (BILLIONS OF CUBIC FEET)
    <S>                                                          <C>        <C>           <C>
    Net Proved Developed and Undeveloped Reserves
    Beginning of period, March 31, 1995.........................   505         300         805
         Revisions of previous estimates........................     7          18          25
         Purchase of reserves in place..........................
         Extensions, discoveries and other additions............    94          14         108
         Production.............................................   (36)        (19)        (55)
         Sales of reserves in place.............................
                                                                  ----         ---        ----
    End of period...............................................   570         313         883
                                                                  ----         ---        ----
    Net Proved Developed Reserves
    Beginning of period.........................................   373         103         476
    End of period...............................................   449         138         587
</TABLE>
 
                                      F-66
<PAGE>   113
 
<TABLE>
<CAPTION>
                                                                       DECEMBER 31, 1995
                                                                 ------------------------------
                                                                 UNITED
                        NATURAL GAS LIQUIDS                      STATES     INDONESIA     TOTAL
    ------------------------------------------------------------ ------     ---------     -----
                                                                     (MILLIONS OF BARRELS)
    <S>                                                          <C>        <C>           <C>
    Net Proved Developed and Undeveloped Reserves
    Beginning of period, March 31, 1995.........................  36.1         9.3        45.4
         Revisions of previous estimates........................   1.5          .1         1.6
         Purchase of reserves in place..........................
         Extensions, discoveries and other additions............   7.4                     7.4
         Production.............................................  (2.4)        (.4)       (2.8)
                                                                  ----        ----
    End of period...............................................  42.6         9.0        51.6
                                                                  ----        ----
    Net Proved Developed Reserves Beginning of period...........  28.9         3.1        32.0
    End of period...............................................  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 9.9 million barrels in 1995.
 
(b) Natural gas is reported on the basis of actual or calculated volumes which
     remain after removal, by lease or field separation facilities, of
     liquefiable hydrocarbons and of non-hydrocarbons where they occur in
     sufficient quantities to render the gas unmarketable. Natural gas reserve
     volumes include liquefiable hydrocarbons approximating 11% of total gas
     reserves in the United States and 4% in Indonesia which are recoverable at
     natural gas processing plants downstream from the lease or field separation
     facilities. Such recoverable liquids also have been included in natural gas
     liquids reserve volumes.
 
(c) Reserves in Venezuela are attributable to an operating service agreement
     under which all hydrocarbons are owned by the Venezuelan government,
     however, the Company receives payment for production and development
     services performed based on production.
 
  Future Net Cash Flows
 
     The standardized measure of discounted future net cash flows relating to
the Company's proved oil and gas reserves as of December 31, 1995 is calculated
and presented in accordance with Statement of Financial Accounting Standards No.
69. Accordingly, future cash inflows were determined by applying year-end oil
and gas prices (adjusted for future fixed and determinable price changes) to the
Company's estimated share of future production from proved oil and gas reserves.
Future income taxes were derived by applying year-end statutory tax rates to the
estimated net future cash flows. A prescribed 10% discount factor was applied to
the future net cash flows.
 
                                      F-67
<PAGE>   114
 
     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                     SOUTH
                                          STATES      INDONESIA     AMERICA     WORLDWIDE
                                          -------     ---------     -------     ---------
        <S>                               <C>         <C>           <C>         <C>
        Future cash flows...............  $1,161.0    $ 3,461.9     $ 822.5     $ 5,445.4
        Future production costs.........   (331.2)     (2,004.7)     (221.3)     (2,557.2)
        Future development costs........    (70.6)       (288.2)     (122.3)       (481.1)
                                          --------    ---------     -------     ---------
        Future net cash flows, before
          income taxes..................    759.2       1,169.0       478.9       2,407.1
        Discount for estimated timing of
          future cash flows.............   (342.9)       (459.4)     (200.0)     (1,002.3)
                                          --------    ---------     -------     ---------
        Present value of future net cash
          flows, before income taxes....    416.3         709.6       278.9       1,404.8
        Future income taxes, discounted
          at 10% (a)....................    (67.8)       (321.7)      (34.3)       (423.8)
                                          --------    ---------     -------     ---------
        Standardized measure of
          discounted future net cash
          flows.........................  $ 348.5     $   387.9     $ 244.6     $   981.0
                                          ========    =========     =======     =========
</TABLE>
 
---------------
 
(a) Future income taxes undiscounted are $161.6 for the United States, $508.2
     for Indonesia and $57.1 for South America at December 31, 1995.
 
