<PAGE>   1
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                       SECURITIES AND EXCHANGE COMMISSION
                            WASHINGTON, D.C.  20549
                            -----------------------

                                   FORM 10-K

[X]   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE 
      ACT OF 1934

                      FOR THE YEAR ENDED DECEMBER 31, 1995

[ ]   TRANSACTION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
      EXCHANGE ACT OF 1934

       For the transition period from _______________ to _______________

                         Commission file number 1- 8674

                         GLOBAL NATURAL RESOURCES INC.
             (Exact name of Registrant as specified in its charter)

           NEW JERSEY                                         93-0835865
(State or other jurisdiction of                              (IRS Employer
 incorporation or organization)                           Identification No.)

 5300 MEMORIAL DRIVE, SUITE 800                               77007-8295
         HOUSTON, TEXAS                                       (Zip Code)
 (Address of principal executive
            offices)

                REGISTRANT'S TELEPHONE NUMBER: (713) 880-5464

                     -----------------------------------

         SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

                                                    NAME OF EACH EXCHANGE
     TITLE OF EACH CLASS                             ON WHICH REGISTERED  
     -------------------                           -----------------------
Common Stock, $1.00 par value                      New York Stock Exchange

                     -----------------------------------

       SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:  None

                ---------------------------------------------

      Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.

                         X   YES                   NO
                       -----                 -----

      Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]

      State the aggregate market value of the voting stock held by
non-affiliates of the registrant.  (Computed by reference to the closing New
York Stock Exchange ("NYSE") price on March 1, 1996): $359,201,597.

      As of March 1, 1996, 29,624,874 shares of common stock were outstanding.

                      DOCUMENTS INCORPORATED BY REFERENCE

      Portions of the Registrant's definitive Proxy Statement dated March 28,
1996 for the Annual Stockholders' Meeting to be held May 7, 1996, are
incorporated by reference into Part III.

--------------------------------------------------------------------------------
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<PAGE>   2
                              TABLE OF CONTENTS
<TABLE>
<CAPTION>
                                                                                                         PAGE
                                                                                                         ----
<S>                                                                                                       <C>
Part I.   Items 1
           and 2.   Business and Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . .        1
                    The Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        1
                    Oil and Gas Reserves  . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        2
                    Oil and Gas Operations  . . . . . . . . . . . . . . . . . . . . . . . . . . . .        4
                        United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        4
                        Russia  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        8
                        Ivory Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       11
                        Egypt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       14
                        Indonesia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       17
                        Malaysia  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       20
                        Turkey  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       21
                    Pipeline Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       21
                    Other Operations  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       23
                          Investment Properties International Limited . . . . . . . . . . . . . . .       23
                          Argentina . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       23
                          Arctic Islands Interest . . . . . . . . . . . . . . . . . . . . . . . . .       23
                          North Cook Inlet  . . . . . . . . . . . . . . . . . . . . . . . . . . . .       23
                          Foreign Acreage . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       24
                    Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       24
                          Regulatory Matters  . . . . . . . . . . . . . . . . . . . . . . . . . . .       24
                          Additional Factors Affecting the Business . . . . . . . . . . . . . . . .       28
                          Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       28

          Item 3.   Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       29

          Item 4.   Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . .       29

Part II.  Item 5.   Market for Registrant's Common Equity and Related Stockholder Matters . . . . .       30

          Item 6.   Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . .       30

          Item 7.   Management's Discussion and Analysis of Financial Condition and Results
                      of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       31

          Item 8.   Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . .       37

          Item 9.   Changes in and Disagreements with Accountants on Accounting and
                      Financial Disclosure  . . . . . . . . . . . . . . . . . . . . . . . . . . . .       64

Part III. Item 10.  Directors and Executive Officers of the Registrant  . . . . . . . . . . . . . .       64

          Item 11.  Executive Compensation  . . . . . . . . . . . . . . . . . . . . . . . . . . . .       64

          Item 12.  Security Ownership of Certain Beneficial Owners and Management  . . . . . . . .       64

          Item 13.  Certain Relationships and Related Transactions  . . . . . . . . . . . . . . . .       64

Part IV.  Item 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . .       65

          Signatures  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       66
</TABLE>





                                       i
<PAGE>   3
                                    PART I

ITEMS 1. AND 2.  BUSINESS AND PROPERTIES

                                  THE COMPANY

     Global Natural Resources Inc., its predecessor, and their respective
subsidiaries are hereinafter referred to collectively as the "Company." The
Company was incorporated in New Jersey in 1983 and is the successor to Global
Natural Resources PLC, a company organized in 1970 under the laws of the United
Kingdom. The Company is an independent producer of oil and natural gas and has
operations in the United States, Tatarstan - Russia, Indonesia, Ivory Coast,
Egypt, and Malaysia.  The principal executive offices of the Company are
located at 5300 Memorial Drive, Suite 800, Houston, Texas 77007-8295.

     In 1992, the Company adopted a two-fold strategy to direct internally
generated cash at growing the Company's  base domestic assets, while directing
the balance sheet cash primarily towards international opportunities.  The
primary objective is to generate significant growth in assets by means of
exploratory drilling, both domestically and internationally.

     The Company's principal domestic activities during 1995 were concentrated
in the Texas gulf coast and offshore Gulf of Mexico.  During 1995, the Company
continued to expand its seismic data base, from which it will identify
opportunities of suitable reserve potential and geologic risk.  One of the six
exploratory wells completed in 1995 was developed and operated by the Company.
In addition, the Company will continue evaluating farm-in opportunities from
other companies.

     The Company's Russian activities began in 1990 and are conducted through
its 90% owned subsidiary, Texneft Inc.  ("Texneft"), which has a 50% interest
in a joint venture ("Tatex") in Tatarstan, a republic which is part of the
Russian Federation.  Texneft's 50% partner in the joint venture is Tatneft, a
Russian open joint stock company which operates the oil fields of Tatarstan.
Joint venture activities currently include three projects: 1) vapor recovery,
2) the development and operation of the Onbysk field and 3) the development and
operation of the Suncheleevsky and Demkinsky fields.

     In May 1993, the Company acquired an interest in 335,320 gross acres in
block CI-11 offshore Ivory Coast, West Africa.  The Company acquired a 10%
working interest in an area referred to as the "Special Area" and a 16% working
interest in an area referred to as the "Remaining Area."  During 1995, the
Company drilled the third discovery well and completed four development wells.
First oil production occurred in the second quarter of 1995 with initial gas
production commencing in the fourth quarter of 1995.  Block CI-11 is currently
producing approximately 20,000 barrels of oil and 50 Mmcf of gas per day.  In
addition, in 1995 the Company and its working interest partners executed a
production sharing contract with the government of the Ivory Coast on Block
CI-12 which lies adjacent to the west of CI-11.

     In August 1994, the Company acquired a 25% working interest in the 1.9
million acre Qarun block located in the western desert of Egypt.  During 1994,
the Company drilled two discoveries on this block (Qarun A and Qarun B) and
added a third discovery (Sakr) in 1995.  Limited oil production began in the
fourth quarter of 1995.  The Company is proceeding with the development of this
block including construction of a pipeline, two 20,000 barrels of oil per day
production trains and storage facilities which are projected to be operational
in the fourth quarter of 1996.

     In Indonesia, the Company has a 1.714% interest in a joint venture for the
exploration, development and production of oil and gas in East Kalimantan,
Indonesia, under a production sharing contract ("PSC") with Perusahaan
Pertambangan Minyak Dan Gas Bumi Negara, the state petroleum enterprise of
Indonesia ("Pertamina").

     USAgas Pipeline, Inc. ("USAgas") is engaged in the operation and
development of natural gas gathering and transmission systems, natural gas
processing and treating plants, and the marketing and transportation of natural
gas for the Company and its joint interest partners.

     For financial information relating to industry segments, see Note 10 of
Notes to Consolidated Financial Statements included herein.


                                       1
<PAGE>   4
                             OIL AND GAS RESERVES*

     The Company's net quantities of proved oil and natural gas reserves, the
estimated future net revenues based upon year end prices held constant for life
and the present value of estimated future net revenues of oil and gas reserves
calculated at a 10% discount rate for the three years ended December 31, 1995
are presented in the table below.

<TABLE>
<CAPTION>
                                                                                   DECEMBER 31,
                                                                      ---------------------------------------
                                                                        1995           1994            1993
                                                                      --------        --------       --------
<S>                                                                   <C>             <C>            <C>
UNITED STATES
Natural gas (Mmcf)  . . . . . . . . . . . . . . . . . . . . . .         68,623          59,498         63,981
Oil and condensate (MBbl) . . . . . . . . . . . . . . . . . . .          2,721           2,173          1,459
Future net revenues before tax (thousands)  . . . . . . . . . .       $146,825        $ 85,396       $108,418
Present value of future net revenues before tax (thousands) . .       $110,477        $ 61,090       $ 73,027
Present value of future net revenues after tax (thousands)  . .       $ 90,747        $ 59,990       $ 68,227

RUSSIA(2)
Natural gas (Mmcf)  . . . . . . . . . . . . . . . . . . . . . .             --              --             --
Oil and condensate (MBbl)(3)  . . . . . . . . . . . . . . . . .         15,570          13,157          7,297
Future net revenues before tax (thousands)  . . . . . . . . . .       $113,690        $ 77,990       $ 34,796
Present value of future net revenues before tax (thousands) . .       $ 58,844        $ 44,193       $ 17,833
Present value of future net revenues after tax (thousands)(4) .       $ 39,510        $ 30,809       $ 12,825

IVORY COAST(5)
Natural gas (Mmcf)  . . . . . . . . . . . . . . . . . . . . . .         21,066          18,432            --
Oil and condensate (MBbl) . . . . . . . . . . . . . . . . . . .          3,010           2,210            --
Future net revenues before tax (thousands)  . . . . . . . . . .       $ 67,855        $ 28,853       $    --
Present value of future net revenues before tax (thousands) . .       $ 48,883        $ 13,778       $    --
Present value of future net revenues after tax (thousands)  . .       $ 37,032        $  9,441       $    --

EGYPT
Natural gas (Mmcf)  . . . . . . . . . . . . . . . . . . . . . .          1,399              --            --
Oil and condensate (MBbl) . . . . . . . . . . . . . . . . . . .          7,918           3,520            --
Future net revenues before tax (thousands)  . . . . . . . . . .       $ 66,097        $ 26,250       $    --
Present value of future net revenues before tax (thousands) . .       $ 44,230        $ 14,357       $    --
Present value of future net revenues after tax (thousands)  . .       $ 25,049        $  8,152       $    --

INDONESIA(1)
Natural gas (Mmcf)  . . . . . . . . . . . . . . . . . . . . . .         72,892          79,990         79,706
Oil and condensate (MBbl) . . . . . . . . . . . . . . . . . . .          1,153           1,066          1,005
Future net revenues before tax (thousands)  . . . . . . . . . .       $143,229        $131,838       $110,900
Present value of future net revenues before tax (thousands) . .       $ 72,187        $ 67,369       $ 55,783
Present value of future net revenues after tax (thousands)  . .       $ 36,708        $ 34,223       $ 28,150

TOTALS
Natural gas (Mmcf)  . . . . . . . . . . . . . . . . . . . . . .        163,980         157,920        143,687
Oil and condensate (MBbl)(3)  . . . . . . . . . . . . . . . . .         30,372          22,126          9,761
Future net revenues before tax (thousands)  . . . . . . . . . .       $537,696        $350,327       $254,114
Present value of future net revenues before tax (thousands) . .       $334,621        $200,787       $146,643
Present value of future net revenues after tax (thousands)(4) .       $229,046        $142,615       $109,202
</TABLE>
------------------
*    Quantities of gas are expressed throughout as "Mcf" or "Mmcf" or "Bcf"
     meaning  thousand, million or billion cubic feet, respectively.
     Quantities of oil are expressed as "Bbl" or "MBbl" or "Mmbl" meaning
     barrel, thousand barrels, or million barrels, respectively.

(1)  The Indonesian Joint Venture ("IJV") has no ownership in the underlying
     oil and gas reserves.  The Company's reserve estimates in Indonesia have
     been obtained by the Company from a public source which, although not
     independently verified, the Company believes to be reliable.  All
     Indonesian Mmcf amounts are for dry gas.

                                         (Footnotes continued on following page)


                                       2
<PAGE>   5
(2)  The Russian reserves are associated with three projects operated by the
     Company's Russian joint venture, Tatex.  These projects are vapor
     recovery, Onbysk field development and the Suncheleevsky and Demkinsky
     field development.  The vapor recovery reserves are derived from recovered
     stock tank vapors which are exchanged for export grade crude oil and sold
     on the international market.  Tatex has no ownership in the underlying oil
     reserves which are initially placed in the stock tanks.  The Company's
     share of the Onbysk field anticipated recoverable reserves are computed
     net of the Base Oil future production which is retained by an affiliate of
     Tatneft under the terms of the field lease agreement.  Base Oil
     attributable to the Onbysk field amounts to 2.8 million barrels over the
     remaining eighteen year term of the field lease.  Production costs
     associated with Base Oil volumes are paid to the joint venture by Tatneft
     affiliates.  The Suncheleevsky and Demkinsky fields have eighteen cased
     wells which have been logged and tested oil and are considered candidates
     for re-entry and completion as potential producers.  Proved undeveloped
     reserves of 1.9 million barrels net to the Company have been assigned.

(3)  Includes reserves of 1,557 MBbl, 1,316 MBbl and 1,459 MBbl in 1995, 1994
     and 1993, respectively, attributable  to a minority interest in a
     consolidated subsidiary  which was 10% in 1995 and 1994 and 20% during
     1993.

(4)  Includes $5.9 million, $3.1 million, and $2.6 million in 1995, 1994 and
     1993, respectively, attributable to a minority interest in a consolidated
     subsidiary  which was 10% in 1995 and 1994 and 20% during 1993.

(5)  Includes primary reserves only in 1995.  If secondary recovery techniques
     were to be implemented, a decrease of 151 Mmcf, an increase of 461 MBbl,
     an increase of $1.2 million in future net revenues before tax and a
     decrease in the present value of future net revenues before tax of $1.5
     million would result.

     At December 31, 1995, 1994 and 1993, the Company's gross oil and gas
reserve estimates for properties located in the United States and Russia were
prepared by Ryder Scott Company Petroleum Engineers.  At December 31, 1995 and
1994, Ivory Coast and Egyptian gross oil and gas reserve estimates were
prepared by Netherland, Sewell & Associates, Inc.  Indonesian reserves were
based on information obtained by the Company from public sources.

     Domestic reserve volumes increased in 1995 in comparison with 1994 because
of a new discovery on South Pass 78 in federal waters offshore Louisiana and
due to revisions from probable to proved reserves at Taylor Lake.  Future net
revenues before taxes increased from $61.1 million in 1994 to $110.4 million in
1995 due to an increase in year end oil and natural gas prices and the
associated volume increases previously discussed.

     Russian reserve volumes increased in 1995 in comparison to 1994 as a
result of upward revisions of previous estimates and the addition of the
Suncheleevsky field development project.  The increase of $14.6 million in
future net revenues from Russian properties in 1995 compared with 1994
corresponds to the combined effects of improved year end oil prices and reserve
additions.

     Ivory Coast reserve volumes increased in 1995 in comparison with 1994 due
to the drilling of three successful development wells and two successful
exploration wells.  The increase of $35.1 million in future net revenues before
tax in 1995 compared with 1994 corresponds to the combined effects of improved
year end oil and natural gas prices and reserve additions.

     Egyptian reserve volumes increased in 1995 in comparison with 1994 due to
the drilling of five successful development wells and one successful
exploration well.  The increase of $29.8 million in future net revenues before
tax in 1995 compared with 1994 corresponds to the combined effects of improved
year end oil prices and reserve additions.

     Indonesian reserve volumes decreased slightly during 1995 in comparison to
1994 due to 1995 production and revisions to previous estimates.  The $11.4
million increase in Indonesian future net revenues before tax in 1995 as
compared to 1994 was primarily the result of an increase in year end gas prices
from 1994 to 1995.

     Domestic reserve volumes remained flat in 1994 in comparison with 1993
because 1994 discoveries, positive revisions to previous reserve estimates and
purchases of reserves offset 1994 production and sales of reserves.  Future net
revenues before taxes decreased from 1993 to 1994 primarily due to the decrease
in year end 1994 natural gas prices.

     Russian reserve volumes increased in 1994 in comparison with 1993 due
primarily to the reclassification of additional undeveloped reserves in the
Onbysk field as proved undeveloped which were previously considered uneconomic
as a result of the lower crude oil price prevailing at year end 1993.
Significant increases also resulted from





                                       3
<PAGE>   6
upward revisions of previous estimates.  The increase in future net revenues
from Russian properties in 1994 compared with 1993 corresponds to the combined
effects of improved year end oil prices and reserve additions.

     Indonesian reserve volumes increased slightly during 1994 in comparison
with 1993 due primarily to revisions to previous estimates being somewhat
greater than production.  The increase in Indonesian future net revenues before
tax in 1994 compared to 1993 was $20.9 million.  This increase was primarily
the result of an increase in year end gas prices from 1993 to 1994.

     Selected major areas in the United States in which the Company held an
interest at December 31, 1995 are summarized in the table below.
<TABLE>
<CAPTION>
                                                              TOTAL
                                                         PROVED RESERVES
                                                     ---------------------
                                                       OIL            GAS
MAJOR AREA                                           (MBBLS)        (MMCF)
                                                     -------        ------
<S>                                                  <C>            <C>
Offshore Gulf Coast . . . . . . . . . . . . .        2,011          32,484
Taylor Lake . . . . . . . . . . . . . . . . .          168          17,462
San Juan Basin  . . . . . . . . . . . . . . .            4          12,987
Royalties . . . . . . . . . . . . . . . . . .          161           3,147
</TABLE>

     The above reserves account for 86% of the Company's United States oil
reserves and 96% of the Company's United States gas reserves at December 31,
1995.

     Reserve estimates are based on many judgmental factors and may differ from
the quantities of oil and gas ultimately recovered. The accuracy of reserve
estimates depends on the quantity and quality of geological data, production
performance data and reservoir engineering data as well as the skill and
judgment of petroleum engineers in interpreting such data. Generally, reserve
estimates based on volumetric analysis (as is the case with certain fields
included in the above estimates) are less reliable than those based on lengthy
production history. The process of estimating reserves involves continual
revision of estimates (usually on an annual basis) based on additional
information becoming available through drilling, testing, reservoir studies and
acquiring historical pressure and production data and to reflect the impact of
changes in oil and gas prices. In addition, the discounted present value of
estimated future net revenues should not be construed as the fair market value
of oil and gas producing properties. Revenue calculations are based on
estimates by petroleum engineers as to the timing of oil and gas production,
and there is no assurance the actual timing of production will conform to, or
approximate, such estimates. Also, the estimates assume that prices will remain
constant from the date of the engineers' estimates except for changes reflected
under natural gas purchase contracts.  There can be no assurance that actual
future prices will not vary as industry conditions, governmental regulations
and other factors affect the market price for oil and gas.

     The Company has not filed estimates of its net oil and gas reserves with
any other federal agencies within the last year.  Certain reserve information
is provided to the Department of Energy each year. However, such reserve
information is accumulated on a total operated and gross working interest basis
and not on a Company net basis, as provided above.

     See Supplementary Tables on Reserve Data and Oil and Gas Operations
following Notes to Consolidated Financial Statements for additional data
relating to oil and gas producing activities in Item 8, herein.

                            OIL AND GAS OPERATIONS
UNITED STATES

GENERAL

     The Company conducts oil and gas exploration and development for its own
interest or in conjunction with others.  In this connection, the Company may
develop its own prospects and "farm-out" a portion of such prospects by
assigning interests to third parties or "farm-in" prospects by acquiring
interests from third parties.  One of the six exploratory wells completed
during 1995 was developed and operated by the Company.   In addition, the
Company continues to add to its seismic database, from which it will identify
suitable opportunities of reserve potential and geologic risk.





                                       4
<PAGE>   7
     In 1995, 1994 and 1993, revenues from domestic production accounted for
approximately 32%, 32% and 26% of the Company's revenues, respectively.
Domestic oil and gas operations reported income (loss) before income tax
expense of $(8) million, $(11.8) million and $3.6 million in 1995, 1994 and
1993, respectively.

EXPLORATION AND DEVELOPMENT ACTIVITIES AND PRODUCING WELLS

     The Company expended approximately $22.9 million, $34.6 million and $14
million in 1995, 1994 and 1993, respectively, for domestic oil and gas
exploration and development.  In 1995, the Company's activities were
principally in the offshore Gulf of Mexico and gulf coast areas.

     The Company's 1996 domestic budget is approximately $16 million, of which
approximately $6 million is intended for exploration activities.  The majority
of these expenditures are planned for the Texas gulf coast and offshore Gulf of
Mexico areas.

     The Company's domestic oil and gas exploration and development drilling
during the years indicated and the gross and net wells in which the Company had
a working interest were as follows:

                              WELLS DRILLED (1)

<TABLE>
<CAPTION>
                                                 EXPLORATORY          DEVELOPMENT
                                                    WELLS                WELLS                TOTAL
                                               --------------       --------------        -------------
                                               GROSS      NET       GROSS      NET        GROSS     NET
                                               -----      ---       -----      ---        -----     ---
<S>                                             <C>       <C>        <C>       <C>          <C>     <C>
1995
Oil . . . . . . . . . . . . . . . . . .          -         -           3       0.1           3      0.1
Gas . . . . . . . . . . . . . . . . . .           2       0.5          4       0.4           6      0.9
Dry . . . . . . . . . . . . . . . . . .           5       1.4         -         -            5      1.4
                                               -----      ---       -----      ---        -----     ---
   Total  . . . . . . . . . . . . . . .           7       1.9          7       0.5          14      2.4
                                               =====      ===       =====      ===        =====     ===
1994                                                                                                
Oil . . . . . . . . . . . . . . . . . .          -         -           6       0.4           6      0.4
Gas . . . . . . . . . . . . . . . . . .           9       2.7         12       1.8          21      4.5
Dry . . . . . . . . . . . . . . . . . .           9       3.8         -         -            9      3.8
                                               -----      ---       -----      ---        -----     ---
   Total  . . . . . . . . . . . . . . .          18       6.5         18       2.2          36      8.7
                                               =====      ===       =====      ===        =====     ===
1993
Oil . . . . . . . . . . . . . . . . . .           1       0.2          3       0.2           4      0.4
Gas . . . . . . . . . . . . . . . . . .           4       1.1         10       0.2          14      1.3
Dry . . . . . . . . . . . . . . . . . .           5       1.1          1       0.3           6      1.4
                                               -----      ---       -----      ---        -----     ---
   Total  . . . . . . . . . . . . . . .          10       2.4         14       0.7          24      3.1
                                               =====      ===       =====      ===        =====     ===
</TABLE>
     ------------------   
     (1)  The term "gross" as used herein with respect to wells refers to the
          total number of wells in which the Company has any interest and "net"
          refers to the Company's  interest in such wells.

     At December 31, 1995, the Company had no exploratory wells and 1 gross
(0.1 net) development well awaiting completion; no exploratory wells and 2
gross (0.3 net) development wells were in the process of drilling.

               PRODUCING WELLS AND WELLS CAPABLE OF PRODUCTION

<TABLE>
<CAPTION>
                                    GROSS PRODUCING               NET PRODUCING
                                    ---------------               -------------
<S>                                          <C>                            <C>
1995(1)                                              
Oil . . . . . . . . . . . . . . .            1,754                          10
Gas . . . . . . . . . . . . . . .              438                          23
                                    ---------------              --------------
    Total   . . . . . . . . . . .            2,192                          33
                                    ===============              ==============
</TABLE>

                                             (Table continued on following page)





                                       5
<PAGE>   8
<TABLE>
<CAPTION>
                                    GROSS PRODUCING               NET PRODUCING
                                    ---------------               -------------
<S>                                          <C>                            <C>
1994                             
Oil . . . . . . . . . . . . . . .            1,754                          10
Gas . . . . . . . . . . . . . . .              430                          20
                                    ---------------              --------------
    Total   . . . . . . . . . . .            2,184                          30
                                    ===============              ==============
                                                                            
1993                                                                        
Oil . . . . . . . . . . . . . . .            1,763                          15
Gas . . . . . . . . . . . . . . .              482                          33
                                    ---------------              --------------
    Total   . . . . . . . . . . .            2,245                          48
                                    ===============              ==============
</TABLE>
         ----------------   
         (1)     The number of oil and gas wells completed in more than one
                 producing formation were 5 gross (1.2 net) wells at December
                 31, 1995.

     The decrease in gross and net producing wells from 1993 to 1994 was the
result of the 1994 dispositions of certain domestic properties.

PRODUCING AND MARKETING ACTIVITIES

     The Company's United States oil and gas sales in 1995 aggregated $24.9
million, of which gas sales accounted for 83%.  The following table is a
summary of the Company's domestic production volumes expressed in Bbls and Mcfs,
average sales prices and average production (lifting) costs for each of the
three years ended December 31, 1995.

<TABLE>
<CAPTION>
VOLUME PRODUCED                                                       1995          1994          1993
---------------                                                   -----------    ----------    ----------
<S>                                                               <C>            <C>           <C>
Oil and Condensate (Bbl)  . . . . . . . . . . . . . . . .             244,000       229,000       263,000
Natural Gas (Mcf) . . . . . . . . . . . . . . . . . . . .          13,710,000     8,904,000     7,088,000

AVERAGE SALES PRICE
-------------------
Oil and Condensate per Bbl  . . . . . . . . . . . . . . .         $     17.20    $    15.65    $    17.11
Natural Gas per Mcf (1) . . . . . . . . . . . . . . . . .         $      1.51    $     1.86    $     2.11

AVERAGE LIFTING COSTS(2)
------------------------
Bbl equivalent  . . . . . . . . . . . . . . . . . . . . .         $      2.27    $     1.97    $     2.61
Mcf equivalent  . . . . . . . . . . . . . . . . . . . . .         $      0.38    $     0.33    $     0.44
</TABLE>
     ------------------    
     (1)  Included in the 1993 gas revenues are pricing dispute settlement
          proceeds of approximately $660,000.  The 1993 gas price excluding
          this settlement would have been $2.01 per Mcf.

     (2)  For purposes of this computation, one barrel is considered equivalent
          to six Mcf, although actual oil to gas equivalent will vary based
          upon British Thermal Unit (BTU) content. Since the same field or well
          often produces both oil and gas, lifting costs per Bbl or Mcf
          represent the aggregate lifting costs per unit based on the foregoing
          equivalent.

     The Company's domestic natural gas production is marketed by USAgas
through a combination of long-term and spot-market contracts. The ability of
the Company to sell natural gas and the price obtained depends on numerous
considerations, including contractual terms (such as "market-out" price
reduction provisions and other provisions of long-term contracts), market
conditions in general, curtailments by gas purchasers and transportation
companies, the effects of government legislation and regulations on production,
transportation tariffs and the proximity of wells to adequate transmission
facilities.  While gas curtailments and price reductions can affect earnings
and cash flow, the ability to seek alternate markets is generally available.

     During 1995, the Company sold gas production from most of its properties
to unaffiliated third parties for spot- market prices.  The Company marketed
the majority of its operated production of crude oil and condensate to
Hydrocarbon Processing, Inc. and Sun Refining and Marketing Company,
unaffiliated third parties. The price obtained for crude oil and condensate
depends on various considerations, including the location, grade and quality of
production and general market conditions in world oil markets. Crude oil and
condensate are generally sold pursuant to short-term contracts.  The Company
generally sells such production at a premium over the posted price.

                                       6
<PAGE>   9
     Reference is made to the Supplementary Tables on Reserve Data and Oil and
Gas Operations following the Notes to Consolidated Financial Statements for
additional data relating to oil and gas producing activities in Item 8, herein.

ACREAGE

     The Company's current policy is to acquire acreage associated with
specific prospects, thereby minimizing carrying costs and administrative
expenses.  Acreage in the United States in which the Company had an interest at
December 31, 1995 is summarized in the table below.

<TABLE>
<CAPTION>
                                                                           MINERAL AND ROYALTY
                                           WORKING INTEREST ACREAGE          INTEREST ACREAGE
                                           ------------------------      ----------------------
                                             GROSS           NET           GROSS          NET
                                           ---------      ---------      ---------     --------
<S>                                         <C>            <C>           <C>           <C>
PRODUCING OR DEVELOPED ACREAGE
Alabama . . . . . . . . . . . . . . . .       4,192         1,360          2,720          312
Alaska  . . . . . . . . . . . . . . . .        --            --            9,920          103
California  . . . . . . . . . . . . . .         152            13            779            7
Colorado  . . . . . . . . . . . . . . .         200            66            838           13
Kansas  . . . . . . . . . . . . . . . .        --            --            5,880           84
Louisiana . . . . . . . . . . . . . . .       1,040           353         17,448          904
Michigan  . . . . . . . . . . . . . . .         837           309           --           --
Mississippi . . . . . . . . . . . . . .         217            54          5,770          195
Montana . . . . . . . . . . . . . . . .         480            41           --           --
New Mexico  . . . . . . . . . . . . . .       2,500           855         45,364          552
North Dakota  . . . . . . . . . . . . .       2,244           279            360            1
Offshore (Gulf of Mexico) . . . . . . .      19,927         6,899           --           --
Oklahoma  . . . . . . . . . . . . . . .       2,319           359         83,553        3,431
Texas . . . . . . . . . . . . . . . . .      26,849         5,257         94,368        2,873
Utah  . . . . . . . . . . . . . . . . .         160            80          9,019          187
Wyoming . . . . . . . . . . . . . . . .       2,510         1,300          1,649           44
Other . . . . . . . . . . . . . . . . .         905            83            320            5
                                           ---------      --------      ---------     --------
    Total   . . . . . . . . . . . . . .      64,532        17,308        277,988        8,711
                                           =========      ========      =========     ========

UNDEVELOPED ACREAGE
Alabama . . . . . . . . . . . . . . . .       2,715           930         13,177        1,190
Alaska  . . . . . . . . . . . . . . . .        --            --            3,834           29
California  . . . . . . . . . . . . . .        --            --              528           30
Colorado  . . . . . . . . . . . . . . .      15,486        13,019         24,948        6,056
Kansas  . . . . . . . . . . . . . . . .         160            72         10,302          308
Louisiana . . . . . . . . . . . . . . .       1,530           597         14,713          223
Michigan  . . . . . . . . . . . . . . .         363           194          1,430          363
Mississippi . . . . . . . . . . . . . .         514           145         29,836          795
Montana . . . . . . . . . . . . . . . .         880            52          4,220          197
New Mexico  . . . . . . . . . . . . . .       4,370           642         16,733          676
North Dakota  . . . . . . . . . . . . .         786            15         38,316        2,582
Offshore (Gulf of Mexico) . . . . . . .      70,499        30,012          1,946           18
Oklahoma  . . . . . . . . . . . . . . .       1,198            56         60,185        3,446
Texas . . . . . . . . . . . . . . . . .      51,477        17,857         64,482        3,525
Utah  . . . . . . . . . . . . . . . . .        --            --           16,323          780
Wyoming . . . . . . . . . . . . . . . .       7,797         2,845          5,936           59
Other . . . . . . . . . . . . . . . . .         792            80          1,348           28
                                           ---------      --------      ---------     --------
    Total   . . . . . . . . . . . . . .     158,567        66,516        308,257       20,305
                                           =========      ========      =========     ========
</TABLE>





                                       7
<PAGE>   10
RUSSIA

GENERAL

     Through its 90% owned subsidiary, Texneft, the Company has a net 45%
interest in a joint venture in Russia with Tatneft, a Russian open joint stock
company which operates the oil fields of Tatarstan, a republic which is part of
the Russian Federation located west of the Ural Mountains and east of the Volga
River.  The joint venture, Tatex, which is owned 50% by Tatneft and 50% by
Texneft, was registered with the Ministry of Finance of the former USSR on
November 15, 1990 and is also registered with the governments of Russia,
Tatarstan and the city of Almetyevsk.  Under the terms of the joint venture and
various supplemental agreements, the funding for the joint venture is supplied
by Texneft and Tatneft through various credit agreements. In November 1994, the
Company purchased an additional 10% of Texneft's common stock for approximately
$.5 million increasing its ownership from 80% to 90%.  An agreement between the
minority shareholder of Texneft and the Company requires the Company to advance
to Texneft sufficient cash to fund its administrative expenses and its
contributions to Tatex.  In turn, Texneft will make no distributions to its
shareholders until the Company has been repaid a sum equal to the total of its
advances to Texneft.

