SECURITIES AND EXCHANGE COMMISSION
                          Washington, D.C.  20549
                                               

                              1995 FORM 10-K
   (Mark One)
           [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
            THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
                For the fiscal year ended December 31, 1995
                                    OR
        [  ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
           THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
   For the transition period from                   to            
     
                       Commission file number 1-5471
                                                  
                              -----------------
                            GLOBAL MARINE INC.
          (Exact name of registrant as specified in its charter)
                    Delaware                      95-1849298
         (State or other jurisdiction of         (IRS Employer
          incorporation or organization)     Identification No.)

     777 N. Eldridge Road, Houston, Texas            77079
     (Address of principal executive offices)     (Zip Code)

Registrant's telephone number, including area code: (713)596-5100
    Securities registered pursuant to Section 12(b) of the Act:

                                           Name of each exchange
         Title of each class                on which registered 
   Common Stock, $0.10 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.
YES  X       NO     

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

As of January 31, 1996, the aggregate market value of the
Company's common stock, $0.10 par value, held by non-
affiliates was $1,431,402,387.

Indicate the number of shares outstanding of each of the
registrant's classes of common stock, as of the latest
practicable date:  Common Stock, $0.10 par value, 166,677,083
shares outstanding as of January 31, 1996.

                    DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement in connection with the 1996
Annual Meeting of Stockholders are incorporated into
Part III of this Report.
                                                                  
                                                                  
                      TABLE OF CONTENTS TO FORM 10-K

                                                                       Page
                                                                       ----
Part I

1. and 2. Business and Properties                                         3
            Contract Drilling                                             3
            Drilling Management Services                                  7
            Oil and Gas Operations                                        8
            Competition and Industry Conditions                          10
            Operational Risks and Insurance                              11
            Foreign Operations                                           13
            Governmental Regulations and Environmental Matters           13
            Employees                                                    14
            Executive Officers of the Registrant                         15

3.        Legal Proceedings                                              15

4.        Submission of Matters to a Vote of Security Holders            15

Part II

5.        Market for Registrant's Common Equity and             
            Related Stockholder Matters                                  16

6.        Selected Financial Data                                        17

7.        Management's Discussion and Analysis of Financial 
            Condition and Results of Operations                          18

8.        Financial Statements and Supplementary Data                    28

9.        Changes in and Disagreements with Accountants 
            on Accounting and Financial Disclosure                       55

Part III

10.       Directors and Executive Officers of the Registrant             55

11.       Executive Compensation                                         55

12.       Security Ownership of Certain Beneficial Owners and
            Management                                                   55

13.       Certain Relationships and Related Transactions                 55

Part IV

14.       Exhibits, Financial Statement Schedules,
            and Reports on Form 8-K                                      56

Signatures                                                               64

                                  PART I


ITEMS 1. AND 2.  BUSINESS AND PROPERTIES

    Global Marine Inc., a Delaware corporation incorporated in
1964, is a holding company that engages in various businesses
through its operating subsidiaries.  Unless otherwise provided,
the terms "Global Marine" and "Company" refer to Global Marine
Inc. and, unless the context otherwise requires,to the Company's
consolidated subsidiaries.  

    The Company is a major international offshore drilling
contractor with a modern, diversified fleet of 26 mobile offshore
drilling rigs.  The Company also owns a currently inactive,
special-purpose mobile offshore rig designed for arctic
operations.  In addition, the Company provides offshore drilling
management services on a turnkey basis and participates in oil
and gas exploration, development and production activities.
Industry segment information relative to the Company is set forth
in Note 9 of Notes to Consolidated Financial Statements in Item 8
of this Annual Report on Form 10-K.  

Contract Drilling

    Substantially all of the Company's offshore contract drilling
operations are conducted by or through its wholly-owned
subsidiary Global Marine Drilling Company ("GMDC").  GMDC is
headquartered in Houston, Texas, has other principal offices in
Lafayette, Louisiana and Aberdeen, Scotland, and has additional
offices in Dubai, United Arab Emirates; London, England; Luanda,
Angola; New Orleans, Louisiana; Pointe Noire, Congo; Port Gentil,
Gabon; Port Harcourt, Nigeria, and Port of Spain, Trinidad.  

    The Company's fleet of 26 mobile offshore drilling rigs
consists of 23 cantilevered jackup rigs, two semisubmersible rigs
and one self-propelled drillship.  The Company's currently
inactive, special-purpose rig designed for arctic operations is a
concrete island drilling system ("CIDS").  The CIDS was
last under contract in 1990.  All of the Company's active
drilling rigs were placed in service in 1979 or later, and, as of
February 28, 1996, the average age of the rigs in the fleet was
approximately 13.7 years.  Twenty-two of the Company's rigs are
subject to mortgages granted to collateralize the Company's 12-
3/4% Senior Secured Notes due 1999 (the "Senior Secured Notes").

    Since 1989, the Company has undertaken in excess of $100
million in capital expenditures for improvements to the fleet,
including approximately $28 million for the purchase and
installation of "top drive" drilling systems on 22 rigs.  Top
drives are now installed on 24 of the  26 rigs in the fleet.  Top
drive drilling systems permit drilling with extended stands of
drill pipe and enable operators to rotate the drill pipe when
exiting the well bore, thereby increasing both the speed and
safety of drilling operations and reducing the risk of the drill
pipe becoming stuck in the well bore.

    The Company's fleet is deployed in the major offshore oil and
gas operating areas worldwide.  The principal areas of the
Company's operations currently include the Gulf of Mexico, the
North Sea, and offshore West Africa.  

    In June 1995 the Company completed the sale of a rig, the
Glomar Main Pass III, to a customer that had been bareboat
chartering the rig from the Company.   The Company received net
proceeds of $22.4 million in cash and recognized a gain of $14.7
million.

    In 1995 the Company completed the purchase of the CIDS, which
was previously chartered by the Company under a long-term lease. 
(See Note 4 of Notes to Consolidated Financial Statements in Item
8 of this Annual Report on Form 10-K.)

    As part of upgrading and expanding its rig fleet and other
assets, the Company considers and pursues the acquisition of
suitable additional rigs and other assets on an ongoing basis. 
If the Company decides to undertake an acquisition, the issuance
of additional shares of stock or additional debt could be
required.   The Company may also consider the disposition of rigs
and other assets if and when a disposition can be effected on
favorable terms.  Disposition proceeds, to the extent available,
could also be used as a source of acquisition financing.

    The following table lists the Company's drilling rigs in the
fleet as of February 15, 1996, indicating the year each rig was
placed in service, as well as its maximum water and drilling
depth capabilities, current location, customer, and estimated
contract expiration date.

<TABLE>
<CAPTION>
                                                                          DRILLING FLEET
                                                                   Status as of February 15, 1996

                                          YEAR
                                         PLACED      MAXIMUM         DRILLING 
                                           IN      WATER DEPTH         DEPTH                         CURRENT           CONTRACT
                                         SERVICE  CAPABILITY (1)    CAPABILITY     LOCATION          CUSTOMER          TERM  (2)
                                         -------  --------------    ----------     --------          ---------         ---------
    Cantilevered Jackup
    <S>                                    <C>        <C>           <C>         <C>               <C>                 <C>
    Glomar High Island I                   1979       250 ft.       20,000 ft.  Gulf of Mexico    Vastar Resources    expires 3/96
    Glomar High Island II                  1979       270 ft.       20,000 ft.  Gulf of Mexico    Unocal              expires 4/96
    Glomar High Island III                 1980       250 ft.       20,000 ft.  West Africa       Texaco              expires 3/98
    Glomar High Island IV                  1980       250 ft.       20,000 ft.  Gulf of Mexico    Unocal              expires 4/96
    Glomar High Island V                   1981       270 ft.       20,000 ft.  West Africa       Cabinda Gulf        expires 8/96
    Glomar High Island VII                 1982       250 ft.       20,000 ft.  West Africa       Kelt                expires 6/96
    Glomar High Island VIII                1982       250 ft.       20,000 ft.  Gulf of Mexico    Vastar Resources    expires 3/96
    Glomar High Island IX                  1983       250 ft.       20,000 ft.  West Africa       Texaco              expires 4/96
    Glomar Adriatic I                      1981       300 ft.       25,000 ft.  West Africa       Elf Gabon           expires 4/96
    Glomar Adriatic II                     1981       350 ft.       25,000 ft.  Gulf of Mexico    Shell               expires 3/96
    Glomar Adriatic III                    1982       300 ft.       25,000 ft.  Gulf of Mexico    Forest Oil          expires 5/96
    Glomar Adriatic IV                     1983       350 ft.       25,000 ft.  Trinidad          Amoco               expires 5/96
    Transocean No. 5                       1979       300 ft.       20,000 ft.  Abu Dhabi         Total               expires 4/96
    Glomar Adriatic VI                     1981       350 ft.       20,000 ft.  Gulf of Mexico    Shell               expires 3/96
    Glomar Adriatic VII                    1983       325 ft.       20,000 ft.  Gulf of Mexico    Amoco               expires 5/96
    Glomar Adriatic VIII                   1983       300 ft.       25,000 ft.  West Africa       Mobil               expires 2/97
    Glomar Adriatic IX                     1981       300 ft.       20,000 ft.  West Africa       Ashland Oil         expires 5/96
    Glomar Adriatic X                      1982       300 ft.       20,000 ft.  West Africa       Total               expires 4/96
    Glomar Adriatic XI                     1983       225 ft.       25,000 ft.  North Sea         Chevron             expires 8/96
    Glomar Main Pass I                     1982       300 ft.       25,000 ft.  Gulf of Mexico    Conoco              expires 3/96
    Glomar Main Pass IV                    1982       300 ft.       25,000 ft.  Gulf of Mexico    Mobil               expires 3/96
    Glomar Labrador I                      1983       300 ft.       25,000 ft.  North Sea         Mobil               expires 4/96
    Glomar Baltic I                        1983       375 ft.       25,000 ft.  Gulf of Mexico    Anadarko            expires 5/96

    Semisubmersible
    Glomar Arctic I                        1983       1,800 ft.     25,000 ft.  North Sea         Amerada Hess        expires 12/96
    Glomar Arctic III                      1984       1,800 ft.     25,000 ft.  North Sea         Conoco              expires 6/96

    Drillship
    Glomar Robert F. Bauer                 1983       2,750 ft.     25,000 ft.  Yemen             British Gas         expires 4/97
    
    Concrete Island Drilling System (3)
    Glomar Beaufort Sea I                  1984       55 ft.        25,000 ft.  Alaska             -                  inactive
                                    
-----------------------
(1) During 1995, the Company revised the water-depth ratings of its jackups
    to conform with standard industry practice, which is to reflect maximum
    limits during most weather seasons.  In prior years, the Company's water-
    depth ratings reflected maximum limits during the most severe weather
    season.
(2) Expiration dates include firm commitments for extensions of current
    contracts and for new contracts which have not yet commenced.  Expiration
    dates relate to both term and well-to-well contracts and, with respect to
    well-to-well contracts, are estimates only.
(3) The Company's inactive Concrete Island Drilling System is excluded from
    the Company's rig utilization rates discussed below.
</TABLE>
         Rig Utilization.  For the year ended December 31, 1995, the Company's
average utilization rate for active rigs in the fleet was 99 percent compared to
94 percent for 1994.  The average rig utilization rate for a period is equal to
the ratio of days in the period during which the rigs were under contract to
the total days in the period during which the rigs were available to work,
but it excludes the CIDS, which is not included in the active fleet.  As of
February 15, 1996, the Company's utilization rate for its active fleet was
100 percent.  The Company expects contracts on 18 of the Company's 26 rigs
under contract as of February 15, 1996, to expire at varying times on or prior
to May 31, 1996.  No assurance can be made that the Company will obtain drilling
contracts for its rigs upon the completion of current contracts; however,
short-term contracts have been typical in the industry for the past decade,
and the Company considers its upcoming contract expirations typical of
prevailing market conditions and consistent with the normal course of business.