     The following are the principal sources for change in the standardized
measure:
 
<TABLE>
<CAPTION>
                                                                              1995
                                                                             -------
        <S>                                                                  <C>
        January 1, 1995..................................................... $ 929.8
             Sales and transfers of oil and gas produced, net of production
              costs.........................................................  (322.7)
             Net changes in prices and production costs, net of future
              production and development costs..............................    99.6
             Extensions, discoveries and improved recovery, less related
              costs.........................................................    79.5
             Development costs incurred during the year that reduced future
              development costs.............................................   140.6
             Revisions of previous quantity estimates.......................    51.5
             Purchase of reserves in place..................................    16.3
             Sale of reserves in place......................................     (.1)
             Net change in income taxes.....................................   (42.8)
             Accretion of discount..........................................   131.1
             Changes in production rates (timing) and other.................  (101.8)
                                                                             -------
        December 31, 1995................................................... $ 981.0
                                                                             =======
</TABLE>
 
     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-68
<PAGE>   115
 
  Quarterly Data
 
<TABLE>
<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)         (.24)         (.28)          (.24)          (.76)
Market price per share:
     Common
          High.......................         529/32        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........................        1745/64       19 1/8         23 5/8        17 5/8         17 5/8
</TABLE>
 
<TABLE>
<CAPTION>
                                                                       1994
                                       ---------------------------------------------------------------------
                                       MARCH 31,      JUNE 30,   SEPTEMBER 30,   DECEMBER 31,   FOR THE YEAR
                                       ---------      --------   -------------   ------------   ------------
<S>                                    <C>            <C>        <C>             <C>            <C>
Sales and operating revenues.........   $ 187.1        $167.5       $ 170.2         $157.3         $682.1
Gross profit(a)(b)...................      41.2          42.0          54.7           44.3          182.2
Net income (loss)....................     (11.2)         30.1         (16.0)         (25.6)(c)      (22.7)
Per Common Share
     Net income (loss)...............      (.17)          .13          (.19)          (.26)          (.49)
Market price per share:
     Common
          High.......................         5 7/8         5 1/4          5 7/8         4 3/4          5 7/8
          Low........................         4 1/8         4 1/8          4 1/2         3 1/4          3 1/4
     $4.00 Preferred
          High.......................        45 3/4        41 1/8         40 1/2        37 3/4         45 3/4
          Low........................        39            33 5/8         37            30 1/8         30 1/8
     $2.50 Preferred
          High.......................        25 3/4        23 1/4         23 3/8        22 3/4         25 3/4
          Low........................        21 1/4        20            21 3/4         17 1/2         17 1/2
</TABLE>
 
---------------
 
(a) Gross profit is sales and operating revenues less purchases and operating
    expenses, gas purchase costs and depreciation, depletion and amortization.
 
(b) Gross profit has been restated to conform to the 1995 presentation.
 
(c) In the fourth quarter of 1994, the Company increased its reserve for future
    environmental liabilities by $49.0 million.
 
                                      F-69
<PAGE>   116
 
EXPLORATION AND PRODUCTION STATISTICS (historic)
 
<TABLE>
<CAPTION>
                                                  NINE MONTHS    THREE MONTHS
                                                     ENDED          ENDED
                                                  DECEMBER 31,    MARCH 31,
                                                      1995           1995          1994       1993       1992       1991
<S>                                               <C>            <C>              <C>        <C>        <C>        <C>
-------------------------------------------------------------------------------------------------------------------------
NET PROVED OIL RESERVES (millions of barrels)
United States                                           4.1            3.7           3.4       12.3       12.2       14.6
Indonesia                                             144.1          154.1         158.9      180.1      155.2      162.8
South America                                          61.1           66.3          67.0       71.6       53.1       27.5
-------------------------------------------------------------------------------------------------------------------------
    Worldwide Total                                   209.3          224.1         229.3      264.0      220.5      204.9
NET PROVED NATURAL GAS RESERVES
(billions of cubic feet)
United States                                           570            505           492        679        584        635
Indonesia                                               313            300           303        262        245         37
-------------------------------------------------------------------------------------------------------------------------
    Worldwide Total                                     883            805           795        941        829        672
NET OIL SALES (mbpd)
United States                                           1.1            1.0           2.4        4.9        5.7        9.9
Indonesia                                              53.0           52.0          59.3       62.4       61.9       67.3
South America                                          10.4            6.9           5.2
-------------------------------------------------------------------------------------------------------------------------
    Worldwide Total                                    64.5           59.9          66.9       67.3       67.6       77.2
AVERAGE OIL SALES PRICE (per bbl)
United States                                        $16.29         $16.07        $13.89     $16.99     $18.28     $19.49
Indonesia                                             17.01          17.54         15.61      17.31      18.40      19.59
South America                                         12.79          12.58         12.58
    Worldwide Average                                 16.31          16.94         15.31      17.28      18.39      19.58
NET NATURAL GAS SALES (mmcfpd)
United States produced                                  104             98           131        181        200        207
United States purchased for processing                   68             69            77         86         51         48
United States purchased for resale                                                    67         98         29         13
Indonesia                                                61             40            44         13          8          7
-------------------------------------------------------------------------------------------------------------------------
    Worldwide Total                                     233            207           319        378        288        275
AVERAGE NATURAL GAS SALES PRICE (per mcf)
United States produced                               $ 1.54         $ 1.42        $ 1.89     $ 2.13     $ 1.80     $ 1.66
United States purchased for processing                 1.42           1.49          1.81       1.91       1.62       1.49
United States purchased for resale                                                  2.00       2.06       1.84       1.57
Indonesia                                              2.62           2.65          2.24       1.30        .20        .20
    Worldwide Average                                  1.79           1.68          1.99       2.03       1.73       1.59
UNITED STATES NGL SALES (mbpd)
Produced                                                8.7            8.8           8.2        7.6        8.9        8.8
Purchased                                               8.9            9.6           9.7        9.8        9.0        7.9
-------------------------------------------------------------------------------------------------------------------------
    United States Total                                17.6           18.4          17.9       17.4       17.9       16.7
UNITED STATES AVERAGE NGL SALES PRICE (per bbl)
Produced                                             $10.42         $10.27        $10.02     $11.08     $11.51     $12.16
Purchased                                             10.57          10.48         10.12      11.19      11.13      12.04
    United States Average                             10.49          10.38         10.07      11.14      11.32      12.11
INDONESIAN NGL SALES (mbpd)                             1.7             .9           2.1        1.5        1.6        1.4
INDONESIAN AVERAGE NGL SALES PRICE (per bbl)         $14.33         $19.19        $ 9.42     $10.57     $11.93     $10.36
NET NATURAL GAS PRODUCTION (mmcfpd)
United States                                           130            125           156        208        227        238
Indonesia                                                70             45            47         13         13         11
-------------------------------------------------------------------------------------------------------------------------
    Worldwide Total                                     200            170           203        221        240        249
GROSS CRUDE OIL PRODUCTION (mbpd)
Indonesia                                               232            250           259        270        294        324
South America                                            40             32            16
</TABLE>
 