     The joint venture's activities currently include three projects:  1) vapor
recovery, 2) the development and operation of the Onbysk field and 3) a new
project, the development and operation of the Suncheleevsky and Demkinsky
fields.  A fourth project, well stimulation in and adjacent to the sizable
Romashkino field is currently inactive.  The vapor recovery project began
operations in 1991.  Tatex installed and operates vapor recovery facilities
which recover stock tank vapors from Tatneft's production facilities located
near the city of Almetyevsk. The recovered vapors are exchanged for export
grade Volga-Ural crude oil, which is sold for hard currency on the
international market.  The vapor recovery activity at certain locations
eliminates gas and associated liquids which would otherwise be flared and thus
reduces the level of harmful pollutants;  however, production has declined at
certain tank farms such that of the twenty-two vapor units delivered, only 20
units were in service at the end of 1995 at 18 tank farms.  Tatex received
774,000 barrels, 790,000 barrels and 573,000 barrels in exchange for recovered
vapors during 1995, 1994 and 1993, respectively.  Tatex expects to meet its
government approved quota to export an average of 2,154 barrels of oil per day
in 1996.

     In August 1993, Tatex signed a 20 year lease agreement with Zainskneft, an
affiliate of Tatneft, pursuant to which Tatex assumed operations and
development of the Onbysk field effective January 1, 1993.  The lease
agreement, which requires lease payments totaling 349 million rubles over the
life of the lease, includes a provision that the equipment will become the sole
property of Tatex at the end of the lease.  Tatex prepaid the lease obligation
in 1993 by making a one time payment of $295,000.  In addition to the lease
payments, the agreement provides for the delivery of Base Oil volumes to
Zainskneft during the life of the lease.  The Base Oil production has been
defined as the expected production of the field were the previous operator to
continue operations and equals a total of 725 barrels of oil per day during
1996 which is estimated to decline at a rate of 10% per year.  Any oil
incremental to this volume, defined as "Own Oil," is the property of Tatex and
may be exported for hard currency.

     Tatex continued development drilling in the Onbysk field in 1995.
Fourteen directional wells, three horizontal wells and one dry exploratory test
well were drilled by Texneft directed personnel.  Production for 1995 before
shrinkage and other losses totaled approximately 1,604,000 barrels of oil, of
which approximately 291,000 barrels were classified as Base Oil and 1,313,000
barrels as Own Oil, from a total of 154 wells producing on December 31, 1995.
Production for 1994 totaled approximately 1,075,000 barrels of oil, of which
approximately 240,000 barrels were classified as Base Oil and 835,000 barrels
as Own Oil, from a total of 139 wells producing on December 31, 1994.
Production for 1993 totaled approximately 541,000 barrels, of which
approximately 328,000 barrels were classified as Base Oil and 213,000 barrels
as Own Oil, from a total of 114 wells producing on December 31, 1993.  The
aerial extent and multiple reservoirs present in the Onbysk field will require
considerable future drilling.  The pace of development of this field will
depend upon results achieved, oil prices, available markets for the oil,
pipeline capacity and applicable taxes and expenses.

     The Company's share of current proved reserves assigned to vapor recovery
activities and to the Onbysk field based upon the year end price of $16.82 per
barrel are 13.6 MBbl.  The average price received during 1995, 1994 and 1993
was $15.11, $14.21 and $14.24 per barrel, respectively.

     Following receipt of the export tax exemption for 1995, Texneft examined
several additional opportunities with Tatneft where previous exploration had
identified reserves but development work remained to be undertaken.  As a
result, Tatex accepted its newest project, the right to develop an area located
110 km south west of Almetyevsk of some 33,000 acres which encompasses five
identified accumulations within the already designated Suncheleevsky and
Demkinsky fields.  Located on these features are a total of eighteen cased
wells which have tested oil and are considered

                                       8
<PAGE>   11
candidates for re-entry and completion as potential producers.  At present,
there is no surface or downhole equipment in either field which would permit
immediate production.  The Suncheleevsky field is located approximately 15 km
from the nearest crude processing/pipeline terminal.  Shooting of 480 km of
seismic began in the Suncheleevsky field in January 1996.  Following
interpretation of new and old seismic and the completion of a development plan,
development drilling is likely to commence late in the last quarter of 1996 in
the Suncheleevsky field.  Independent reservoir engineers have assigned proved
undeveloped reserves of 1.9 million barrels net to the Company under primary
depletion based on a future drilling program limited at this time to thirty-two
immediate offsets to eight existing wells in the Suncheleevsky field proper and
based on an export tax rate of 10 European Currency Units ("ECUs") per ton.  No
reserves have been attributed at this time to the Demkinsky field as present
drilling commitments allow only for drilling up the more accessible
Suncheleevsky area as the first stage of development.  A reserve evaluation of
the Demkinsky field will be carried out as the second phase of the development
is initiated.

     In January 1992, the Russian Federation imposed a tax of 30 ECUs per ton,
currently approximately $5.16 per barrel, on crude oil exported from Russia.
Effective January 1, 1995, the export tax for the first quarter of 1995 was set
by Resolution 1446 at 23 ECUs per ton or approximately $4.00 per barrel.  On
February 28, 1995, Mr. V. Chernomyrdin, the Prime Minister of the Russian
Federation, signed Government Order #282r whereby Tatex received an exemption
from paying export tax on exported oil effective January 1, 1995.  This
exemption is subject to an annual review by the government and can be effective
for no more than three years.  The Company believes it has complied with the
investment criteria which form the basis of the exemption for 1996.  However,
at the time of writing, Tatex had not received notification of exemption from
the export tax for 1996, although seven joint ventures which also received the
exemption for 1995 and which did so before Tatex, have all been exempted from
export tax for 1996.  Tatex paid export tax on 25,000 tons (approximately
182,700 barrels) at a rate of 20 ECUs per ton in January and February of 1996
on the expectation that these funds will be recouped upon receipt of the
exemption.

     Tatex oil production through December 31, 1995 has been sold outside of
the former USSR for hard currency via the Transneft operated Druzhba pipeline.
Access to the Transneft pipeline system has been subject to minimal
interruption since startup.  Recent statements and actions by government
ministries in connection with the liberalization of Russian crude export
controls indicate that in the future, joint ventures may have to compete with
Russian production associations for limited pipeline capacity to export
markets.

     Article 25 of the Foreign Investment Law guarantees the right of joint
ventures with a foreign equity interest of more than thirty percent to export
their own production.  Under Decree 209 issued on February 28, 1995 which
confirmed priority export pipeline access to joint ventures exempted from
export tax, Mintopenergo (the Ministry of Petroleum and Energy) sets the export
quotas for the total oil available quarterly for joint ventures (typically 30
percent of production) not granted the export tax.  Crude oil not exported from
the Russian Federation is sold on the domestic market or exported to the
"near-abroad" countries which formerly comprised the USSR for prices at
approximately 70 percent of world market levels.  Until the export tax
exemption is officially granted Tatex it is impossible to forecast with
accuracy the volume to be exported for world prices.  For the purpose of
reserve evaluation, for all cases an export tax rate of 10 ECUs was applied
for the life of the project.

     The International Monetary Fund has made the complete removal of the
export tax from all exporters by July 1, 1996 a precondition for granting of
certain loans to the Russian government.  Some Russian officials have indicated
that in the event of the removal of the export tax, the excise tax and or a
pipeline transportation tariff may be raised to compensate for lost tax
revenues at that time.  The excise tax was reintroduced in April 1995 and the
joint venture is currently paying 50,000 rubles per ton or approximately $1.42
per barrel.

     Tatex's production is subject to an annual determination of Own Oil
established by the Ministry of Fuel & Energy of the Russian Federation and
certified by the Ministry of Economics as registered for export as follows for
1996: vapor recovery 4,739,738 barrels and Onbysk field development 8,851,643
barrels after deduction of future Base Oil amounts.  The Company believes that
the export quota levels set for 1996 are commensurate with the planned
activities for the projects.

EXPLORATION AND DEVELOPMENT ACTIVITIES AND PRODUCING WELLS

     The Russian joint venture expended approximately $9.9 million, $9.1
million and $5.2 million in 1995, 1994 and 1993, respectively, for oil
exploration and development in Russia.  In 1995, the joint venture's activities
were principally development drilling and oil production.


                                       9
<PAGE>   12
     The Company's 1996 capital expenditure budget includes approximately $11.7
million for Russian activities, of which approximately $11.5 million is
intended for Onbysk field development.  The majority of these budgeted
expenditures are projected to be funded through cash flow generated from the
joint venture.

     The Company's Russian oil and gas exploration and development drilling
during the years indicated and the gross and net wells in which the Company had
a working interest were as follows:

                               WELLS DRILLED (1)

<TABLE>
<CAPTION>
                                         EXPLORATORY          DEVELOPMENT             TOTAL
                                      -----------------    ----------------    -----------------
                                       GROSS       NET      GROSS      NET      GROSS       NET
                                      -------     -----    -------    -----    ------      -----
<S>                                     <C>        <C>       <C>       <C>       <C>        <C>
1995             
Oil . . . . . . . . . . . . . . . .     --         --         17       8.5        18         9
Gas . . . . . . . . . . . . . . . .     --         --        --        --        --         --
Dry . . . . . . . . . . . . . . . .      1         0.5       --        --        --         --
                                      -----------------    ----------------    -----------------
   Total  . . . . . . . . . . . . .      1         0.5        17       8.5        18         9
                                      =================    ================    =================
                 
1994             
Oil . . . . . . . . . . . . . . . .     --         --         19       9.5        19        9.5
Gas . . . . . . . . . . . . . . . .     --         --        --        --        --         --
Dry . . . . . . . . . . . . . . . .     --         --        --        --        --         --
                                      -----------------    ----------------    -----------------
   Total  . . . . . . . . . . . . .     --         --         19       9.5        19        9.5
                                      =================    ================    =================
                 
1993             
Oil . . . . . . . . . . . . . . . .     --         --         22        11        22        11
Gas . . . . . . . . . . . . . . . .     --         --        --        --        --         --
Dry . . . . . . . . . . . . . . . .     --         --        --        --        --         --
                                      -----------------    ----------------    -----------------
   Total  . . . . . . . . . . . . .     --         --         22        11        22        11
                                      =================    ================    =================
</TABLE>
     ------------------   
    (1)  The term "gross" as used herein with respect to wells refers to the
         total number of wells in which the Company has any interest and "net"
         refers to the Company's  interest in such wells.

    At December 31, 1995, the Russian joint venture had 4 gross (2 net)
development wells awaiting completion; and 1 gross (0.5 net) development well
was in the process of being drilled.

                PRODUCING WELLS AND WELLS CAPABLE OF PRODUCTION

<TABLE>
<CAPTION>
                                                                GROSS PRODUCING      NET PRODUCING
                                                                ---------------      -------------
<S>                                                                       <C>                <C>
1995(1)          
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . .                  154                 77
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . .                  --                 --
                                                                ---------------      -------------
   Total  . . . . . . . . . . . . . . . . . . . . . . . .                  154                 77
                                                                ===============      =============
                 
1994             
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . .                  139                69.5
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . .                  --                 --
                                                                ---------------      -------------
   Total  . . . . . . . . . . . . . . . . . . . . . . . .                  139                69.5
                                                                ===============      =============
                 
1993             
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . .                  114                 57
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . .                  --                 --
                                                                ---------------      -------------
   Total  . . . . . . . . . . . . . . . . . . . . . . . .                  114                 57
                                                                ===============      =============
</TABLE>

    ----------------
    (1)   The number of oil wells completed in more than one producing
          formation was 35 at December 31, 1995.





                                       10
<PAGE>   13
CERTAIN RISKS APPLICABLE TO OPERATIONS IN RUSSIA

    The Company's activities in Russia are subject to the usual risks
associated with foreign operations, including political and economic
uncertainties, risks of cancellation or unilateral modification of agreements,
operating restrictions, currency repatriation restrictions, expropriation,
export restrictions, the imposition of new taxes and the increase of existing
taxes, inflation, foreign exchange fluctuations and other risks arising out of
foreign government sovereignty over areas in which the operations are
conducted. The Company has endeavored to protect itself against certain
political and commercial risks inherent in the venture. There is no certainty
that the steps taken by the Company will provide adequate protection.

IVORY COAST

GENERAL

     In May 1993, the Company acquired an interest in 335,320 gross acres in
the CI-11 Production Sharing Contract ("PSC") approximately eight miles
offshore Ivory Coast, West Africa.  The Company acquired a 10% working interest
in an area referred to as the "Special Area" and a 16% working interest in an
area referred to as the "Remaining Area."

     During 1993, the Panthere 1 well was drilled in the Remaining Area to a
total depth of 10,575 feet and tested gas and condensate at the rate of 34.8
Mmcf per day plus 675 Bbls per day on a 56/64 inch choke with a flowing tubing
pressure of 1,909 pounds per square inch from 66 feet of perforations between
9,316 and 9,382 feet.  The well was drilled in 264 feet of water and a
production caisson was set over the well.

     During 1994, the Lion 1 well was drilled in the Special Area to test a
separate structure.  This well was directionally drilled to a total depth of
11,270 feet and encountered approximately 205 feet of log-indicated net
hydrocarbon pay.  Three intervals flowed a combined 23,700 barrels of 38 degree
crude oil per day and 65 Mmcf of gas per day through choke sizes ranging from
one inch to 7/8 inch.  In November 1994, the B1-8X well, which was drilled by
the previous operator, was re-entered, completed and tied back to the Lion
caisson.  The well tested a combined rate of 9,575 barrels of oil per day and
10 Mmcf of gas per day on a 3/4 inch choke from a total of 75 feet of
perforations between 8,294 and 9,495 feet.  The Lion A-2 well was spudded in
December 1994, and during initial tests flowed 5,460 barrels of 37.1 degree
crude oil per day and 4 Mmcf of gas per day on a one inch choke.

     On September 12, 1994, the government of the Ivory Coast granted the
Company and its PSC partners an exclusive exploitation authorization covering a
portion of the Special Area and a portion of the Remaining Area.  This
authorization allows the joint venture to proceed with development activities
in the authorized area.  In addition, the government has approved a gas
development project and has signed with the Company and its PSC partners a gas
sales contract for gas produced from the exploitation area.  The contract calls
for initial deliveries of 20 Mmcf per day which increases to 50 Mmcf per day in
year two, with a maximum of 90 Mmcf per day.  The gas will be sold at
approximately $1.75 per Mcf with a cost escalator in the fifth year of the
contract.  The Company receives payment for gas sold under this contract in
barrels of oil (assigned from the government's portion of production) which the
Company sells on the open market.

     During 1995, the Company drilled four additional wells; the Lion B-1, Lion
B-2, Lion B-3 and Panthere C-2 wells.  All four wells were successfully
completed and are producing, together with the Lion 1, Lion A-2, B1-8X and
Panthere C-1 wells.  Oil production commenced from the Lion field in April 1995
via an offshore loading facility.  Gas and condensate production from the
Panthere field commenced in October 1995 and is being sold via a gas pipeline
from the field for purchasers in Abidjan.  The field produced 3.2 million
barrels of oil and 1.1 Bcf of gas during 1995.

     A second gas contract with the SIR Refinery located in Abidjan was signed
in early 1996.  The Company will receive payment for 60% of the gas sold under
this contract in U.S. dollars and 40% in Ivorian francs.

     In April 1995, the Company signed a PSC for block CI-12 which lies
adjacent to the west of block CI-11.  The Company acquired a 16.67% working
interest in the PSC which covers 524,845 acres.  The Company has committed to
drill one exploratory well in the initial two year exploratory period.  The
exploration rights may be extended for an additional four years by the
assumption of additional drilling obligations.

     Future activity in the Ivory Coast includes exploratory drilling on
additional prospects which have been identified on Blocks CI-11 and CI-12.





                                       11
<PAGE>   14
EXPLORATION AND DEVELOPMENT ACTIVITIES AND PRODUCING WELLS

     In 1995, 1994 and 1993, the Company's activities were principally in Block
CI-11 offshore.  The Company expended approximately $0.4 million, $3 million,
and $4 million in 1995, 1994 and 1993, respectively, for oil and gas
exploration activities in the Ivory Coast.  In addition, the Company expended
in 1995 and 1994 approximately $18.4 million and $2.6 million, respectively,
for development activities. The Company's 1996 Ivory Coast budget is
approximately $3.9 million, of which approximately $2.8 million is intended for
developmental activities in Block CI-11.

     The Company's Ivory Coast oil and gas exploration and development drilling
during the years indicated and the gross and net wells in which the Company had
a working interest were as follows:

                              WELLS DRILLED (1)
<TABLE>
<CAPTION>
                                                EXPLORATORY         DEVELOPMENT             TOTAL
                                            -----------------   ----------------    -----------------
                                             GROSS       NET     GROSS      NET      GROSS       NET
                                            -------     -----   -------    -----    ------      -----
<S>                                            <C>        <C>      <C>     <C>         <C>       <C>
1995                                                                                   
Oil . . . . . . . . . . . . . . . . . .         --        --         3      0.4         3        0.4 
Gas . . . . . . . . . . . . . . . . . .         --        --         1      0.2         1        0.2 
Dry . . . . . . . . . . . . . . . . . .         --        --        --       --        --         -- 
                                            -------     -----   -------    -----    ------      -----
   Total  . . . . . . . . . . . . . . .         --        --         4      0.6         4        0.6 
                                            =======     =====   =======    =====    ======      =====
1994                                                                                                 
Oil . . . . . . . . . . . . . . . . . .          1       0.1         1      0.1         2        0.2 
Gas . . . . . . . . . . . . . . . . . .         --        --        --       --        --         -- 
Dry . . . . . . . . . . . . . . . . . .         --        --        --       --        --         -- 
                                            -------     -----   -------    -----    ------      -----
   Total  . . . . . . . . . . . . . . .          1       0.1         1      0.1         2        0.2 
                                            =======     =====   =======    =====    ======      =====
1993                                                                                                 
Oil . . . . . . . . . . . . . . . . . .         --        --        --       --        --        --  
Gas . . . . . . . . . . . . . . . . . .          1       0.2        --       --         1        0.2 
Dry . . . . . . . . . . . . . . . . . .         --        --        --       --        --         -- 
                                            -------     -----   -------    -----    ------      -----
   Total  . . . . . . . . . . . . . . .          1       0.2        --       --         1        0.2 
                                            =======     =====   =======    =====    ======      =====
</TABLE>
     ------------------    
     (1)  The term "gross" as used herein with respect to wells refers to the
          total number of wells in which the Company has any interest and "net"
          refers to the Company's interest in such wells.

     At December 31, 1995, the Company had no exploratory wells and no
development wells awaiting completion; no exploratory wells and no development
wells were in the process of being drilled.

               PRODUCING WELLS AND WELLS CAPABLE OF PRODUCTION
<TABLE>
<CAPTION>
                                                           GROSS PRODUCING                 NET PRODUCING
                                                           ---------------                 -------------
<S>                                                               <C>                           <C>
1995(1)
Oil . . . . . . . . . . . . . . . . . . . . . . . . . .           6                             0.7
Gas . . . . . . . . . . . . . . . . . . . . . . . . . .           2                             0.3
                                                           ---------------                 -------------
    Total   . . . . . . . . . . . . . . . . . . . . . .           8                             1.0
                                                           ===============                 =============
1994
Oil . . . . . . . . . . . . . . . . . . . . . . . . . .           3                             0.3
Gas . . . . . . . . . . . . . . . . . . . . . . . . . .           1                             0.2
                                                           ---------------                 -------------
    Total   . . . . . . . . . . . . . . . . . . . . . .           4                             0.5
                                                           ===============                 =============
</TABLE>
    ------------------    
     (1)  There were no oil or gas wells completed in more than one producing
          formation at December 31, 1995.

PRODUCTION SHARING CONTRACTS CI-11 AND CI-12

     Under the CI-11 PSC, the working interest partners pay 100% of capital and
operating costs, and production is split between the Ivorian government and the
working interest partners.  Up to 40% of the oil and gas produced and sold from
the contract area is available to the working interest partners to recover costs
("cost recovery petroleum").  Cost recovery petroleum forms a single unified
pool for the entire area from which costs of all fields, zones, products and
types may be recovered without differentiation, except that operating costs and
financial costs are recovered prior to the recovery of any capital costs.
Capital costs include exploration, development and other equipment and
facilities costs.  If during 
                                       12
<PAGE>   15
a calendar year any costs are not recovered by the working interest partners
from that year's cost recovery petroleum, the unrecovered costs are carried
forward to the next succeeding  calendar year until full recovery of all costs
or until the end of the contract.  Any portion of cost recovery petroleum not
used to recover costs will be split between the Ivorian government and the
working interest partners in the same manner as remaining petroleum.

     The remaining 60% of oil and gas produced and sold ("remaining petroleum")
is divided between the Ivorian government and the working interest partners.
All Ivorian government royalties and the working interest partners' Ivorian
income taxes attributable to their share of Ivorian taxable income, determined
in barrels ("tax petroleum"), are included in the Ivorian government's share of
remaining petroleum.

     The working interest partners' percentage of  remaining petroleum
("remaining oil and remaining gas") is applied to increments of production
based on the gross daily average of oil or gas production determined on a
quarterly basis and varies with respect to the water depth location of the
specific wellhead as follows:

<TABLE>
<CAPTION>
                                                                  WORKING INTEREST PARTNERS' % OF REMAINING OIL
                                                               ---------------------------------------------------
       GROSS PRODUCTION                                            WATER DEPTHS                 WATER DEPTHS
    (BBLS OF OIL PER DAY)                                      LESS THAN 200 METERS        GREATER THAN 200 METERS
--------------------------------                               --------------------        -----------------------
<S>                                                                    <C>                          <C>
Up to 10,000  . . . . . . . . . . . . . . . . . . . . . .               40%                          50%
10,001 to 20,000  . . . . . . . . . . . . . . . . . . . .               30%                          50%
20,001 to 25,000  . . . . . . . . . . . . . . . . . . . .               20%                          50%
25,001 to 30,000  . . . . . . . . . . . . . . . . . . . .               20%                          40%
30,001 to 50,000  . . . . . . . . . . . . . . . . . . . .               10%                          40%
Over 50,000 . . . . . . . . . . . . . . . . . . . . . . .               10%                          30%

<CAPTION>
                                                                  WORKING INTEREST PARTNERS' % OF REMAINING GAS
                                                               ---------------------------------------------------
       GROSS PRODUCTION                                            WATER DEPTHS                 WATER DEPTHS
     (MCF OF GAS PER DAY)                                      LESS THAN 200 METERS        GREATER THAN 200 METERS
--------------------------------                               --------------------        -----------------------
<S>                                                                    <C>                          <C>
Up to 75,000  . . . . . . . . . . . . . . . . . . . . . .               40%                          50%
75,001 to 150,000 . . . . . . . . . . . . . . . . . . . .               30%                          50%
Over 150,000  . . . . . . . . . . . . . . . . . . . . . .               20%                          40%
</TABLE>


     The terms and conditions of the CI-12 PSC are similar to those of CI-11.
The working interest partners continue to pay 100% of the capital and operating
costs and the oil and gas sold from the contract area is split 50% to cost
recovery petroleum and 50% to remaining petroleum.  All Ivorian government
royalties and the working interest partners' Ivorian income taxes attributable
to their share of Ivorian taxable income are included in the Ivorian
government's share of remaining petroleum.  The working interest partners'
percentage of remaining petroleum for CI-12 is the same as stated above for
CI-11.

RESERVES

     At December 31, 1995, gross proved oil and gas reserves for the CI-11 area
were estimated to be 31 million barrels of oil and 224.1 million cubic feet of
gas.  The Company's net proved oil and gas reserves at December 31, 1995 were
6.5 million barrels of oil equivalent.  The Company's share of proved reserve
quantities includes an assumed dollar amount of estimated future production
necessary to recover costs.  Therefore, the amount of Company net reserves for
a given amount of total CI-11 reserves varies with the assumed oil and gas
prices.  The Company's net reserves include its share of cost recovery
petroleum, remaining petroleum and tax petroleum which are 3.7 million
equivalent barrels, 2.1 million equivalent barrels, and 1.1 million equivalent
barrels, respectively.

CERTAIN RISKS APPLICABLE TO OPERATIONS IN IVORY COAST

     The Company's activities in the Ivory Coast are subject to certain risks,
including political and economic uncertainties, risks of cancellation or
unilateral modification of agreements, operating restrictions, currency
repatriation restrictions, expropriation, export restrictions, the imposition
of new taxes and the increase of existing taxes, inflation and other risks
arising out of foreign government sovereignty over areas in which the
operations are conducted.


                                       13
<PAGE>   16
EGYPT

GENERAL

     In August 1994, the Company acquired a 25% working interest in the Qarun
Concession Agreement ("QCA") located 45 miles southwest of Cairo, Egypt.  The
concession covers approximately 1.9 million acres.  The Company together with
its QCA partners were committed to drill at least one exploratory well in the
initial three year exploratory period.  The exploration rights may be extended
up to an additional four years by the assumption of additional drilling
obligations.

     The first exploratory well, the El Sagha #1A, was spudded on August 28,
1994 with dual objectives at approximately 9,000 and 14,000 feet.  The
shallower objectives were successfully drilled and logged with open hole logs
indicating hydrocarbon zones in both the Bahariya and Kharita formations.  The
logs indicated the presence of an aggregate of over 100 feet of net oil pay in
three sandstone intervals in the Bahariya plus over 100 feet of net oil pay in
a single sandstone interval in the Kharita.

     On November 30, 1994, the El Sagha #2 was spudded at a location
approximately 1.6 miles northwest of the El Sagha #1.  This exploratory well
had the same objectives (shallow and deep) as the first well and resulted in
the second new field discovery (Qarun B).  This well encountered, at the
shallow objective, approximately 45 feet of net pay.  The El Sagha #3X
confirmed the commerciality of the Qarun A field, encountering 305 feet of net
oil pay.  The well tested 7,154 barrels of oil per day from the Bahariya
formation and 4,803 barrels of oil per day from the Kharita formation.

     The Egyptian government approved the Qarun development program in August
1995.  Additional development wells, Qarun 4X and Qarun 5X, were successfully
completed in 1995.  In November 1995, the Company announced the drilling of the
Sakr well, an exploratory test well which found new accumulations and which
tested at a rate of 405 barrels of oil per day.

     The Company is currently drilling additional development wells and
building facilities and a pipeline for oil production which are to be completed
by year end 1996.  The development plan includes drilling 11 additional wells
and building facilities with an initial production capacity of 40,000 barrels
of oil per day and a 16 inch pipeline from the field to Dashour approximately
30 miles east of the field, where oil will be stored in two 350,000 barrel
storage tanks.  Oil will then be transferred and sold via the Sumed pipeline,
an existing facility, with a capacity of 2 million barrels of oil per day.
However, early oil production, via trucking, commenced on November 29, 1995 at
the rate of approximately 4,000 barrels of oil per day.  In addition to the
development drilling activity and the facilities construction, a 3-D seismic
survey over the Qarun field and a 2-D seismic program designed to identify
additional exploratory locations were carried out during 1995.

     On August 13, 1995, the Qarun Production Company ("QPC") as required by
the QCA was formed to operate the Qarun block.  QPC is jointly owned by the QCA
partners and EGPC (the Egyptian national oil company).

     In December 1995, the Company signed a Concession Agreement for the East
Beni Suef ("EBSCA") block which lies adjacent to the south of the Qarun
concession.  The concession covers approximately 6.8 million acres and was
awarded 100% to the Company.  The Company has committed to drill one
exploratory well in the initial three year exploratory period.  The exploration
rights may be extended for an additional six years by the assumption of
additional drilling obligations.  The EBSCA will be formally approved by the
Egyptian government in 1996. The Company has farmed out fifty percent of the
concession but will remain the operator.

     Also in December 1995, the Company was notified of its successful bid with
its partner on the Darag block which is located in the northern portion of the
Gulf of Suez.  The Company will own a 50% interest in the 460,000 acre
concession.  The Darag Concession Agreement ("DCA") was signed in March, 1996
with formal approval by the Egyptian government anticipated in the second half
of 1996.  There are three existing wells in the northern portion of this
concession, one of which tested at a rate of 2,500 barrels of oil per day.  It
is anticipated that additional seismic will be shot in the second half of 1996
with a well to be drilled in mid-1997.


                                       14
<PAGE>   17
EXPLORATION AND DEVELOPMENT ACTIVITIES AND PRODUCING WELLS

     The Company's Qarun concession oil and gas exploration and development
drilling during the years indicated were as follows:

                              WELLS DRILLED (1)

<TABLE>
<CAPTION>
                                                EXPLORATORY          DEVELOPMENT             TOTAL
                                             -----------------    -----------------     ----------------
                                              GROSS       NET      GROSS       NET       GROSS      NET
                                             -------     -----    -------     -----     -------    -----
<S>                                             <C>       <C>        <C>       <C>         <C>      <C>
1995
Oil . . . . . . . . . . . . . . . . . . .         2       0.5          4       1.0           6      1.5
Gas . . . . . . . . . . . . . . . . . . .        --        --         --        --          --       --
Dry . . . . . . . . . . . . . . . . . . .         1       0.3          1       0.3           2      0.6
                                             -------     -----    -------     -----     -------    -----
    Total   . . . . . . . . . . . . . . .         3       0.8          5       1.3           8      2.1
                                             =======     =====    =======     =====     =======    =====
1994
Oil . . . . . . . . . . . . . . . . . . .         2       0.5         --        --           2      0.5
Gas . . . . . . . . . . . . . . . . . . .        --        --         --        --          --       --
Dry . . . . . . . . . . . . . . . . . . .        --        --         --        --          --       --
                                             -------     -----    -------     -----     -------    -----
    Total   . . . . . . . . . . . . . . .         2       0.5         --        --           2      0.5
                                             =======     =====    =======     =====     =======    =====
</TABLE>
     ------------------
     (1)  The term "gross" as used herein with respect to wells refers to the
          total number of wells in which the Company has any interest and "net"
          refers to the Company's  interest in such wells.

     At December 31, 1995, the Qarun concession had 2 (0.5 net) exploratory and
1 (0.3 net) development wells awaiting completion; and 2 (0.5) net development
wells were in the process of being drilled.

               PRODUCING WELLS AND WELLS CAPABLE OF PRODUCTION

<TABLE>
<CAPTION>
                                                         GROSS PRODUCING                 NET PRODUCING
                                                         ---------------                 -------------
<S>                                                             <C>                           <C>
1995 (1)  
Oil . . . . . . . . . . . . . . . . . . . . . . .               5                             1.3
Gas . . . . . . . . . . . . . . . . . . . . . . .               -                              -
                                                         ---------------                 -------------
    Total . . . . . . . . . . . . . . . . . . . .               5                             1.3
                                                         ===============                 =============
</TABLE>
     ------------------  
     (1)  There were no oil or gas wells completed in more than one producing
          formation at December 31, 1995.