         As of December 31, 1995, all twelve of the Company's rigs in the Gulf
of Mexico were employed.  As of that date, the industry utilization rate in the
Gulf of Mexico was 80 percent compared with a rate of 74 percent as of December
31, 1994.  Industry utilization rates were derived from data published in the
Offshore Rig Locator.  Revenues attributable to the Gulf of Mexico accounted for
44 percent, 53 percent and 38 percent of the Company's contract drilling
revenues in 1995, 1994, and 1993, respectively.

         As of December 31, 1995, all four of the Company's rigs in the North
Sea were employed.  As of that date, the industry utilization rate in the North
Sea was 93 percent compared with a rate of 80 percent as of December 31, 1994.
Revenues from this market accounted for 22 percent, 14 percent and 28 percent of
the Company's contract drilling revenues in 1995, 1994, and 1993, respectively.

         As of December 31, 1995, all seven of the Company's rigs offshore West
Africa were employed.  As of that date, the industry utilization rate offshore
West Africa was 81 percent compared with a rate of 86 percent as of December 31,
1994.  Revenues from this market accounted for 21 percent, 15 percent and 16
percent of the Company's contract drilling revenues in 1995, 1994, and 1993,
respectively.

         The following table sets forth the size and average utilization rate of
the Company's fleet.
<TABLE>
                                     1995    1994   1993   1992  1991
                                     ----    ----   ----   ----  ----
<S>                                   <C>     <C>    <C>    <C>   <C>
Rigs in service at year-end           26      25     24     24    26
Average rig utilization               99%     94%    91%    81%   89%
</TABLE>
         As of December 31, 1995, none of the Company's rigs was
subject to a firm commitment beyond 1997.  The following tables show, for
each of the Company's three principal groups of drilling rigs and each major
geographic area in which the Company operates, the number of contract-months
available, the number of contract-months under firm commitments, and the
percentage of available months committed for each of 1996 and 1997, determined
on the basis of executed contracts as of December 31, 1995, excluding
customer option periods.  The number of rigs in each category is indicated in
parenthesis.

<TABLE>
<CAPTION>
                                      1996                                            1997
                   ----------------------------------------        ----------------------------------------
                   Rig Contract   Rig Contract   Percentage        Rig Contract   Rig Contract   Percentage
                      Months          Months     Committed/           Months          Months     Committed/
                     Available      Committed    Available           Available      Committed    Available 
                   ------------   ------------   ----------        ------------   ------------   ----------
  
<S>                     <C>             <C>        <C>                    <C>           <C>        <C>
Jackups (23)            276             77         28%                    276            2           1%
Semisubmersibles (2)     24             13         54%                     24            -           -
Drillships (1)           12             12        100%                     12            4          33%
                        ---            ---                                ---           --
    Total               312            102         33%                    312            6           2%
                        ===            ===                                ===           ==
</TABLE>

<TABLE>
<CAPTION>
                                      1996                                            1997
                   ----------------------------------------        ---------------------------------------
                   Rig Contract   Rig Contract   Percentage        Rig Contract  Rig Contract   Percentage
                      Months         Months      Committed/           Months        Months      Committed/
                     Available     Committed     Available           Available    Committed     Available
                   ------------   ------------   ----------        ------------  ------------   ----------
<S>                     <C>             <C>        <C>                    <C>          <C>        <C> 
Gulf of Mexico (12)     144             26         18%                    144            -          -
West Africa (7)          84             30         36%                     84            2          2%
North Sea (4)            48             21         44%                     48            -          -
Other (3)                36             25         69%                     36            4         11%
                        ---            ---                                ---           ---
    Total               312            102         33%                    312            6          2%
                        ===            ===                                ===           ===
</TABLE>
         The numbers of rigs in the preceding table reflect their locations
as of December 31, 1995.

         As of December 31, 1995, the Company's contract drilling backlog was
approximately $130 million, $112 million of which is expected to be realized in
1996.  The contract drilling backlog at December 31, 1994, was $70 million.

         Drilling Contracts and Major Customers.  Each of the Company's
drilling rigs is employed under an individual contract which extends over a
period of time covering either a stated term or the time required to drill a
well or number of wells.  While the final contract for employment of a rig is
the result of negotiations between the Company and the customer, most
contracts are awarded based upon competitive bidding.  The rates specified in
drilling contracts are generally on a per day basis, payable in U.S. dollars,
and vary depending upon the equipment and services supplied, the areas involved,
the duration of the work, competitive conditions and other variables.  The
contracts provide for a basic dayrate during drilling operations, with lower
rates or no payment for periods of equipment breakdown, adverse weather, or
other conditions which may be beyond the control of the Company.  When a rig
mobilizes to or demobilizes from an operating area, a contract may provide
for different dayrates, specified fixed amounts, or for no payment during the
mobilization period.  A contract may be terminated by the customer if the rig is
destroyed or lost, if drilling operations are suspended for a specified period
of time due to a breakdown of major equipment or, in some cases, if other
events occur that are beyond the control of either party.  

         The Company's offshore contract drilling business is subject to the
usual risks associated with having a limited number of customers for its
services.   In 1995, Shell Oil Company provided $51.2 million, or 11 percent, of
consolidated revenues.  In 1994, no single customer provided more than 10
percent of consolidated revenues.  In 1993, Arco provided $29.2 million, or
11 percent, of consolidated revenues.

Drilling Management Services  

         The Company provides drilling management services on a
turnkey basis through its wholly-owned subsidiaries, Applied Drilling Technology
Inc. ("ADTI") and Global Marine Integrated Services - International Inc.
("GMIS-I"), and through Global Marine Integrated Services - Europe ("GMIS-E"),
which is a division of GMDC.  ADTI operates primarily in the U.S. Gulf of
Mexico, and GMIS-I and GMIS-E operate in areas other than the U.S. Gulf of
Mexico.  For a guaranteed price, each will assume responsibility for the design
and execution of specific offshore drilling programs and deliver a logged or
loggable hole to an agreed depth. Compensation is contingent upon satisfactory
completion of the drilling program.  

         Since commencing operations in 1980, ADTI has completed 233 turnkey
wells as of December 31, 1995, including 57 in 1995, 50 in 1994, and 18 in 1993.
GMIS-E completed six wells in 1995 and two wells in 1994, its first year of
operations.  GMIS-I completed four wells in 1995, its first year of operations.

         As of December 31, 1995, the Company's drilling management services
backlog was approximately $25 million, all of which is expected to be realized
in 1996.  As of December 31, 1994, the drilling management services backlog was
approximately $57 million.

         The Company, as well as several of its offshore drilling competitors
and other oil service companies, has also started offering services as a general
contractor under arrangements variously described as "partnering," "full service
contracting," and "integrated drilling services" arrangements, among others.
When the Company acts as a general contractor, it provides planning, engineering
and management services beyond the scope of its traditional contract drilling
business, and thereby assumes greater liability.  In 1994 and 1995, 
respectively, GMIS-E and GMIS-I began providing such planning, engineering
and management services, as well as turnkey drilling services, in areas other
than the U.S. Gulf of Mexico.

Oil and Gas Operations

         Oil and gas exploration, development and production activities are
conducted through Challenger Minerals Inc. ("CMI"), which is a wholly-owned
subsidiary of the Company.  Such activities primarily include participation in
the development and operation of properties for oil and gas production.  In
addition, the Company incurs through ADTI and other subsidiaries certain
limited exploration and leasehold acquisition costs in connection with its
turnkey drilling operations.  Substantially all of the Company's oil and gas
activities are conducted in the United States offshore Louisiana and Texas and
onshore in Oklahoma and Texas.  

         Sales Prices and Production Costs.  The following table summarizes the
Company's oil and gas sales prices and production costs:
<TABLE>
<CAPTION>
     
                                                            1995        1994        1993 
                                                           ------      ------      ------
Average sales prices:
   <S>                                                     <C>         <C>         <C>
   Gas (per MCF)                                           $ 1.57      $ 1.86      $ 1.98
   Oil (per barrel)                                        $16.89      $15.79      $16.89
Average production cost:
   Oil and natural gas (per BTU equivalent MCF of gas)     $  .34      $  .46      $  .37
</TABLE>

     Productive Wells.  The following table summarizes the Company's gross and
net wells as of December 31, 1995, including producing wells and those that are
shut-in but capable of producing:
<TABLE>
                                  Gross Wells         Net Wells     
                                  ------------      --------------
                                   Oil    Gas        Oil      Gas 
                                  -----  -----      -----    -----
Offshore
   <S>                             <C>    <C>       <C>      <C>
   Louisiana                       11     11        1.48     1.73
   Texas                            -     17           -     2.79
                                  ---    ---        ----     ----
     Total offshore                11     28        1.48     4.52
                                  ---    ---        ----     ----

Onshore
   Oklahoma                         2      -         .14        -
   Texas                            -      1           -      .11
                                  ---    ---        ----     ----
     Total onshore                  2      1         .14      .11
                                  ---    ---        ----     ----

                                   13     29        1.62     4.63
                                  ===    ===        ====     ====
</TABLE>
     For purposes of the tables included in this report, a gross
well or a gross acre is a well or acre in which a working interest is owned by
the Company.  A net well or net acre is used to show the cumulative total of the
Company's fractional working interests in one or more wells or acres.