                                      F-70
<PAGE>   117
 
                               INDEX TO EXHIBITS
 
<TABLE>
<CAPTION>
                                                                                     SEQUENTIALLY
 EXHIBIT                                                                               NUMBERED
   NO.                                   DESCRIPTION                                     PAGE
---------- ------------------------------------------------------------------------  ------------
<C>        <S>                                                                       <C>
     3(i)  --Restated Certificate of Incorporation of the Company (Exhibit 3(i).2
             to the Company's Quarterly Report on Form 10-Q for the quarter ended
             June 30, 1995).*
     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).*
</TABLE>
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<TABLE>
<CAPTION>
                                                                                     SEQUENTIALLY
 EXHIBIT                                                                               NUMBERED
   NO.                                   DESCRIPTION                                     PAGE
---------- ------------------------------------------------------------------------  ------------
<C>        <S>                                                                       <C>
     4.11  --Indenture dated as of April 1, 1988 between the Company and Chemical
             Bank relating to unspecified debt securities of the Company (Exhibit
             4.11 to the 1992 Form 10-K).*
     4.12  --Officers' Certificate dated June 1, 1988 establishing a series of debt
             securities ($150,000,000 Medium-Term Notes, Series A) to be issued
             under the Indenture described in Exhibit 4.11 above (Exhibit 4.12 to
             the 1992 Form 10-K).*
     4.13  --Indenture dated as of November 1, 1990 between the Company and
             Chemical Bank relating to unspecified debt securities of the Company
             (Exhibit 4.13 to the 1992 Form 10-K).*
     4.14  --Officers' Certificate dated February 13, 1991 establishing a series of
             debt securities ($150,000,000 Medium-Term Notes, Series B) to be
             issued under the Indenture described in Exhibit 4.13 above (Exhibit
             4.14 to the 1992 Form 10-K).*
     4.15  --Officers' Certificate dated September 28, 1992 establishing a series
             of debt securities ($250,000,000 9 7/8% Notes Due 2002) to be issued
             under the Indenture described in Exhibit 4.13 above (Exhibit 4.15 to
             the 1992 Form 10-K).*
     4.16  --Officers' Certificate dated January 26, 1993 establishing a series of
             debt securities ($100,000,000 9 1/2% Notes Due 2003) to be issued
             under the Indenture described in Exhibit 4.13 above (Exhibit 4.16 to
             the 1992 Form 10-K).*
     4.17  --Officer's Certificate dated June 30, 1993 establishing a series of
             debt securities ($150,000,000 Medium-Term Notes, Series C) to be
             issued under the Indenture described in Exhibit 4.13 above (Exhibit 4
             to the Company's Current Report on Form 8-K dated June 21, 1993).*
     4.18  --Officer's Certificate dated 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  --Preferred Stock Purchase Agreement dated February 1, 1987 (the
             "Preferred Stock Purchase Agreement") between the Company and The
             Prudential Insurance Company of America ("Prudential") (Exhibit 4.17
             to the 1992 Form 10-K).*
     4.21  --Amendment dated February 8, 1987 to the Preferred Stock Purchase
             Agreement (Exhibit 4.18 to the 1992 Form 10-K).*
     4.22  --Registration Rights Agreement dated as of February 1, 1987 between the
             Company and Prudential (Exhibit 4.19 to the 1992 Form 10-K).*
     4.23  --Agreement dated April 12, 1990 amending the Preferred Stock Purchase
             Agreement (Exhibit 4.20 to the 1992 Form 10-K).*
     4.24  --Waiver of Certain Rights Relating to $9.75 Preferred Stock dated June
             5, 1990 between the Company and Prudential (Exhibit 4.21 to the 1992
             Form 10-K).*
     4.25  --Waiver of Certain Equity Offering Rights dated April 12, 1990 between
             the Company and Prudential amending the Preferred Stock Purchase
             Agreement (Exhibit 4.22 to the 1992 Form 10-K).*
</TABLE>
<PAGE>   119
 