QARUN CONCESSION AGREEMENT

     Under the QCA, the working interest partners pay 100% of capital and
operating costs and the production is split between EGPC and the working
interest partners.  Up to 40% of the oil and gas produced and sold from the
Qarun concession is available to the working interest partners to recover costs
("cost recovery petroleum").  Cost recovery petroleum forms a single unified
pool for the entire concession from which costs of all fields, zones, products
and types may be recovered without differentiation, except that operating costs
are recovered prior to the recovery of any capital costs.  Capital costs (which
include exploration, development and other equipment and facilities costs) are
amortized for recovery over five years while operating expenses are recoverable
on a current basis.  To the extent that costs eligible for recovery in any
quarter exceed the amount of cost recovery petroleum produced and sold in that
quarter, such costs are recoverable from cost recovery petroleum in future
quarters with no limit on the ability to carry forward such costs.  Any portion
of cost recovery petroleum not used to recover costs goes to EGPC.

     The remaining 60% of oil and gas produced and sold ("remaining petroleum")
is divided between EGPC and the working interest partners.  All Egyptian
government royalties and the working interest partners' Egyptian income taxes
attributable to their share of Egyptian taxable income, determined in barrels
("tax petroleum"), are included in EGPC's share of remaining petroleum.





                                       15
<PAGE>   18
     The working interest partners' percentage of remaining petroleum
("remaining oil") is applied to increments of production based on the gross
daily average of oil production determined on a quarterly basis as follows:

<TABLE>
<CAPTION>
     GROSS PRODUCTION                            WORKING INTEREST PARTNERS'
   (BBLS OF OIL PER DAY)                             % OF REMAINING OIL
--------------------------                       --------------------------
<S>                                                        <C>
Up to 5,000 . . . . . . . . . . . . . . . . . . .           30%
5,001 to 25,000 . . . . . . . . . . . . . . . . .           25%
25,001 to 50,000  . . . . . . . . . . . . . . . .           22%
Over 50,000 . . . . . . . . . . . . . . . . . . .           20%
</TABLE>


    The working interest partners' percentage of the gas segment of remaining
petroleum is 22%.

EAST BENI SUEF CONCESSION AGREEMENT

    Under the EBSCA, the working interest partners pay 100% of capital and
operating costs and the production is split between EGPC and the working
interest partners.  Up to 40% of the oil and gas produced and sold from the
East Beni Suef concession is available to the working interest partners as cost
recovery petroleum.  As with QCA, cost recovery petroleum forms a single
unified pool for the entire concession from which costs of all fields, zones,
products and types may be recovered without differentiation, except that
operating costs are recovered prior to the recovery of any capital costs.
Capital costs are amortized for recovery over four years while operating
expenses are recoverable on a current basis.  To the extent that costs eligible
for recovery in any quarter exceed the amount of cost recovery petroleum
produced and sold in that quarter, such costs are recoverable from cost
recovery petroleum in future quarters with no limit on the ability to carry
forward such costs.  Any portion of cost recovery petroleum not used to recover
costs is split between EGPC and working interest partners.

    The remaining petroleum is divided between EGPC and the working interest
partners.  All Egyptian government royalties and the working interest partners'
Egyptian income taxes attributable to their share of Egyptian taxable income,
determined in barrels, are included in EGPC's share of remaining petroleum.

<TABLE>
<CAPTION>
     GROSS PRODUCTION                            WORKING INTEREST PARTNERS'
   (BBLS OF OIL PER DAY)                             % OF REMAINING OIL
----------------------------                     --------------------------
<S>                                                        <C>
Up to 10,000  . . . . . . . . . . . . . . . . . . . .       30%
10,001 to 25,000  . . . . . . . . . . . . . . . . . .       25%
25,001 to 50,000  . . . . . . . . . . . . . . . . . .       22.5%
50,001 to 75,000  . . . . . . . . . . . . . . . . . .       20%
over 75,000 . . . . . . . . . . . . . . . . . . . . .       15%
</TABLE>

    The working interest partners' percentage of the gas segment of remaining
petroleum is 25%.

DARAG CONCESSION AGREEMENT

    Under the proposed DCA, the working interest partners pay 100% of capital
and operating costs and the production is split between EGPC and the working
interest partners.  Up to 40% of the oil and gas produced and sold from the
Darag concession is available to the working interest partners as cost recovery
petroleum.  As with QCA and EBSCA, cost recovery petroleum forms a single
unified pool for the entire concession from which costs of all fields, zones,
products and types may be recovered without differentiation, except that
operating costs are recovered prior to the recovery of any capital costs.
Capital costs are amortized for recovery over four years while operating
expenses are recoverable on a current basis.  To the extent that costs eligible
for recovery in any quarter exceed the amount of cost recovery petroleum
produced and sold in that quarter, such costs are recoverable from cost
recovery petroleum in future quarters with no limit on the ability to carry
forward such costs.  Any portion of cost recovery petroleum not used to recover
costs is split between EGPC and working interest partners.

    The remaining petroleum is divided between EGPC and the working interest
partners.  All Egyptian government royalties and the working interest partners'
Egyptian income taxes attributable to their share of Egyptian taxable income,
determined in barrels, are included in EGPC's share of remaining petroleum.


                                       16
<PAGE>   19
<TABLE>
<CAPTION>
     GROSS PRODUCTION                            WORKING INTEREST PARTNERS'
   (BBLS OF OIL PER DAY)                             % OF REMAINING OIL
----------------------------                     --------------------------
<S>                                                         <C>
Up to 5,000 . . . . . . . . . . . . . . . . . . . . .       30%
5,001 to 10,000 . . . . . . . . . . . . . . . . . . .       27%
10,001 to 25,000  . . . . . . . . . . . . . . . . . .       25%
25,001 to 50,000  . . . . . . . . . . . . . . . . . .       22%
50,001 to 75,000  . . . . . . . . . . . . . . . . . .       17.5%
75,001 to 100,000 . . . . . . . . . . . . . . . . . .       15%
over 100,000  . . . . . . . . . . . . . . . . . . . .       13%
</TABLE>

    The working interest partners' percentage of the gas segment of remaining
petroleum is 25%.

RESERVES

    At December 31, 1995, gross  proved oil and gas reserves for the Qarun
concession were estimated to be 53.2 million barrels of oil and 11.9 million
cubic feet of gas.  The Company's net proved oil and gas reserves at December
31, 1995 were 8.2 million barrels of oil equivalent.  The Company's share of
proved reserve quantities includes an assumed dollar amount of estimated future
production necessary to recover costs.  Therefore, the amount of Company net
reserves for a given amount of total concession reserves varies with the
assumed oil price.  The Company's net reserves include its share of cost
recovery petroleum, remaining petroleum and tax petroleum which are 4.6 million
barrels, 2.2 million barrels and 1.4 million barrels, respectively.

CERTAIN RISKS APPLICABLE TO OPERATIONS IN EGYPT

    The Company's activities in Egypt are subject to certain risks, including
political and economic uncertainties, risks of cancellation or unilateral
modification of agreements, operating restrictions, currency repatriation
restrictions, expropriation, export restrictions, the imposition of new taxes
and the increase of existing taxes, inflation and other risks arising out of
foreign government sovereignty over areas in which the operations are
conducted.

INDONESIA

GENERAL

    The Company has a 1.714% interest in the IJV, a joint venture for the
exploration, development and production of oil and natural gas in East
Kalimantan, Indonesia, under a PSC with Pertamina.  The majority of the revenue
derived from the IJV results from the sale of liquefied natural gas ("LNG").

    In 1995, the $12.4 million of revenues from the Company's interest in the
IJV accounted for approximately 16% of the Company's revenues.  Approximately
19% and 15%  of the Company's 1994 and 1993 revenues, respectively, were
contributed by the IJV.

    Under the PSC with Pertamina that was amended and extended in 1990 until
August 7, 2018, the IJV is authorized to explore for, develop and produce
petroleum reserves in an approximately 1.1 million acre area in East
Kalimantan.  In accordance with the requirements of the PSC, the IJV must
relinquish 10% of the PSC area by  August 7, 1998; 10% by December 31, 2000;
15% by December 31, 2002 and 15% by December 31, 2004.  However, the IJV is not
required to relinquish any of the PSC area in which oil or gas is held for
production.

    Under the PSC, the IJV participants are entitled to recover cumulative
operating and certain capital costs out of the crude oil, condensate and
natural gas ("gas") produced each year, and to receive a share of the remaining
crude oil and condensate production and a share of the remaining revenues from
the sale of gas on an after Indonesian tax basis.

    The share of revenues from the sale of gas after cost recovery through
August 7, 1998 will remain at 35% to the IJV after Indonesian income taxes and
65% to Pertamina.  The split after August 7, 1998 will be 25% to the IJV after
Indonesian income taxes and 75% to Pertamina for gas sales under the 1973 and
1981 LNG Sales Contracts, Korean Carryover Sales Contract and the seven 1986
liquefied petroleum gas sales contracts to the extent that the gas to fulfill
these contracts is committed from the Badak or Nilam fields.  After August 7,
1998, all other LNG sales contract revenues will be split 30% to the IJV after
Indonesian income taxes and 70% to Pertamina.


                                       17
<PAGE>   20
    Based on current and projected oil production, the revenue split from oil
sales after cost recovery through August 7, 2018 will remain at 15% to the IJV
after Indonesian income taxes and 85% to Pertamina. These revenue splits are
based on Indonesian income tax rates of 56% through August 7, 1998 and 48%
thereafter.

    In addition, the IJV is required to sell out of its share of production
8.5% of the total oil and gas condensate production from the contract area for
Indonesian domestic consumption.  The sales price for the domestic market
consumption is $0.20 per barrel with respect to fields commencing production
prior to February 23, 1989 and 10% of the weighted average price of crude oil
sold from such fields commencing production after February 23, 1989. However,
for the first sixty consecutive months of production from new fields, domestic
market compensation is priced at the official Indonesian crude price.  The
participants' remaining oil and condensate production is generally sold in
world markets.

    The IJV is also obligated to supply approximately 74 Mmcf per day of gas to
three local fertilizer plants at a price of $1.00 per million British Thermal
Units ("MMBTU") subject to a pipeline tariff.  In addition, the IJV is required
to supply approximately 5 Mmcf per day of gas to the Balikpapan refinery at a
price of $1.49 per MMBTU.  In 1994, Pertamina executed a twenty-year contract,
commencing in November of 1997, for the sale of approximately 70 Mmcf per day
of gas to a local methanol plant at a price not less than $1.25 per MMBTU for
the first ten years.

    The IJV has no ownership interest in the oil and gas reserves.  The IJV has
long-term supply agreements with Pertamina for the supply of natural gas and
petroleum gas to be liquefied at a liquefaction plant owned by Pertamina at
Bontang Bay (the "LNG Plant") and sold to certain buyers pursuant to sales
contracts.  The IJV, other participating production sharing contractors and
Pertamina together market the LNG and the liquefied petroleum gas ("LPG")
produced at the LNG Plant and LPG facilities, and as to the amounts allocated
to the PSC, the IJV and Pertamina divide the net proceeds in accordance with
the percentages set out above.

    Since the Company does not have direct access to information with respect
to oil and gas operations under the PSC, the information contained herein is
from a public source which, although not independently verified, the Company
believes to be reliable.

PRODUCING AND MARKETING ACTIVITIES

    The following table sets forth total natural gas liquefied and sold as LNG,
the Company's net share of such production, average sales prices (excluding
transportation costs) and average production (lifting) costs for each of the
three years ended December 31, 1995.

<TABLE>
<CAPTION>
                                                           1995             1994           1993
                                                         ---------        ---------      ---------
<S>                                                      <C>              <C>            <C>
Natural Gas Production for LNG (Mmcf)(1)  . . . . .        636,339          735,116        637,847
Company's net share of gas (Mmcf equivalency)(2)  .          3,933            4,473          3,769
Average Sales Price per Mcf(3)  . . . . . . . . . .      $    2.96        $    2.45      $    2.75
Average Production (Lifting) cost per Mcf(4)  . . .      $    0.20        $    0.12      $    0.13
</TABLE>
     ----------------      
     (1)  Represents the volumes of LNG delivered and sold to purchasers, which
          is measured by its BTU content and, for purposes of this table, has
          been converted to Mmcf equivalents based on a ratio of approximately
          1.107 BTUs per Mmcf of gas.  The total natural gas production
          includes production attributable to others.

     (2)  The Company's net share figures shown above represent the Mcf
          equivalent of the Company's share of IJV revenues.

     (3)  The sales price is based on the average sales price (excluding
          transportation) per MMBTU of LNG received by Pertamina.  The sales
          price per MMBTU has been converted to a price per Mcf based on the
          conversion ratio referred to in note (1) above.

     (4)  The production (lifting) costs do not include costs of liquefaction
          and transportation.

     The majority of the revenue derived from the IJV results from gas
produced, liquefied and sold as LNG. Gas subject to the PSC is liquefied at the
LNG Plant and transported via special tankers pursuant to several sales
contracts between Pertamina and its customers which principally consist of
Japanese, Taiwanese and Korean utility and industrial





                                       18
<PAGE>   21
companies. The following table sets forth information regarding the LNG Plant's
share of the LNG sales contracts grouped together by the IJV's participating
percentages in the sales contracts (each such group being referred to as a
"package").

<TABLE>
<CAPTION>
                                                                                         BASE LNG PRICE PER
                                                                    REMAINING LNG               MMBTU
                                                                        SALES         -------------------------
   PACKAGE AND EQUITY INTEREST                         TERM            VOLUMES         12/31/95       02/12/96
---------------------------------                  ------------    ---------------    ----------     ----------
                                                                   (TRILLION BTUS)
<S>                                                <C>                    <C>         <C>            <C>
Package I - 97.9%
  1973 LNG Sales  . . . . . . . . . . . . . .      1977-1999                267       $  2.88        $ 3.03
Package II - 66.4%
  1981 LNG Sales Contract . . . . . . . . . .      1983-2003              1,238       $  2.87        $ 3.02
Package III A - 50%
  Korean Carryover Sales Contract . . . . . .      1986-2006                158       $  2.88        $ 3.03
Package III B - 29.6%
  Taiwan  . . . . . . . . . . . . . . . . . .      1990-2009              1,246       $  2.83        $ 2.98
  Toho  . . . . . . . . . . . . . . . . . . .      Various,                  12       $  2.88        $ 3.03
                                                   ranging from
                                                   1988 to 1997
  Additional 1981 Sales Contract Cargoes  . .      1990-2003                131       $  2.87        $ 3.02
Package IV - 27.2%
  Train F LNG Sales Contract  . . . . . . . .      1994-2013              2,151       $  2.71        $ 2.85
  Korea II LNG Sales Contract . . . . . . . .      1994-2014                980       $  2.73        $ 2.88
  Other LNG Sales Contracts . . . . . . . . .      1990-2015                654       $  2.73        $ 2.88
Package V - 21.6%
  1973 Sales Contract Extension . . . . . . .      2000-2009              4,638       $  --          $ --
  Korea Medium Term Sales . . . . . . . . . .      1995-1999                277       $  2.87        $ 3.02
  Taiwan Medium Term Sales  . . . . . . . . .      1998-1999                 46       $  --          $ --
</TABLE>

     Pertamina and the IJV have executed additional sales packages.  The equity
sharing percentage for Packages VI and VII have not yet been determined.  The
1981 Sales Contract Extension (Package VI) involves the sale of 941 trillion
BTUs over a five-year period commencing in 2003.  The 1973 Sales Contract
Extension (Package VII) involves the sale of 436 trillion BTUs during 2010.

EXPLORATION ACTIVITIES

     The IJV has conducted extensive drilling activities on the island of East
Kalimantan.  From 1972 through December 31, 1995, the IJV drilled 557 wells in
the area, 487 of which resulted in oil and/or gas condensate production. Two
significant fields, Badak and Nilam, have been discovered.  The following
tables summarize drilling activity for each of the three years ended December
31, 1995.

                             EXPLORATORY DRILLING

<TABLE>
<CAPTION>
                                                                           WELLS              NEW
  YEAR                                                                    DRILLED         DISCOVERIES         DRY HOLES
---------                                                                ---------       -------------       -----------
<S>                                                                          <C>               <C>                <C>
1995  . . . . . . . . . . . . . . . . . . . . . . . . . . . .                -                 -                  -
1994  . . . . . . . . . . . . . . . . . . . . . . . . . . . .                2                 1                  1
1993  . . . . . . . . . . . . . . . . . . . . . . . . . . . .                3                 -                  3
</TABLE>


                   DEVELOPMENT OR FIELD EXTENSION DRILLING

<TABLE>
<CAPTION>
                                                    WELLS                               DUAL OIL &
  YEAR                                             DRILLED        GAS          OIL         GAS       DRY HOLES
--------                                          ---------      -----        -----    ------------ -----------
<S>                                                  <C>          <C>           <C>         <C>          <C>
1995  . . . . . . . . . . . . . . . . . . .          16            7            2           7            -
1994  . . . . . . . . . . . . . . . . . . .          20           10            1           8            1
1993  . . . . . . . . . . . . . . . . . . .          31           25            1           3            2
</TABLE>


                                       19
<PAGE>   22
     Of the 487 completed productive wells in the East Kalimantan contract
area, 282 contain more than one completion in the same bore hole.

     Two wells were in progress at December 31, 1995.  These include wells
which were drilled but not completed at the end of 1995.  None of the suspended
or "in-progress" wells are included in the table above.

CERTAIN RISKS APPLICABLE TO OPERATIONS IN INDONESIA

     The Company's interest in the IJV is an assignment of an interest in a
constructive trust.  This interest is essentially a revenue interest without
any operating or informational rights.  Although the Company now obtains
information about the IJV from a public source, there is no assurance that this
source of information will continue to be available in the future or that the
Company will be able to find alternative sources of information if its current
source of information becomes unavailable.

     Indonesian oil competes in the world market with oil produced from other
nations. Indonesia is a member of the Organization of Petroleum Exporting
Countries ("OPEC"), and any OPEC-imposed restrictions on oil or LNG exports in
which Indonesia participates could have a material adverse effect on the
Company.  The price of Indonesian oil is regulated by Pertamina.

     The LNG Plant competes for sales with other LNG plants in Indonesia, the
Middle East, Australia, Malaysia and elsewhere.

     The IJV's activities in Indonesia are subject to risks common to foreign
operations in the oil and gas industry, including political and economic
uncertainties, the risks of cancellation or unilateral modification of contract
rights, operating restrictions, currency repatriation restrictions,
expropriation, export restrictions,  the imposition of new taxes and the
increase of existing taxes and other risks arising out of foreign governmental
sovereignty over areas in which the IJV's operations are conducted.

     No methods to deliver or utilize the East Kalimantan natural gas reserves
are presently in place or in operation except liquefaction at the LNG Plant and
shipment by LNG tanker to purchasers.  Consequently, any significant reduction
in the output of the LNG Plant or disruption in tanker operations would have a
material adverse effect on the Company's revenues from the IJV.

MALAYSIA

GENERAL

     In September 1992, the Company acquired a 10% net working interest in the
SB-4 contract area offshore Sabah, Malaysia, covering 1,556,100 acres. In 1993,
the Company exercised an option to increase its net working interest to 15% in
the contract area.  In 1995, the Company increased its working interest to 25%
in the contract area.

     The initial well, Titik Terang #1, reached a total depth of 9,021 feet in
October 1992 and was abandoned as a gas discovery after three tests flowed gas
at a combined flow rate of approximately 46 Mmcf per day.  The well encountered
in excess of 250 feet of net gas pay.

     During 1993, the Nangka-1 well was drilled on a second structure to a
total depth of 5,366 feet without successfully finding hydrocarbons.  In
November 1995, the Company drilled the Deluar well to a total depth of 5,151
feet.  This well did not find commercial quantities of hydrocarbons, but
extended the contract area by an additional three years.

     At this time neither the Company nor its joint venture partners have any
additional plans for Malaysia.  However, Petronas, the Malaysian state oil
company, is building a new gas pipeline in the vicinity of the Company's field
which will be used for transportation of natural gas from fields owned by
Petronas to the island of Sabak for electrical power generation.  If in the
future the Company is able to obtain a gas sales contract, it would trigger the
development of Titik Terang field and the associated cost recovery process.
Under this process, expenditures already incurred together with future
exploratory and development costs would be recovered from hydrocarbon sales.





                                       20
<PAGE>   23
CERTAIN RISKS APPLICABLE TO OPERATIONS IN MALAYSIA

     The Company's activities in Malaysia are subject to certain risks,
including political and economic uncertainties, risks of cancellation or
unilateral modification of agreements, operating restrictions, currency
repatriation restrictions, expropriation, export restrictions, the imposition
of new taxes and the increase of existing taxes, inflation and other risks
arising out of foreign government sovereignty over areas in which the
operations are conducted.

TURKEY

GENERAL

     The Company owns interests in the "Isparta Permit," "Egridir Permit" and
"Akseki Permit" in southwestern Turkey covering 1,714,350 gross acres.  In
1992, the Company contributed to Tatex a 10% working interest in all three
exploration licenses, concurrently with the contribution to Tatex by Tatneft of
a study which Tatneft conducted of the area.

     In April 1993, the Company signed a farm-out agreement with Tatneft
whereby Tatneft would conduct certain activities in the permit areas during
1993 to earn the right to drill two exploratory wells in 1994.  The first phase
of the farm-out agreement was fulfilled during the last quarter of 1993 when
Tatneft successfully completed a 195 kilometer seismic survey.  In the second
phase, Tatneft agreed to drill at least one exploratory well during 1994 and to
consider drilling a second well.  The first well, Sobutepe #1, was spudded on
August 21, 1994.  The well was temporarily suspended at approximately 9,350
feet.

     Tatneft has informed the Company that it does not intend to drill the
second exploratory well and it does not intend to re-enter the first well.  At
this time, the Company has no additional activities planned for these permits
and is in the process of relinquishing its remaining acreage in Turkey.

CERTAIN RISKS APPLICABLE TO OPERATIONS IN TURKEY

     The Company's activities in Turkey are subject to certain risks, including
political and economic uncertainties, risks of cancellation or unilateral
modification of agreements, operating restrictions, currency repatriation
restrictions, expropriation, export restrictions, the imposition of new taxes
and the increase of existing taxes, inflation and other risks arising out of
foreign government sovereignty over areas in which the operations are
conducted.


                              PIPELINE OPERATIONS

GENERAL

     The Company's pipeline operations are conducted through its 100% owned
subsidiary USAgas Pipeline, Inc. ("USAgas").  USAgas is engaged in the
operation and development of natural gas gathering systems, natural gas
processing and treating plants and the marketing and transportation of natural
gas for the Company and its joint interest partners.  USAgas purchases and
takes title to gas at the wellhead, processing plants or other points of
receipt and sells such gas to major pipelines, industrial and institutional
users, local gas distribution companies and electric utilities.

     USAgas' pipeline operating assets are as follows:

<TABLE>
<CAPTION>
                                                                                      CAPACITY
                                                                                 ------------------
<S>                                                                              <C>
Natural Gas Processing Plant  . . . . . . . . . . . . . . . . . . . . . . . .    20,000 gallons/day
Natural Gas Treating Plant  . . . . . . . . . . . . . . . . . . . . . . . . .        10,000 Mcf/day
Gathering Systems (14 systems)  . . . . . . . . . . . . . . . . . . . . . . .       250,000 Mcf/day
</TABLE>

NATURAL GAS MARKETING

     USAgas' gas marketing activities are conducted through its office in
Houston, Texas.  It is USAgas' general practice to contract for a diverse
supply of gas from various geographic locations and producers to minimize its
reliance on any single source or region and to maximize its ability to deliver
gas to its customers.





                                       21
<PAGE>   24
     USAgas' practice is to match its gas sales contracts with corresponding
gas purchase contracts.  A single matched group may include one or more sales
contracts and one or more purchase contracts.  The objective is for the
corresponding purchase and sales contracts to provide for the same aggregate
maximum (and minimum, if any) volumes of gas to be delivered, to extend for the
same term between price re-determinations or other possible events of
termination and to provide for a built-in "spread" between the purchase and
sales prices.

NATURAL GAS SUPPLY

     There is a trend in the natural gas pipeline business toward more
flexibility in commitment of gas reserves both as to term and pricing.  It is
not practical for a pipeline company to tabulate gas reserves as being firmly
committed to its facilities.  The Company believes that most of the gas wells
connected to USAgas' fourteen existing gathering systems are likely to remain
connected until their depletion.  The gas from these reserves is primarily sold
to customers under contracts which require the customers to purchase defined
daily volumes.   The shutting in or curtailment of these volumes is minimized
because the systems are tied into numerous major East Texas/Northwest Louisiana
pipeline systems.  When one market lowers its daily throughput requirements,
the natural gas can be routed to another market.

     In order for USAgas to maintain current levels of throughput in its
pipeline systems, new natural gas supplies must be obtained, primarily from
newly drilled wells, to offset the natural decline of production from existing
wells.  Newly drilled wells also provide opportunities to increase business by
building additional natural gas pipeline systems to purchase or transport these
new supplies.  However, the Company cannot predict whether new natural gas
supplies will become available in adequate quantities to maintain current
levels of throughput in USAgas' pipeline system.

NATURAL GAS PIPELINE OPERATIONS

     The natural gas pipeline operations involve transportation of natural gas
located primarily in East Texas for others on a fee basis as well as the
purchase of natural gas from various suppliers and the transportation and
resale of such natural gas. USAgas' pipeline systems have considerable
flexibility in providing connections between producing and consuming areas.
The systems have multiple interconnections with interstate and intrastate
pipelines.

NATURAL GAS PROCESSING

      USAgas' natural gas processing plant located in McLeod, Texas extracts
natural gas liquids (ethane, propane, butane and natural gasoline,
collectively), ("NGLs") from natural gas supplied by producers located on two
gathering systems.  After processing, the residue natural gas is sold.   The
processing contracts provide that USAgas receives, as its fee for the
gathering, processing, treating and compressing of the natural gas, a portion
of the proceeds from the sale of the extracted NGLs and a portion of the
proceeds from the sale of the residue gas.  USAgas sells the extracted NGLs and
residue gas on the open market.  The profitability of such plants depends
directly upon the volumes and sales prices of the extracted NGLs and residue
gas.

NATURAL GAS TREATING

      USAgas also owns a natural gas treating plant located in McLeod, Texas.
Natural gas treating operations involve removing impurities from natural gas to
make it marketable.  This service is generally performed for purchasers or
producers located on the gathering systems. USAgas' facility removes acid gas
components, such as carbon dioxide, and inert gases, such as nitrogen, from the
natural gas delivered to the facility.  These services are performed under
long-term contracts for a fee per unit of natural gas treated.  The Company has
temporarily shut down operations of the nitrogen rejection unit at its McLeod
plant because of insufficient quantities of nitrogen-laden natural gas.  The
Company is not certain when or if sufficient quantities of nitrogen-laden
natural gas will be available to resume operations of this unit.

COMPETITION

     The natural gas pipeline industry is highly competitive, both in terms of
buying, transporting and marketing natural gas on existing pipelines and in
terms of obtaining opportunities to construct new pipelines to connect new
supplies and serve new markets.  Because of intense competition and market
uncertainties, USAgas' ability to maintain or increase its natural gas pipeline
throughput cannot be predicted.  In addition, gas pipeline operations are
subject to significant state and federal regulations.





                                       22
<PAGE>   25
                                OTHER OPERATIONS

INVESTMENT PROPERTIES INTERNATIONAL LIMITED

     The Company owns a 47% equity interest in Investment Properties
International Limited ("IPI"), a real estate investment company now in
liquidation under the supervision of a liquidator appointed by the Supreme
Court of Ontario.  The principal asset of IPI is 89% of the equity interest in
Property Resources Limited ("PRL"), a Bahamian real estate investment company.
The Board of PRL has undertaken to liquidate PRL and has made seven
distributions to its shareholders of proceeds received from the disposition of
its assets.  The Company has received approximately $79.3 million in
liquidating distributions since 1979. The estimated net realizable assets of
IPI and PRL are subject to liquidators' fees and to certain other claims which
could reduce the amount of any potential future distributions.  Definitive
information as to the remaining net realizable assets of IPI is not readily
available. However, based upon the limited information available, the Company
believes that the majority of the assets have been liquidated.  The Company
received distributions of $1.5 million and $1.3 million during 1995 and 1993,
respectively.  The Company received no distribution from IPI during 1994.  At
December 31, 1995 and 1994, the Company had no costs recorded related to this
investment.

ARGENTINA

     The Company owns overriding royalty interests in approximately 1,268,100
gross acres in the northwest basin of Argentina.  The properties are comprised
of the Santa Victoria exploration permit and the Ipaguazu concession, covering
1,114,900 acres in which the Company has a 1.5 percent overriding royalty, and
the El Chivil and Surubi concessions, covering 153,300 acres in which the
Company has a 1.5 percent overriding royalty.  During the fourth quarter of
1995, the Nacatimbay 1001 well was drilled and tested from two intervals at a
combined rate of 34.9 Mmcf of gas per day and 2,279 barrels of condensate per
day.  The well is located in the Santa Victoria concession and the Company
continues to monitor the activity in this area.

ARCTIC ISLANDS INTEREST

     The Company has interests in thirteen "Significant Discovery Areas"
("SDAs") representing 752,293 gross (33,364 net) acres in the Queen Elizabeth
Islands.  These SDAs are Hecla, Whitefish, Cisco, Drake, Char, Balaena, Cape
MacMillan, MacLean, Skate, Jackson Bay, Kristoffer Bay, Cape Allison and
Sculpin.  In the current economic environment, oil and gas prices are not
sufficient to generate positive cash flows from the production of oil and gas
from any of the aforementioned SDAs.  Additionally, certain environmental and
engineering questions must also be resolved and transportation facilities for
Arctic oil and gas must be developed.  Development of the region may also be
slowed by reduced demand, uncertain price structures and the Canadian
government's policies regarding the export of natural resources.  The Company
cannot predict when or if its Arctic interest may be developed.  At December
31, 1995 and 1994, the Company had no costs recorded related to this
investment.

NORTH COOK INLET

     The Company has a 1% override in 9,620 acres in the North Cook Inlet area
of Alaska.  Test rates announced for certain wells drilled during 1993 indicate
the presence of a potentially significant oil field.  The Company continues to
monitor the activity in this area.


                                       23
<PAGE>   26
FOREIGN ACREAGE

     The Company's acreage in areas outside the United States as of December
31, 1995 is summarized in the tables below.

<TABLE>
<CAPTION>
UNDEVELOPED ACREAGE
                                        WORKING INTEREST ACREAGE          ROYALTY INTEREST ACREAGE
                                      ----------------------------      ----------------------------
                                          GROSS            NET             GROSS              NET
                                      ------------     -----------      -----------         --------
<S>                                    <C>              <C>              <C>                 <C>
AREA:
Arctic Islands. . . . . . . . . . . .     752,293          33,364              --               --
Argentina . . . . . . . . . . . . . .         --              --         1,268,100           19,022
Australia . . . . . . . . . . . . . .         --              --         1,055,117            1,328
Egypt . . . . . . . . . . . . . . . .   9,159,806       7,519,823              --               --
Indonesia . . . . . . . . . . . . . .   1,156,780          19,827              --               --
Ivory Coast   . . . . . . . . . . . .     765,369          59,755              --               --
Malaysia  . . . . . . . . . . . . . .   1,556,100         233,415              --               --
Russia  . . . . . . . . . . . . . . .      12,107           6,053              --               --
Turkey  . . . . . . . . . . . . . . .     977,009         216,017              --               --
                                      ------------     -----------      -----------         --------
          Total . . . . . . . . . . .  14,379,464       8,088,254        2,323,217           20,350
                                      ============     ===========      ===========         ========

PRODUCING OR DEVELOPED ACREAGE

AREA:
Argentina . . . . . . . . . . . . . .         --              --               479                7
Australia . . . . . . . . . . . . . .         --              --            87,866               77
Egypt . . . . . . . . . . . . . . . .      19,760           4,940              --               --
Indonesia . . . . . . . . . . . . . .      97,000           1,663              --               --
Ivory Coast . . . . . . . . . . . . .     765,369         118,765              --               --
Russia  . . . . . . . . . . . . . . .      12,630           6,315              --               --
                                      ------------     -----------      -----------         --------
          Total . . . . . . . . . . .     894,759         131,683           88,345               84
                                      ============     ===========      ===========         ========
</TABLE>


                                     OTHER

REGULATORY MATTERS

     Regulation at the federal level of natural gas transportation and sale for
resale is administered primarily by the Federal Energy Regulatory Commission
("FERC") pursuant to the Natural Gas Act ("NGA") and the Natural Gas Policy Act
("NGPA").  The sale for resale of natural gas in interstate commerce is
regulated, in part, pursuant to the NGA, and maximum sales prices of certain
categories of gas, whether sold in interstate or intrastate commerce, have been
regulated pursuant to the NGPA since 1978. Effective January 1, 1993, the
Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas prices for
all "first sales" of natural gas, which include all sales by the Company of its
own production.  Consequently, sales of the Company's natural gas currently may
be made at market prices, subject to applicable contract provisions.