     Developed and Undeveloped Acreage.   The following table summarizes the
Company's developed and undeveloped acreage as of December 31, 1995:
<TABLE>
                         Developed Acreage       Undeveloped Acreage   
                      -----------------------   ----------------------
                      Gross Acres   Net Acres   Gross Acres  Net Acres
                      -----------   ---------   -----------  ---------

Offshore
   <S>                   <C>          <C>          <C>         <C>
   Louisiana             35,134       6,114        26,988      11,579
   Texas                 10,280       1,735         7,040       1,568
                        -------      ------       -------     -------
     Total offshore      45,414       7,849        34,028      13,147

Onshore
   Louisiana                205           1             -           -
   Oklahoma                  64          18             -           -
   Texas                    325          74             -           -
                        -------      ------       -------     -------
     Total onshore          594          93             -           -
                        -------      ------       -------     -------

                         46,008       7,942        34,028      13,147
                        =======      ======       =======     =======
</TABLE>

     Drilling Activities.  The following table shows the Company's gross and net
exploratory and development wells drilled during the years indicated:
<TABLE>
                                  1995              1994              1993
                             ------------      -------------     -------------
                             Gross    Net      Gross     Net     Gross     Net
                             -----    ---      -----     ---     -----     ---
Exploratory
   <S>                         <C>    <C>        <C>   <C>         <C>   <C>
   Gas                         1      .10         4     .68        1       .20
   Dry                         3      .50         4     .95        4       .88
Development
   Gas                         1      .17         2     .34        -         -
Total
   Gas*                        2      .27         6    1.02        1       .20
   Dry                         3      .50         4     .95        4       .88
                             ---     ----       ---   -----      ---     -----

                               5      .77        10    1.97        5      1.08
                             ===     ====       ===   =====      ===     =====
______________
* Includes wells that are shut-in but capable of producing.
</TABLE>
     At December 31, 1995, the Company was participating in the drilling of one
well in which the Company had a ten percent working interest.

Competition and Industry Conditions

     Offshore contract drilling is a highly competitive and cyclical business.
It is characterized by high capital costs, long lead times for construction of
new rigs and numerous industry participants, none of which has a significant
market share but several of which have substantially greater financial resources
than the Company.  Offshore drilling rigs have few alternative uses and, because
of their nature and the environment in which they work, have relatively high
maintenance costs whether employed or unemployed.  Contracts are awarded on a
competitive bid basis and, while an operator selecting a rig may consider, among
other things, quality of service and equipment, price competition is the primary
factor in determining which qualified contractor is awarded a job.  In addition,
the Company's offshore drilling business is subject to the usual risks
associated with having a limited number of customers for its services.

     From 1982 through 1994, the offshore contract drilling market was
adversely affected by a supply of offshore rigs that significantly exceeded rig
demand as well as by a reduced level of demand generally for such equipment.
The reduced demand principally was the result of low oil and gas prices,
reductions in the exploration and development expenditures of the Company's
customers, and prolonged uncertainty and volatility in oil and gas prices.
Although oil prices have not increased to any significant extent, drilling
markets have strengthened considerably over the past twelve months.  The number
of rigs under contract has increased, the number of available rigs has
declined, and dayrates for newly contracted rigs have risen, particularly for
semisubmersibles in the North Sea.  Despite the overall improvements, the
Company estimates that market dayrates on average are at only one-half of the
levels required to justify significant new rig construction.  The Company cannot
predict the future level of demand or dayrates for the Company's contract
drilling services or the timing or extent of any further improvement in the
industry.  Worldwide military, political and economic events, including
initiatives by the Organization of Petroleum Exporting Countries ("OPEC"),
are likely to continue to cause oil and gas price volatility.  Factors which
influence demand for the Company's services include the ability of OPEC to
set and maintain production levels and prices, the level of production by
non-OPEC countries, worldwide demand for oil and gas, and contract and other
terms sought by various governments to explore and develop oil, gas and other
hydrocarbons within their offshore waters.  

     ADTI, GMIS-I and GMIS-E compete with other participants in the drilling
management services industry, some of which have greater resources.  In
addition, the Company's drilling management services business is subject to
the usual risks associated with having a limited number of customers for
its services.

     Cash flow from the Company's drilling management services may be limited
by certain factors, in particular, the ability of the Company to obtain and
successfully perform turnkey drilling contracts based on competitive bids, which
in turn is largely dependent on the number of such contracts available for
bid.  Accordingly, results of the Company's drilling management service
operations may vary widely from year to year.  Furthermore, turnkey operations
may be constrained by the availability of rigs as demand for rigs increases.
In the U.S. Gulf of Mexico, ADTI relied on third-party rigs for approximately
97 percent of its rig-time in 1995, and had an average of five rigs under
short-term contracts during the year.  To minimize the risk of not having a
rig available for a turnkey job, ADTI considers and may undertake to commit to
several rigs under term contracts of from three to twelve months.  In the North
Sea and West Africa, the market for turnkey drilling is not well established,
and growth in these markets may be constrained by rig availability in 1996.

     With respect to the Company's oil and gas operations, CMI experiences
competition from other oil and gas companies in all phases of its operations.
Many competing companies have substantially greater financial and other
resources.  The Company's oil and gas business has been adversely affected
by the same oil and gas market conditions that have affected the Company's
contract drilling operations over the past several years, including low prices,
prolonged uncertainty and price volatility.  A worldwide surplus of oil has
affected and continues to affect the prices received for the Company's oil
production.

     The Company's oil and gas production operations and economics are also
affected by governmental regulation, the use and allocation of oil and 
natural gas, the extent of domestic production, and the levels of imports and of
prices of competitive fuels.  They are also affected by fluctuation in demand
in the Company's market areas due to excess supplies of oil, as well as
seasonal demand factors, tax and other laws relating to the petroleum industry
and changes in such laws, and by constantly changing administrative regulations.

Operational Risks and Insurance

     The Company's operations are subject to the usual hazards incident to the
drilling of oil and gas wells, such as blowouts, explosions, oil spills and
fires, which can severely damage or destroy equipment or cause environmental
damage.  The Company's activities are also subject to perils peculiar to marine
operations, such as collision, grounding, and damage or loss from severe
weather.  These hazards can cause personal injury and loss of life, severe
damage to and destruction of property and equipment, pollution or environmental
damage, and suspension of operations.

     The Company maintains insurance coverage against certain general and marine
public liability, including liability for personal injury, in the amount of $200
million, subject to a self-insured retention of no more than $250,000 per
occurrence.  In addition, the Company's rigs and related equipment are
separately insured under hull and machinery policies against certain marine and
other perils, subject to a self-insured retention generally of no more than
$300,000 per occurrence.  The Company's current practice is to insure each
active rig for its market value.  Although each rig is insured for at least its
financial book value, the Company's insurance does not cover all costs that
would be required to replace each rig.  In addition to hull and machinery
coverage, the Company purchases rig business interruption insurance with respect
to its operating rigs.  Business interruption coverage applies only to business
interruptions as a result of a loss insured under hull and machinery policies.
The deductible for business interruption claims is 30 days.  As a result of
historical claims involving damage to the "spud cans" (i.e., the bases of the
legs of jackup rigs) of certain of the Company's jackup drilling units, insurers
have excluded business interruption coverage with respect to spud can damage
incurred after May 3, 1992.  Although the Company currently purchases rig
business interruption insurance with respect to all of its operating rigs,
the decision to insure a rig against interruption risks is dependent on a number
of factors, including dayrate and utilization levels, and no assurance can be
made that the Company will continue to insure any or all of its operating rigs
against such risks.  All of the Company's rigs which are operated
internationally are presently insured against loss due to war, including
terrorism.  

     The Company is permitted under the terms of the rig mortgages securing
the Senior Secured Notes to change the limits on its general and marine public
liability insurance to $150 million, and to be subject, with respect to such
liability insurance and its marine hull and machinery insurance, to self-insured
retention amounts of up to $1 million per occurrence.  In addition, the
indenture governing the Senior Secured Notes contains certain restrictions
regarding the use of insurance proceeds received by the Company due to the loss
of any Company-owned rig other than the Glomar Baltic I, the Glomar Adriatic
IX, the Glomar Adriatic X, the Glomar Adriatic XI and the Glomar Beaufort
Sea I.

     Although the general and marine public liability policies cover
liability for pollution under most circumstances, they do not cover liability
for bringing a well under control following a blowout.  In the case of turnkey
drilling operations, the Company maintains insurance covering the cost of
controlling the well, including any environmental damage resulting therefrom,
the cost of cleanup, and the cost of redrilling ("well control liabilities") in
an amount not less than $20 million per occurrence subject to a self-insured
retention of $200,000 per occurrence.  Under turnkey drilling contracts, the
Company generally assumes the risk of the cost of well control, but on
occasion the Company receives indemnification from the customer for such risk in
excess of the $20 million insurance coverage.   In many instances, however, the
Company is not indemnified by its customers for well control liabilities. 
Furthermore, the Company is not insured against certain drilling risks, such
as stuck drill stem and loss of in-hole equipment not arising from an insured
peril, that could result in delays or nonperformance of a turnkey drilling
contract.  In connection with the Company's offshore contract drilling
operations, the Company is generally indemnified for any cost of well control by
its customers.  In any event, however, the Company maintains insurance against
such liabilities in the amount of $50 million per occurrence subject to a
self-insured retention of $200,000 per occurrence.

     The occurrence of a significant event, including pollution or environmental
damage, not fully insured or indemnified against or the failure of a customer to
meet its indemnification obligations, could materially and adversely affect the
Company's operations and financial condition.  Moreover, no assurance can be
made that the Company will be able to maintain adequate insurance in the future
at rates it considers reasonable.  See "-- Governmental Regulations and
Environmental Matters."

Foreign Operations

    A significant portion of the Company's revenues is attributable to
drilling operations in foreign countries.  Such activities accounted for 41
percent, 29 percent and 44 percent of the Company's total revenues in 1995, 1994
and 1993, respectively. Risks associated with the Company's operations in
foreign areas include risks of war and civil disturbances or other risks that
may limit or disrupt markets, expropriation, nationalization, renegotiation or
nullification of existing contracts, foreign exchange restrictions and currency
fluctuations, foreign taxation, changing political conditions and foreign and
domestic monetary policies.  To date, the Company has experienced no material
loss as a result of any of these factors.  Additionally, the ability of the
Company to compete in the international drilling market may be adversely
affected by foreign governmental regulations favoring or requiring the awarding
of drilling contracts to local contractors, or by regulations requiring foreign
contractors to employ citizens of, or purchase supplies from, a particular
jurisdiction.  Furthermore, foreign governmental regulations, which may in
the future become applicable to the industry served by the Company, could reduce
demand for the Company's services, or such regulations could directly affect the
Company's ability to compete for customers.

Governmental Regulations and Environmental Matters

     The Company's business is affected by changes in public policy and by
federal, state, foreign and local laws and regulations relating to the energy
industry.  The adoption of laws and regulations curtailing exploration and
development drilling for oil and gas for economic, environmental and other
policy reasons adversely affects the Company's operations by limiting
available drilling and other opportunities in the energy service industry.