<TABLE>
<CAPTION>
                                                                                     SEQUENTIALLY
 EXHIBIT                                                                               NUMBERED
   NO.                                   DESCRIPTION                                     PAGE
---------- ------------------------------------------------------------------------  ------------
<C>        <S>                                                                       <C>
     4.26  --Agreement dated February 28, 1995 between Prudential and the Company
             (Exhibit 2 to the Company's Schedule 14D-9 dated March 3, 1995 [the
             "Schedule 14D-9"]).*
     4.27  --Waiver of Certain Rights Relating to $9.75 Preferred Stock dated June
             8, 1995 between Prudential and the Company, filed herewith.
     4.28  --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).*
     4.29  --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).*
     4.30  --Agreement of Merger, dated February 28, 1995, among the Company, YPF
             Sociedad Anonima ("YPF") and YPF Acquisition Corp. ("YPFA") (Exhibit 3
             to the Schedule 14D-9).*
     4.31  --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"]).*
     4.32  --Credit Agreement dated as of June 16, 1995, between Maxus Indonesia,
             Inc., Maxus Northwest Java Inc., Maxus Southeast Sumatra, Inc., the
             lenders signatory thereto and Chase, as agent (Exhibit 4.2 to the June
             8, 1995 Form 8-K).*
    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 its executive officers (Exhibit 10.7 to the 1992
             Form 10-K).*
    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), filed herewith.
    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 1993 Form 10-K).*
    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).*
</TABLE>
<PAGE>   120
 
<TABLE>
<CAPTION>
                                                                                     SEQUENTIALLY
 EXHIBIT                                                                               NUMBERED
   NO.                                   DESCRIPTION                                     PAGE
---------- ------------------------------------------------------------------------  ------------
<C>        <S>                                                                       <C>
    10.12  --Rights Agreement dated as of September 2, 1988 between the Company and
             AmeriTrust Company National Association (Exhibit 10.24 to the 1992
             Form 10-K).*
    10.13  --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).*
    10.14  --Agreement of Merger dated as of February 28, 1995 among YPF, YPFA
             Corp. and the Company (Exhibit 3 to the Schedule 14D-9).*
    10.15  --International Consulting Agreement, dated May 1, 1995 between C. L.
             Blackburn and YPF, filed herewith.
    10.16  --Assignment of International Consulting Agreement, dated November 2,
             1995 between C. L. Blackburn, YPF, and the Company, filed herewith.
    10.17  --Maxus Severance Agreement dated August 3, 1995 between the Company and
             Roberto Luis Monti, filed herewith.
    10.18  --Compensation Agreement dated December 27, 1995 between the Company and
             Roberto L. Monti, filed herewith.
    10.19  --Services Agreement dated April 5, 1995 between the Company and Peter
             D. Gaffney, filed herewith.
    10.20  --Secondment Agreement dated April 5, 1995 between the Company, YPF and
             Gaffney, Cline & Associates, Inc., filed herewith.
    10.21  --Amendment to Change in Control Agreement dated May 11, 1995 between
             the Company and W. Mark Miller, filed herewith.
    10.22  --Employment Agreement effective as of July 1, 1995 between the Company
             and W. Mark Miller, filed herewith.
    10.23  --Specimen copy of a letter agreement regarding Change in Control
             Agreement dated April 7, 1995 between the Company and certain of its
             executive officers, filed herewith.
    10.24  --Letter Agreement regarding Change in Control Agreement dated April 13,
             1995 between the Company and Michael C. Forrest, filed herewith.
    10.25  --Specimen copy of a letter agreement regarding Change in Control
             Agreement dated ------------, 1995 between the Company and certain of
             its executive officers, 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.
</TABLE>