     Transportation and sales for resale of gas in interstate commerce by
intrastate pipelines are regulated by FERC pursuant to NGPA Section 311.
Section 311 permits intrastate companies under certain circumstances to sell
gas to, transport gas for, or have gas transported by interstate pipeline
companies without being regulated as interstate pipelines under the NGA.  In
1991, FERC issued regulations (Order 555) regarding new pipeline construction,
including construction performed by intrastate pipelines of facilities for use
for transportation pursuant to Section 311.  The regulations impose certain
reporting and environmental requirements that could affect new pipeline
construction the Company may undertake.  While FERC has withdrawn these rules
with respect to interstate pipelines, the reporting and environmental
requirements still apply to intrastate pipelines.

     Since 1985, FERC has endeavored to make natural gas transportation more
accessible to gas buyers and sellers on an open and non-discriminatory basis.
These efforts have significantly altered the marketing and pricing of natural
gas.  Commencing in April 1992, FERC issued Order Nos. 636, 636-A and 636-B
("Order 636"), which contemplate, in part, the unbundling of pipeline merchant
and transportation functions.  The goal of Order 636 is to ensure comparability
of service so that pipeline system supply is treated no differently than gas of
third-party shippers.


                                       24
<PAGE>   27
Specifically, Order 636 includes several procedures to increase competition in
the industry, including: (i) the issuance of blanket sales certificates to
interstate pipelines for unbundled services; (ii) the continuation of
pregranted abandonment of previously committed pipeline sales and
transportation services, essentially freeing up unused pipeline capacity and
clearing the way for excess transportation capacity to be reallocated to the
marketplace; (iii) requiring that firm and interruptible transportation
services be provided by the pipelines to all parties on a comparable basis; and
(iv) generally requiring that pipelines derive transportation rates using a
straight fixed variable ("SFV") rate method, which places all fixed costs in a
fixed demand charge.  The specific details of each interstate pipeline's
restructuring plan were to be resolved in restructuring compliance filings and
through settlement conferences held between each interstate pipeline and all
interested parties.  In many instances, Order 636 has substantially reduced or
brought to an end interstate pipelines' traditional role as wholesalers of
natural gas in favor of providing only storage and transportation services.

     As of early 1995, FERC has issued final orders accepting most pipelines'
Order 636 compliance filings, and had commenced a series of one year reviews of
individual pipeline implementations of Order 636.  Numerous parties have filed
petitions for review of Order 636, as well as orders in individual pipeline
restructuring proceedings.  Upon such judicial review, these orders may be
remanded or reversed in whole or in part.  With Order 636 subject to court
review, and pending ongoing FERC reviews of individual pipeline restructurings,
it is difficult to predict with precision its ultimate effects.

     While Order 636 does not directly regulate the Company's activities, it
has had and will have an indirect effect because of its broad scope.  Among
other effects, Order 636 has substantially increased competition in natural gas
markets, even though there remains significant uncertainty with respect to the
marketing and transportation of natural gas.  Ultimately, however, Order 636
may enhance the Company's ability to market and transport its gas production,
although it may also subject the Company to more restrictive pipeline imbalance
tolerances and greater penalties for violations of such tolerances.

     In July 1994, the FERC eliminated a regulation that had rendered virtually
all sales of natural gas by pipeline affiliates, such as the Company's, to be
deregulated first sales.  As a result, only sales by the Company of its own
production now qualify for this status.  All other interstate sales for resale
of gas by the Company, such as those of gas purchased from third parties, are
now jurisdictional sales subject to a NGA certificate.  The Company does not
anticipate this change will have any significant current adverse effects in
light of the flexible terms and conditions of the existing blanket certificate.
Such sales are subject to the future possibility of greater federal oversight;
however, including the possibility the FERC might prospectively impose more
restrictive conditions on such sales.

     The FERC has announced its intention to re-examine certain of its
transportation-related policies, including the appropriate manner in which
interstate pipelines release transportation capacity under Order 636, and the
use of market-based rates for interstate gas transmission.  While any
resulting FERC action would affect the Company only indirectly, the FERC's
current rules and policy statements may have the effect of enhancing
competition in natural gas markets by, among other things, encouraging
non-producer natural gas marketers to engage in certain purchase and sale
transactions.  The Company cannot predict what action the FERC will take on
these matters, nor can it accurately predict whether the FERC's actions will
achieve the goal of increasing competition in markets in which the Company's
natural gas is sold.  However, the Company does not believe that the effect on
the Company of any such action will be materially different from the effect on
other natural gas producers and marketers with which the Company competes.

     Recently, the FERC issued a policy statement on how interstate natural gas
pipelines can recover the costs of new pipeline facilities.  While this policy
statement affects the Company only indirectly, in its present form, the new
policy should enhance competition in natural gas markets and facilitate
construction of gas supply laterals.  However, requests for rehearing of this
policy statement are currently pending.  The Company cannot predict what action
the FERC will take on these requests.

     The Company's natural gas gathering operations may be or become subject to
safety and operational regulations relating to the design, installation,
testing, construction, operation, replacement, and management of facilities.
Pipeline safety issues have recently become the subject of increasing focus in
various political and administrative arenas at both the state and federal
levels.  For example, federal legislation addressing pipeline safety issues has
been introduced, which, if enacted, would establish a federal "one call"
notification system.  Additional pending legislation would, among other things,
increase the frequency with which certain pipelines must be inspected, as well
as increase potential civil and criminal penalties for violations of pipeline
safety requirements.  The Company cannot predict what effect, if any, the
adoption of this or other additional pipeline safety legislation might have on
its operations.


                                       25
<PAGE>   28
     Regulatory agencies in certain states have authority to issue permits for
the drilling of wells, regulate the spacing of wells, prevent the waste of oil
and gas resources through proration, require drilling bonds and reports
concerning operations, and regulate environmental and safety matters.  In 1993,
the states of Texas and Oklahoma adopted changes to oil and gas production and
proration regulations which alter the methods used to prorate gas production
from wells located in the state.  These measures may limit the rate at which
gas can be produced from wells the Company operates or in which it has an
interest in such states.

     Regulation of natural gas gathering activities is primarily a matter of
state oversight.  While some states provide for the rate regulation of
pipelines engaged in the intrastate transportation of natural gas, such
regulation has not generally been applied against gatherers of natural gas.
State regulation of gathering facilities generally includes various safety,
environmental, and in some circumstances, non-discriminatory take requirements.
Natural gas gathering may receive greater regulatory scrutiny at the federal
and state levels as the pipeline restructuring under Order 636 is completed.
For example, in 1995, the State of Oklahoma enacted legislation that requires
provision of open access, non-discriminatory gathering service and a
prohibition against discriminatory gathering rates.  Commencing in May 1994,
FERC issued a series of orders in individual cases that delineate its gathering
policy.  Among other matters, FERC slightly narrowed its statutory tests for
establishing gathering status and reaffirmed that, except in situations in
which the gatherer acts in concert with an interstate pipeline affiliate to
frustrate FERC's transportation policies, it does not have jurisdiction over
gathering facilities and services and that such facilities and services are
properly regulated by state authorities.  This FERC action may further
encourage regulatory scrutiny of natural gas gathering by state agencies.  In
addition, FERC has approved several transfers by interstate pipelines of
gathering facilities to unregulated, independent or affiliated gathering
companies.  This could increase competition among gatherers in the affected
areas.  Certain FERC orders delineating its new gathering policy are subject to
pending court appeals.  The Company's operations could be adversely affected
should they be subject in the future to the application of state or federal
regulation of rates and services.

     Regulation of gathering and transportation activities in Louisiana and
Texas includes various transportation, safety, environmental and
non-discriminatory purchase and transport requirements. Most of the Company's
intrastate transportation operations occur within the State of Texas.
Intrastate pipeline rates excluding rates for city-gate sales for resale are
presumed by the Railroad Commission of Texas ("RRC") to be just and reasonable
where:  (i) neither the company nor the customer had an unfair advantage during
negotiations, (ii) the rates are substantially the same as rates for similar
service, or (iii) competition does or did exist for the market with another
supplier of natural gas or an alternative form of energy.

     Operations conducted by the Company on federal oil and gas leases must
comply with numerous regulatory restrictions, including various
non-discrimination statutes.  Additionally, certain operations must be
conducted pursuant to appropriate permits issued by the Bureau of Land
Management and the Minerals Management Service ("MMS") of the Department of
Interior, and, in regard to certain federal leases, with prior approval of
drill site locations by the Environmental Protection Agency.

     As required by the Energy Policy Act of 1992, in October 1993 the FERC
adopted a proposal to simplify the manner in which oil pipeline rates are set,
which, effective as of January 1, 1995, allows or requires pipelines to index
such rates to inflation, subject to certain conditions and limitations.  The
FERC's decision in this matter is currently the subject of various petitions
for judicial review.  It is difficult to predict at this time what effect the
new rules might have on the cost of moving the Company's oil, condensate, and
other liquid products to market, but the new rules may have the effect of
increasing the cost of such transportation.

     The Outer Continental Shelf Lands Act ("OCSLA") requires that all
pipelines operating on or across the Outer Continental Shelf ("OCS") provide
open-access, non-discriminatory service.  Although the FERC has opted not to
impose the regulations of Order No. 509, in which the FERC implemented the
OCSLA, on gatherers and other non-jurisdictional entities, the FERC has
retained the authority to exercise jurisdiction over those entities if
necessary to permit non-discriminatory access to service on the OCS.

     Certain operations the Company conducts are on federal oil and gas leases,
which the MMS administers.  The MMS issues such leases through competitive
bidding.  These leases contain relatively standardized terms and require
compliance with detailed MMS regulations and orders pursuant to the OCSLA
(which are subject to change by the MMS).  For offshore operations, lessees
must obtain MMS approval for exploration plans and development and production
plans prior to the commencement of operations.  In addition to permits required
from other agencies (such as the Coast Guard, the Army Corps of Engineers and
the Environmental Protection Agency), lessees must obtain a


                                       26
<PAGE>   29
permit from the MMS prior to the commencement of drilling.  The MMS has
promulgated regulations requiring offshore production facilities located on the
OCS to meet stringent engineering and construction specifications.  The MMS
proposed additional safety-related regulations concerning the design and
operating procedures for OCS production platforms and pipelines.  These
proposed regulations were withdrawn pending further discussions among
interested federal agencies.  The MMS also has regulations restricting the
flaring or venting of natural gas, and has recently proposed to amend such
regulations to prohibit the flaring of liquid hydrocarbons and oil without
prior authorization.  Similarly, the MMS has promulgated other regulations
governing the plugging and abandonment of wells located offshore and the
removal of all production facilities.  To cover the various obligations of
lessees on the OCS, the MMS generally requires that lessees post substantial
bonds or other acceptable assurances that such obligations will be met.  The
cost of such bonds or other surety can be substantial and there is no assurance
that the Company can continue to obtain bonds or other surety in all cases.

     The MMS has recently issued a notice of proposed rulemaking in which it
proposes to amend its regulations governing the calculation of royalties and
the valuation of natural gas produced from federal leases.  The principle
feature in the amendments, as proposed, would establish an alternative
market-index based method to calculate royalties on certain natural gas
production sold to affiliates or pursuant to non-arm's-length sales contracts.
The MMS has proposed this rulemaking to facilitate royalty valuation in light
of changes in the gas marketing environment.  The Company cannot predict what
action the MMS will take on these matters, nor can it predict at this stage of
the rulemaking proceeding how the Company might be affected by amendments to
the regulations.

     The Company cannot predict the effect that any of the aforementioned
orders or the challenges to the orders will have on the Company's operations.
Additional proposals and proceedings that might affect the natural gas industry
are pending before Congress, FERC and the courts. These include congressional
energy bills and executive branch energy initiatives which have as their goal
the decreased reliance by the United States on foreign energy supplies. The
Company cannot predict when or whether any such proposals or proceedings may
become effective.

     Various federal, state and local laws and regulations covering the
discharge of materials into the environment, or otherwise relating to the
protection of the public health and the environment, may affect the Company's
operations, expenses and costs.  The clear trend in environmental regulation is
to place more restrictions and limitations on activities that may impact the
environment, such as emissions of pollutants, generation and disposal of
wastes, and use and handling of chemical substances.  Increasingly strict
environmental restrictions and limitations have resulted in increased operating
costs for the Company and other similar businesses throughout the United
States, and it is possible that the costs of compliance with environmental laws
and regulations will continue to increase.  In particular, Congress has
considered including provisions in the reauthorization of the Federal Resource
Conservation and Recovery Act ("RCRA"), the principal statute governing the
disposal of solid and hazardous wastes, that would repeal the statutory
exemption that classifies oil and gas exploration and production wastes as
non-hazardous.  Such amendments, if adopted, could result in substantial
ongoing management and remedial obligations with respect to such wastes being
imposed on domestic oil and gas producers, including the Company.  State
initiatives to regulate further  the disposal of oil and gas wastes are also
pending in certain states, including states in which the Company has
operations, and these initiatives could have a similar impact on the Company.
For instance, pursuant to Texas State Senate Bill 1103, the RRC recently
promulgated additional rules for the management and disposal of certain oil and
gas waste, which will become effective on April 1, 1996.   In addition, the
Company is subject to laws and regulations concerning occupational health and
safety.  It is not anticipated that the Company will be required in the near
future to expend amounts that are material in relation to its total capital
expenditures program by reason of environmental or occupational health and
safety laws and regulations, but inasmuch as such laws and regulations are
frequently changed, the Company is unable to predict the ultimate cost of
compliance.

     The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder
impose a variety of regulations on "responsible parties" related to the
prevention of oil spills and liability for damages resulting from such spills
in United States waters.  A "responsible party" includes the owner or operator
of a facility or vessel, or the lessee or permittee of the area in which an
offshore facility is located.  The OPA assigns liability to each responsible
party for oil removal costs and a variety of public and private damages.  While
liability limits apply in some circumstances, a party cannot take advantage of
liability limits if the spill was caused by gross negligence or willful
misconduct or resulted from violation of a federal safety, construction or
operating regulation.  If the party fails to report a spill or to cooperate
fully in the cleanup, liability limits likewise do not apply.  Few defenses
exist to the liability imposed by the OPA.

     The OPA also imposes ongoing requirements on a responsible party,
including proof of $150 million in financial responsibility for offshore
facility lessees or permittees to cover at least some costs in a potential
spill.  On August 25,
                                       27
<PAGE>   30
1993, the MMS, which administers federal oil and gas leases, published an
advance notice of its intention to adopt a rule under the OPA to implement the
offshore facility financial responsibility requirement.  Under the proposed
rule, financial responsibility could be established through insurance,
guaranty, indemnity, surety bond, letter of credit, qualification as a
self-insurer or a combination thereof.  There is some question as to whether
insurance companies or underwriters would be willing to provide coverage under
the OPA because the statute provides for direct lawsuits against insurers who
provide financial responsibility coverage, and most insurers have strongly
protested this requirement.  Because of the negative comments submitted to the
advanced rulemaking notice, the MMS has not yet proposed a financial
responsibility rule under the OPA.  Furthermore, the MMS is not expected to
propose the financial responsibility rule until Congress has had an opportunity
to reevaluate the $150 million financial responsibility requirement in the OPA.
Both the United States House of Representatives and Senate have passed bills
that would lower the OPA financial responsibility requirements for offshore
facilities to $35 million, the amount currently required under the OCSLA.
Differences between the two bills are being resolved in conference committee,
and the OPA financial responsibility requirements for offshore facilities may
be reduced sometime in 1996.

     The OPA also imposes other requirements, such as the preparation of an oil
spill contingency plan.  The Company has such a plan in place.  Failure to
comply with ongoing requirements or inadequate cooperation during a spill event
may subject a responsible party to civil or criminal enforcement actions.

ADDITIONAL FACTORS AFFECTING THE BUSINESS

     The oil and gas business is highly competitive in both the exploration and
the acquisition of reserves and in the marketing of oil and gas production.
Exploration for oil and gas is subject to a high degree of risk, and the
Company faces intense competition from present and potential competitors, many
of whom have greater resources than the Company.

     Large expenditures are required to locate and acquire properties and to
drill exploratory and development wells, and the Company can never be certain
that such expenditures will result in the discovery of oil and gas reserves in
commercial quantities sufficient to replace reserves currently being produced
and sold.  In certain areas where the Company operates, even where natural gas
or crude oil is present in substantial quantities, there may be no means to
transport the gas or oil to market.

     The operations of the Company have been, and in the future from time to
time may be, affected by political developments in countries in which it
operates and by federal, state and local laws and regulations, such as
restrictions on production, changes in taxes, royalties and other amounts
payable to governments or governmental agencies, price controls and
environmental protection regulations, and the risks of nationalization and of
unilateral cancellation or adverse modification of contract or other rights.

     The exploration, development, and production of crude oil and natural gas
are also subject to such operating risks as fires, blowouts, pollution and
other hazards.  In many cases, insurance for such risks is unavailable or
prohibitively expensive, and the occurrence of certain uninsured hazards could
have a material adverse effect on the Company's financial position and
operating results.

EMPLOYEES

     As of March 1, 1996, the Company had a total of 88 full-time U.S.
employees which included 19 employees of the Company's wholly-owned subsidiary,
USAgas.  In addition, outside consultants and specialists are sometimes
utilized in gathering and analyzing technical data, lease acquisitions,
operating activities, and field supervision.





                                       28
<PAGE>   31
ITEM 3.  LEGAL PROCEEDINGS

     The Company has pending litigation incidental to its operations.
Management believes that none of the litigation is expected to have a material
adverse effect on the Company's financial position or results of operations.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     There were no matters submitted to a vote of the Company's security
holders during the fourth quarter of the fiscal year ended December 31, 1995.





                                       29
<PAGE>   32
                                    PART II

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

     The high and low sales prices for the common stock of the Company for each
quarter of the two years ended December 31, 1995, in the United States on the
New York Stock Exchange (under the symbol "GNR"), were as follows:

<TABLE>
<CAPTION>
                                                 1995 MARKET PRICE          1994 MARKET PRICE
                                             ------------------------    -----------------------
QUARTER ENDED                                   HIGH           LOW         HIGH           LOW
-------------                                ----------     ---------    ---------     ---------                                   
<S>                                           <C>            <C>          <C>           <C>
March 31  . . . . . . . . . . . . . . . . . . $  8.750       $ 7.000      $ 8.375       $ 6.750
June 30 . . . . . . . . . . . . . . . . . . . $ 12.375       $ 7.500      $ 7.875       $ 6.375
September 30  . . . . . . . . . . . . . . . . $ 11.750       $ 9.000      $ 8.125       $ 7.125
December 31 . . . . . . . . . . . . . . . . . $ 10.625       $ 9.375      $ 9.625       $ 6.625
</TABLE>


     As of March 1, 1996, the Company had 2,492 shareholders of record.  The
Company has never paid cash dividends and does not expect to pay cash dividends
in the near future.

     As of December 31, 1995 and March 1, 1996, the Company held 3,887,513 of
its own shares in treasury.

ITEM 6.  SELECTED FINANCIAL DATA

FIVE YEAR DATA

     Selected financial data for the Company on a consolidated basis is
presented below.

<TABLE>
<CAPTION>
                                              1995           1994          1993          1992          1991
                                           ----------     ----------    ----------    ----------    ----------
                                                     (AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
<S>                                        <C>            <C>           <C>           <C>           <C>
Revenues  . . . . . . . . . . . . . . .    $  78,457      $  62,943     $  75,084     $  57,506     $  60,194
Exploration expense . . . . . . . . . .       11,768         19,325         6,946         6,522        11,925
Net income (loss) . . . . . . . . . . .       (6,307)        (8,253)        4,487        (2,846)      (39,105)
Net income (loss) per share(1)  . . . .         (.21)          (.28)          .16          (.12)        (1.66)
Cash provided by operating activities(2)      54,751         38,189        19,531         6,713        15,071
IPI distributions . . . . . . . . . . .        1,520          --            1,267         --            3,040
Additions to properties and equipment .       58,754         52,301        25,852         7,873        24,649
Standardized measure of discounted
     future net cash flows relating to
     proved oil and gas reserves  . . .      229,046        142,615       109,202        93,955        97,075
Total assets  . . . . . . . . . . . . .      160,329        154,500       161,931       131,511       140,177
Non-current redeemable bearer shares(3)       16,591         17,467        18,375         --            --
Shareholders' equity(4) . . . . . . . .      102,226        107,756       120,376       114,653       118,156
Long-term portion of debt . . . . . . .       11,764          1,275         --               55           234
Working capital . . . . . . . . . . . .        5,263         26,299        61,689        42,467        35,276
Weighted average common shares
     outstanding  . . . . . . . . . . .       29,497         29,661        28,361        23,593        23,515
</TABLE>

(1)  Net income on a fully diluted basis for 1993 was $.15 per share.
(2)  To be read in the context of the Consolidated Statements of Cash Flows
     included in Item 8 herein.
(3)  See Note 3 to Consolidated Financial Statements for discussion of
     redeemable bearer shares.
(4)  See Note 5 to Consolidated Financial Statements for discussion of
     convertible preferred shares.


                                       30
<PAGE>   33
INTERIM FINANCIAL DATA (UNAUDITED)

     The following is a condensed summary of the results of operations for the
calendar quarters of 1995 and 1994.

<TABLE>
<CAPTION>
                                                                         1995 QUARTER ENDED
                                                       ------------------------------------------------------
                                                        MARCH 31       JUNE 30      SEPT. 30        DEC. 31
                                                       ----------     ----------   ----------      ----------
                                                          (AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
<S>                                                    <C>            <C>          <C>             <C>
Revenues  . . . . . . . . . . . . . . . . . . . .      $  18,721      $  17,877    $  18,654       $  23,205
Income (loss) from operations . . . . . . . . . .          1,363         (2,107)         946            (463)
Net income (loss) . . . . . . . . . . . . . . . .           (734)        (3,923)       1,158          (2,808)
Net income (loss) per share . . . . . . . . . . .           (.02)          (.13)         .04            (.10)
</TABLE>

     During the first, second, third and fourth quarters of 1995, the Company
incurred exploration expenditures of approximately $2.9 million, $4.1 million,
$2.6 million and $2.2 million, respectively.  Included in these expenditures
were dry hole costs for unsuccessful exploratory wells of $1.2 million, $2.7
million, $1.2 million and $0.9 million, respectively.  Included in the third
quarter of 1995 was a $1.5 million distribution from IPI.  Included in the
fourth quarter of 1995 was a $4.5 million non-cash impairment of long-lived
assets resulting from the Company's adoption during that quarter of Statement
No. 121.

<TABLE>
<CAPTION>
                                                                          1994 QUARTER ENDED
                                                       ------------------------------------------------------
                                                        MARCH 31       JUNE 30      SEPT. 30        DEC. 31
                                                       ----------     ----------   ----------      ----------
                                                          (AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
<S>                                                    <C>            <C>          <C>             <C>
Revenues  . . . . . . . . . . . . . . . . . . . . .    $  16,054      $  13,450    $  16,565       $  16,874
Income (loss) from operations . . . . . . . . . . .        3,110         (3,568)        (706)         (2,015)
Net income (loss) . . . . . . . . . . . . . . . . .        2,065         (4,376)      (2,415)         (3,527)
Net income (loss) per share . . . . . . . . . . . .          .07           (.15)        (.08)           (.12)
</TABLE>

     During the first, second, third and fourth quarters of 1994, the Company
incurred exploration expenditures of $1.7 million, $6.4 million, $4.8 million
and $6.4  million, respectively.  Included in these expenditures were dry hole
costs for unsuccessful exploratory wells of $0.2 million, $4.6 million, $2.5
million and $3.9 million, respectively.

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
         RESULTS OF OPERATIONS

INTRODUCTION

     During 1995, 1994 and 1993 the Company's worldwide oil and gas production
increased approximately 1.3 Mmbls (38%), .9 Mmbls (36%), and .3 Mmbls (12%) of
oil equivalent, respectively.  During these same periods, the Company's
worldwide oil and gas reserve base increased approximately 9.3 Mmbls (19%),
14.7 Mmbls (44%), and 7.2 Mmbls (27%) of oil equivalent, respectively.  During
1995 and 1994, the Company increased the future discounted net values before
tax effects as compared to the previous period by $133.8 million (67%) and
$54.1 million (37%), respectively.  At the same time, the Company increased the
future discounted net value after tax effects as compared to the previous
period by $86.4 million (61%) and $33.4 million (31%), respectively.  These
increases are primarily the result of the Company's exploration and development
efforts undertaken during these years.

     The Company's reserve replacement ratio, inclusive of revisions of
previous estimates and purchases of reserves in place, and based on net
equivalent barrels, from exploration and development activities for 1995, 1994
and 1993 was 301%, 587% and 403%, respectively.  The reserve replacement ratio
for 1995 was the result of the Company's 1995 domestic and international
drilling programs combined with positive revisions to previous estimates and
the addition of proved reserves from the Suncheleevsky field in Russia.  The
reserve replacement ratio for 1994 was the result of the Company's 1994
drilling program, primarily international, and positive revisions to previous
estimates. The reserve replacement ratio for 1993 was the result of the
Company's 1993 drilling program, primarily domestic, and positive revisions to
previous reserve estimates, primarily associated with the Company's Taylor Lake
and San Juan properties.

     In 1995, 1994 and 1993, the Company generated $54.8 million, $38.2 million
and $19.5 million, respectively, in cash from operating activities.  The
Company's expenditures for exploration and development activities in 1995, 1994
and 1993 were $56.3 million, $49.0 million and $22.1 million, respectively.  In
1995 and 1994, the Company's expenditures for the acquisition of producing
properties were $3.2 million and $3.8 million, respectively.  In 1993, the

                                       31
<PAGE>   34
Company acquired no producing properties.  The Company currently anticipates
expending approximately $51.4 million in 1996 for exploration and development
activities.  Of this amount, domestic exploration and development expenditures
are projected to be approximately $14.3 million and international exploration
and development activities are projected to be approximately $37.1 million.

RESULTS OF OPERATIONS

     In 1995, the Company recorded a net loss of $6.3 million ($.21 per share)
compared to a net loss of $8.3 million ($.28 per share) in 1994 and net income
of $4.5 million ($.16 per share) in 1993.  The net loss for 1995 includes a
$4.5 million non-cash impairment of long-lived assets that resulted from the
Company's adoption of Statement of Financial Accounting Standards ("Statement")
No. 121 in the fourth quarter of 1995.  The 1995 net loss also includes $11.8
million in exploration expenses.  During 1994 and 1993, exploration expenses
were $19.3 million and $6.9 million, respectively.  Included in exploration
expenditures were dry hole costs of $6 million, $11.2 million and $1.9 million
in 1995, 1994 and 1993, respectively.  The net loss for 1995 includes a $1.5
million distribution from Investment Properties International Limited ("IPI").
No such distribution was received during 1994.  The net income for 1993
includes a $1.3 million distribution from IPI and a $2.3 million net gain on
the sale of producing properties and other assets.

  Oil and Gas

     In 1995, 1994 and 1993, worldwide oil and gas production accounted for
$58.1 million (74%), $43.8 million (70%) and $35.7 million (48%) of the
Company's operating revenues, respectively.  Domestic oil and gas operations
accounted for $24.9 million (32%), $20.1 million (32%) and $19.3 million (26%)
of the Company's operating revenues during the same periods.  Indonesian oil
and gas operations accounted for $12.4 million (16%), $11.7 million (19%) and
$11.3 million (15%) of the Company's operating revenues in 1995, 1994 and 1993,
respectively.  Russian oil and gas operations accounted for $16 million (20%),
$12 million (19%) and $4.6 million (6%) of the Company's operating revenues in
1995, 1994 and 1993, respectively.

     Worldwide oil and gas revenues increased approximately $14.3 million (33%)
from 1994 to 1995.  Russian revenues increased $4.1 million (34%) during 1995,
primarily as the result of increased oil production from the Onbysk field and
higher oil prices.  Domestic oil and gas revenues increased $4.7 million (24%)
during 1995 primarily because of increased natural gas production from the
Company's Taylor Lake and offshore fields.  When compared to 1994, domestic
natural gas production increased 54% during 1995.  This production increase
more than offset the 19% decrease in the Company's domestic gas prices from
1994 to 1995.  During 1995, the Company recorded initial revenues from its
operations in the Ivory Coast and Egypt of $4.4 million and $0.5 million,
respectively.  Initial Ivory Coast oil and natural gas production began in
April and October of 1995, respectively.  Egyptian oil production began in
December of 1995.

     Worldwide oil and gas revenues increased approximately $8.1 million (23%)
from 1993 to 1994.  Russian revenues increased $7.4 million (160%) during 1994,
primarily as the result of increased oil production from the Onbysk field.
Slight increases were recorded for both Indonesian and domestic revenues.
During 1994, domestic oil and gas revenues increased approximately 4% as
compared to 1993.  This increase was the direct result of increased natural gas
production from the Company's Taylor Lake field and from new offshore fields
from which initial production began late in 1994.  Compared to 1993, domestic
natural gas production increased 27% during 1994.  This increased production
was principally offset by decreases during 1994 as compared to 1993 in gas
prices, oil prices and oil production of 12%, 9% and 13%, respectively.

     The Company's oil and gas volumes and unit prices for the United States,
Indonesia, Russia, Ivory Coast and Egypt for 1995, 1994 and 1993 are summarized
in the following table:

<TABLE>
<CAPTION>
                                         VOLUMES                              UNIT PRICE
                           ----------------------------------    -----------------------------------
                             1995         1994         1993        1995         1994          1993
                           --------      -------      -------    --------     --------      --------
<S>                         <C>           <C>          <C>        <C>          <C>           <C>
UNITED STATES
Oil (MBbl)  . . . . .          244          229          263      $17.20       $15.65        $17.11
Gas (Mmcf)  . . . . .       13,710        8,904        7,088      $ 1.51       $ 1.86        $ 2.11

INDONESIA
Oil (MBbl)  . . . . .           45           47           54      $17.18       $16.58        $18.31
Gas (Mmcf)  . . . . .        3,933        4,473        3,769      $ 2.96       $ 2.45         $2.75
</TABLE>

                                             (Table continued on following page)


                                       32
<PAGE>   35
<TABLE>
<CAPTION>
                                         VOLUMES                              UNIT PRICE
                           ----------------------------------    -----------------------------------
                             1995         1994         1993        1995         1994          1993
                           --------      -------      -------    --------     --------      --------
<S>                         <C>           <C>          <C>        <C>          <C>           <C>
RUSSIA
Oil (MBbl)  . . . . .        1,062          842          323      $15.11       $14.21        $14.24
Gas(Mmcf) . . . . . .          --           --           --       $  --        $  --         $  --   

IVORY COAST
Oil (MBbl)  . . . . .          261          --           --       $15.51       $  --         $  --   
Gas (Mmcf)  . . . . .          203          --           --       $ 1.61       $  --         $  --   
                                                                                                   
EGYPT
Oil (MBbl)  . . . . .           25          --           --       $17.97       $  --         $  --   
Gas (Mmcf)  . . . . .          --           --           --       $  --        $  --         $  --   
</TABLE>

     The oil and gas revenue variances resulting from volume and price changes
for the United States, Indonesia and Russia during 1995 and 1994 are summarized
in the table below (amounts in thousands).