      The Company's operations are subject to numerous federal, state and
local laws and regulations controlling the discharge of materials into the
environment or otherwise relating to the protection of the environment.  For
example, the Company, as an operator of mobile offshore drilling units in
navigable U.S. waters and certain offshore areas, including the Outer
Continental Shelf, is liable for damages and for the cost of removing oil spills
for which it may be held responsible, subject to certain limitations.  The
Company's operations may involve the use or handling of materials that may be
classified as environmentally hazardous substances.  Laws and regulations
protecting the environment have generally become more stringent, and may in
certain circumstances impose "strict liability," rendering a person liable
for environmental damage without regard to negligence or fault.  The Company
does not believe that environmental regulations have had any material adverse
effect on its capital expenditures, results of operations or competitive
position to date, and does not presently anticipate that any material 
expenditures will be required to enable it to comply with existing laws and 
regulations.  It is possible, however, that modification of existing regulations
or the adoption of new regulations in the future, particularly with respect to
environmental and safety standards, could have such a material adverse effect
on the Company's operations.

     The U.S. Oil Pollution Act of 1990 ("OPA '90") and similar legislation
enacted in Texas, Louisiana and other coastal states address oil spill
prevention and control and significantly expand liability exposure across all
spectrums of the oil and gas industry.  The Company is of the opinion that it
maintains sufficient insurance coverage to respond to the added exposures.

     OPA '90 also mandated increases in the amounts of financial responsibility
that must be certified with respect to mobile offshore drilling units and
offshore facilities (e.g. oil and gas production platforms, among others)
located in U.S. waters.  Operators of mobile offshore drilling units, together
with operators of vessels, must provide evidence of financial responsibility
based on a tonnage formula, which, in the Company's case, would not exceed $15
million for its largest rig located in U.S. waters.  The Company has complied
with the requirement by providing evidence of adequate U.S.-based net worth.
The Company's inability to comply with the rule in the future, however, could
have a material adverse effect on its operations and financial condition.
During 1995, 45 percent of the Company's contract drilling revenues were
attributable to operations in U.S. waters, and, as of February 15, 1996, 11 of
the Company's 26 active rigs were located in U.S. waters.

     Under OPA '90, lessees, permittees, or holders of a right of use for
offshore facilities will be required to certify evidence of financial
responsibility in the amount of $150 million.  The Department of the Interior
("DOI") is responsible for promulgating regulations implementing the new
financial responsibility requirements with respect to offshore facilities. 
The Minerals Management Service of the DOI issued an Advance Notice of Proposed
Rulemaking in 1993 which contemplated regulations for offshore facilities
similar to the Coast Guard regulations for vessels.  The DOI solicited comments
from the offshore oil industry with respect to the proposed regulations, which
will also be subject to review and comment before adoption.  The DOI
regulations, with the regulations promulgated by the Coast Guard, could
adversely affect CMI as well as GMDC and ADTI.  CMI presently operates an
offshore production platform, and ADTI's business and GMDC's operations in
the Gulf of Mexico are largely dependent on oil and gas companies' drilling
activities, which, in turn, ultimately depend on their ability to meet the OPA
'90 financial responsibility requirements.  The DOI regulations, however, are
not expected to be promulgated until Congress has had an opportunity to
reevaluate the $150 million financial responsibility requirements.  The Company
cannot predict the exact nature or effect of any regulations promulgated
under OPA '90 or any amendments thereto.

Employees

     The Company had approximately 2,100 employees at December 31, 1995.  The
Company requires highly skilled personnel to operate its drilling rigs.  In
recognition of this, the Company conducts extensive personnel training and
safety programs.

Executive Officers of the Registrant

     The name, age as of December 31, 1995, and office or offices currently
held by each of the executive officers of the Company are as follows:
<TABLE>
    Name                    Age   Office or Offices
    ----                    ---   -----------------

    <S>                      <C>  <C>
    David A. Herasimchuk     53   Vice President, Market Development
    Thomas R. Johnson        47   Vice President and Corporate Controller
    Gary L. Kott             53   President and Chief Operating Officer of
                                  Global Marine Drilling Co.
    C. Russell Luigs         62   Chairman of the Board, President and Chief
                                  Executive Officer
    Jon A. Marshall          44   Group Vice President of the Company, and
                                  President of Challenger Minerals Inc.
    Jerry C. Martin          63   Senior Vice President and Chief Financial
                                  Officer
    James L. McCulloch       43   Vice President and General Counsel
    John G. Ryan             43   Chairman and Chief Executive Officer of
                                  Global Marine Drilling Co., and Corporate
                                  Secretary of the Company
    Robert E. Sleet, Jr.     49   Vice President and Treasurer
</TABLE>
     Officers serve for a one-year term or until their successors
are elected and qualified to serve.  Each executive officer's principal
occupation has been as an executive officer of the Company for more
than the past five years, with the exception of Messrs. Marshall and
McCulloch.  Mr. Marshall has served as the Company's Group Vice President since
February 1995, prior to which he had been President of Applied Drilling
Technology Inc. and Challenger Minerals Inc. since April 1992.  From
1990 to April 1992, he was Applied Drilling Technology's Vice President of
Operations, prior to which he held various operating positions with Applied
Drilling Technology Inc. and with Global Marine Drilling Company.  Mr. McCulloch
has served in his present position since May 1993 and has had general
supervision of the Company's legal affairs since February 1993, prior to which
he was the Company's Vice President, Litigation and Risk Management.

ITEM 3.  LEGAL PROCEEDINGS

     Not applicable.

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 1995.

                                  PART II

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

     The Company's Common Stock, $0.10 par value per share, is listed on the
New York Stock Exchange under the symbol "GLM."  At January 31, 1996, there were
8,015 stockholders of record of the Common Stock.  The high and low sales prices
of the Common Stock as reported on the New York Stock Exchange Composite
Transactions Tape for each full quarterly period within the past two years
appear under "Consolidated Selected Quarterly Financial Data," which follows the
notes to the consolidated financial statements.

     The Company has not declared any dividends on its common stock since 1985.
Subject to the preferential dividend rights of holders of the Company's 
preferred stock, if any, the holders of the Common Stock will be entitled to
receive when, as and if declared by the Board of Directors out of funds legally
available therefor, all other dividends payable in cash, in property, or in
shares of Common Stock.  The indenture governing the Company's Senior Secured
Notes contains certain restrictions with respect to the payment of dividends on
the Common Stock (other than stock dividends).  (See Note 6 of Notes to
Consolidated Financial Statements.)  It is not expected that dividends will be
declared or paid on the Common Stock in the foreseeable future.

<TABLE>
<CAPTION>
ITEM 6.  SELECTED FINANCIAL DATA

                                                   GLOBAL MARINE INC. AND SUBSIDIARIES
                                                               FIVE-YEAR REVIEW
                                                 (Dollars in millions, except per share data)
                                                                  
                                                                  
                                                 ------------------------------------------------------
                                                   1995      1994        1993        1992        1991
                                                 ------------------------------------------------------
Financial Performance  
Revenues:
  <S>                                            <C>        <C>         <C>         <C>         <C>
  Contract drilling                              $ 248.9    $ 211.4     $ 200.3     $ 214.1     $ 249.9
  Drilling management services                     209.3      137.8        57.1        26.9        37.2
  Oil and gas                                        9.8        9.8        11.6        19.3        28.1
                                                 -------    -------      ------     -------     -------
     Total revenues                              $ 468.0    $ 359.0     $ 269.0     $ 260.3     $ 315.2
                                                 =======    =======     =======     =======     =======

Operating income:
  Contract drilling                              $  54.6    $  25.6     $   4.5     $  17.3     $  49.2
  Drilling management services (1)                  17.3       10.8         7.6        (2.2)        4.5
  Oil and gas                                        3.4        3.7         5.3         3.2         9.1
  Corporate expenses                               (15.0)     (14.0)      (14.2)      (13.5)      (13.7)
                                                 -------    -------     -------     -------     -------
    Total operating income                          60.3       26.1         3.2         4.8        49.1
                                                 -------    -------     -------     -------     -------

Other income (expense):
  Interest expense                                 (30.2)     (30.2)      (32.1)      (43.6)      (49.9)
  Interest capitalized                               5.6        3.7           -           -           -
  Interest income                                    4.7        3.8         2.7         2.8         3.5
  Gain on sale of offshore drilling rigs            14.7          -           -        10.9           -
  Litigation settlement                                -          -           -        55.0           -
  Other                                                -        2.0           -         0.7         0.8
                                                 -------    -------     -------     -------     -------
     Total other income (expense)                   (5.2)     (20.7)      (29.4)       25.8       (45.6)
                                                 -------    -------     -------     -------     -------

     Income (loss) before income taxes              55.1        5.4       (26.2)       30.6         3.5
Income tax expense                                   3.2        0.6         0.3         3.1         2.5
                                                 -------    -------     -------     -------     -------
  Income (loss) before extraordinary item and
     cumulative effect of accounting changes        51.9        4.8       (26.5)       27.5         1.0
  Extraordinary gain on extinguishment of debt         -          -           -        28.3           -
  Cumulative effect of accounting changes, net         -       (3.5)          -         1.4           -
                                                 -------    -------     -------     -------     -------
     Net income (loss)                           $  51.9    $   1.3     $ (26.5)    $  57.2     $   1.0
                                                 =======    =======     =======     =======     =======

Primary net income (loss) per common share:
  Before extraordinary item and cumulative
     effect of accounting changes                $  0.31    $  0.03     $ (0.17)    $  0.24      $  0.01
  Extraordinary gain on extinguishment of debt         -          -           -        0.24            -
  Cumulative effect of accounting changes, net         -      (0.02)          -        0.01            -
                                                 -------    -------     -------     -------      -------
     Primary net income (loss) per common share  $  0.31    $  0.01     $ (0.17)    $  0.49      $  0.01
                                                 =======    =======     =======     =======      =======

Average common shares outstanding                  165.1      163.8      152.01        16.3        109.2
Dividends declared per common share (2)          $     -    $     -     $     -     $     -      $     -
Capital expenditures                             $  73.5    $  75.9     $   40.6    $  20.9      $  22.7

Financial Position (end of year)  
Working capital                                  $ 116.2    $  93.4     $  107.2    $  30.7      $  88.4
Net properties                                   $ 386.6    $ 353.4     $  314.6    $ 318.0      $ 353.7
Total assets                                     $ 563.0    $ 512.4     $  492.9    $ 479.9      $ 523.7
Long-term debt, including current maturities     $ 225.0    $ 225.0     $  225.0    $ 249.0      $ 391.8
Shareholders' equity                             $ 269.0    $ 212.3     $  205.4    $ 154.5      $  44.6

Operational Data
Average rig utilization (3) (4)                       99%        94%          91%        81%          89%
Fleet average dayrate (5)                        $28,700    $25,600      $25,600    $27,600      $29,300
Number of active rigs (end of year) (4)               26         27           24         24           26
Turnkey wells completed                               67         52           18         10           16
Number of employees (end of year)                  2,100      1,700        1,500      1,500        1,900
                      
-----------------
(1)   Excludes the aggregate net profit earned on turnkey wells drilled on oil
      and gas properties in which the Company has working interests.
(2)   The indenture governing the Senior Secured Notes contains certain
      restrictions with respect to the payment of dividends on the Common
      Stock (other than stock dividends).  See Note 6 of Notes to Consolidated
      Financial Statements.
(3)   The average rig utilization rate for a period is equal to the ratio of
      days in the period during which the rigs were under contract to the total
      days in the period during which the rigs were available to work.
(4)   Excludes the Company's Concrete Island Drilling System, a currently
      inactive, special-purpose mobile offshore rig designed for arctic
      operations. 
(5)   Contract drilling revenues less non-rig related revenues divided by the
      aggregate contract days, adjusted to exclude days under contract at zero
      dayrate.
</TABLE>

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

Operating Results

Summary

     For 1995, operating income increased to $60.3 million from $26.1 million
for 1994.  The improvement in operating results was primarily due to generally
higher contract drilling dayrates and utilization, lower depreciation expense
due to a change in estimated rig service lives, the commencement of operations
in 1995 of three offshore drilling rigs purchased in 1994, and an increase in
the number of turnkey wells completed.  

     For 1994, operating income increased to $26.1 million from $3.2 million for
1993.  The improvement in operating results was due to (i) higher revenues
and lower operating expenses attributable to operating five additional rigs in
the lower-cost Gulf of Mexico market during 1994 compared to 1993, when the
rigs were operating for a portion of the year in weaker, higher-cost foreign
markets, (ii) the full-year effect of three rigs acquired from Transocean
Drilling AS in September 1993, (iii) lower mobilization expense attributable to
moving fewer rigs during 1994, (iv) increased contract drilling dayrates in the
U.S. Gulf of Mexico for 1994 compared to 1993, and (v) an increase in the number
of turnkey drilling contracts completed.  These improvements were partially
offset by lower turnkey profit margins, normal declines in oil and gas
production and lower oil and gas sales prices.

     Data relating to the Company's operations by business segment follows:  
<TABLE>
<CAPTION>
                                         Increase/             Increase/
                                   1995  (Decrease)    1994    (Decrease)     1993
                                   ----  ----------    ----    ----------     ----
                                               (Dollars in millions)        
Revenues:
 <S>                              <C>        <C>      <C>        <C>         <C>
 Contract drilling                $258.4     20%      $215.4       6%        $203.1
 Drilling management               212.8     49%       142.8     138%          59.9
 Oil and gas                         9.8      -          9.8     (16%)         11.6
 Less: Intersegment revenues       (13.0)    44%        (9.0)     61%          (5.6)
                                  ------              ------                 ------
                                  $468.0     30%      $359.0      33%        $269.0
                                  ======              ======                 ======

Operating income:
 Contract drilling                $ 54.6     113%     $ 25.6     469%        $  4.5
 Drilling management                17.3      60%       10.8      42%           7.6
 Oil and gas                         3.4      (8%)       3.7     (30%)          5.3
 Corporate expenses                (15.0)      7%      (14.0)     (1%)        (14.2)
                                  ------              ------                 ------
                                  $ 60.3     131%     $ 26.1     716%        $  3.2
                                  ======              ======                 ======
</TABLE>
     The Company reported net income of $51.9 million for 1995 as compared
with net income of $1.3 million for 1994 and a net loss of $26.5 million for
1993.  Net income for 1995 included a $14.7 million gain on the sale of the
offshore drilling rig, Glomar Main Pass III.  Net income for 1994 included a
$3.5 million charge for the cumulative effect of a required change in accounting
for postemployment benefits.  Excluding such nonrecurring items, net income for
1995 and 1994 was $37.2 million and $4.8 million, respectively, compared to a
net loss of $26.5 million for 1993.

    In the U.K. sector of the North Sea, increased rig demand and a decrease in
the number of rigs available have resulted in higher contract drilling dayrates
in 1995 as compared with 1994, particularly for semisubmersible rigs.  A current
oversupply of natural gas in the  North Sea's U.K. sector, however, has
created uncertainty regarding future demand for North Sea jackups.  An
oversupply of jackups in the North Sea, which could result from any reduction in
future demand, could put downward pressure on dayrates and utilization rates for
the Company's two jackup drilling rigs which operate in the U.K. sector of
the North Sea.  Demand in other sectors of the North Sea remains strong.
Offshore West Africa, industry utilization and dayrates have steadily improved
since the end of 1994.  In the U.S. Gulf of Mexico, industry demand began
weakening in late December 1994 due to seasonal factors, but stabilized
during the first quarter of 1995.  Since March 1995, demand in the U.S. Gulf
of Mexico has increased, and, as of December 31, 1995, 141 Gulf rigs were under
contract, up from a low of 109 earlier in the year.

Contract Drilling Operations 

    Data with respect to the Company's contract drilling operations follows:  
<TABLE>
<CAPTION>
                                                  Increase/                 Increase/
                                          1995    (Decrease)     1994      (Decrease)     1993
                                         ------   ----------    ------    ----------     ------
                                          (Dollars in millions, except for fleet average dayrate)
        
Contract drilling revenues by area: (1) 
   <S>                                   <C>         <C>       <C>            <C>         <C>
   Gulf of Mexico                        $ 112.9      (1%)     $ 113.7        49%         $  76.4
   North Sea                                55.6      91%         29.1       (49%)           57.2
   West Africa                              55.3      74%         31.8         1%            31.6
   Other                                    34.6     (15%)        40.8         8%            37.9
                                         -------               -------                    -------
                                         $ 258.4      20%      $ 215.4         6%         $ 203.1
                                         =======               =======                    =======  

Average rig utilization (2)                   99%                   94%                        91% 
Fleet average dayrate                    $28,700               $25,600                    $25,600 
                      
-------------------
(1) Includes revenues earned from affiliates.
(2) Excludes the Company's Concrete Island Drilling System, a currently
    inactive, special-purpose mobile offshore rig designed for arctic
    operations.
</TABLE>
    Of the $43.0 million increase in contract drilling revenues
for 1995 compared to 1994, $26.4 million was attributable to increases in
dayrates, $14.2 million was attributable to increases in rig utilization, and
$2.4 million was attributable to an increase in non-dayrate revenue.  On a
regional basis, revenues from the North Sea increased by $26.5 million due to
higher utilization and dayrates.  The $23.5 million increase in revenues
attributable to offshore West Africa was primarily the result of the
full-year effect of two rigs mobilized to West Africa from other areas in
1994 and the commencement  of operations of the Glomar Adriatic IX and Glomar
Adriatic X in 1995.  The $6.2 million decline in revenues in the "other"
category for 1995 compared to 1994 was due to the mobilization of the two rigs
to West Africa in 1994 noted above.

    Of the $12.3 million increase in contract drilling revenues for
1994 compared to 1993, $16.7 million was attributable to increases in rig
utilization and $2.0 million was attributable to increases in dayrates.  Such
increases were partially offset by a decrease of $6.4 million in non-dayrate
revenue primarily attributable to the completion of an integrated services
contract in the North Sea in December 1993.  Regionally, revenues from the Gulf
of Mexico increased by $37.3 million due to (i) the 1993 mobilization to the
Gulf of two rigs from West Africa and three rigs from the North Sea, (ii) the
full-year effect of two of three rigs acquired from Transocean Drilling AS
and (iii) higher dayrates for the Company's other rigs in the Gulf of Mexico.
Revenues from the North Sea decreased by $28.1 million due to (i) the
mobilization of the three rigs from the North Sea to the Gulf of Mexico in 1993,
(ii) the sale of the offshore drilling rig, Glomar Moray Firth, to Transocean
Drilling AS in September 1993 and the termination of a management contract with
respect to that rig in December 1993, and (iii) lower North Sea dayrates and
utilization.  The $2.9 million increase in revenues in the "other" category for
1994 compared to 1993 was due to higher dayrates and utilization with respect to
one rig in the Far East, the 1993 mobilization of one rig to Trinidad from the
Gulf of Mexico, and the full-year effect of one of the three rigs acquired from
Transocean Drilling AS in September 1993, partially offset by the mobilization
of one rig from Alaska to West Africa in the fourth quarter of 1994 and the
termination of a management contract in Alaska during 1993.

    Effective January 1, 1995, the Company increased to 25 years the estimated
useful lives of its jackup drilling rigs and increased to 20 years the estimated
useful lives of its semisubmersible drilling rigs and drillship.  In addition,
salvage values were reduced to $500,000 per rig for jackups and $1,000,000 per
rig for both semisubmersibles and the drillship.  The effect of the change in
estimated service lives and salvage values was to decrease 1995 depreciation
expense by approximately $11.2 million.  Depreciation expense for contract
drilling operations totaled $27.4 million for 1995, $34.9 million for 1994 and
$32.0 million for 1993.  The number of rigs subject to depreciation averaged 25
rigs in 1995 and 1994 and 24 rigs in 1993.  Three rigs, the Glomar Adriatic IX,
Glomar Adriatic X, and Glomar Adriatic XI, were not in service nor subject to
depreciation for part of 1995.  The  Glomar Adriatic IX and Glomar Adriatic X
were purchased by the Company in February 1994 and began undergoing
refurbishment at that time.  Refurbishment of the Glomar Adriatic IX was
completed in March 1995, and the rig was mobilized to Nigeria where it began
drilling in May.  Refurbishment of the Glomar Adriatic X was completed in
October 1995, and the rig was mobilized to Angola where it began drilling
for a customer in November.  The Glomar Adriatic XI was purchased by the
Company in November 1994 and began operations for a customer in the North Sea in
October 1995 after extensive modifications were completed.

    The Company's operating profit margin for contract drilling operations
for 1995 increased to 21 percent from 12 percent in 1994 and 2 percent in 1993.
The increase in operating profit margin in 1995 compared to 1994 was due to the
decrease in depreciation expense discussed above as well as to higher dayrates
earned on the Company's rigs in 1995.  Operating expenses other than
depreciation increased by $21.5 million in 1995 compared to 1994.  The increase
in operating expenses in 1995 was due in part to (i) the 1995 commencement of
operations of the Glomar Adriatic IX, Glomar Adriatic X and Glomar Adriatic XI,
(ii) a higher payout under a net revenue-sharing arrangement with Transocean
Drilling AS with respect to two rigs, (iii) the March 1995 commencement of a
drilling contract in Nigeria for a rig which was mobilized from Alaska where it
had been on standby for a customer in 1994, (iv) the September 1994 commencement
of a drilling contract in Angola for a rig which was previously leased to an
operator in Saudi Arabia under a bareboat charter agreement, and (v) higher
utilization of three North Sea rigs which were idle for a significant part of
1994.  The operating profit margin for 1993 was relatively low primarily as a
result of the cost of mobilizing a number of rigs from the North Sea and
West Africa to the Gulf of Mexico in 1993, as well as to lower dayrates and
utilization in 1993.