<TABLE>
<CAPTION>
                                   UNITED STATES              INDONESIA                 RUSSIA
                               ----------------------    ---------------------  --------------------
                                  VARIANCE DUE TO:           VARIANCE DUE TO:      VARIANCE DUE TO:
                                 PRICE        VOLUME       PRICE       VOLUME    PRICE       VOLUME
                               ---------     --------    ---------   ---------  -------     --------
<S>                            <C>           <C>         <C>         <C>        <C>         <C>
1995 VS 1994
------------
Oil . . . . . . . . . . . .    $    378      $   235     $     27    $    (33)  $  956      $ 3,126
Gas . . . . . . . . . . . .    $ (4,799)     $ 8,939     $  2,006    $ (1,323)  $   --      $    --
1994 VS 1993
------------
Oil . . . . . . . . . . . .    $   (334)     $  (582)    $    (81)   $   (128)  $  (25)     $ 7,390
Gas . . . . . . . . . . . .    $ (2,226)     $ 3,832     $ (1,342)   $  1,936   $   --      $    --
</TABLE>

     Worldwide production expenses increased 16% and 38% during 1995 and 1994,
respectively, when compared to production expenses of the previous year.  These
increases in production expenses are primarily reflective of increased worldwide
production on an equivalent barrel of oil basis of 38% and 36% during those
periods, respectively.  Worldwide production expenses per equivalent barrel of
oil produced during 1995, 1994 and 1993 were $2.82, $3.35 and $3.30,
respectively.  The significant decrease in production expenses per equivalent
barrel of oil from 1994 to 1995 is primarily due to the exemption from export
tax in the Company's Russian operations for 1995.  Domestic production expenses
per equivalent barrel of oil produced during 1995, 1994 and 1993 were $2.27,
$1.97 and $2.61, respectively.  The decrease in domestic production expenses per
equivalent barrel of oil during 1994 is reflective of increased production
during 1994 from the Company's lower cost Taylor Lake field.  The increase in
domestic production expense per equivalent barrel of oil during 1995 is
primarily the result of three workovers associated with the Company's offshore
properties.  Excluding workover costs, production expenses per equivalent barrel
of oil produced would have been $1.93, $1.93 and $2.47, respectively. Russian
production expenses accounted for $6.2 million (48%), $7.8 million (70%) and
$4.0 million (49%) of the Company's production expenses in 1995, 1994 and 1993,
respectively.  Included in Russian production expenses were export tax expenses
of $4.1 million and $1.7 million during 1994 and 1993, respectively.  No export
tax expense was incurred in 1995.

     Exploration expenses in 1995 decreased approximately $7.6 million when
compared to exploration expenses incurred during 1994.  This decrease is
reflective of a $5.3 million decrease in dry hole costs and a $1.3 million
decrease in leasehold impairments.  Included in 1994 exploration expenses were
dry hole expenditures, leasehold impairments and geological costs of
approximately $11.2 million, $2.4 million and $3.1 million.  The same
expenditures during 1993 were approximately $1.9 million, $2.4 million and $1.1
million, respectively.  The Company added to its reserve base during 1995 and
1994 approximately 9.3 Mmbls (19%) and 14.7 Mmbls (44%), respectively, on a
barrel of equivalent oil basis.

     Depletion, depreciation and amortization increased approximately $11.7
million (119%) during 1995 when compared to 1994 and $1.5 million (17%) during
1994 when compared to 1993.  Worldwide depletion, depreciation and amortization
per equivalent barrel of oil produced during 1995, 1994 and 1993 were $4.67,
$2.94 and $3.39, respectively.  The increase in the aggregate and the per
equivalent barrel of oil depletion, depreciation and amortization during 1995 is
partially associated with the Company's Mustang Island 783 field.  Because of
rapidly decreasing bottom hole pressure with corresponding production decreases,
the Company recorded depletion expense of $4 million associated with this field
during 1995.  Excluding depletion expense and production volumes associated with
Mustang Island 783, the 1995 
                                       33
<PAGE>   36
worldwide rate per equivalent barrel of oil would have been $3.92.  Domestic
depletion, depreciation and amortization expenses per equivalent barrel of oil
production excluding Mustang Island 783 during 1995, 1994 and 1993 were $4.79,
$3.74 and $4.12, respectively.  Russian depletion, depreciation and
amortization expenses accounted for $2.1 million (10%), $1.6 million (16%) and
$0.6 million (7%) of the Company's depletion, depreciation and amortization
expenses in 1995, 1994 and 1993, respectively.

     Administrative expenses increased approximately 10% during 1995 when
compared to the previous year.  Administrative expenses per equivalent barrel
of oil produced during 1995, 1994 and 1993 were $2.11, $2.66 and $3.65,
respectively.  This decrease from 1993 to 1995 is reflective of the Company's
continuing efforts to focus on and reduce controllable costs whenever possible.
These administrative cost reductions per equivalent barrel of oil produced have
occurred during periods of increased exploration and development activities and
increased oil and gas production.

  Pipeline Operations

      Pipeline operations accounted for $19.5 million (25%), $18 million (29%)
and $38.6 million (51%) of the Company's consolidated revenues in 1995, 1994
and 1993, respectively.  Pipeline operating expenses exclusive of depreciation
were $18.2 million, $16.9 million and $37.5 million for 1995, 1994 and 1993,
respectively. The pipeline segment generated losses from operations before
taxes of $3 million in 1995,  $0.3 million in 1994 and $0.6 million in 1993.
The loss from operations before taxes during 1995 included a $2.8 million
non-cash impairment of long-lived assets associated with the Company's nitrogen
rejection unit at its McLeod plant.  This impairment was the result of the
Company's adoption of Statement No. 121 during the fourth quarter of 1995.
While the losses from operations before taxes excluding the impairment of
long-lived assets remained flat in 1995 as compared to 1994 and improved during
1994 as compared to 1993, the pipeline segment continues to experience
constricted operating margins.

     The primary reason for the increase in pipeline segment revenues and
expenditures in 1995 as compared to 1994 was due to an increase in marketing
activities for the Company's Rosewood, Greggton and Todville systems.  An
increase in volumes and prices on these systems were contributing factors in
the increased revenues and expenditures.

     The primary reason for the decrease in pipeline segment revenues and
expenditures in 1994 as compared to 1993 was a decrease in marketing activities
for working interest partners at the Taylor Lake field.  During 1994, revenue
and expenses, excluding depreciation, attributable to the marketing of gas
production from certain of the Company's operated properties were $3.3 million
and $3.2 million, respectively.  During 1993, these revenues and expenses were
$22.4 million and $22.2 million, respectively.

  Russian Operations

     The Company, through its 90% owned subsidiary, Texneft, has a net 45%
interest in Tatex, a Russian joint venture.  Tatex's activities currently
include three projects: 1) vapor recovery, 2) the development and operation of
the Onbysk field and 3) the development and operation of the Suncheleevsky and
Demkinsky fields.  The vapor recovery activity during 1995 consisted of 20
units at 18 tank farms.  During 1995, Tatex drilled 18 wells in the Onbysk
field with a total of 154 wells producing at year end.  The Suncheleevsky and
Demkinsky fields development project was accepted by Tatex during the fourth
quarter of 1995.  Initial seismic is scheduled for early 1996 with development
drilling likely to commence during the fourth quarter of 1996.

     As of December 31, 1995 and 1994, the Company's advances to Texneft were
$18.2 million.  During 1995, the Company recorded net income from Russian
operations of $4 million.  The Company  recognized net losses from its Russian
operations for 1994 and 1993 of $0.1 million and $1.2 million, respectively.
Included in the 1994 and 1993 losses were $4.1 million and $1.7 million,
respectively, of expense for the Russian government export tax on crude oil.
On March 3, 1995, the Company was notified that its Russian joint venture had
received an exemption from paying export tax on crude oil sold outside of
Russia.  The exemption, which is subject to annual review by the Russian
government, was for one year beginning January 1, 1995.  With government
approval, the exemption can be renewed for two additional years.  The Company
believes it has complied with the investment criteria which form the basis of
the exemption for 1996.  However, at the time of writing, Tatex had not
received notification of exemption from the export tax in 1996.

     Tatex oil production through the end of 1995 has been sold outside of the
former USSR for hard currency via the Transneft operated Druzhba pipeline.
Access to the Transneft pipeline system has been subject to minimal
interruption since startup.  Recent statements and actions by government
ministries in connection with the liberalization of Russian





                                       34
<PAGE>   37
crude export controls indicate that in the future, joint ventures may have to
compete with Russian production associations for limited pipeline capacity to
export markets.

     Under Decree 209 issued on February 28, 1995 which confirmed priority
export pipeline access to joint ventures exempted from export tax, Mintopenergo
(the Ministry of Petroleum and Energy) sets the export quotas for the total oil
available quarterly for joint ventures (typically 30 percent of production) not
granted the export tax exemption.  Crude oil not exported from the Russian
Federation is sold on the domestic market or exported to the "near-abroad",
countries which formerly comprised the USSR, for prices at approximately 70
percent of world market levels.  Until the export tax exemption is officially
granted or denied Tatex, it is impossible to forecast with accuracy the volume
to be exported for world prices.

     The International Monetary Fund has made the complete removal of the
export tax from all exporters by July 1, 1996 a precondition for granting
certain loans to the Russian government.  Some officials have indicated that in
this event, the excise tax and or pipeline transportation tariff may be raised
to compensate for lost tax revenues at that time.  The excise tax was
reintroduced in April 1995 and the joint venture is currently paying 50,000
rubles per ton or approximately $1.42 per barrel.

  Ivory Coast Operations

     During April 1995, oil production commenced from the Lion field via an
offshore loading facility.  Natural gas and condensate production from the
Panthere field began in October 1995 and is being sold through a gas pipeline
from the offshore production facilities to the capital city of Abidjan.  As of
December 31, 1995, the Company has expended $29.6 million for its share of oil
and gas exploration, development and production activities in the Ivory Coast.
At year end there were seven completed wells on the CI-11 block.  The Company
plans to expend $3.8 million on projects in the Ivory Coast during 1996.

  Egyptian Operations

     During November 1995, early oil production, via trucking, commenced from
the Qarun concession.  As of December 31, 1995 the Company has expended $12.5
million for its share of exploration, development and production activities on
this concession.  At year end, there were ten completed wells of which only two
were producing.  The Company is currently drilling additional development wells
and building production facilities and oil pipelines.  The Company plans to
expend $27.5 million on these activities which are projected to be completed by
year end 1996.

LIQUIDITY AND CAPITAL RESOURCES

     Key balance sheet amounts and ratios stated in millions (except ratios and
per share amounts) at December 31, 1995, 1994 and 1993 were as follows:

<TABLE>
<CAPTION>
                                                                    1995                   1994                 1993
                                                                  ---------             ---------             ---------
<S>                                                               <C>                   <C>                   <C>
Cash and cash equivalents . . . . . . . . . . . . . . . . .       $   10.3              $    3.9              $   16.4
Short-term liquid investments . . . . . . . . . . . . . . .       $    5.0              $   33.3              $   49.9
Current assets  . . . . . . . . . . . . . . . . . . . . . .       $   34.1              $   53.1              $   84.3
Current liabilities . . . . . . . . . . . . . . . . . . . .       $   28.8              $   26.8              $   22.6
Current ratio . . . . . . . . . . . . . . . . . . . . . . .            118%                  198%                  373%
Non-current redeemable bearer shares  . . . . . . . . . . .       $   16.6              $   17.5              $   18.4
Non-current long-term debt  . . . . . . . . . . . . . . . .       $   11.8              $    1.3              $    --
Shareholders' equity  . . . . . . . . . . . . . . . . . .         $  102.2              $  107.8              $  120.4
Debt to equity ratio  . . . . . . . . . . . . . . . . . . .           27.7%                 17.4%                 15.3%
Equity per common share outstanding . . . . . . . . . . . .       $   3.46              $   3.67              $   4.01
Common shares outstanding at year end . . . . . . . . . . .           29.5                  29.4                  30.0
</TABLE>

     Cash and cash equivalents combined with short-term liquid investments
decreased $21.9 million during the year ended December 31, 1995.  This decrease
was primarily due to capital expenditures of $58.8 million.  These cash
expenditures were partially offset by $12.2 million proceeds from long-term
debt and $54.8 million of cash provided by operating activities excluding the
$28.5 million change in short-term liquid investments.





                                       35
<PAGE>   38
     Cash and cash equivalents combined with short-term liquid investments
decreased by $29.1 million during the year ended December 31, 1994.  This
decrease was primarily due to capital expenditures of $52.3 million and a $5.3
million treasury stock acquisition.  These cash outlays were partially offset
by the $38.2 million of cash provided by operating activities excluding the
$16.2 million change in short-term liquid investments.

     Cash provided by operating activities for the year ended December 31, 1995
was $54.8 million as compared to $38.2 million for the same period in 1994.
This $16.6 million increase in cash provided by operations was primarily due to
the increase in cash flows from operating activities before changes in
operating assets and liabilities.

     Cash provided by operating activities for the year ended December 31, 1994
was $38.2 million compared to $19.5 million for the same period in 1993.  This
$18.7 million increase in cash provided by operations was primarily the result
of a decrease in short-term liquid investments of $16.2 million.

     On May 19, 1995 the Company executed a $35 million unsecured line of
credit (see Note 6).  The proceeds from this line of credit will be used for
general corporate needs.  As of December 31, 1995 the Company, under this
agreement, had no loans outstanding and had approximately $18 million of
letters of credit issued.  In addition, the Company executed on July 14, 1995 a
$17.5 million secured line of credit specifically for the financing of
development activities for the Ivory Coast CI-11 project.  During 1995, the
Company utilized $12.2 million of this line of credit.  In February 1996, the
Company borrowed the remaining $5.3 million.

     In 1996, the Company intends to direct cash flow from its current base of
domestic properties to expand its exploration and development efforts in the
United States, mainly offshore Gulf of Mexico.  The Company intends to direct
its balance sheet cash (cash and short-term investments), its available credit
facilities and its cash flows from international properties toward
international opportunities.  The Company plans to spend in 1996 approximately
$14.3 million on exploration and development activities in the United States.
Capital expenditures for international activities, primarily in Russia, Egypt
and the Ivory Coast, are projected to be approximately $37.1 million for 1996.
Factors such as political stability in the various host countries and world oil
prices will heavily influence the amount and timing of these expenditures.  The
Company believes that it has adequate resources to fund these planned
expenditures.

     Effective December 31, 1995 the Company adopted Statement No. 121
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of."  This statement requires, among other things, that
long-lived assets and certain identifiable intangibles to be held and used by
an entity be reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable.  The adoption of this statement resulted in a non-cash impairment
expense of approximately $4.5 million during the fourth quarter of 1995.

     The Financial Accounting Standards Board issued Statement No. 123
"Accounting for Stock-Based Compensation," on October 23, 1995.  This standard
addresses the timing and measurement of stock-based compensation expense.  The
Company has elected to retain the approach of Accounting Principles Board
Opinion (APB) No. 25 "Accounting for Stock Issued to Employees," (the intrinsic
value method) for recognizing stock-based expense in the consolidated financial
statements.  The Company will adopt Statement No. 123 in 1996 with respect to
the disclosure requirements set forth therein for companies retaining the
intrinsic value approach of APB No. 25.

     The Company believes inflation has not had a material effect on its
operations or on its financial condition, but there can be no assurance that
future increases in inflation rates, particularly in Russia, would not have an
adverse effect on the Company's financial statements.  In addition, the Company
is not aware of any impending material change in its cost of supplies,
materials, equipment or labor.  The Company's employees are currently not
members of any labor union or trade association.

     A continued trend to greater environmental and safety awareness and
increasing environmental regulation has resulted in higher operating costs for
the oil and gas industry and the Company.  The Company believes environmental
and safety costs will continue to increase in the future.  To date, compliance
with environmental laws and regulations has not had a material impact on the
Company's capital expenditures, earnings or competitive position.  The Company
has not received any notices from any regulatory agency regarding violations of
environmental laws.  The Company monitors environmental laws and believes it is
in compliance with applicable environmental regulations and certain air quality
standards set by the Texas Air Quality Control Board and other appropriate
regulatory agencies.  The Company is unable to predict the impact of future
laws and regulations on the Company's operations.





                                       36
<PAGE>   39
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


                          INDEPENDENT AUDITORS' REPORT


The Board of Directors and Shareholders of
Global Natural Resources Inc.:

     We have audited the accompanying consolidated balance sheets of Global
Natural Resources Inc. and subsidiaries as of  December 31, 1995 and 1994 and
the related consolidated statements of operations, shareholders' equity and
cash flows for each of the years in the three-year period ended December 31,
1995.  These consolidated financial statements are the responsibility of the
Company's management.  Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.

     We conducted our audits in accordance with generally accepted auditing
standards.  Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement.  An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements.  An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation.  We believe that our audits provide a reasonable basis
for our opinion.

     In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Global
Natural Resources Inc. and subsidiaries as of December 31, 1995 and 1994, and
the results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 1995, in conformity with generally
accepted accounting principles.

     As discussed in note 1 to the consolidated financial statements, in 1995
the Company adopted the provisions of Statement of Financial Accounting
Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long- Lived Assets to be Disposed Of."  As discussed in note 1 to the
consolidated financial statements, in 1994 the Company changed its method of
accounting for certain investments to adopt the provisions of Statement of
Financial Accounting Standards No. 115, "Accounting for Certain Debt and Equity
Securities."



                                           KPMG PEAT MARWICK LLP


Houston, Texas
February 27, 1996





                                       37
<PAGE>   40
                 GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
                          CONSOLIDATED BALANCE SHEETS
                           DECEMBER 31, 1995 AND 1994
           (AMOUNTS IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)


                                     ASSETS

<TABLE>
<CAPTION>
                                                                                        1995           1994
                                                                                    -----------    -----------
<S>                                                                                 <C>            <C>
Current assets:
    Cash and cash equivalents   . . . . . . . . . . . . . . . . . . . . . . . .     $   10,272     $    3,881
    Short-term liquid investments   . . . . . . . . . . . . . . . . . . . . . .          5,004         33,279
    Accounts receivable   . . . . . . . . . . . . . . . . . . . . . . . . . . .         11,811         10,665
    Current investments   . . . . . . . . . . . . . . . . . . . . . . . . . . .            481            832
    Other   . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          6,482          4,436
                                                                                    -----------    -----------
         Total current assets . . . . . . . . . . . . . . . . . . . . . . . . .         34,050         53,093
                                                                                    -----------    -----------
Properties and equipment, at cost:
    Oil and gas properties (successful efforts method)  . . . . . . . . . . . .        169,590        119,602
    Pipeline facilities   . . . . . . . . . . . . . . . . . . . . . . . . . . .         19,519         19,320
    Other   . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         13,052         12,961
                                                                                    -----------    -----------
                                                                                       202,161        151,883
    Less:  accumulated depletion, depreciation and amortization   . . . . . . .        (83,398)       (58,534)
                                                                                    -----------    -----------
         Net properties and equipment . . . . . . . . . . . . . . . . . . . . .        118,763         93,349
                                                                                    -----------    -----------
Notes receivable-Russian joint venture  . . . . . . . . . . . . . . . . . . . .          3,867          3,606
Indonesian venture advances, net  . . . . . . . . . . . . . . . . . . . . . . .          2,425          2,453
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .          1,224          1,999
                                                                                    -----------    -----------
                                                                                    $  160,329     $  154,500
                                                                                    ===========    ===========
                                LIABILITIES AND SHAREHOLDERS' EQUITY


Current liabilities:
    Accounts payable  . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     $   11,207     $   13,256
    Accrued liabilities   . . . . . . . . . . . . . . . . . . . . . . . . . . .         16,341         12,229
    Current maturities of long-term debt  . . . . . . . . . . . . . . . . . . .            436            --
    Other   . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .            803          1,309
                                                                                    -----------    -----------
          Total current liabilities . . . . . . . . . . . . . . . . . . . . . .         28,787         26,794
                                                                                    -----------    -----------
Long-term debt  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         11,764          1,275
Deferred credits and other  . . . . . . . . . . . . . . . . . . . . . . . . . .            961          1,208
Commitments and contingencies . . . . . . . . . . . . . . . . . . . . . . . . .            --             --
Redeemable bearer shares  . . . . . . . . . . . . . . . . . . . . . . . . . . .         16,591         17,467
Shareholders' equity:
    Common stock; authorized 100,000,000 shares at $1.00 par value;
      issued and outstanding 33,433,987 in 1995 and 33,335,487 in 1994  . . . .         33,434         33,335
    Capital in excess of par value  . . . . . . . . . . . . . . . . . . . . . .        138,967        138,355
    Accumulated deficit   . . . . . . . . . . . . . . . . . . . . . . . . . . .        (50,474)       (44,167)
                                                                                    -----------    -----------
                                                                                       121,927        127,523
    Less:  treasury stock; 3,887,513 shares in 1995 and 3,900,697 in 1994   . .        (19,701)       (19,767)
                                                                                    -----------    -----------
          Total shareholders' equity  . . . . . . . . . . . . . . . . . . . . .        102,226        107,756
                                                                                    -----------    -----------
                                                                                    $  160,329     $  154,500
                                                                                    ===========    ===========
</TABLE>


          See accompanying notes to consolidated financial statements.

                                       38
<PAGE>   41
                 GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF OPERATIONS
                  FOR THE THREE YEARS ENDED DECEMBER 31, 1995
           (AMOUNTS IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)


<TABLE>
<CAPTION>
                                                                          1995               1994              1993
                                                                       ------------      ------------      ------------
<S>                                                                    <C>               <C>               <C>
Revenues:                                                              
   Oil and gas  . . . . . . . . . . . . . . . . . . . . . . . .       $     58,134      $     43,814      $     35,693
   Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . .             19,534            18,009            38,610
   Other  . . . . . . . . . . . . . . . . . . . . . . . . . . .                789             1,120               781
                                                                      -------------     -------------     -------------
                                                                            78,457            62,943            75,084
                                                                      -------------     -------------     -------------
Expenses:
   Production . . . . . . . . . . . . . . . . . . . . . . . . .             12,999            11,203             8,135
   Exploration  . . . . . . . . . . . . . . . . . . . . . . . .             11,768            19,325             6,946
   Pipeline cost of sales . . . . . . . . . . . . . . . . . . .             18,202            16,852            37,495
   Depletion, depreciation and amortization . . . . . . . . . .             21,520             9,837             8,376
   Impairment of long-lived assets  . . . . . . . . . . . . . .              4,466             --                --
   Administrative . . . . . . . . . . . . . . . . . . . . . . .              9,763             8,905             9,021
                                                                      -------------     -------------     -------------
                                                                            78,718            66,122            69,973
                                                                      -------------     -------------     -------------

       Income (loss) from operations  . . . . . . . . . . . . .               (261)           (3,179)            5,111

Other income (expense):
   Interest income  . . . . . . . . . . . . . . . . . . . . . .              1,842             2,308             2,046
   Interest expense . . . . . . . . . . . . . . . . . . . . . .               (164)             (124)             (101)
   Distribution from IPI  . . . . . . . . . . . . . . . . . . .              1,520             --                1,267
   Other, net . . . . . . . . . . . . . . . . . . . . . . . . .               (213)             (602)            2,696
                                                                      -------------     -------------     -------------
                                                                             2,985             1,582             5,908
                                                                      -------------     -------------     -------------

       Income (loss) before income tax expense  . . . . . . . .              2,724            (1,597)           11,019

Income tax expense  . . . . . . . . . . . . . . . . . . . . . .              9,031             6,656             6,532
                                                                      -------------     -------------     -------------

   Net income (loss)  . . . . . . . . . . . . . . . . . . . . .       $     (6,307)     $     (8,253)     $      4,487
                                                                      =============     =============     =============

Income (loss) per share based on weighted average shares
  outstanding:
   Net income (loss) primary  . . . . . . . . . . . . . . . . .       $      (0.21)     $      (0.28)     $       0.16
                                                                      =============     =============     =============
   Net income (loss) assuming full dilution . . . . . . . . . .       $      (0.21)     $      (0.28)     $       0.15
                                                                      =============     =============     =============

Weighted average common shares outstanding:
   Primary  . . . . . . . . . . . . . . . . . . . . . . . . . .         29,497,272        29,660,578        28,360,697
                                                                      =============     =============     =============
   Assuming full dilution . . . . . . . . . . . . . . . . . . .         29,497,272        29,660,578        29,903,391
                                                                      =============     =============     =============
</TABLE>


          See accompanying notes to consolidated financial statements.


                                       39
<PAGE>   42
                 GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
                CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
                  FOR THE THREE YEARS ENDED DECEMBER 31, 1995
                             (AMOUNTS IN THOUSANDS)


<TABLE>
<CAPTION>
                                                                1995               1994                1993
                                                             ----------         ----------          ----------
<S>                                                          <C>                <C>                 <C>
COMMON STOCK
   Balance at beginning of year . . . . . . . . . .          $  33,335          $  33,190           $  26,701
   Adjustment of common stock subject to put  . . .                --                 --                   28
   Conversion of preferred stock into common stock                 --                 --                6,311
   Issuance of common stock . . . . . . . . . . . .                 99                145                 150
                                                             ----------         ----------          ----------
   Balance at end of year . . . . . . . . . . . . .             33,434             33,335              33,190
                                                             ----------         ----------          ----------

CAPITAL IN EXCESS OF PAR VALUE
   Balance at beginning of year . . . . . . . . . .            138,355            137,648              88,423
   Adjustment of common stock subject to put  . . .                --                 --                  172
   Issuance of treasury stock for bearer shares . .                --                 --                 (198)
   Issuance of treasury stock to 401(k) plan  . . .                 52                 35                  13
   Conversion of preferred stock into common stock                 --                 --               48,387
   Issuance of common stock . . . . . . . . . . . .                560                672                 851
                                                             ----------         ----------          ----------
   Balance at end of year . . . . . . . . . . . . .            138,967            138,355             137,648
                                                             ----------         ----------          ----------

CONVERTIBLE PREFERRED STOCK
   Balance at beginning of year . . . . . . . . . .                --                 --               54,698
   Conversion of preferred stock into common stock                 --                 --              (54,698)
                                                             ----------         ----------          ----------
   Balance at end of year . . . . . . . . . . . . .                --                 --                  --
                                                             ----------         ----------          ----------

ACCUMULATED DEFICIT
   Balance at beginning of year . . . . . . . . . .            (44,167)           (35,914)            (40,401)
   Net income (loss)  . . . . . . . . . . . . . . .             (6,307)            (8,253)              4,487
                                                             ----------         ----------          ----------
   Balance at end of year . . . . . . . . . . . . .            (50,474)           (44,167)            (35,914)
                                                             ----------         ----------          ----------

TREASURY STOCK, AT COST
   Balance at beginning of year . . . . . . . . . .            (19,767)           (14,548)            (14,768)
   Acquisition of treasury stock  . . . . . . . . .                --              (5,289)                --
   Issuance of treasury stock for bearer shares . .                --                 --                  198
   Issuance of treasury stock to 401(k) plan  . . .                 66                 70                  22
                                                             ----------         ----------          ----------
   Balance at end of year . . . . . . . . . . . . .            (19,701)           (19,767)            (14,548)
                                                             ----------         ----------          ----------

TOTAL SHAREHOLDERS' EQUITY                                   $ 102,226          $ 107,756           $ 120,376
                                                             ==========         ==========          ==========
</TABLE>


          See accompanying notes to consolidated financial statements.

                                       40
<PAGE>   43
                 GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                  FOR THE THREE YEARS ENDED DECEMBER 31, 1995
                             (AMOUNTS IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                               1995            1994               1993
                                                                           -----------      -----------        ----------
<S>                                                                        <C>              <C>                <C>
Cash Flows from Operating Activities:                                      
   Net income (loss)  . . . . . . . . . . . . . . . . . . . . . . . . . .  $   (6,307)      $   (8,253)        $   4,487
   Adjustments to reconcile net income (loss) to net cash provided by
     operating activities:
      Depreciation, depletion and amortization  . . . . . . . . . . . . .      21,520            9,837             8,376
      Impairments of long-lived assets  . . . . . . . . . . . . . . . . .       4,466              --                --
      Leasehold impairments and dry hole expense  . . . . . . . . . . . .       7,106           13,635             4,272
      Unrealized (gain) loss on short-term liquid and current
        investments.  . . . . . . . . . . . . . . . . . . . . . . . . . .        (167)             458               --
      (Gain) loss on asset sales  . . . . . . . . . . . . . . . . . . . .         203                8            (2,974)
      Other   . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .         617              (37)             (226)
                                                                           -----------      -----------        ----------
   Changes in:                                                                 27,438           15,648            13,935
                                                                                                                        
      Accounts receivable   . . . . . . . . . . . . . . . . . . . . . . .      (1,146)           4,204            (2,095)
      Other current assets  . . . . . . . . . . . . . . . . . . . . . . .      (1,792)          (2,171)            1,775
      Accounts payable  . . . . . . . . . . . . . . . . . . . . . . . . .      (2,152)          (2,267)            3,670
      Accrued liabilities   . . . . . . . . . . . . . . . . . . . . . . .       4,112            5,957             2,303
      Short-term liquid investments   . . . . . . . . . . . . . . . . . .      28,538           16,210               --
      Deferred credits  . . . . . . . . . . . . . . . . . . . . . . . . .        (247)             608               (57)
                                                                           -----------      -----------        ----------
   Net cash provided by operating activities  . . . . . . . . . . . . . .      54,751           38,189            19,531
                                                                           -----------      -----------        ----------

Cash Flows from Investing Activities:
   Additions to oil and gas properties  . . . . . . . . . . . . . . . . .     (57,633)         (50,381)          (23,121)
   Additions to pipeline facilities and other properties and equipment         (1,121)          (1,920)           (2,731)
   Purchases of short-term liquid investments . . . . . . . . . . . . . .         --               --           (829,948)
   Maturities of short-term liquid investments  . . . . . . . . . . . . .         --               --             11,849
   Proceeds from sales of short-term liquid investments . . . . . . . . .         --               --            789,936
   Proceeds from sales of assets  . . . . . . . . . . . . . . . . . . . .         446            6,843            10,251
   Other  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        (307)          (1,775)              331
                                                                           -----------      -----------        ----------
   Net cash used in investing activities  . . . . . . . . . . . . . . . .     (58,615)         (47,233)          (43,433)
                                                                           -----------      -----------        ----------

Cash Flows from Financing Activities:
   Proceeds from common stock issuance  . . . . . . . . . . . . . . . . .         711              852               685
   Proceeds from redeemable bearer shares . . . . . . . . . . . . . . . .         --               --             19,149
   Proceeds from long-term debt . . . . . . . . . . . . . . . . . . . . .      12,200            1,275               --
   Payments on long-term debt . . . . . . . . . . . . . . . . . . . . . .      (1,275)             --                --
   Redemptions of bearer shares . . . . . . . . . . . . . . . . . . . . .        (876)            (908)             (129)
   Acquisitions of treasury stock . . . . . . . . . . . . . . . . . . . .         --            (5,289)              --
   Other  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        (505)             639               (13)
                                                                           -----------      -----------        ----------
   Net cash provided by (used in) financing activities  . . . . . . . . .      10,255           (3,431)           19,692
                                                                           -----------      -----------        ----------
   Net increase (decrease) in cash and cash equivalents . . . . . . . . .       6,391          (12,475)           (4,210)
   Cash and cash equivalents at beginning of period . . . . . . . . . . .       3,881           16,356            20,566
                                                                           -----------      -----------        ----------
   Cash and cash equivalents at end of period . . . . . . . . . . . . . .  $   10,272       $    3,881         $  16,356
                                                                           ===========      ===========        ==========
Supplemental disclosure of cash flow information:
Cash paid for:
   Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  $      141       $       32         $     125
                                                                           ===========      ===========        ==========
   Income taxes:
   Domestic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  $     --         $     --           $     150
   Foreign  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .       8,681            6,577             6,320
                                                                           -----------      -----------        ----------
      Total   . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  $    8,681       $    6,577         $   6,470
                                                                           ===========      ===========        ==========
</TABLE>


          See accompanying notes to consolidated financial statements.

                                       41
<PAGE>   44
                 GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
               CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
                  FOR THE THREE YEARS ENDED DECEMBER 31, 1995


Supplemental disclosure of non-cash investing and financing activities:

     In connection with the Company's Employees 401(k) Savings Plan referred to
in Note 8, the Company contributed to the plan during 1995, 1994 and 1993
treasury shares totaling 13,184, 14,194 and 4,638, respectively.  The market
values of the contributed shares during 1995, 1994 and 1993 were approximately
$118,000, $104,000 and $35,000, respectively.

     As referred to in Note 5, in March 1993, Prudential converted its
preferred stock into 6,311,537 shares of the Company's common stock.

     On November 29, 1993, Noel Group, Inc. ("Noel") distributed shares owned
by Noel in Sylvan Foods Holdings, Inc.  ("Sylvan") to Noel shareholders.  The
Company received from Noel 54,860 shares of Sylvan as a result of the Noel
distribution.  The Company recorded the investment in Sylvan at its November
29, 1993 market value and reduced the book value of the investment in Noel by a
corresponding amount.

     As a result of the Hambros agreements referred to in Note 3, $0.2 million
was transferred into capital in excess of par value and approximately $28,000
into common stock as a result of the reduction in common stock subject to put
during 1993.


          See accompanying notes to consolidated financial statements.

                                       42
<PAGE>   45
                 GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  General

     The accompanying consolidated financial statements of Global Natural
Resources Inc. (the "Company"), a New Jersey corporation, have been prepared
according to generally accepted accounting principles and pursuant to the rules
and regulations of the Securities and Exchange Commission ("SEC").  These
accounting principles require the use of estimates and assumptions regarding
certain assets, liabilities, revenues, and expenses.  Actual results may differ
from estimated amounts.

  Principles of Consolidation

     The consolidated financial statements include the accounts of Global
Natural Resources Inc. and its majority-owned entities.  The Company's accounts
include its pro rata share of the balances and operations of its Russian joint
venture, Tatex, in which a 90% owned subsidiary of the Company owns an
undivided 50% interest.  All significant intercompany accounts and transactions
have been eliminated.  Certain reclassifications have been made in the 1994 and
1993 financial statements to conform to the presentation used in 1995.

  Cash Equivalents

     The Company considers all investments with a maturity of ninety days or
less when purchased to be cash equivalents.

  Short-Term Liquid Investments

     Short-term liquid investments include investments having a maturity at the
date of purchase of more than ninety days.  These investments, which have a
minimum rating of A1/P1, consist primarily of repurchase agreements, commercial
paper, certificates of deposit and U.S. government securities and are carried
at cost, which approximates market value.  The Company believes that no single
short-term liquid investment exposes the Company to significant credit risk.
As of December 31, 1995, short-term liquid investments consisted entirely of
U.S. government securities.  As of December 31, 1994, excluding U.S. government
securities, the largest individual short-term liquid investment did not exceed
$6 million.

  Current Investments

     Effective January 1, 1994, the Company adopted Statement of Financial
Accounting Standards No. 115 ("Statement No. 115"), "Accounting for Certain
Investments in Debt and Equity Securities."  The cumulative effect of this
accounting change as of January 1, 1994 had no material impact upon the
financial statements of the Company.  Under Statement No.  115, the Company
classifies its debt and marketable equity securities in one of three
categories:  trading, available-for-sale, or held-to-maturity.  Trading
securities are bought and held principally for the purpose of selling them in
the near term.  Held-to-maturity securities are those securities for which the
Company has the ability and intent to hold until maturity.  Any securities not
classified as trading or held-to-maturity are classified as available-for-sale.

     The Company has no held-to-maturity or available-for-sale securities.
Trading securities are recorded at fair value.  Unrealized holding gains and
losses on trading securities are included in earnings.  Dividend and interest
income are recognized when earned.

     Current investments are trading securities carried at fair value.  Prior
to the adoption of Statement No. 115, current investments were carried at the
lower of aggregate cost or market value.





                                       43
<PAGE>   46
 Oil and Gas Properties

     The Company follows the successful efforts method of accounting for its
oil and gas operations whereby acquisition costs and exploratory drilling costs
related to properties with proved reserves and all development costs, including
development dry holes, are capitalized. Geological and geophysical costs and
the cost of retaining unproven properties are charged to expense as incurred.
Exploratory drilling costs applicable to unsuccessful exploration efforts are
charged to expense at the time the wells or other exploration activities are
determined to be nonproductive. Costs incurred to operate and maintain wells
and equipment and to lift oil and gas to the surface are expended as incurred.
Acquisition costs of unproved properties are evaluated periodically and any
impairment assessed is charged to expense.  Capitalized costs are depleted
using the unit of production method based upon estimates of proved reserves for
acquisition costs and estimates of proved developed reserves for exploration
and development costs.  Estimated costs (net of salvage value) of dismantling
oil and gas production facilities, including abandonment and site restoration
costs, are computed by the Company's engineers and are included when
calculating depreciation and depletion using the unit-of-production method.

     Effective December 31, 1995, the Company adopted Statement of Financial
Accounting Standards No. 121 ("Statement No. 121"), "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of."
Statement No. 121 requires that long-lived assets be reviewed for impairment
whenever circumstances indicate that the carrying amount of an asset may not be
recoverable.  If the sum of the estimated future cash flows expected from the
use of an asset is less than the carrying amount of an asset, an impairment
loss is recognized.  The impairment loss is measured by the estimated fair
value of the asset as compared to the carrying value of the asset.  Under
Statement No. 121, the Company performs its impairment review of proved oil and
gas properties on a depletable unit basis.  For each oil and gas property
determined to be impaired, the Company estimates fair value to be the present
value of expected future cash flows determined in part by applying estimated
future oil and gas prices, as determined by management, to estimated future
production of oil and gas reserves over the economic lives of the reserves.
During 1995, the Company recorded, in accordance with Statement No. 121, a
non-cash charge against earnings of $1.7 million ($0.06 per share) for the
impairment of proved oil and gas properties.

     Prior to December 31, 1995, the Company determined the impairment of
proved oil and gas properties on a world-wide basis.  If net capitalized costs
exceeded estimated future undiscounted after tax net cash flows from proved oil
and gas reserves, such excess costs would be charged to expense.

  Other Property and Equipment

     Pipelines, plant and equipment are depreciated on the straight-line method
over their estimated useful lives ranging from three to twenty-two years.
Miscellaneous property and equipment are depreciated on the straight-line and
declining-balance methods, based upon estimated useful lives ranging from three
to ten years.  Under Statement No. 121, assets are grouped and evaluated for
impairment based on the ability to identify separate cash flows generated
therefrom.  Upon adoption of Statement No. 121, the Company determined the
nitrogen rejection unit at its McLeod, Texas plant, part of the pipeline
operations segment, to be impaired, and wrote the asset down to its estimated
fair value (salvage value), as determined by management.  As a result, the
Company recognized a non-cash charge against earnings of $2.8 million ($0.09
per share) for impairment of other property and equipment.

  Investment in Texneft Inc.

     The Company's 90% (80% at December 31, 1993) owned subsidiary, Texneft
Inc. ("Texneft"), participates in a joint venture in Russia with Tatneft, a
Russian open joint stock company which operates the oil fields of Tatarstan,
Russia.  Texneft has a 50% interest in the joint venture, Tatex.  An agreement
between the minority shareholder of Texneft and the Company requires the
Company to advance to Texneft sufficient cash to fund its administrative
expenses and its contributions to Tatex.  In turn, Texneft will make no
distributions to its shareholders until the Company has been repaid a sum equal
to the total of its advances to Texneft.  As of December 31, 1995, the
Company's outstanding advances were $18.2 million.

  Investment in Indonesian Production Sharing Contract

     The Company has a 1.714% interest in a joint venture (the "IJV") for the
exploration, development and production of oil and natural gas in East
Kalimantan, Indonesia, under a production sharing contract ("PSC") with
Perusahaan Pertambangan Minyak Dan Gas Bumi Negara, the state petroleum
enterprise of Indonesia ("Pertamina"). The Company


                                       44
<PAGE>   47
makes advances to the operator for exploration, development and operating
costs. In April 1990, Pertamina and the IJV signed an amendment and a 20-year
extension to the PSC with generally similar terms and conditions as the PSC
prior to such amendment and extension. The extended PSC will expire August 7,
2018. The share of revenues from the sale of gas after cost recovery through
August 7, 1998 will remain at 35% to the IJV after Indonesian income taxes and
65% to Pertamina.  The split after August 7, 1998 will be either 25% or 30% to
the IJV after Indonesian income taxes and 75% or 70% to Pertamina, depending
upon the sales contract involved.  Based on current and projected oil
production, the revenue split from oil sales after cost recovery through August
7, 2018 will remain at 15% to the IJV after Indonesian income taxes and 85% to
Pertamina.  These revenue splits are based on Indonesian income tax rates of
56% through August 7, 1998 and 48% thereafter. The cost of the Company's
original investment is depleted on a straight-line basis over the remaining
life of the original production sharing contract.

  Investment Properties International, Limited (IPI)

     The Company owns 47% of the equity interests in IPI, which was a real
estate investment company that is now in liquidation under the supervision of a
liquidator.  Definitive information relative to the net realizable assets of
IPI is not available. However, based upon limited information available from
the liquidator, the Company believes that the majority of the assets have been
liquidated.  In 1995 and 1993, the Company received distributions from IPI of
approximately $1.5 million and $1.3 million, respectively.  No distributions
were received from IPI during 1994.  At December 31, 1995 and 1994, the Company
had no recorded costs related to this investment.

  Foreign Currency Translation

     The Company uses the U.S. dollar as the functional currency for its
operations in Russia.  Monetary assets and liabilities denominated in rubles
are translated into U.S. dollars using the market rate, as set by the Central
Bank of the Russian Federation.  Non-monetary assets and liabilities
denominated in rubles are translated at historical rates.  Exchange gains or
losses arising from the translation of ruble denominated assets and liabilities
into U.S. dollars are included in net income.

     The ruble is not a convertible currency outside the territory of Russia.
In addition, the economy in Russia has experienced hyperinflation, which has
resulted in a significant devaluation of the ruble.  If hyperinflation
continues, additional devaluation of the ruble may occur.  As of December 31,
1995, the Company's consolidated financial statements include ruble denominated
net monetary liabilities of approximately 6.0 billion rubles, which have been
translated into approximately $1.3 million.

     The Company uses the U.S. dollar as the functional currency for all other
foreign operations, as predominantly all transactions in those operations are
denominated in U.S. dollars.

  Concentrations of Credit Risk

     The Company's trade receivables include amounts due from purchasers of oil
and gas production and amounts due from joint venture partners for their
respective portions of operating expenses and exploration and development
costs.  The Company believes that no single customer or joint venture partner
exposes the Company to significant credit risk.  The Company's customers and
joint venture partners may be similarly affected by changes in economic,
regulatory or other factors and thereby impact the Company's overall credit
risk.  There can be no assurance that the Company's joint venture partners will
be in a position to pay their joint venture obligations, in which case the
Company may be required to assume all or a portion of their financing
obligations.  Trade receivables are generally not collateralized; however, the
Company analyzes customers' and joint venture partners' historical credit
positions prior to extending credit.

  Environmental Liabilities

     A provision for environmentally related expenditures is recorded when it
is determined that the Company's liability for environmental assessments and/or
cleanup is probable and the cost can be reasonably estimated.  If it is
anticipated that future economic benefit will arise from environmental
expenditures, the amounts are capitalized; otherwise, they are expensed.





                                       45
<PAGE>   48
  Oil and Natural Gas Revenues

     The Company records its natural gas revenues on the entitlement method
whereby the Company recognizes natural gas revenues based upon its entitled
share of gas production.  As of December 31, 1995 and 1994, the Company's
natural gas imbalances were not material.  With the exception of its Russian
activities, the Company records its oil revenues on the entitlement method
also.  Because of the uncertainties relating to pipeline capacity and access,
the Company records its Russian oil revenues based upon its share of oil
shipped.  As of December 31, 1995 and 1994, the Company had approximately
57,000 and 59,000 barrels in inventory, respectively.  Oil inventory is valued
at the lower of cost, determined on a first-in, first-out basis, or market
value, and is included in other current assets on the consolidated balance
sheets.

  Income Taxes

     The Company follows the asset and liability method of accounting for
income taxes.  Deferred tax assets and liabilities are recognized for the
future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their
respective tax bases and operating loss and tax credit carry forwards.
Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled.  The effect on deferred
tax assets and liabilities of a change in tax rates is recognized in income in
the period that includes the enactment date.

  Common Stock Options and Awards

     The Company follows the intrinsic value method of accounting for common
stock options and awards issued to employees.  See Note 5.

  Earnings per Share

     Earnings per share is computed based upon the weighted average common
shares outstanding, determined on a monthly basis.  Unexercised stock options
do not have a dilutive effect on the reported amount of earnings per common
share.  Fully diluted earnings per share for 1993 was calculated assuming
conversion of Prudential's preferred stock into Company common stock effective
January 1, 1993.  See Note 5.

(2)  CURRENT INVESTMENTS

     Current investments at December 31, 1995 and 1994 consist of certificates
of deposit and U.S. government and corporate debt securities (included in
short-term liquid investments), and equity securities (included in current
investments).  During the twelve month period ended December 31, 1995 and 1994,
the Company recorded $0.2 million of unrealized gains and $0.5 million of
unrealized losses, respectively, resulting from changes in the differences
between cost and market value of short-term liquid investments and current
investments.   In 1993, the Company recorded a net unrealized loss of
approximately $0.6 million as the result of changes in the differences between
the cost and market value of items held as current investments at year end.

(3)  REDEEMABLE BEARER SHARES

     Global Natural Resources Inc. became the successor issuer to Global
Natural Resources PLC, a United Kingdom company ("U.K. Company"), on July 26,
1983 pursuant to the terms of a Scheme of Arrangement (the "Arrangement") under
Section 206 of the English Companies Act. The effect of the Arrangement was to
move the domicile of the parent company to the United States from the United
Kingdom.

     Under the terms of the Arrangement, 24,270,876 registered common shares of
the Company were registered in the name of Hambros Trust ("Trust Shares"). The
Trust Shares were held for the owners of share warrants to bearer issued by the
U.K. Company.  Holders of bearer shares were entitled to receive at their
election either cash or Company shares on a share-for-share basis until July
1993.  After July 1993, holders of bearer shares are entitled to receive only
cash.

     The Arrangement provided that Trust Shares not claimed by July 26, 1988
could be sold by the Trust and the proceeds from such sale together with earned
interest be used to satisfy future claims by the holders of share warrants to
bearer.  Prior to August 1993, the Company was obligated to maintain a
sufficient number of treasury shares or


                                       46
<PAGE>   49
unissued shares to be issued in case the Trust determined that it held an
insufficient number of Company shares to effect an exchange.  The Company was
also obligated to maintain a letter of credit in favor of the Trust equal to
the number of Company shares held by the Trust multiplied by the escalated
price. This obligation was accounted for as common stock subject to put.

     In August 1993, the Company received $19.2 million, the remaining cash
held by the Trust, in the form of an interest-free loan.  The loan is repayable
on demand only to the extent necessary to redeem bearer shares presented for
exchange until July 2008.  Each bearer share presented during this period will
be redeemed for $6.66.  As of December 31, 1995 and 1994, there were 2,575,947
and 2,685,487 outstanding bearer shares, respectively.  The loan is secured by
a letter of credit which is secured by the Credit Agreement (see Note 6).
During 1995, 1994 and 1993, there were no drawings under the letter of credit.
In July 2008, the obligation of the Company to holders of bearer shares will
cease, the interest-free loan will terminate, and any remaining cash will
revert to the Company and will be accounted for as an increase to capital in
excess of par value.

(4)  FAIR VALUE OF FINANCIAL INSTRUMENTS

     The following disclosure of the estimated fair value of financial
instruments is made in accordance with the requirements of SFAS No. 107
"Disclosures About Fair Value of Financial Instruments."  The estimated fair
value amounts have been determined by the Company using available market
information and valuation methodologies described below.  Considerable
judgement is required in interpreting market data to develop the estimates of
fair value.  The use of different market assumptions or valuation methodologies
may have a material effect on the estimated fair value amounts.

<TABLE>
<CAPTION>
                                                    DECEMBER 31, 1995           DECEMBER 31, 1994
                                                -----------------------     ------------------------
                                                  BOOK          FAIR          BOOK           FAIR
                                                  VALUE         VALUE         VALUE          VALUE
                                                ---------     ---------     ---------      ---------
<S>                                             <C>           <C>           <C>            <C>
Cash and cash equivalents . . . . . . .         $ 10,272      $ 10,272      $  3,881       $  3,881
Short-term liquid investments . . . . .            5,004         5,004        33,279         33,279
Current investments . . . . . . . . . .              481           481           832            832
Notes receivable-Russian joint venture             3,867         3,867         3,606          3,606
Long-term debt  . . . . . . . . . . . .           12,200        12,200         1,275          1,275
Redeemable bearer shares  . . . . . . .           17,362           n/a        18,238            n/a
</TABLE>


     The carrying values of cash and cash equivalents approximate fair value
due to the short-term maturities of these investments.  For short-term liquid
investments and current investments, carrying values are equal to fair values,
which are estimated based upon quoted market prices.  The fair value of notes
receivable-Russian joint venture is based on rates at which the joint venture
could obtain funds from other sources within Russia.  The carrying value of
long-term debt approximates its fair value as interest rates associated with
this debt are variable, and are based on prevailing market rates.  The fair
value of the redeemable bearer shares is not determinable because reductions in
the outstanding balance are on demand only to the extent necessary to redeem
bearer shares presented for exchange until July 2008 with any remaining balance
reverting to the Company.  The Company is not able to determine  when the
bearer shares will be presented and how many will not be redeemed.

(5)  SHAREHOLDERS' EQUITY

  Preferred Share Purchase Rights Plan

     In October 1988, the Board of Directors of the Company adopted a preferred
share rights plan (the "Rights Plan") pursuant to which holders of the
Company's common stock were issued rights ("Rights") to purchase shares of a
series of the Company's preferred stock.  Generally, the Rights are exercisable
only if a person or group acquires 20% or more of the Company's outstanding
voting stock.  The Rights Certificates are exercisable on the tenth business
day after the shares acquisition date, as defined, or such later date as
determined by the Board of Directors.  Each Right entitles the holder thereof
to buy one one-hundredth of a share of Series B Junior Preferred Stock
("Preferred Stock") at an exercise price of $20.00 per Right, subject to
anti-dilution provisions.  The Rights, under certain circumstances, are
redeemable at the option of the Company's Board of Directors at a price of $.01
per Right and expire on October 20, 1998.





                                       47
<PAGE>   50
     In addition to the right to purchase Preferred Stock, in the event that
the Company is acquired in a merger or other business combination transaction
or 50% or more of its consolidated assets or earning power are sold, each
holder of a Right will thereafter have the right to receive, upon the exercise
thereof at the then current exercise price of the Right, that number of shares
of common stock of the acquiring company which at the time of such transaction
will have a market value of two times the exercise price of the Right.  In the
event that the Company is the surviving corporation in a merger and the
Company's common stock is not changed or exchanged, each holder of a Right,
other than Rights that are beneficially owned by the Acquiring Person (which
will thereafter be void), will thereafter have the right to receive upon
exercise that number of shares of the Company's common stock having a market
value of two times the exercise price of the Right.

     In the event that a person or group acquires 20% or more of the
outstanding Voting Shares, then each Right (other than Rights owned by the
Acquiring Person and its affiliates and associates and all transferees thereof)
will entitle the holder to purchase, for the exercise price, a number of shares
of the Company's common stock having a then current market value of two times
the exercise price of the Right.  If this provision becomes effective and the
Acquiring Person owns less than 50% of the Company's Voting Shares then
outstanding, the Board of Directors would have the option to redeem the Rights
in exchange for Common Shares at the rate of one share for each two shares for
which the Rights are then exercisable.

  Stock Activity

     The following table reflects the activity in shares of the Company's
Common Stock, Convertible Preferred Stock and Treasury Stock during the three
years ended December 31, 1995.

<TABLE>
<CAPTION>
                                                             1995               1994                1993
                                                          -------------      -------------       -------------
<S>                                                       <C>                <C>                 <C>
COMMON STOCK OUTSTANDING
   Shares at beginning of year  . . . . . . . . . .         33,335,487         33,190,287          26,700,646
   Adjustment of common stock subject to put  . . .                --                 --               28,304
   Conversion of preferred stock into common stock                 --                 --            6,311,537
   Issuance of common stock . . . . . . . . . . . .             98,500            145,200             149,800
                                                          -------------      -------------       -------------
   Shares at end of year  . . . . . . . . . . . . .         33,433,987         33,335,487          33,190,287
                                                          =============      =============       =============
CONVERTIBLE PREFERRED STOCK OUTSTANDING
   Shares at beginning of year  . . . . . . . . . .                --                 --            6,153,847
   Conversion of preferred stock into common stock                 --                 --           (6,153,847)
                                                          -------------      -------------       -------------
   Shares at end of year  . . . . . . . . . . . . .                --                 --                  --
                                                          =============      =============       =============

TREASURY STOCK
   Shares at beginning of year  . . . . . . . . . .          3,900,697          3,186,329           3,234,473
   Acquisition of treasury stock  . . . . . . . . .                --             728,562                 --
   Issuance of treasury stock for bearer shares . .                --                 --              (43,506)
   Issuance of treasury stock to 401(k) plan  . . .            (13,184)           (14,194)             (4,638)
                                                          -------------      -------------       -------------
   Shares at end of year  . . . . . . . . . . . . .          3,887,513          3,900,697           3,186,329
                                                          =============      =============       =============
</TABLE>

     On May 31, 1994, the Company purchased in a private transaction 705,196
shares of its common stock from Noel Group Inc. ("Noel").  The purchase price
was $7.50 per share or approximately $5.3 million.  In connection with the
repurchase of the shares, two of the four representatives of Noel on the
Company's Board of Directors resigned.

  Preferred Stock

     In 1987, the Board of Directors authorized the issuance of 6,153,847
shares of $1.00 par value Series A Preferred Stock (the "Preferred Stock").
All such Preferred Stock was issued to Prudential Insurance Company of America
("Prudential") in 1991 in exchange for $50 million of convertible subordinated
notes ("Notes").  Accrued long-term interest of $5.5 million that would have
been paid at the end of the term of the Notes, net of unamortized deferred debt
costs, was credited to convertible preferred stock.  In March 1993, Prudential
converted the Preferred Stock into 6,311,537 shares of the Company's common
stock.  These shares are not registered and Prudential will be unable to sell
these shares in the public market without registration with the SEC or an
exemption from such registration.


                                       48
<PAGE>   51
     In 1988, the Board of Directors of the Company authorized the issuance of
750,000 shares of $1.00 par value Series B Junior Preferred Stock for the
purpose of issuance upon the exercise of Rights under the Rights Plan as
described above. Each share of such preferred stock issuable upon exercise of
the Rights will bear quarterly dividends of $2.50, a liquidation preference of
$2,000 and will be redeemable by the Company.

  Stock Option Plans

     The Key Employees Stock Option Plan was approved by the Company's
shareholders in June 1989.  This plan reserved 1,500,000 shares of the
Company's common stock for issuance to employees at a price not less than the
greater of par value or fifty percent of the fair market value of such shares.
Options granted vest as determined by the Board of Directors and expire ten
years after grant. All options granted as of December 31, 1995 were granted at
the fair market value of the Company's common stock on the date of grant. At
December 31, 1995, 24,450 shares of common stock were available for grant.

     Information related to the options granted under the Key Employees Stock
Option Plan is summarized as follows:

<TABLE>
<CAPTION>
                                                   1995                                   1994
                                    ----------------------------------       --------------------------------
                                     NUMBER OF         OPTION PRICE            NUMBER OF      OPTION PRICE
                                      SHARES          RANGE PER SHARE           SHARES       RANGE PER SHARE
                                    ----------       -----------------       ------------   -----------------
<S>                                 <C>              <C>                     <C>            <C>
Options outstanding:
   Beginning of period  . . . .       899,750        $5.1875 - $10.50          1,045,350    $5.1875 - $10.50
   Granted  . . . . . . . . . .        46,500        $7.75   - $8.50               5,000    $7.75   - $7.9375
   Exercised  . . . . . . . . .       (60,100)       $5.1875 - $8.3125          (145,200)   $5.1875 - $6.25
   Canceled . . . . . . . . . .        -                 -         -              (5,400)   $6.25   - $6.6875
                                    ----------       -----------------       ------------   -----------------
   End of period  . . . . . . .       886,150        $5.1875 - $10.50            899,750    $5.1875 - $10.50
                                    ==========       =================       ============   =================
   Options exercisable  . . . .       733,050        $5.1875 - $10.50            662,150    $5.1875 - $10.50
                                    ==========       =================       ============   =================
</TABLE>

     The 1992 Stock Option Plan ("1992 Plan") was approved by the Company's
shareholders in June 1992.  This plan reserved 1,000,000 shares of the
Company's common stock for issuance to employees, directors and other persons
who perform services for or on behalf of the Company.  Options granted under
the 1992 Plan may be either incentive stock options ("ISO"), within the meaning
of the Internal Revenue Code or options which do not constitute incentive stock
options ("NQSO").  The price at which the Company can issue the options shall
not be less than the fair market value of such shares at the date of the grant
for ISO options and shall not be less than 50% of the fair market value of such
shares at the date of the grant for NQSO options.  As of December 31, 1995, all
options granted were NQSO options and all except 50,000 options were granted at
the fair market value of the Company's common stock on the date of the grant.
On May 3, 1993, 50,000 options were granted to a member of the Board of
Directors at an option price of $5.875.  The fair market value of the Company's
common stock on that date was $8.50.  At December 31, 1995, 208,500 shares of
common stock were available for grant.

     Information related to the options granted under the 1992 Plan is 
summarized as follows:

<TABLE>
<CAPTION>
                                                   1995                                   1994
                                    ----------------------------------       --------------------------------
                                     NUMBER OF         OPTION PRICE            NUMBER OF      OPTION PRICE
                                      SHARES          RANGE PER SHARE           SHARES       RANGE PER SHARE
                                    ----------       -----------------       ------------   -----------------
<S>                                 <C>              <C>                     <C>            <C>
Options outstanding:
   Beginning of period  . . . .       660,000        $5.875   - $8.00            622,500    $5.875   - $7.75
   Granted  . . . . . . . . . .       131,500        $8.3125  - $9.75             37,500    $7.1875  - $8.00
   Exercised  . . . . . . . . .       (38,000)       $5.875   - $7.75                -          -        -
                                    ----------       -----------------       ------------   -----------------
   End of period  . . . . . . .       753,500        $5.875   - $9.75            660,000    $5.875   - $8.00
                                    ==========       =================       ============   =================
   Options exercisable  . . . .       580,300        $5.875   - $9.75            480,000    $5.875   - $8.00
                                    ==========       =================       ============   =================
</TABLE>


                                       49
<PAGE>   52
     The Financial Accounting Standards Board issued Statement No. 123
"Accounting for Stock-Based Compensation" on October 23, 1995.  This standard
addresses the timing and measurement of stock-based compensation expense.  The
Company has elected to retain the approach of Accounting Principles Board
Opinion (APB) No. 25, "Accounting for Stock Issued to Employees," (the
intrinsic value method) for recognizing stock-based expense in the consolidated
financial statements.  The Company will adopt Statement No. 123 in 1996 with
respect to the disclosure requirements set forth therein for companies
retaining the intrinsic value approach of APB No. 25.

Dividends

     No dividends have been paid or declared.

(6)  LONG-TERM DEBT

     The Company executed a Credit Agreement dated May 19, 1995 (the "Credit
Agreement") with a bank.  Pursuant to the Credit Agreement, the bank has agreed
to provide loans to the Company from time to time, not to exceed in the
aggregate $35 million (subject in all events to certain periodic reductions and
to the calculation of the Available Borrowing Base, as defined in the Credit
Agreement).  The Company may borrow, repay and re-borrow such amounts available
under the Credit Agreement until March 31, 2000 (subject to certain early
termination dates determined in accordance with the Credit Agreement).  In
addition, the bank has agreed to extend credit to the Company (or any
subsidiary of the Company) by issuing, renewing, extending or reissuing letters
of credit not exceeding the lesser of (i) $20 million or (ii) the Aggregate
Commitments (as defined in the Credit Agreement) minus the aggregate principle
amount of all loans then outstanding under the Credit Agreement.  The loan
facility is unsecured.  As of December 31, 1995, the Company, under this
agreement, had no loans outstanding and had approximately $18 million in
letters of credit issued.  These letters of credit are primarily associated
with the Redeemable Bearer Shares discussed in Note 3.  The Credit Agreement
contains covenants which, among other things, restrict the payment of cash
dividends to the lesser of $2.5 million or 25% of net income annually, limit
the amount of consolidated debt and provide that the Company must maintain a
specified relationship between current assets and current liabilities and must
maintain a specified net worth.

     The Company executed a Financing Agreement dated July 14, 1995 (the
"Financing Agreement") with the International Finance Corporation ("IFC"), a
subsidiary of the World Bank.  The Financing Agreement is secured by the
present and future assets of the borrower, GNR (Cote d' Ivoire) Ltd., a wholly
owned subsidiary of the Company.  Until the completion date of the project, as
defined, the loan is guaranteed by the Company.  After completion of the
project, the amount guaranteed by the Company, if any, is determined by the
amount of the proved oil and gas reserves related to the activities.  Pursuant
to the Financing Agreement, the IFC has agreed to provide a $17.5 million
secured line of credit specifically for the financing of development activities
for the Ivory Coast CI-11 project.  As of December 31, 1995, the Company, under
this agreement, had approximately $12.2 million of loans outstanding with a
weighted average annual interest rate of 8.4%.  On February 29, 1996, the
Company borrowed the remaining balance of this line of credit.  The Financing
Agreement contains covenants which, among other things, requires the Company to
maintain a cash reserve amount equal to the aggregate of the principal and
interest which will be due and payable within the next six months.

     The Company's Russian joint venture has a $5 million line of credit with a
bank.  At December 31, 1995 the joint venture had no loans outstanding under
this agreement.  At December 31, 1994, this loan had an outstanding balance of
$2,550,000 ($1,275,000 net to the Company's interest).  This loan bears annual
bank charges at the lower of interest at 8.75% per annum plus bank fees, or
interest at 10% per annum payable semi-annually on June 15 and December 15.
The line of credit is secured by the guarantee of Tatneft, the Company's
Russian joint venture partner.

     The Company capitalizes a portion of its interest costs as part of
property and equipment.  Interest capitalized in 1995 and 1994 was $382
thousand and $23 thousand, respectively.

     The aggregate amount of maturities of all long-term indebtedness at
December 31, 1995 for the next five years are: 1996 - $0.4 million; 1997 - $1.2
million; 1998 - $1.7 million; 1999 - $1.8 million; and 2000 - $1.8 million.