    For the offshore drilling industry as a whole, the number of rigs under
contract in the Gulf of Mexico increased throughout 1993 due to stronger
domestic natural gas prices and a growing number of drilling prospects developed
from enhanced seismic technology.  As demand in the Gulf increased, drilling
contractors during 1993 and 1994 relocated a significant number of offshore rigs
from weak overseas markets to the Gulf, resulting in downward pressure on
Gulf dayrates.  A seasonal decline in demand beginning in December 1994 was
exacerbated by low natural gas prices, and the number of rigs under contract
industry-wide fell substantially from December 1994 to February 1995.  As a
result of this weakening in demand, dayrates received for newly contracted
jackups in the Gulf of Mexico trended downward between November 1994 and March
1995.  Despite stagnant natural gas prices in the first half of 1995, drilling
demand in the Gulf increased significantly since March and, as of December 31,
1995, 141 Gulf rigs were under contract.  As demand increased, dayrates for
jackups in the Gulf began recovering.  Aside from the seasonal recovery, the
strength in demand in the U.S. Gulf of Mexico beginning in the second quarter of
1995 can be attributed to, among other things, (i) improved seismic and
drilling technologies which have lowered the finding costs of oil and gas and
lower oil and gas producers' operating costs, making exploration and production
economical at lower oil and natural gas prices, and (ii) expectations of higher
future natural gas prices.  For the full year, average demand in the Gulf
increased to 134 rigs under contract (76 percent utilization) for 1995 from 131
rigs (75 percent utilization) for 1994 and 118 rigs (78 percent utilization) for
1993.  As of February 15, 1996, all eleven of the Company's rigs in the Gulf of
Mexico were under contract.  The Company averaged 100 percent utilization for
its rigs in the Gulf of Mexico for 1995, 99 percent for 1994 and 95 percent for
1993.

    In the U.K. sector of the North Sea, (i) promising oil discoveries west of
the Shetland Islands, (ii) operators' increased drilling to fulfill commitments
to drill previously awarded blocks, (iii) fewer available North Sea rigs, (iv)
increasing optimism with respect to the outlook for stable oil prices, and
(v) increased levels of operators' cash flow, among other factors, have resulted
in higher dayrates and utilization in the U.K. sector of the North Sea in 1995
compared to 1994, particularly for semisubmersible rigs.  However, an oversupply
of natural gas in the U.K. sector of the North Sea has caused some gas drilling
programs to be delayed and has created uncertainty over future demand for North
Sea jackups, which in the U.K. drill predominantly for gas.  An oversupply of
jackups in the North Sea, which could result from any reduction in future
demand, could put downward pressure on dayrates and utilization rates for the
Company's Glomar Labrador I and Glomar Adriatic XI jackups.  Under the
Glomar Labrador I's current contract, which is expected to terminate in April
1996, the dayrate is subject to adjustment periodically based on an index of
market dayrates.   The Glomar Adriatic XI is under contract through
approximately October 1996 at dayrates higher than or equal to the dayrate the
rig is presently receiving.  The Company's two semisubmersible rigs operating in
the North Sea, the Glomar Arctic I and Glomar Arctic III, compete in markets
driven primarily by oil prices and are not expected to be affected by any
weakness caused by low natural gas prices.  For the fourth quarter of 1995,
average drilling industry demand in the North Sea decreased to 76 rigs
under contract (94 percent utilization) from 77 rigs (96 percent utilization)
for the third quarter of 1995.  For the full year, average demand in the
North Sea increased to 71 rigs under contract (90 percent utilization) for
1995 from 64 rigs (76 percent utilization) for 1994.  For 1993, North Sea demand
averaged 81 rigs (79 percent utilization).  As of February 15, 1996, all four of
the Company's rigs in the North Sea were under contract.  The Company
averaged 100 percent utilization for its drilling rigs in the North Sea for
1995, 68 percent for 1994 and 83 percent for 1993.

    During 1993, the civil war in Angola, a reduction of the Nigerian national
oil company's participation in ongoing projects and volatile oil prices caused
a reduction in the demand for drilling rigs offshore West Africa and,
accordingly, a reduction in dayrates.  Despite the unrest, supply and demand
stabilized in 1994.  As a result, the Company mobilized two offshore drilling
rigs, the Glomar High Island IX and the Glomar Adriatic VIII, from weakening
other markets to West Africa during 1994.  In 1995, the Company placed into
service the recently acquired Glomar Adriatic IX and Glomar Adriatic X, which
commenced drilling operations offshore West Africa in May and November,
respectively.  For the fourth quarter of 1995, average drilling industry demand
offshore West Africa increased to 35 rigs under contract (87 percent
utilization) from 32 rigs (84 percent utilization) for the third quarter of
1995.   For the full year, average demand offshore West Africa increased
to 31 rigs under contract (83 percent utilization) for 1995 from 24 rigs (75
percent utilization) for 1994.  For 1993, West African demand averaged 26 rigs
(70 percent utilization).  In February 1996, the Company began mobilizing the
Glomar High Island III from the U.S. Gulf of Mexico to Angola where it will
begin drilling for a customer in March.  The cost of the mobilization is
expected to be substantially reimbursed by the client.  As of February 15,
1996, all eight of the Company's rigs located offshore West Africa, including
the Glomar High Island III, were under contract.  The Company's average
utilization rate for its rigs located offshore West Africa was 95 percent for
1995, 98 percent for 1994 and 88 percent for 1993.

    As of December 31, 1995, the worldwide industry utilization rate for
competitive offshore rigs was 83 percent, with 91 of the 546 worldwide
competitive rigs unemployed.  The Company anticipates that contracts on 18 of
the Company's 26 rigs under contract as of February 15, 1996, will expire at
varying times on or prior to May 31, 1996.  No assurance can be made that the
Company will obtain drilling contracts for its rigs upon the completion of
current contracts; however, short-term contracts have been typical in the
industry for the past decade, and the Company considers its upcoming contract
expirations typical of prevailing market conditions and consistent with the
normal course of business.

Drilling Management Services

    Revenues for drilling management services increased by $70.0 million to
$212.8 million in 1995 from $142.8 million in 1994.  Operating income
increased by $6.5 million to $17.3 million in 1995 from $10.8 million in 1994.
The $70.0 million increase in revenues for the year consisted of (i) a $41.9
million increase attributable to an increase in the number of wells drilled,
from 52 in 1994 to 67 in 1995, (ii) a $12.3 million increase attributable to
higher average turnkey revenues per well, (iii) $13.9 million from the
completion work on a multi-well North Sea turnkey project in 1995, and (iv) a
$1.9 million increase in other drilling management revenues.  Average turnkey
revenues per well were higher because a higher percentage of the wells drilled
in 1995 were directional and/or deep, high-pressured wells as compared with
those completed in the prior year.

    For 1994, drilling management services reported an $82.9 million increase in
revenues to $142.8 million from $59.9 million in 1993, and a $3.2 million
increase in operating income to $10.8 million from $7.6 million in 1993.  The
improvement resulted from the completion of 52 wells in 1994 as compared to
18 wells in 1993, partially offset by lower average profit margins on the
1994 wells.  

    The increase in the number of turnkey wells drilled in 1995 and in 1994
was attributable in part to a more competitive pricing policy and oil and gas
operators' increased reliance on turnkey contractors to supplement internal
drilling staffs.  

    Operating income for drilling management services expressed as a
percentage of drilling management revenues declined to 8 percent for each of
1995 and 1994 as compared with 13 percent for 1993.  Four wells in 1995
incurred losses aggregating $5.7 million, compared to losses on seven wells
aggregating $5.4 million in 1994, and no losses on wells in 1993.

Oil and Gas Operations

Data related to the Company's oil and gas production follows:
<TABLE>
<CAPTION>
                                             Increase/          Increase/
                                       1995  (Decrease)  1994   Decrease)   1993
                                       ----  ----------  ----   ---------   ----
Gas:
 Production (in millions 
   <S>                              <C>        <C>     <C>        <C>      <C>
   of cubic feet)                     4,382      9%      4,009    (12%)      4,557
 Average sale price (per 
   thousand cubic feet)               $1.57    (15%)     $1.86     (6%)      $1.98

Oil:
 Production (in barrels)            169,317     15%    147,715     (4%)    154,436
 Average sale price (per barrel)     $16.89      7%     $15.79     (7%)     $16.89
</TABLE>
    Despite higher oil and natural gas production and higher oil prices,
revenues from oil and gas were unchanged at $9.8 million for each of 1995 and
1994 due to a decline in the average price received for gas.  The increase in
oil and gas production was due to production from new properties, partially
offset by normal production declines.  Operating income of $3.4 million
for 1995 was slightly lower than for 1994 due principally to higher depletion
expense.

    Oil and gas revenues in the amount of $9.8 million for 1994 were lower
than the $11.6 million of revenues reported for 1993 due to lower volumes of oil
and gas produced and lower oil and gas prices.  Oil and gas production
decreased as a result of normal production declines, the 1993 sale of an oil
producing property, and the temporary suspension of production in order to
repair an oil and gas well in 1994, partially offset by production from two new
properties.  Operating income of $3.7 million for 1994 was lower than the $5.3
million of operating income reported for 1993 due to the lower revenues
discussed above and higher costs associated with the development of new
prospects, offset in part by a lower depletion rate in 1994 as compared with
1993.  Depletion expense decreased to $1.9 million for 1994 from $3.3 million
for 1993.  The lower depletion rate resulted in part from the property sale
in 1993, and from the deferral of net profits earned on certain turnkey
drilling contracts, which reduced the depletable base.

Other Income and Expense

    Interest expense was $30.2 million for each of 1995 and 1994 compared to
$32.1 million in 1993. The decrease in interest expense from 1993 to 1994 was
due to the reduction in long-term debt resulting from the retirement of the rig
mortgage note for the Glomar Baltic I in August 1993.

    Interest capitalized increased by $1.9 million to $5.6 million in 1995 from
$3.7 million in 1994.  Interest capitalized in 1994 was attributable to the
acquisition and refurbishment of two offshore drilling rigs, the Glomar Adriatic
IX and Glomar Adriatic X, which were acquired in February 1994.  The increase in
interest capitalized in 1995 was primarily due to the construction work on
the Glomar Adriatic XI, which was acquired in November 1994, and to higher
amounts capitalized with respect to the Glomar Adriatic IX and Glomar Adriatic X
as a result of continuing capital expenditures.  The higher interest
capitalization was offset in part by the completion of the refurbishment of
the Glomar Adriatic IX in the second quarter of 1995.  Work on the Glomar
Adriatic X and Glomar Adriatic XI was completed in the fourth quarter of 1995.