                                       50
<PAGE>   53
(7)  INCOME TAXES

     Income before income taxes and the components of income tax expense for
each of the three years ended December 31, 1995 stated in thousands, consisted
of the following:

<TABLE>
<CAPTION>
                                                                   1995                    1994                   1993
                                                                 ----------              ----------            ----------
<S>                                                              <C>                     <C>                   <C>
Income (loss) before income tax expense:
          Domestic  . . . . . . . . . . . . .                    $  (9,722)              $  (7,490)            $   4,857
          Foreign . . . . . . . . . . . . . .                       12,446                   5,893                 6,162
                                                                 ----------              ----------            ----------
                                                                 $   2,724               $  (1,597)            $  11,019
                                                                 ==========              ==========            ==========
Current income tax expense:
          Federal . . . . . . . . . . . . . .                    $     121               $      24             $     175
          Foreign . . . . . . . . . . . . . .                        8,910                   6,632                 6,357
                                                                 ----------              ----------            ----------
                                                                 $   9,031               $   6,656             $   6,532
                                                                 ==========              ==========            ==========
</TABLE>

     The tax effects of temporary differences that gave rise to the significant
portions of the deferred tax assets as of December 31, 1995, 1994, and 1993
stated in thousands were as follows:

<TABLE>
<CAPTION>
                                                                   1995           1994           1993
                                                                ----------     -----------    -----------
     <S>                                                        <C>            <C>            <C>
     Deferred tax assets:                                    
          Properties and equipment  . . . . . . . . . . . .     $   7,653      $    3,160     $    2,327
          Notes receivable  . . . . . . . . . . . . . . . .         5,333           5,248          6,978
          Other . . . . . . . . . . . . . . . . . . . . . .           230              84            273
          Net operating loss carryforwards  . . . . . . . .         7,129          10,267          8,955
          Percentage depletion carryforwards  . . . . . . .         2,942           3,736          3,485
          Foreign tax credit carryforwards  . . . . . . . .         --              1,545          2,067
          Minimum tax credit carryforwards  . . . . . . . .           848             934            811
          Investment tax credit carryforwards . . . . . . .           517           1,192          1,290
                                                                ----------     -----------    -----------
             Deferred tax assets  . . . . . . . . . . . . .        24,652          26,166         26,186
          Less - valuation allowance  . . . . . . . . . . .       (24,652)        (26,166)       (26,186)
                                                                ----------     -----------    -----------
             Net deferred tax . . . . . . . . . . . . . . .     $    --        $     --       $     --
                                                                ==========     ===========    ===========
</TABLE>

     The Company's operating loss carryforwards expire in various amounts from
1997-2006, and the investment tax credit carryforwards expire in various
amounts from 1996-2000.  The statutory depletion carryforward may be carried
forward indefinitely.  Utilization of these carryforwards may be limited
because these tax attributes were generated in separate return limitation
years.  In management's judgement, it is unlikely that the majority of the
deferred tax assets in the preceding table can be realized as reductions in
future taxable income or by utilizing available tax planning strategies.
Therefore, an appropriate valuation allowance has been established to recognize
this uncertainty.  The Company will periodically review the likelihood of
realizing these assets and adjust the valuation allowance as needed.

     The effective tax rate in the accompanying consolidated statements of
operations was more than the computed expected tax expense at the federal
statutory rate of 35% for the three years ended December 31, 1995.  Sources of
these differences for each of the three years stated in thousands are as 
follows:

<TABLE>
<CAPTION>
                                                                                 1995            1994             1993
                                                                               ---------       ---------        ---------
<S>                                                                            <C>             <C>              <C>
Computed statutory tax expense (benefit)  . . . . . . . . . . .                $    953        $   (559)        $  3,857
Increase (decrease) in taxes resulting from:
         Foreign tax expense, net of federal income tax benefits                  5,213           4,311            4,132
         Benefit from sale of Canadian subsidiary . . . . . . .                     --              --            (4,129)
         Income tax benefits not realized . . . . . . . . . . .                   2,695           2,880            2,497
         Realization of changes in valuation allowance  . . . .                    (484)            --               --
         Percentage depletion deductible for tax purposes . . .                    (134)            --               --
         Foreign income not taxed or taxed at different rates on
            which U.S. federal income taxes are not provided  .                     890             --               --
         Other  . . . . . . . . . . . . . . . . . . . . . . . .                    (102)             24              175
                                                                               ---------       ---------        ---------
                                                                               $  9,031        $  6,656         $  6,532
                                                                               =========       =========        =========
</TABLE>

                                                  51
<PAGE>   54
(8)  EMPLOYEES' PENSION AND RETIREMENT BENEFITS

  Pension Plan

     The Company sponsors a defined benefit pension plan which covers
substantially all U.S. employees. The plan provides benefits based on the
employees' years of service and compensation during the years immediately
preceding retirement. The Company makes annual contributions to the plan to
comply with the minimum funding provisions of the Employee Retirement Income
Security Act. The plan investments consist primarily of common equities and
fixed income securities.

     The following tables (stated in thousands) detail (i) the components of
pension income and expense, (ii) the funded status of the plan and amounts
recognized in the Company's consolidated balance sheets and (iii) major
assumptions used to determine these projected benefit obligations.  Certain
assumptions are based on factors, such as interest rates and long-term rates of
return on investments, which are subject to change due to forces beyond the
Company's control.  Changes in the various assumptions utilized could have a
significant effect on the amounts reported.

<TABLE>
<CAPTION>
                                                                             1995               1994               1993
                                                                          ----------         ----------        ----------
<S>                                                                       <C>                <C>               <C>
Components of pension income (expense):
         Service cost . . . . . . . . . . . . . . . . . . .               $    (546)         $    (492)        $    (524)
         Interest cost  . . . . . . . . . . . . . . . . . .                    (375)              (348)             (311)
         Actual return (loss) on plan assets  . . . . . . .                     917               (306)              430
         Net amortization and deferral  . . . . . . . . . .                    (696)               577             (168)
                                                                          ----------         ----------        ----------
                 Net pension cost . . . . . . . . . . . . .               $    (700)         $    (569)        $    (573)
                                                                          ==========         ==========        ==========

Actuarial present value of benefit obligations:
         Accumulated benefit obligations
            Vested  . . . . . . . . . . . . . . . . . . . .               $   4,448          $   3,952         $   3,877
            Nonvested . . . . . . . . . . . . . . . . . . .                     319                361               430
                                                                          ----------         ----------        ----------
                 Total  . . . . . . . . . . . . . . . . . .               $   4,767          $   4,313         $   4,307
                                                                          ==========         ==========        ==========

Projected benefit obligations for service rendered
         to date  . . . . . . . . . . . . . . . . . . . . .               $   6,351          $   5,229         $   5,129
Plan assets at fair value . . . . . . . . . . . . . . . . .                   4,587              3,733             3,952
                                                                          ----------         ----------        ----------
Projected benefit obligations in excess of plan
         assets . . . . . . . . . . . . . . . . . . . . . .                   1,764              1,496             1,177
Unrecognized net transition obligation at January 1,
         1986, recognized over 15 years . . . . . . . . . .                     (55)               (66)              (76)
Unrecognized prior service cost at January 1, 1989,
         recognized over 9 years  . . . . . . . . . . . . .                    (171)              (180)             (189)
Unrecognized net loss . . . . . . . . . . . . . . . . . . .                    (696)              (670)             (377)
                                                                          ----------         ----------        ----------
         Accrued pension liability  . . . . . . . . . . . .               $     842          $     580         $     535
                                                                          ==========         ==========        ==========
Assumptions:
         Discount rate  . . . . . . . . . . . . . . . . . .                     7.0%               7.5%              7.0%
         Rate of increase in compensation levels  . . . . .                     5.0%               5.0%              5.0%
         Expected long-term rate of return on plan assets .                     7.0%               7.0%              8.0%
</TABLE>


Employee Savings Plan

     On October 1, 1993, the Company adopted the Employees 401(k) Savings Plan
("ESP"), a defined contribution plan, which covers substantially all U.S.
employees.  The Company matches a portion of the employees' contributions with
treasury shares of the Company's common stock.  The Company recorded expense of
approximately $118,000, $104,000 and $35,000 relating to its contributions to
the ESP during 1995, 1994 and 1993, respectively.


                                       52
<PAGE>   55
(9)  COMMITMENTS AND CONTINGENCIES

  Commitments

     In the normal course of business, the Company undertakes commitments for
purchases of leases and delay rentals under oil, gas and mineral leases, all of
which are not expected to be material.

     The Company leases office space under operating leases that expire over
the next several years. Minimum annual rental payments stated in thousands for
each of the next five years are:

<TABLE>
<S>                                                    <C>
1996 . . . . . . . . . . . . . . . . . . . . . . . . . $   353
1997 . . . . . . . . . . . . . . . . . . . . . . . . .     456
1998 . . . . . . . . . . . . . . . . . . . . . . . . .     507
1999 . . . . . . . . . . . . . . . . . . . . . . . . .     461
2000 . . . . . . . . . . . . . . . . . . . . . . . . .      38
                                                       -------
                                                       $ 1,815
                                                       =======
</TABLE>

     During 1995, 1994 and 1993, the Company's rent expense was $380,000,
$372,000 and $434,000, respectively.

  Contingencies

     The Company has pending litigation incidental to its operations.
Management believes none of the litigation is expected to have a material
adverse effect on the Company's financial position or the results of
operations.

(10) MAJOR BUSINESS SEGMENTS AND MAJOR CUSTOMERS

     The Company operates in two industry segments, oil and gas exploration,
development and production and the gathering and transportation of natural gas
and crude oil.  Domestic oil and gas production is marketed to numerous
purchasers under long-term, short-term and spot-market contracts.  These
purchasers consist primarily of natural gas marketing companies, natural gas
and electric utilities and their affiliates, industrial companies and oil
refineries and marketers located in the South and Southwest regions of the
United States.   In 1995, 1994 and 1993, sales to El Paso Natural Gas Company
represented 2%, 9% and 13% of the Company's consolidated oil and gas revenues,
respectively.  Beginning January 1, 1994, the Company entered into a long-term
contract with Midcon Texas Pipeline ("Midcon") for gas sales from the Taylor
Lake field.  During 1995 and 1994, 11% and 13%, respectively, of the Company's
consolidated oil and gas revenues were attributable to sales to Midcon.
International oil and gas production is also marketed to various purchasers
under long-term, short-term and spot-market contracts.  Purchases of LNG from
the IJV include Japanese, Taiwanese and Korean utility and industrial
companies, while purchases of other foreign oil and gas production consist of
international oil marketers, electric utilities and oil refineries.  During
1995 and 1994, 100% and 95%, respectively, of the Company's Russian oil sales
were made to Rusoil GMBH through the international oil marketer, Nafta Moscow.
No other international purchaser represented more than 10% of the Company's
consolidated oil and gas revenues.

     The pipeline segment's customers consist of natural gas marketing
companies, natural gas and electric utilities and industrial companies which
are primarily located in the Southwest and Midwest states.  During 1995, the
pipeline segment's sales were concentrated with eleven customers accounting for
81% of its total sales.

     Prices received for domestic and international oil and natural gas
fluctuate based on numerous factors, including general market conditions and
weather in the region.  Fluctuations in prices received for these commodities
could significantly impact the Company's revenues and future cash flows.

     Financial information by segment is stated in thousands and summarized as
follows:

<TABLE>
<CAPTION>
                                                                    1995          1994           1993
                                                                 ----------    ----------     ----------
     <S>                                                         <C>           <C>            <C>
     Revenues:
          Oil and gas operations  . . . . . . . . . . . . . .    $  58,923     $  44,934      $  36,474
          Pipeline operations . . . . . . . . . . . . . . . .       29,637        20,664         43,415
          Intersegment eliminations . . . . . . . . . . . . .      (10,103)       (2,655)        (4,805)
                                                                 ----------    ----------     ----------
              Total revenues  . . . . . . . . . . . . . . . .    $  78,457     $  62,943      $  75,084
                                                                 ==========    ==========     ==========
</TABLE>
                                             (Table continued on following page)


                                       53
<PAGE>   56
<TABLE>
<CAPTION>
                                                                    1995          1994           1993
                                                                 ----------    ----------     ----------
     <S>                                                         <C>           <C>            <C>
     Income (loss) before income tax expense:
          Oil and gas operations (1)  . . . . . . . . . . . .    $   5,372     $  (2,012)     $  10,486
          Pipeline operations (1) . . . . . . . . . . . . . .       (3,025)         (299)          (642)
          Corporate  .. . . . . . . . . . . . . . . . . . . .          377           714          1,175
                                                                 ----------    ----------     ----------
              Total income (loss) before income tax expense .    $   2,724     $  (1,597)     $  11,019
                                                                 ==========    ==========     ==========

     Depletion, depreciation and amortization:
          Oil and gas operations (1)  . . . . . . . . . . . .    $  21,046     $   7,744      $   6,591
          Pipeline operations (1) . . . . . . . . . . . . . .        3,864         1,057          1,106               
          Corporate  .. . . . . . . . . . . . . . . . . . . .        1,076         1,036            679
                                                                 ----------    ----------     ----------
              Total depletion, depreciation and amortization     $  25,986     $   9,837      $   8,376
                                                                 ==========    ==========     ==========

     Capital expenditures:
          Oil and gas operations  . . . . . . . . . . . . . .    $  57,633     $  50,381      $  23,121
          Pipeline operations . . . . . . . . . . . . . . . .          304           477          1,191           
          Corporate . . . . . . . . . . . . . . . . . . . . .          817         1,443          1,540
                                                                 ----------    ----------     ----------
              Total capital expenditures  . . . . . . . . . .    $  58,754     $  52,301      $  25,852
                                                                 ==========    ==========     ==========

     Identifiable assets:
          Oil and gas operations  . . . . . . . . . . . . . .    $ 128,738     $  96,398      $  68,752                         
          Pipeline operations . . . . . . . . . . . . . . . .       16,291        18,303         24,146
          Corporate . . . . . . . . . . . . . . . . . . . . .       15,300        39,799         69,033
                                                                 ----------    ----------     ----------
              Total identifiable assets . . . . . . . . . . .    $ 160,329     $ 154,500      $ 161,931
                                                                 ==========    ==========     ==========
</TABLE>

----------------
(1)  Includes 1995 non-cash impairment expenses of $1.7 million and $2.8
     million for oil and gas operations and pipeline operations, respectively,
     resulting from the adoption of Statement No. 121.  See Note 1.

     The Company has a significant portion of its operations in various
geographic areas of the world.  During 1995, 42% of the revenues, 43% of the
identifiable assets and 75% of the equivalent barrels of oil reserves were
derived from or located in areas outside of the United States.  In addition,
100% of the Company's income before income tax expense relates to activities
outside of the United States during 1995.

     The Company's activities in these areas are subject to the usual risks
associated with foreign operations, including political and economic
uncertainties, risks of cancellation or unilateral modification of agreements,
operating restrictions, currency repatriation restrictions, expropriation,
export restrictions, the imposition of new taxes and the increase of existing
taxes, inflation, foreign exchange fluctuations and other risks arising out of
foreign government sovereignty over areas in which the operations are
conducted.  The Company has endeavored to protect itself against certain
political and commercial risks inherent in these operations.  There is no
certainty that the steps taken by the Company will provide adequate protection.

     On March 3, 1995, the Company was notified that its Russian joint venture
had received an exemption from paying export tax on crude oil sold outside of
Russia for one year beginning January 1, 1995.  The Company believes it has
complied with the investment criteria which form the basis of the exemption for
1996.  However, at the time of writing, Tatex had not received notification of
exemption from the export tax in 1996.  The International Monetary Fund has
made the complete removal of the export tax from all exporters by July 1, 1996
a precondition for granting certain loans to the Russian government.  Some
officials have indicated that in the event of the removal of the export tax,
the excise tax will be raised to compensate for lost tax revenues at that time.
Recent statements and actions by government ministries in connection with the
liberalization of Russian crude export controls indicate that in the future,
joint ventures may have to compete with Russian production associations for
limited pipeline capacity to export markets.  Crude oil not exported from the
Russian Federation is sold on the domestic market or exported to the
"near-abroad", countries which formerly comprised the USSR, for prices at
approximately 70 percent of world market levels.  Until the export tax
exemption is officially granted to Tatex, it is impossible to forecast with
accuracy the volume to be exported for world prices.





                                       54
<PAGE>   57
     Financial information by geographic area is stated in thousands and
summarized as follows:

<TABLE>
<CAPTION>
                                                       1995            1994              1993
                                                    -----------     -----------      -----------
<S>                                                 <C>             <C>              <C>
Revenues
     United States  . . . . . . . . . . . . .       $   45,137      $   39,028       $   58,667
     Indonesia  . . . . . . . . . . . . . . .           12,418          11,738           11,349
     Russia   . . . . . . . . . . . . . . . .           16,075          12,171            4,602
     Ivory Coast  . . . . . . . . . . . . . .            4,377             --               --
     Egypt  . . . . . . . . . . . . . . . . .              442             --               --
     Other International (1)  . . . . . . . .                8               6              466
                                                    -----------     -----------      -----------
          Total . . . . . . . . . . . . . . .       $   78,457      $   62,943       $   75,084
                                                    ===========     ===========      ===========
Income (loss) before income tax expense
     United States (2)  . . . . . . . . . . .       $   (9,722)     $   (7,490)      $    4,857
     Indonesia  . . . . . . . . . . . . . . .           12,235          11,600           11,218
     Russia   . . . . . . . . . . . . . . . .            3,333          (1,475)          (2,457)
     Ivory Coast  . . . . . . . . . . . . . .              415            (641)             --
     Egypt  . . . . . . . . . . . . . . . . .           (1,860)           (145)             --
     Other International (1)  . . . . . . . .           (1,677)         (3,446)          (2,599)
                                                    -----------     -----------      -----------
          Total . . . . . . . . . . . . . . .       $    2,724      $   (1,597)      $   11,019
                                                    ===========     ===========      ===========
Identifiable assets
     United States  . . . . . . . . . . . . .       $   90,398      $  115,678       $  140,933
     Indonesia  . . . . . . . . . . . . . . .            4,237           4,535            5,636
     Russia   . . . . . . . . . . . . . . . .           21,120          19,228           10,011
     Ivory Coast  . . . . . . . . . . . . . .           33,167          10,949            3,787
     Egypt  . . . . . . . . . . . . . . . . .           11,003           2,772              --
     Other International (1)  . . . . . . . .              404           1,338            1,564
                                                    -----------     -----------      -----------
          Total . . . . . . . . . . . . . . .       $  160,329      $  154,500       $  161,931
                                                    ===========     ===========      ===========
</TABLE>
----------------      
(1)  Other International includes Turkey, Malaysia, Argentina and Canada.
     During 1993, the Company sold its Argentinean and Canadian properties.
(2)  Includes 1995 non-cash impairment charges of $4.5 million resulting from
     the adoption of Statement No. 121.  See Note 1.

(11) RELATED PARTY TRANSACTIONS

     In 1990, the Company issued 1,100,000 shares of common stock from its
treasury to Noel in exchange for Noel's 10% subordinated convertible debenture
in the principal amount of $6.6 million (the "Noel Debenture").  On December
31, 1990, the Noel Debenture was surrendered to Noel in exchange for 789,946
shares of Noel common stock.  Noel conducts its principal operations through
small and medium sized operating companies in which Noel holds controlling or
other significant equity interests.

     On September 21, 1992, Noel distributed shares of certain companies owned
by Noel to Noel shareholders.  The Company received 46,468 shares of Garnet,
53,907 shares of VISX Incorporated ("VISX") and 203,098 shares of the Company's
stock as a result of the distribution.  During February 1993, the Company
disposed of its entire investment in VISX for an average net sales proceeds of
$11.76 per share.  The distribution by Noel of shares of common stock of the
Company reduced Noel's ownership of the Company from approximately 25% to
approximately 3%.

     On November 29, 1993, Noel distributed shares of Sylvan Foods Holdings,
Inc. ("Sylvan").  The Company received 54,860 shares of Sylvan as the result of
the distribution.  During December 1993, the Company disposed of 25,000 shares
of Sylvan stock for an average net sales proceeds of $8.37 per share.  During
January 1994, the Company disposed of its remaining investment in Sylvan for an
average net sales proceeds of $7.89 per share.

     On December 22, 1993, the Company sold 710,000 shares of Noel common stock
for an average net sales proceeds of $6.625 per share.  On January 10, 1994,
the Company sold its remaining 79,946 shares of Noel common stock for an
average net sales proceeds of $7.00 per share.

     See Note 5 for discussion of additional related party transactions.





                                       55
<PAGE>   58
                         GLOBAL NATURAL RESOURCES INC.
        SUPPLEMENTARY TABLES ON RESERVE DATA AND OIL AND GAS OPERATIONS
                                  (UNAUDITED)

<TABLE>
<CAPTION>
                                                                                                          PAGE
                                                                                                          ----
<S>                                                                                                        <C>
Results of Operations for Producing Activities and Costs Incurred in Oil and
   Gas Property Acquisition, Exploration and Development Activities for the
   three years ended December 31, 1995 and Capitalized Costs Relating to Oil
   and Gas Producing Activities at December 31, 1995, 1994 and 1993
   Table 1  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    57

Reserve Quantity Information for the three years ended December 31, 1995
   Table 2  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    60

Standardized Measure of Discounted Future Net Cash Flows Related to Proved
   Oil and Gas Reserves for the three years ended December 31, 1995
   Table 3  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    62

Notes to Supplementary Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .    63
</TABLE>





                                       56
<PAGE>   59
TABLE 1

                GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
 RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES AND COSTS INCURRED IN OIL AND
GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES FOR THE THREE
 YEARS ENDED DECEMBER 31, 1995 AND CAPITALIZED COSTS RELATING TO OIL AND GAS
           PRODUCING ACTIVITIES AT DECEMBER 31, 1995, 1994 AND 1993
                      (AMOUNTS IN THOUSANDS) (UNAUDITED)

       The following table reflects activity relating to oil and gas producing
activities by geographic area.

<TABLE>
<CAPTION>
                                              UNITED                                IVORY
                                              STATES       RUSSIA    INDONESIA      COAST        OTHER(1)      TOTAL
                                            ----------   ---------- -----------   ----------    ----------   ----------
<S>                                         <C>          <C>        <C>           <C>           <C>          <C>
YEAR ENDED DECEMBER 31, 1995
Net Revenues from production:
   Sales of oil and gas to non-affiliates   $  24,851    $  16,038  $   12,418    $   4,377     $     450    $  58,134
Production (lifting costs)  . . . . . . .       5,743        6,190         --         1,010            56       12,999
Depletion, depreciation and amortization       15,422        1,513         131        2,100           134       19,300
Impairment of long-lived assets . . . . .       1,746          --          --           --            --         1,746
Exploration expense . . . . . . . . . . .       7,119          367         --           471         3,811       11,768
Income tax expense  . . . . . . . . . . .         121        1,066       6,953          832            59        9,031
                                            ----------   ---------- -----------   ----------    ----------   ----------
Results of activities . . . . . . . . . .   $  (5,300)   $   6,902  $    5,334    $     (36)    $  (3,610)   $   3,290
                                            ==========   ========== ===========   ==========    ==========   ==========
                                                                                   
YEAR ENDED DECEMBER 31, 1994                                                       
Net Revenues from production:                                                      
   Sales of oil and gas to non-affiliates   $  20,119    $  11,951  $   11,738    $     --      $       6    $  43,814
Production (lifting costs)(2) . . . . . .       3,368        7,835         --           --            --        11,203
Depletion, depreciation and amortization        6,559        1,054         131          --            --         7,744
Exploration expense . . . . . . . . . . .      17,710          496         --           --          1,119       19,325
Income tax expense  . . . . . . . . . . .          24           55       6,577          --            --         6,656
                                            ----------   ---------- -----------   ----------    ----------   ----------
Results of activities . . . . . . . . . .   $  (7,542)   $   2,511  $    5,030    $     --      $  (1,113)   $  (1,114)
                                            ==========   ========== ===========   ==========    ==========   ==========
                                                                                   
YEAR ENDED DECEMBER 31, 1993                                                       
Net Revenues from production:                                                      
   Sales of oil and gas to non-affiliates   $  19,276    $   4,602  $   11,349    $     --      $     466    $  35,693
Production (lifting costs)(2) . . . . . .       3,730        3,962         --           --            443        8,135
Depletion, depreciation and amortization        5,888          260         131          --            312        6,591
Exploration expense . . . . . . . . . . .       5,580          124         --           --          1,242        6,946
Income tax expense  . . . . . . . . . . .         177           37       6,320          --             (2)       6,532
                                            ----------   ---------- -----------   ----------    ----------   ----------
Results of activities . . . . . . . . . .   $   3,901    $     219  $    4,898    $     --      $  (1,529)   $   7,489
                                            ==========   ========== ===========   ==========    ==========   ==========
</TABLE>

------------------------
(1)   Other includes Malaysia, Egypt, Turkey, Argentina and Canada.  During
      1993, the Company sold its Argentinean  and Canadian properties.

(2)   Included in Russian production expenses are export tax expenses of $4.1
      million and $1.7 million during 1994 and 1993, respectively.





                See accompanying notes to supplementary tables.

                                       57
<PAGE>   60
TABLE 1 CONTINUED.

     The following table reflects activity relating to costs incurred in oil
and gas property acquisition, exploration and development activities by
geographic area.

<TABLE>
<CAPTION>
                                              UNITED                                IVORY
                                              STATES       RUSSIA      EGYPT        COAST        OTHER(1)      TOTAL
                                            ----------   ---------- -----------   ----------    ----------   ----------
<S>                                         <C>          <C>        <C>           <C>           <C>          <C>
YEAR ENDED DECEMBER 31, 1995
Property acquisition costs:                                                         
  Proved  . . . . . . . . . . . . . .       $   3,182    $     --   $      --     $     --      $    --      $   3,182 
  Unproved  . . . . . . . . . . . . .           2,676          --           13          126          --          2,815 
Exploration costs . . . . . . . . . .          12,756          367       4,772          441          776        19,112 
Development costs . . . . . . . . . .          10,101        3,933       4,792       18,359          --         37,185 
                                            ----------   ---------- -----------   ----------    ----------   ----------
Total   . . . . . . . . . . . . . . .       $  28,715       $4,300  $    9,577    $  18,926         $776     $  62,294 
                                            ==========   ========== ===========   ==========    ==========   ==========
                                                                                                                       
YEAR ENDED DECEMBER 31, 1994                                                                                           
Property acquisition costs:                                                                                            
  Proved  . . . . . . . . . . . . . .       $   3,790    $     --   $      --     $     --      $    --      $   3,790 
  Unproved  . . . . . . . . . . . . .           2,440          --          885          --           --          3,325 
Exploration costs . . . . . . . . . .          25,876          496       2,022        3,032          602        32,028 
Development costs . . . . . . . . . .           8,773        5,527         --         2,624          --         16,924 
                                            ----------   ---------- -----------   ----------    ----------   ----------
Total   . . . . . . . . . . . . . . .       $  40,879       $6,023  $    2,907    $   5,656     $    602     $  56,067 
                                            ==========   ========== ===========   ==========    ==========   ==========
                                                                                                                       
YEAR ENDED DECEMBER 31, 1993                                                                                           
Property acquisition costs:                                                                                            
  Proved  . . . . . . . . . . . . .         $    --      $     --   $      --     $     --      $    --      $     --     
  Unproved  . . . . . . . . . . . .             3,334          --          --             9           21         3,364 
Exploration costs . . . . . . . . .            12,971          124         --         4,001          917        18,013 
Development costs . . . . . . . . .             1,027        3,007         --            41          (10)        4,065 
                                            ----------   ---------- -----------   ----------    ----------   ----------
Total   . . . . . . . . . . . . . .         $  17,332    $   3,131  $      --     $   4,051     $    928     $  25,442 
                                            ==========   ========== ===========   ==========    ==========   ==========
</TABLE>                           

------------------------
(1)   Other includes Malaysia, Turkey, Argentina and Canada.  During 1993, the
      Company sold its Argentinean  and Canadian properties.





                See accompanying notes to supplementary tables.

                                       58
<PAGE>   61
TABLE 1 CONTINUED.


       The following table reflects the capitalized costs relating to oil and
gas producing activities by geographic area.

<TABLE>
<CAPTION>
                                       UNITED                                             IVORY
                                       STATES       RUSSIA    INDONESIA       EGYPT       COAST        OTHER(1)      TOTAL
                                     ----------   ----------  ----------    ---------   ----------     --------    ----------
<S>                                  <C>          <C>         <C>           <C>          <C>           <C>         <C>
AT DECEMBER 31, 1995                                                                  
Capitalized cost:                                                                     
   Unproved . . . . . . . . . . .    $   4,850    $     --    $     --      $    897     $    118      $   245     $   6,110
   Producing  . . . . . . . . . .      109,804       13,103       3,962        9,331       27,146          134       163,480      
Accumulated depletion and                                                                                                      
   depreciation . . . . . . . . .      (62,895)      (2,635)     (2,779)        (134)      (2,100)         --        (70,543)     
                                     ----------   ----------  ----------    ---------    ---------     --------    ----------
Net capitalized costs . . . . . .    $  51,759    $  10,468   $   1,183     $ 10,094     $ 25,164      $   379     $  99,047      
                                     ==========   ==========  ==========    =========    =========     ========    ==========
                                                                                                                               
AT DECEMBER 31, 1994                                                                                                           
Capitalized cost:                                                                                                              
   Unproved . . . . . . . . . . .    $   3,350    $     --    $     --      $    885     $      9      $   386     $   4,630      
   Producing  . . . . . . . . . .       89,666        9,753       3,962        1,877        8,798          916       114,972      
Accumulated depletion and                                                                                                      
   depreciation . . . . . . . . .      (45,727)      (1,423)     (2,648)         --           --           --        (49,798)     
                                     ----------   ----------  ----------    ---------    ---------     --------    ----------
Net capitalized costs . . . . . .    $  47,289    $   8,330   $   1,314     $  2,762     $  8,807      $ 1,302     $  69,804      
                                     ==========   ==========  ==========    =========    =========     ========    ==========
                                                                                                                                   
AT DECEMBER 31, 1993                                                                                                           
Capitalized cost:                                                                                                              
   Unproved . . . . . . . . . . .    $   6,064    $     --    $     --      $    --      $      9      $   389     $   6,462      
   Producing  . . . . . . . . . .       76,828        4,332       3,962          --         3,784          --         88,906      
Accumulated depletion and                                                                                                      
   depreciation . . . . . . . . .      (44,832)        (387)     (2,516)         --           --           --        (47,735)     
                                     ----------   ----------  ----------    ---------    ---------     --------    ----------
Net capitalized costs . . . . . .    $  38,060    $   3,945   $   1,446     $    --      $  3,793      $   389     $  47,633      
                                     ==========   ==========  ==========    =========    =========     ========    ==========
</TABLE>          


------------------------
(1)   Other includes Malaysia, Turkey, Argentina and Canada.  During 1993, the
      Company sold its Argentinean  and Canadian properties.





                See accompanying notes to supplementary tables.