    Interest income increased by $0.9 million to $4.7 million in 1995 from
$3.8 million in 1994 primarily due to higher short-term investment balances.
Interest income increased to $3.8 million for 1994 from $2.7 million for 1993,
primarily due to the recognition of $0.8 million in connection with the
favorable 1994 settlement of the Company's demobilization obligations with
respect to a third-party owned rig aboard the Glomar Beaufort Sea I.  

    In June 1995 the Company completed the sale of its offshore drilling rig,
the Glomar Main Pass III, for $22.4 million in cash, net of expenses, and
recognized a gain of $14.7 million.

    Other income for 1994 consisted of $1.4 million in dividend income and a
$0.6 million gain on the sale of marketable equity securities.

    For 1995, the provision for income taxes was not significant due to the
utilization of net operating loss carryforwards for U.S. federal income tax
purposes.  Income tax expense for 1995, 1994 and 1993 primarily consisted of
income taxes applicable to foreign countries in which the Company had no loss
carryforwards.

    As of December 31, 1995, the Company had approximately $1.1 billion of
net operating loss carryforwards ("NOLs") expiring in various amounts at various
times from the year 2000 to 2009.  The NOLs may be used to reduce taxable
income in future years prior to their expiration.  The Company's ability to
utilize the NOLs is dependent on the amount and timing of future earnings.
Due to the uncertain nature of their ultimate realization, the Company has
not recognized on its balance sheet an asset for the amount of the future tax
benefits of the NOLs.  Instead, the Company has recorded a valuation
allowance against the deferred tax asset in the amount of $381.8 million as
of December 31, 1995.  The amount of the valuation allowance is subject to
periodic review.  A reasonable possibility exists that the conditions which
existed at December 31, 1995 giving rise to the recognition of the valuation
allowance as of that date may change in the near term.  If the allowance is
reduced in a future period, the adjustment would be recorded as a reduction to
income tax expense.

    During 1994, the Company adopted Statement of Financial Accounting Standards
("SFAS") No. 112, "Employers' Accounting for Postemployment Benefits."  The
cumulative impact of this change was to decrease 1994 net income by $3.5
million.
  
    In October 1995, the Financial Accounting Standards Board issued SFAS No.
123, "Accounting for Stock-Based Compensation," which sets forth accounting and
disclosure requirements for stock-based compensation arrangements.  The new
statement encourages, but does not require, companies to measure stock-based
compensation cost using a fair-value method, rather than the intrinsic-value
method prescribed by Accounting Principles Board ("APB") Opinion No. 25.
Companies choosing to continue to measure stock-based compensation using the
intrinsic-value method must disclose on a pro forma basis net income and net
income per share as if the fair-value method were used.  The Company intends
to adopt the disclosure requirements of SFAS No. 123 in 1996 and to continue
to measure stock-based compensation cost using the intrinsic-value approach
prescribed by APB Opinion No. 25.  Adoption of the new standard is not
expected to have a material effect on the Company's earnings.

Liquidity and Capital Resources

    During the three-year period ended December 31, 1995, the Company entered
into a number of transactions designed to improve its financial and competitive
positions.  In 1993 the Company sold 21,150,000 shares of common stock for $74.2
million, of which $26.0 million was used to retire a rig mortgage note and $17.0
million was used to pay part of the purchase price of three offshore drilling
rigs.  In 1994 the Company sold marketable securities received in connection
with a 1992 settlement of natural gas take-or-pay litigation for total cash
proceeds of $30.8 million.  The Company used the $30.8 million sale proceeds
plus available cash, for a total of $39.8 million, to purchase three offshore
drilling rigs in 1994.  In 1994 and 1995, the Company spent an additional $56
million to refurbish and upgrade the three rigs purchased in 1994.  Finally, in
1995 the Company sold a jackup rig for $22.4 million, recognizing a gain of
$14.7 million.

    In 1995, cash flow provided by operating activities amounted to $75.0
million.  An additional $23.9 million was provided from sales of properties and
equipment, primarily the sale of the Glomar Main Pass III.  From the $98.9
million sum of cash flow from operations and proceeds from sales of properties
and equipment, plus available cash, $73.5 million was used for capital
expenditures, and $28.8 million was used for purchases of marketable securities
(net of maturities).  In 1994, cash flow provided by operating activities
totaled $61.3 million, including $17.9 million in proceeds from the liquidation
of a promissory note received in connection with the 1992 settlement of the
Company's take-or-pay litigation.

    As of December 31, 1995, the Company's long-term debt totaled $225.0
million, consisting entirely of 12-3/4% Senior Secured Notes due 1999 (the
"Senior Secured Notes"), and shareholders' equity totaled $269.0 million.  The
annual interest on the Senior Secured Notes is $28.7 million, payable
semiannually, each June and December. 

    The Senior Secured Notes do not require any payments of principal prior
to their stated maturity in December 1999, but the Company is required to make
offers to purchase Senior Secured Notes upon the occurrence of certain events
defined in the indenture, such as asset sales, or a change of control, or
if the annual cash flow of the Company exceeds certain specified levels.  In
the first quarter of 1996, the Company will make an offer to purchase, at a
price of 100 percent of principal, $39.3 million aggregate principal amount of
Senior Secured Notes from the sum of the excess cash flow for 1995 and the
proceeds of asset sales that were not applied to the purchase of Replacement
Assets as defined in the indenture.  As of February 9, 1996, the quoted market
price of the Senior Secured Notes was 110 percent of principal, which exceeds
the price at which the Company is required to make its purchase offer.  The
amount of Senior Secured Notes the Company will purchase, if any, is not
expected to be material.  The portion of the $39.3 million of cash that is not
used to purchase Senior Secured Notes will become unrestricted and available to
the Company for general purposes upon termination of the Company's purchase
offer in the second quarter of 1996.

    The Senior Secured Notes are not redeemable at the option of the Company
prior to December 15, 1997.  On or after December 15, 1997, the Senior Secured
Notes are redeemable at the option of the Company, in whole at any time or in
part from time to time, at a price of 102 percent of principal if redeemed
during the twelve months beginning December 15, 1997, or at a price of 100
percent of principal if redeemed on or after December 15, 1998, in each case
together with interest accrued to the redemption date.  The Company presently
expects that, absent unforeseen circumstances, it will seek to retire the Senior
Secured Notes from the Company's cash and marketable securities, to the extent
available, and/or the proceeds of debt financings as early as December 1997.

    The indenture under which the Senior Secured Notes are issued imposes
significant operating and financial restrictions on the Company and requires
that a first lien in favor of the trustee be maintained, for the benefit of the
holders of Senior Secured Notes, on a significant portion of the Company's
material assets.  Such restrictions affect, and in many respects limit or
prohibit, among other things, the ability of the Company to incur additional
indebtedness, make capital expenditures, create liens, sell assets, engage in
mergers or acquisitions, and make dividends or other payments.  The restrictive
covenants contained in and liens provided for under the indenture could
significantly limit the ability of the Company to respond to changing business
or economic conditions or to respond to substantial declines in operating
results.

    Capital expenditures for 1996 are estimated to be $35 million, principally
for improvements to the Company's drilling fleet.

    As of December 31, 1995, the Company had $86.6 million in cash, cash
equivalents and marketable securities, including $42.1 million which was
restricted from use for general corporate purposes.  The restricted amount
includes (i) $27.7 million in proceeds from asset sales and $11.6 million
in excess cash flow for 1995, which will become unrestricted only after and
to the extent not used to purchase Senior Secured Notes in the Senior Secured
Notes purchase offer in the first quarter of 1996, and (ii) $2.8 million
collateralizing outstanding operating letters of credit.  As of December 31,
1994, the Company had $57.9 million in cash and marketable securities,
net of restricted amounts of $19.3 million.

    An additional source of liquidity is the cash flow from the Company's oil
and gas properties and drilling management service operations, both of which
are available to service the Company's debt and to fund its working capital
requirements and capital expenditures.  Cash flow from the Company's drilling
management services may be limited by certain factors, in particular, the
ability of the Company to obtain and successfully perform turnkey drilling
contracts based on competitive bids, which in turn is largely dependent on
the number of such contracts available for bid.  Accordingly, results of the
Company's drilling management service operations may vary widely from quarter
to quarter and from year to year.  Furthermore, turnkey operations may be
constrained by the availability of rigs as demand for rigs increases.  In
the U.S. Gulf of Mexico, ADTI relied on third-party rigs for approximately
97 percent of its rig-time in 1995, and had an average of five rigs under
short-term contracts during the year.  To minimize the risk of not having a
rig available for a turnkey job, ADTI considers and may undertake to commit
to several rigs under term contracts of from three to twelve months.  In the
North Sea and West Africa, the market for turnkey drilling is not well
established, and growth in these markets may be constrained by rig
availability in 1996.

    In February 1996, the Company entered into an agreement to extend to
December 1998 its $25 million revolving credit and letter of credit facility
with a major international bank.  Under the credit facility, the Company may
borrow an amount of up to 80 percent of eligible accounts receivable.
Borrowings under the facility would accrue interest at the lowest of three
market-based interest rates.  The unused portion of the line of credit is
subject to an annual commitment fee of .1875 percent.  There were no
borrowings or letters of credit outstanding under the facility as of December
31, 1995 or 1994.  As of December 31, 1995, the Company was eligible to
borrow the full $25 million under the revolving credit facility.

    The Company believes that it will be able to meet all of its current
obligations, including capital expenditures and debt service, from its cash flow
from operations and its cash, cash equivalents and marketable securities.  

    As part of upgrading and expanding its rig fleet and other assets, the
Company considers and pursues the acquisition of suitable additional rigs and
other assets on an ongoing basis.  If the Company decides to undertake an
acquisition, the issuance of additional shares of stock or additional debt could
be required.  The Company may also consider the disposition of rigs and other
assets if and when a disposition can be effected on favorable terms.
Disposition proceeds, to the extent available, could also be used as a source of
acquisition financing.

    In April 1995, the Company filed with the Securities and Exchange Commission
a Registration Statement on Form S-3 for the proposed offering from time to time
of (i) debt securities, which may be subordinated to other indebtedness of the
Company, (ii) shares of preferred stock, $0.01 par value per share, and/or (iii)
shares of common stock, $0.10 par value per share, for an aggregate initial
public offering price not to exceed $75 million.  Any net proceeds from the
sale of offered securities would be used for general corporate purposes which
may include, but are not limited to, capital expenditures and the financing
of acquisitions.  The Registration Statement was declared effective by the
Commission in June 1995.  The Company has not yet offered for sale or sold any
securities under the Registration Statement.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA




                     REPORT OF INDEPENDENT ACCOUNTANTS


To the Board of Directors and Shareholders of Global Marine Inc.