                                       59
<PAGE>   62
TABLE 2

                 GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
                          RESERVE QUANTITY INFORMATION
                               NATURAL GAS (MMCF)
                  FOR THE THREE YEARS ENDED DECEMBER 31, 1995
                                  (UNAUDITED)

<TABLE>
<CAPTION>
                                           UNITED
                                           STATES      INDONESIA(1)      EGYPT         IVORY        OTHER(2)       TOTAL
                                          ----------   ------------     -------       --------      --------    ----------
<S>                                       <C>            <C>            <C>           <C>           <C>         <C>
Proved Reserves:
January 1, 1993 . . . . . . . . . .          42,094        76,081           --             --           239       118,414
   Revisions of previous estimates            6,651         7,394           --             --           --         14,045
   Extensions, discoveries and
      other additions   . . . . . .          22,920           --            --             --           --         22,920
   Sales of reserves-in-place   . .            (665)          --            --             --          (170)         (835)
   Production   . . . . . . . . . .          (7,019)       (3,769)          --             --           (69)      (10,857)
                                          ----------   -----------      -------       --------      --------    ----------

December 31, 1993 . . . . . . . . .          63,981        79,706           --             --           --        143,687
   Revisions of previous estimates            1,270         4,757           --             --           --          6,027
   Extensions, discoveries and
      other additions   . . . . . .           9,875           --            --          18,432          --         28,307
   Purchases of reserves-in-place             2,079           --            --             --           --          2,079
   Sales of reserves-in-place   . .          (8,803)          --            --             --           --         (8,803)
   Production   . . . . . . . . . .          (8,904)       (4,473)          --             --           --        (13,377)
                                          ----------   -----------      -------       --------      --------    ----------

December 31, 1994 . . . . . . . . .          59,498        79,990           --          18,432          --        157,920
   Revisions of previous estimates            8,471        (3,165)        1,399            278          --          6,983
   Extensions, discoveries and
      other additions   . . . . . .          11,524           --            --           2,559          --         14,083
   Purchases of reserves-in-place             2,840           --            --             --           --          2,840
   Sales of reserves-in-place   . .             --            --            --             --           --          --
   Production   . . . . . . . . . .         (13,710)       (3,933)          --            (203)         --        (17,846)
                                          ----------   -----------      -------       --------      --------    ----------
December 31, 1995 . . . . . . . . .          68,623        72,892         1,399         21,066          --        163,980
                                          ==========   ===========      =======       ========      ========    ==========
Proved Developed Reserves:
   December 31, 1993  . . . . . . .          42,204        53,931           --             --           --         96,135
   December 31, 1994  . . . . . . .          48,946        65,021           --             --           --        113,967
   December 31, 1995  . . . . . . .          59,626        57,777         1,399         11,415          --        130,217
</TABLE>
------------------------  
(1)  All Indonesia Mmcf amounts appearing in this table are for dry gas.
(2)  Other includes Argentina and Canada which were sold during 1993.
(3)  Includes for 1995 primary reserves only.  If secondary recovery techniques
     would be implemented a decrease of 151 Mmcf would result.





                See accompanying notes to supplementary tables.

                                       60
<PAGE>   63
TABLE 2 CONTINUED.

                 GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
                          RESERVE QUANTITY INFORMATION
                             OIL/CONDENSATE (MBBL)
                  FOR THE THREE YEARS ENDED DECEMBER 31, 1995
                                  (UNAUDITED)

<TABLE>
<CAPTION>
                                         UNITED                                               IVORY
                                         STATES      INDONESIA     RUSSIA        EGYPT       COAST(3)    OTHER(1)      TOTAL
                                         --------    ---------    --------      -------     --------    ----------   --------
<S>                                      <C>          <C>         <C>           <C>          <C>          <C>        <C>
Proved Reserves:
January 1, 1993 . . . . . . . . . .          939          837       4,882          --                        148       6,806
   Revisions of previous estimates           161          222         142          --                        --          525
   Extensions, discoveries and
      other additions   . . . . . .          666          --        2,596          --                        --        3,262
   Sales of reserves-in-place   . .          (48)         --          --           --                       (125)       (173)
   Production   . . . . . . . . . .         (259)         (54)       (323)         --                        (23)       (659)
                                         --------    ---------    --------      -------     --------    ---------    --------

December 31, 1993(2)  . . . . . . .        1,459        1,005       7,297          --                        --        9,761
   Revisions of previous estimates           232          108       2,109          --                        --        2,449
   Extensions, discoveries and
      other additions   . . . . . .          792          --        4,593        3,520        2,210          --       11,115
   Purchase of reserves-in-place  .           15          --          --           --           --           --           15
   Sales of reserves-in-place   . .          (96)         --          --           --           --           --          (96)
   Production   . . . . . . . . . .         (229)         (47)       (842)         --           --           --       (1,118)
                                         --------    ---------    --------      -------     --------    ---------    --------

December 31, 1994(2)  . . . . . . .        2,173        1,066      13,157        3,520        2,210          --       22,126
   Revisions of previous estimates           --           132       1,497        4,423           72          --        6,124
   Extensions, discoveries and
      other additions(4)  . . . . .           11          --        1,978          --           989          --        2,978
   Purchase of reserves-in-place  .          781          --          --           --           --           --          781
   Sales of reserves-in-place   . .          --           --          --           --           --           --          --
   Production   . . . . . . . . . .         (244)         (45)     (1,062)         (25)        (261)         --       (1,637)
                                         --------    ---------    --------      -------     --------    ---------    --------
December 31, 1995(2)  . . . . . . .        2,721        1,153      15,570        7,918        3,010          --       30,372
                                         ========    =========    ========      =======     ========    =========    ========
PROVED DEVELOPED RESERVES:                                                                  
   December 31, 1993  . . . . . . .          859          762       7,297          --           --           --        8,918
   December 31, 1994  . . . . . . .        1,085          870       8,866          --           --           --       10,821
   December 31, 1995  . . . . . . .        1,861        1,022       9,176          265        1,720          --       14,044
------------------------                                                                                                    
</TABLE>
(1)   Other includes Argentina and Canada which were sold during 1993.
(2)   Includes reserves of 1,557 MBbl, 1,316 MBbl and 1,459 MBbl in 1995, 1994
      and 1993, respectively, attributable to a minority interest (10% in 1995
      and 1994 and 20% during 1993) in a consolidated subsidiary.
(3)   Includes for 1995 primary reserves only.  If secondary recovery
      techniques would be implemented an increase of 461 MBbls would result.
(4)   Includes for 1995 reserves associated with the right to develop the
      Suncheleevsky field in Russia.





                See accompanying notes to supplementary tables.

                                       61
<PAGE>   64
TABLE 3
                GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
           STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
          RELATED TO PROVED OIL AND GAS RESERVES FOR THE THREE YEARS
                           ENDED DECEMBER 31, 1995
                      (AMOUNTS IN THOUSANDS) (UNAUDITED)

<TABLE>
<CAPTION>
                                            UNITED
                                            STATES      INDONESIA      RUSSIA        EGYPT       IVORY         TOTAL
                                          ----------    ----------    ---------    ----------  ----------    ----------
<S>                                       <C>           <C>           <C>          <C>         <C>           <C>
DECEMBER 31, 1995                                                                               
   Future cash flows  . . . . . . . . . . $ 197,591     $ 179,534     $ 261,880    $ 144,528   $ 103,820     $ 887,353
   Future production and                                                                        
      development costs   . . . . . . . .    50,766        36,305       148,190       78,431      35,964       349,656
   Future income taxes  . . . . . . . . .    26,934        70,323        37,360       25,195      16,733       176,545
                                          ----------    ----------    ---------    ----------  ----------    ----------
   Future net cash flows  . . . . . . . .   119,891        72,906        76,330       40,902      51,123       361,152
   10% annual discount for estimated                                                                                  
      timing of cash flows  . . . . . . .    29,144        36,198        36,820       15,853      14,091       132,106
                                          ----------    ----------    ---------    ----------  ----------    ----------
   Standardized measure of                                                                      
      discounted future net cash flows                                                          
      relating to oil and gas
       reserves(1). . . . . . . . . . . . $  90,747     $  36,708     $  39,510    $  25,049   $  37,032     $ 229,046
                                          =========    ==========    =========    ==========  ==========    ==========

DECEMBER 31, 1994
   Future cash flows  . . . . . . . . . . $ 124,471     $ 175,855     $ 189,592    $  55,378   $  66,448     $ 611,744
   Future production and                                                                        
      development costs   . . . . . . . .    39,075        44,017       111,602       29,128      37,595       261,417
   Future income taxes  . . . . . . . . .     2,076        64,823        23,619        9,497       8,974       108,989
                                          ----------    ----------    ---------    ----------  ----------    ----------
   Future net cash flows  . . . . . . . .    83,320        67,015        54,371       16,753      19,879       241,338
   10% annual discount for estimated                                                            
      timing of cash flows  . . . . . . .    23,330        32,792        23,562        8,601      10,438        98,723
                                          ----------    ----------    ---------    ----------  ----------    ----------
   Standardized measure of                                                                      
      discounted future net cash flows                                                      
      relating to oil and gas
      reserves(1) . . . . . . . . . . . . $  59,990     $  34,223     $  30,809    $   8,152   $   9,441     $ 142,615
                                          ==========    ==========    =========    ==========  ==========    ==========

DECEMBER 31, 1993                                                                            
   Future cash flows  . . . . . . . . . . $ 160,935     $ 154,573     $  83,552    $     --    $     --      $ 399,060
   Future production and                                                            
      development costs   . . . . . . . .    52,516        43,673        48,756          --          --        144,945
   Future income taxes  . . . . . . . . .     7,705        54,915         9,771          --          --         72,391
                                          ----------    ----------    ---------    ----------  ----------    ----------
   Future net cash flows  . . . . . . . .   100,714        55,985        25,025          --          --        181,724
   10% annual discount for estimated                                             
      timing of cash flows  . . . . . . .    32,487        27,835        12,200          --          --         72,522
                                          ----------    ----------    ---------    ----------  ----------    ----------
   Standardized measure of               
      discounted future net cash flows   
      relating to oil and gas
      reserves(1) . . . . . . . . . . . . $  68,227     $  28,150     $  12,825    $     --    $     --      $ 109,202
                                          ==========    ==========    =========    ==========  ==========    ==========
</TABLE>
------------------------        
(1)   Includes $5.9 million, $3.1 million and $2.6 million in 1995, 1994 and
      1993, respectively, attributed to a minority interest (10% in 1995 and
      1994 and 20% during 1993) in a consolidated subsidiary.


                 See accompanying Notes to Supplementary Tables

                                       62
<PAGE>   65
TABLE 3 CONTINUED.

      The following table shows changes in the Standardized Measure of
Discounted Future Net Cash Flows for the three years ended December 31, 1995.



<TABLE>
<CAPTION>
                                                               1995                1994                1993
                                                           -----------         -----------         -----------
<S>                                                        <C>                 <C>                 <C>
Beginning of year . . . . . . . . . . . . . . . . .        $  142,615          $  109,202          $   93,955
Changes resulting from:
Sales and transfers of oil and gas produced, net
     of production costs  . . . . . . . . . . . . .           (45,124)            (32,612)            (27,558)
Net changes in prices and production costs  . . . .            19,616             (17,822)            (45,242)
Extensions, discoveries, additions and improved
    recovery, less related costs  . . . . . . . . .            94,866              49,847              33,610
Change in development cost during the period  . . .           (33,022)             (1,444)              3,308
Revisions of previous quantity estimates  . . . . .            52,621              15,534              16,306
Purchase and sales of minerals-in-place, net  . . .            11,037              (9,115)             (1,763)
Accretion of discount . . . . . . . . . . . . . . .            19,725              14,407              12,944
Net changes in income taxes . . . . . . . . . . . .           (47,191)            (20,731)              7,955
Changes in production, timing and other . . . . . .            13,903              35,349              15,687
                                                           -----------         -----------         -----------
End of year . . . . . . . . . . . . . . . . . . . .        $  229,046          $  142,615          $  109,202
                                                           ===========         ===========         ===========
</TABLE>


Notes to Supplementary Tables

     The estimates of proved reserves are inherently imprecise and are
continually subject to revision based on production history, results of
additional exploration and development and other factors.

     At December 31, 1995, 1994 and 1993, the Company's gross oil and gas
reserve estimates for properties located in the United States and Russia were
prepared by Ryder Scott Company Petroleum Engineers.   At December 31, 1995 and
1994, Ivory Coast and Egyptian gross oil and gas reserve estimates were
prepared by Netherland, Sewell & Associates, Inc.  Indonesian reserves are
based on information obtained by the Company from public sources.

     Income tax expense (benefit) in Table 1 for United States is alternative
minimum tax.  There are no other income taxes for this geographic area because
of net operating loss carryforwards (see Note 7 to Consolidated Financial
Statements).  The income tax expense in Table 1 for Indonesia and the Ivory
Coast reflects actual taxes paid in those countries.





                                       63
<PAGE>   66
ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE.

     None
                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

     The Company will file with the Securities and Exchange Commission pursuant
to Regulation 14A a definitive Proxy Statement involving the election of
directors not later than 120 days after December 31, 1995.  The information
required by this item with respect to officers and directors will appear in
such definitive Proxy Statement and is incorporated herein by reference.

ITEM 11.  EXECUTIVE COMPENSATION.

     The Company will file with the Securities and Exchange Commission pursuant
to Regulation 14A a definitive Proxy Statement involving the election of
directors not later than 120 days after December 31, 1995.  The information
required by this item with respect to executive compensation will appear in
such definitive Proxy Statement and is incorporated herein by reference.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

     The Company will file with the Securities and Exchange Commission pursuant
to Regulation 14A a definitive Proxy Statement involving the election of
directors not later than 120 days after December 31, 1995.  The information
required by this item with respect to security ownership will appear in such
definitive Proxy Statement and is incorporated herein by reference.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

     The Company will file with the Securities and Exchange Commission pursuant
to Regulation 14A a definitive Proxy Statement involving the election of
directors not later than 120 days after December 31, 1995.  The information
required by this item with respect to certain relationships and related
transactions will appear in such definitive Proxy Statement and is incorporated
herein by reference.





                                       64
<PAGE>   67
                                    PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)(1)   Financial Statements listed below are included as Part II, Item 8
hereof:

<TABLE>
<CAPTION>
         CONSOLIDATED FINANCIAL STATEMENTS                                                                PAGE
                                                                                                          ----
<S>      <C>                                                                                               <C>
             Independent Auditors' Report   . . . . . . . . . . . . . . . . . . . . . . . . . . . .        37

             Consolidated Balance Sheets at December 31, 1995 and 1994  . . . . . . . . . . . . . .        38

             Consolidated Statements of Operations for the three years ended December 31,
               1995   . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        39

             Consolidated Statements of Shareholders' Equity for the three years ended December
               31, 1995   . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        40

             Consolidated Statements of Cash Flows for the three years ended December
               31, 1995   . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        41

         Notes to Consolidated Financial Statements   . . . . . . . . . . . . . . . . . . . . . . .        43

         Supplementary Tables on Reserve Data and Oil and Gas Operations  . . . . . . . . . . . . .        56

(a)(2)   Financial Statement Schedules

         None

(a)(3)   Exhibits   . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        67
</TABLE>

(b)      Reports on Form 8-K for the quarter ended December 31, 1995

         None





                                       65
<PAGE>   68
                                   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.


                                        GLOBAL NATURAL RESOURCES INC.
Date: March 25, 1996         
                             By              /s/ ROBERT F. VAGT                 
                                 ----------------------------------------------
                                               Robert F. Vagt
                                            Chairman of the Board
                                    President and Chief Executive Officer
Date: March 25, 1996         
                             
                             By              /s/ ERIC LYNN HILL                 
                                 ----------------------------------------------
                                               Eric Lynn Hill
                              Senior Vice President, Finance and Administration
                                (Principal Financial and Accounting Officer)

 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 INDICATED AS OF MARCH 25, 1996.


      /s/ WILLIAM L. BENNETT *                    Director
-------------------------------------                     
         William L. Bennett          
                                     
        /s/ JOHN A. BROCK *                       Director
-------------------------------------                     
           John A. Brock             
                                     
       /s/ PAUL E. CARLTON *                      Director
-------------------------------------                     
          Paul E. Carlton            
                                     
    /s/ PATRICK L. MACDOUGALL *                   Director
-------------------------------------                     
       Patrick L. Macdougall         
                                     
        /s/ JAMES G. NIVEN *                      Director
-------------------------------------                     
           James G. Niven            
                                     
      /s/ SIDNEY R. PETERSEN *                    Director
-------------------------------------                     
        Sidney R. Petersen           
                                     
       /s/ LINDA F. SJOMAN *                      Director
-------------------------------------                     
          Linda F. Sjoman            
                                     
         /s/ ROBERT F. VAGT                 Chairman of the Board
-------------------------------------                            
           Robert F. Vagt               
                                     

*Signed via Power of Attorney





                                       66
<PAGE>   69
(a)3.      Exhibits:

 The following documents are included as Exhibits to this report.  Those
Exhibits listed below as "incorporated herein by reference" are indicated as
such by the information supplied in the parenthetical thereafter.  If no
parenthetical appears after an Exhibit in the list, copies of the document have
been filed with this Report.

         3.1     Restated Certificate of Incorporation of the Company dated May
                 10, 1983.  (Incorporated herein by reference to Exhibit 3.1 to
                 the Company's Form 10-K for the year ended December 31, 1992.)

         3.2     Amendment to Restated Certificate of Incorporation of the
                 Company dated July 31, 1987.  (Incorporated herein by
                 reference to Exhibit 3.2 to the Company's Form 10-K for the
                 year ended December 31, 1992.)

         3.3     Amendment to Restated Certificate of Incorporation of the
                 Company dated August 20, 1987.  (Incorporated herein by
                 reference to Exhibit 3.3 to the Company's Form 10-K for the
                 year ended December 31, 1992.)

         3.4     Correction to Amendment to Restated Certificate of
                 Incorporation of the Company dated September 9, 1988.
                 (Incorporated herein by reference to Exhibit 3.4 to the
                 Company's Form 10-K for the year ended December 31, 1992.)

         3.5     Amendment to Restated Certificate of Incorporation of the
                 Company dated October 5, 1988.  (Incorporated herein by
                 reference to Exhibit 3.5 to the Company's Form 10-K for the
                 year ended December 31, 1992.)

         3.6     Amendment to Restated Certificate of Incorporation of the
                 Company dated October 17, 1990.  (Incorporated herein by
                 reference to Exhibit 3.6 to the Company's Form 10-K for the
                 year ended December 31, 1992.)

         3.7     Bylaws of the Company, as amended June 7, 1990.  (Incorporated
                 herein by reference to Exhibit 3.7 to the Company's Form 10-K
                 for the year ended December 31, 1992.)

         3.8     Amendment to Restated Certificate of Incorporation of the
                 Company dated May 26, 1993.  (Incorporated hererin by
                 reference to Exhibit 3.8 to the Company's Form 10-K for the
                 year ended December 31, 1993.)

         3.9     Bylaws of the Company, as amended May 25, 1993.  (Incorporated
                 herein by reference to Exhibit 3.9 to the Company's Form 10-K
                 for the year ended December 31, 1993.)

         4.1     Rights Agreement dated as of October 5, 1988 between Global
                 Natural Resources Inc. and Registrar and Transfer Company,
                 which includes the form of Certificate of Amendment of
                 Restated Certificate of Incorporation setting forth the terms
                 of the Series B Junior Preferred Stock, par value $1.00 per
                 share, as Exhibit A, the form of Right Certificate as Exhibit
                 B and the Summary of Rights to Purchase Preferred Shares as
                 Exhibit C incorporated by reference to Exhibit A to the
                 Company's Registration Statement on Form 8-A, dated October
                 11, 1988. (Incorporated herein by reference to Exhibit A to
                 the Form 10-Q for the quarter ended September 30, 1988.)

         4.2     First Amendment to Rights Agreement dated as of July 19, 1989
                 between Global Natural Resources Inc. and Registrar and
                 Transfer Company (Incorporated herein by reference to Exhibit
                 1.1 to Form 8 dated August 9, 1989.)

         4.3     Second Amendment to Rights Agreement dated as of February 5,
                 1993 between Global Natural Resources Inc.  and Registrar and
                 Transfer Company. (Incorporated herein by reference to Exhibit
                 7.2 to Form 8 dated February 16, 1993.)





                                       67
<PAGE>   70
         4.4     Amended and Restated Rights Agreement dated as of September
                 28, 1993 between Global Natural Resources Inc. and Registrar
                 and Transfer Company.  (Incorporated herein by reference to
                 Exhibit 1.1 to Form 8-K dated October 20, 1993.)

         10.1    Joint Venture Agreement dated August 8, 1968, between
                 Huffington, Virginia International Company, Austral Petroleum
                 Gas Corporation, Golden Eagle Indonesia, Limited and Union
                 Texas Far East Corporation, as amended.  (Incorporated herein
                 by reference to Exhibit 6.6 to Registration Statement No.
                 2-58834.)

         10.2    Agreement dated as of October 1, 1979 among the parties to the
                 Joint Venture Agreement referred to in Exhibit 10.1 above.
                 (Incorporated herein by reference to Exhibit 5.2 to
                 Registration Statement No.  2-66661.)

         10.3    Production Sharing Contract, dated August 8, 1968, between
                 Pertamina, Huffington, and Virginia International Company, as
                 amended.  (Incorporated herein by reference to Exhibit 6.5 to
                 Registration Statement No. 2-58834.)

         10.4    Amendment dated as of January 1, 1978, to Production Sharing
                 Contract referred to in Exhibit 10.3 above.  (Incorporated
                 herein by reference to Exhibit 5.4 to Registration Statement
                 No. 2-66661.)

         10.5    LNG Sales Contract, dated November 3, 1973, between Pertamina,
                 The Chubu Electric Power Co., Inc., The Kansan Electric Power
                 Co., Inc., Kyushu Electric Power Co., Inc., Nippon Steel
                 Corporation and Osaka Gas Company, Ltd., as amended.
                 (Incorporated herein by reference to Exhibit 6.8 to
                 Registration Statement No. 2-58834.)

         10.6    Form of Agreement for Sale of Additional Cargoes, draft of
                 November 19, 1979, between the parties to the LNG Sales
                 Contract referred to in Exhibit 10.5 above.  (Incorporated
                 herein by reference to Exhibit 5.6 to Registration Statement
                 No. 2-66661.)

         10.7    Supply  Agreement, dated as of December 3, 1974, between
                 Pertamina and the parties to the Joint Venture Agreement
                 referred to in Exhibit 10.1 above.  (Incorporated herein by
                 reference to Exhibit 6.7 to Registration Statement No.
                 2-58834.)

         10.8    Amendment, dated as of August 15, 1977, to Supply Agreement,
                 dated as of December 3, 1974, between Pertamina and the
                 parties to the Joint Venture Agreement referred to in Exhibit
                 10.1 above.  (Incorporated herein by reference to Exhibit
                 5.5.1 to Registration Statement No. 2-64347.)

         10.9    Form of Supply Agreement for Additional Sales of Liquefied
                 Natural Gas from Badak Liquefaction Facility, draft of
                 November 16, 1979, between the parties to the Supply Agreement
                 referred to in Exhibit 10.7 above.   (Incorporated herein by
                 reference to Exhibit 5.9 to Registration Statement No.
                 2-66661.)

         10.10   Transportation Agreement dated as of September 23, 1973,
                 between Burmast East Shipping Corporation and Pertamina, as
                 amended.  (Incorporated herein by reference to Exhibit 6.11 to
                 Registration Statement No.  2-58834.)

         10.11   Amendment No. 1 to Transportation Agreement referred to in
                 Exhibit 10.10 above, dated as of August 31, 1976, between
                 Burmah Gas Transport Limited and Pertamina.  (Incorporated
                 herein by reference to Exhibit 5.11 to the Annual Report on
                 Form 20-F for the year ending December 31, 1979 (the "1979
                 20-F"), of the U.K. Company.)

         10.12   Badak LNG Sales Contract, dated April 14, 1981, between
                 Perusahaan Pertambangan Minyak Dan Gas Bumi Negara
                 ("Pertamina") as "Seller" and the Chubu Electric Power Co.,
                 Inc., The Kansan Electric Power Co., Inc., Osaka Gas Company,
                 Ltd., and Toho Gas Company, Ltd. as "Buyers."  (Incorporated
                 herein by reference to Exhibit (10)-23 to the Annual Report on
                 Form 20-F for the year ending December 31, 1981, of Virginia
                 International Company.)





                                       68
<PAGE>   71
         10.13   Royalty Incentive Plan, as amended.  (Incorporated herein by
                 reference to Exhibit 1.4 to the Annual Report on Form 20-F for
                 the year ending December 31, 1981 (the "1981 20-F"), of the
                 U.K. Company.)

         10.14   Natural Resources Corporation Supplemental Retirement Plan, as
                 amended by the Board of Directors effective December 12, 1985.
                 (Incorporated herein by reference to Exhibit 10.17 to the 1985
                 10-K.)

         10.15   Arctic Lands Farm Out Agreement made as of the 29th day of
                 November, 1983, between Global Natural Resources Canada
                 Limited and Thomson-Jensen Energy.  (Incorporated herein by
                 reference to Exhibit 2 to Global's report on Form 8-K dated
                 December 8, 1983.)

         10.16   Global-TJE  Agency  Agreement made as of the 29th day of
                 November, 1983, between Global Natural Resources Canada
                 Limited and Thomson-Jensen Energy.  (Incorporated herein by
                 reference to Exhibit 3 to Global's report on Form 8-K dated
                 December 8, 1983.)

         10.17   Settlement Agreement dated July 13, 1986 between Amoco
                 Production Company, Douglas Energy Company, Inc.  and Global
                 Natural Resources Corporation.  (Incorporated by reference to
                 Exhibit 10.25 to the 1986 10-K.)

         10.18   Farm Out Contract dated July 1, 1986 between Amoco Production
                 Company, Douglas Energy Company, Inc. and Global Natural
                 Resources Corporation.  (Incorporated herein by reference to
                 Exhibit 10.26 to the 1986 10-K.)

         10.19   Joint Exploration and Development Agreement dated November 5,
                 1986 between Barnes Hugoton Corporation and Global Natural
                 Resources Corporation.  (Incorporated herein by reference to
                 Exhibit 10.27 to the 1986 10-K.)

         10.20   Global/Smith Participation Agreement (with exhibit).
                 (Incorporated herein by reference to Exhibit 2 to the
                 September 30, 1987 Form 10-Q.)

         10.21   First Amendment to Claims Purchase Agreement.  (Incorporated
                 herein by reference to Exhibit 3 to the September 30, 1987
                 Form 10-Q.)

         10.22   San Pedro Ranch Venture Agreement (with exhibits) dated July
                 1, 1984 between Scicomp Inc., Galaxy Oil Company and SPR
                 Energy Corporation. (Incorporated herein by reference to
                 Exhibits to the December 31, 1987 Form 10-K.)

         10.23   San Pedro Ranch Agreement (with exhibits) dated April 1, 1988
                 between Global Natural Resources Corporation of Nevada and
                 Global Nevada-Galaxy I, Ltd. (Incorporated herein by reference
                 to Exhibits to the December 31, 1987 Form 10-K.)

         10.24   Trust Agreement (with exhibits) dated March 31, 1988 between
                 Galaxy Oil Company, Global Natural Resources Corporation of
                 Nevada and MTrust Corp., N.A. (Incorporated herein by
                 reference to Exhibits to the December 31, 1987 Form 10-K.)

         10.25   Agreement of Limited Partnership (with exhibits) dated April
                 1, 1988 between Global Nevada-Galaxy I, Ltd. and the Partners.
                 (Incorporated herein by reference to Exhibits to the December
                 31, 1987 Form 10-K.)

         10.27   Settlement Agreement between Global Natural Resources
                 Corporation of Nevada, Global Nevada-Galaxy, Inc., Global
                 Nevada-Galaxy I, Ltd., SPR Energy Corporation and Valero
                 Transmission, L.P. (Incorporated herein by reference to
                 Exhibit 3 to the June 30, 1989 Form 10-Q.)

         10.28   Indemnification Agreement and Agreement to Keep Registration
                 Statement Effective dated July 19, 1989 between Noel Group,
                 Inc. and Global Natural Resources Inc. (Incorporated herein by
                 reference to Exhibit 4.6 to Registration Statement No.
                 33-31536.)





                                       69
<PAGE>   72
*          10.29     Global Natural Resources Inc. Key Employees Stock Option
                     Plan. (1989) (Incorporated herein by reference to Exhibit
                     4.1 to Registration Statement No. 33-31537)

*          10.30     Form of Stock Option Agreement. (Incorporated herein by
                     reference to Exhibit 4.2 to Registration Statement No.
                     33-31537.)

           10.31     Amendment to Agreement of Limited Partnership of Global
                     Nevada-Galaxy I, Ltd. (Incorporated herein by reference to
                     Exhibit 10.41 to the 1989 Form 10-K.)

           10.32     Concession Purchase Agreement between Global Natural
                     Resources Corporation of Nevada and Chuska Energy Company.
                     (Incorporated herein by reference to Exhibit 10.43 to the
                     1989 Form 10-K.)

           10.33     Stock Exchange Agreement by and between Noel Group, Inc.
                     and Global Natural Resources Inc.  (Incorporated herein by
                     reference to Exhibit 2 to the September 30, 1990 Form
                     10-Q.)

           10.34     USAgas Pipeline Company General Partnership Agreement.
                     (Incorporated herein by reference to Exhibit 1 to the
                     September 30, 1990 Form 10-Q.)

           10.35     San Pedro Ranch Purchase and Sale Agreement.
                     (Incorporated herein by reference to Exhibit 10.51 to the
                     1991 Form 10-K.)

           10.36     Alabama Ferry Field Purchase and Sale Agreement.
                     (Incorporated herein by reference to Exhibit 10.52 to the
                     1991 Form 10-K.)

*          10.37     Global Natural Resources Inc. 1992 Stock Option Plan.
                     (Incorporated herein by reference to Exhibit 10.47 to the
                     June 30, 1992 Form 10-Q.)

*          10.38     Form of Stock Option Agreement. (Incorporated herein by
                     reference to Exhibit 10.48 to the June 30, 1992 Form
                     10-Q.)

           10.39     Assignment of Partnership Interests and Mutual Release
                     Agreement. (Incorporated herein by reference to Exhibit
                     10.50 to the September 30, 1992 Form 10-Q.)

           10.40     Acquisition Agreement dated May 17, 1993 between UMIC Cote
                     D'Ivoire Corporation and G.N.R. (Cote D'Ivoire) Ltd. Ivory
                     Coast Production Sharing Contract - Block CI-11.
                     (Incorporated herein by reference to Exhibit 10.40 to the
                     1994 Form 10-K.)

           10.41     Farmout Agreement dated July 25, 1994 between GNR (Egypt)
                     Ltd.  And Apache Oil Egypt, Inc.  Qarun Concession Egypt.
                     (Incorporated herein by reference to Exhibit 10.41 to the
                     1994 Form 10-K.)

           10.42     Credit Agreement dated May 19, 1995 among Global Natural
                     Resources Corporation of Nevada as Borrower, Global
                     Natural Resources Inc., as Guarantor, NationsBank of
                     Texas, N.A. as agent.  (Incorporated herein by reference
                     to Exhibit 1.1 to the May 19, 1995 Form 8-K.)

           10.43     Loan Agreement between GNR (Cote d'Ivoire) Ltd. and
                     International Finance Corporation dated July 14, 1995.
                     (Incorporated herein by reference to Exhibit 10.43 to the
                     June 30, 1995 Form 10-Q.)

           11.1      Computation of Per Share Earnings

           18        Letter of KPMG Peat Marwick LLP Regarding a Change in
                     Accounting method.  (Incorporated herein by reference to
                     Exhibit 18 to the Company's Form 10-Q for the quarter
                     ended June 30, 1994.)

           21.1      Subsidiaries of Global Natural Resources Inc.





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<PAGE>   73
           23.1      Consent of KPMG Peat Marwick LLP.

           23.2      Consent of Ryder Scott Company Petroleum Engineers

           23.3      Consent of Netherland, Sewell & Associates, Inc.

           24.1      Powers of Attorney of certain directors of the Company.

           27        Financial Data Schedule for the year ended December 31,
                     1995.
---------------
*          Management contract or compensatory plan or arrangement required to
           be filed as an exhibit to this Form 10-K pursuant to Item 14(c) of
           this report.





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