   We have audited the consolidated balance sheet of Global Marine 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 three years in the period ended December 31, 1995.  These financial
statements are the responsibility of the Company's management.  Our
responsibility is to express an opinion on these financial statements based
on our audits.

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

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

As discussed in Note 1 to the consolidated financial statements, in 1994 the
Company adopted the new method of accounting for postemployment benefits, as
prescribed by Statement of Financial Accounting Standards No. 112.


/s/ Coopers & Lybrand L.L.P.


Houston, Texas
February 9, 1996

<TABLE>
                    GLOBAL MARINE INC. AND SUBSIDIARIES
                    CONSOLIDATED STATEMENT OF OPERATIONS
                    (In millions, except per share data)
<CAPTION>
                                                                Year Ended December 31,
                                                                -----------------------
                                                                1995     1994      1993
                                                                ----     ----      ---- 
Revenues
  <S>                                                          <C>      <C>       <C>
  Contract drilling                                            $248.9   $211.4    $200.3
  Drilling management                                           209.3    137.8      57.1
  Oil and gas                                                     9.8      9.8      11.6
                                                               ------   ------    ------
     Total revenues                                             468.0    359.0     269.0
                                                               ------   ------    ------  


Expenses
  Contract drilling                                             166.9    150.9     163.8
  Drilling management                                           192.0    127.0      49.5
  Oil and gas                                                     3.4      4.2       3.0
  Depreciation, depletion and amortization                       31.0     37.4      35.9
  General and administrative                                     14.4     13.4      13.6
                                                               ------   ------    ------
                                                                407.7    332.9     265.8
                                                               ------   ------    ------
     Operating income                                            60.3     26.1       3.2
                                                               ------   ------    ------

Other income (expense)
  Interest expense                                              (30.2)   (30.2)    (32.1)
  Interest capitalized                                            5.6      3.7         -
  Interest income                                                 4.7      3.8       2.7
  Gain on sale of offshore drilling rig                          14.7        -         -
  Other                                                             -      2.0         -
                                                               ------   ------    ------
     Total other income (expense)                                (5.2)   (20.7)    (29.4)
                                                               ------   ------    ------
     Income (loss) before income taxes                           55.1      5.4     (26.2)

  Income tax expense (Note 8)                                     3.2       .6        .3
                                                               ------   ------    ------

  Income (loss) before cumulative effect 
     of change in accounting principle                           51.9      4.8     (26.5)
        Cumulative effect of change in accounting 
          for postemployment benefits (Note 1)                      -     (3.5)        -
                                                               ------   ------    ------
     Net income (loss)                                         $ 51.9   $  1.3    $(26.5)
                                                               ======   ======    ======

Primary net income (loss) per common share (Note 7):
  Before cumulative effect of change in accounting principle   $ 0.31   $ 0.03   $ (0.17)
  Cumulative effect of change in accounting  
     for postemployment benefits (Note 1)                           -    (0.02)        -
                                                               ------   ------   -------
     Primary net income (loss) per common share                $ 0.31   $ 0.01   $ (0.17)
                                                               ======   ======   =======

Fully diluted net income per common and common
  equivalent share (Note 7):
  Before cumulative effect of change in accounting principle   $ 0.30   $ 0.03      N/A 
  Cumulative effect of change in accounting
     for postemployment benefits (Note 1)                           -    (0.02)     N/A 
                                                               ------   ------
  Fully diluted net income per common
     and common equivalent share                               $ 0.30   $ 0.01      N/A 
                                                               ======   ======

              See notes to consolidated financial statements.
</TABLE>

<TABLE>
                    GLOBAL MARINE INC. AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEET
                           (Dollars in millions)

                                  ASSETS

<CAPTION>
                                                                         December 31,
                                                                 -------------------------
                                                                   1995              1994
                                                                  ------            ------
Current assets
  <S>                                                            <C>               <C>
  Cash and cash equivalents (Note 2)                             $  33.2           $  33.3
  Marketable securities (Note 2)                                    53.4              24.6
  Accounts receivable, less allowance for doubtful 
     accounts of $1.1 in 1995 and $1.2 in 1994                      70.2              63.1
  Costs incurred on turnkey drilling contracts in progress           8.4              18.5
  Prepaid expenses                                                   2.2              10.0
  Other current assets                                                .9                .3
                                                                  ------           -------

       Total current assets                                        168.3             149.8
                                                                  ------           -------

Properties (Note 3)
   Rigs and drilling equipment, less accumulated
     depreciation of $189.0 in 1995 and $168.4 in 1994             377.9             346.9
   Oil and gas properties, full cost method, less accumulated 
     depreciation, depletion and amortization of $26.4 in 1995 
       and $26.9 in 1994                                             8.7               6.5
                                                                  ------           -------

       Net properties                                              386.6             353.4
                                                                  ------           -------

Other assets                                                         8.1               9.2
                                                                  ------           -------

       Total assets                                               $563.0            $512.4
                                                                  ======           =======


              See notes to consolidated financial statements.
</TABLE>

<TABLE>
                   GLOBAL MARINE INC. AND SUBSIDIARIES
                        CONSOLIDATED BALANCE SHEET
                          (Dollars in millions)

                   LIABILITIES AND SHAREHOLDERS' EQUITY

<CAPTION>
                                                                 December 31,
                                                           -----------------------
                                                            1995             1994 
                                                           ------           ------
Current liabilities
  <S>                                                      <C>              <C>
  Accounts payable                                         $ 33.9           $ 39.5
  Accrued compensation and related employee costs            10.8              9.0
  Other accrued liabilities                                   7.4              7.9
                                                           ------           ------ 

       Total current liabilities                             52.1             56.4
                                                           ------           ------

Long-term debt (Note 3)                                     225.0            225.0 
Other long-term liabilities                                  16.9             18.7 
Commitments and contingencies (Note 4)                          -                - 

Shareholders' equity
  Preferred stock, $0.01 par value, 10 million shares 
     authorized, no shares issued or outstanding                -                - 
  Common stock, $0.10 par value, 300 million shares 
     authorized, 166,458,083 shares and 164,408,185 shares  
     issued and outstanding at December 31, 1995 
     and 1994, respectively (Note 6)                         16.6             16.4 
  Additional paid-in capital                                264.8            260.2 
  Accumulated deficit                                       (12.4)           (64.3)
                                                           ------           ------

       Total shareholders' equity                           269.0            212.3
                                                           ------           ------

       Total liabilities and shareholders' equity          $563.0           $512.4
                                                           ======           ======


             See notes to consolidated financial statements.
</TABLE>

<TABLE>
                   GLOBAL MARINE INC. AND SUBSIDIARIES
                   CONSOLIDATED STATEMENT OF CASH FLOWS
                              (In millions)
<CAPTION>
                                                               Year Ended December 31,
                                                              -------------------------
                                                               1995      1994     1993
                                                              ------    ------   ------

Cash flows from operating activities
  <S>                                                         <C>      <C>       <C>
  Net income (loss)                                           $ 51.9   $  1.3    $(26.5)
  Adjustments to reconcile net income (loss) to net
   cash provided by (used in) operating activities:
     Depreciation, depletion and amortization                   31.0     37.4      35.9
     Gain on sale of offshore drilling rig                     (14.7)       -         -
     Cumulative effect of change in accounting 
        principle                                                  -      3.5         -
     Increase in accounts receivable                            (7.1)    (5.2)    (11.5)
     Decrease in note receivable                                   -     17.9         -
     (Increase) decrease in costs incurred on turnkey
        drilling contracts in progress                          10.1    (17.0)     (1.5)
     (Increase) decrease in other current assets                 7.2     (1.9)      (.7)
     Increase (decrease) in accounts payable                    (5.6)    19.6       4.7
     Increase (decrease) in accrued liabilities                  3.0      1.2      (2.5)
     Other, net                                                  (.8)     4.5       1.4
                                                              ------   ------    ------

   Net cash flow provided by (used in) operating activities     75.0     61.3       (.7)
                                                              ------   ------    ------

Cash flows from investing activities
  Capital expenditures                                         (73.5)   (75.9)    (40.6)
  Purchases of held-to-maturity securities                    (124.3)   (64.7)    (26.7)
  Proceeds from maturities of held-to-maturity securities       95.5     60.2      16.8
  Proceeds from sales of available-for-sale securities             -     15.6         -
  Proceeds from sales of properties and equipment               23.9      2.6      10.3
  Other                                                            -      2.1      (1.9)
                                                              ------   ------    ------
     Net cash flow used in investing activities                (78.4)   (60.1)    (42.1)
                                                              ------   ------    ------

Cash flows from financing activities
  Common stock offerings, net of expenses                          -        -      74.2
  Payments on long-term debt                                       -        -     (25.4)
  Proceeds from exercise of employee stock options               3.3       .9       1.9
                                                              ------   ------    ------

   Net cash flow provided by financing activities                3.3       .9      50.7
                                                              ------   ------    ------

Increase (decrease) in cash and cash equivalents                 (.1)     2.1       7.9

Cash and cash equivalents at beginning of year                  33.3     31.2      23.3
                                                              ------   ------    ------

Cash and cash equivalents at end of year                      $ 33.2   $ 33.3    $ 31.2
                                                              ======   ======    ======




             See notes to consolidated financial statements.
</TABLE>

<TABLE>
                                GLOBAL MARINE INC. AND SUBSIDIARIES
                            CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
                                         (Dollars in millions)
<CAPTION>
                                                                       Additional
                                                Common Stock             Paid-in     Accumulated 
                                           ------------------------ 
                                              Shares      Par Value      Capital       Deficit         Total 
                                           -----------    ---------    -----------   ------------     -------

<S>                                        <C>               <C>         <C>           <C>            <C>
Balance, December 31, 1992                 140,228,732       $14.0       $179.6        $(39.1)        $154.5
       Net loss                                      -           -            -         (26.5)         (26.5)
       Common stock offerings               21,150,000         2.1         72.1             -           74.2
       Exercise of employee stock options      779,500          .1          1.0             -            1.1
       Common stock issued under
         other employee benefit plans          674,567          .1          2.0             -            2.1
                                           -----------       -----       ------        ------         ------

Balance, December 31, 1993                 162,832,799        16.3        254.7         (65.6)         205.4
       Net income                                    -           -            -           1.3            1.3
       Common stock issued in 
         connection with the acquisition
         of two offshore drilling rigs         750,000          .1          2.9             -            3.0
       Exercise of employee stock options      484,500           -           .9             -             .9
       Common stock issued under
         other employee benefit plans          340,886           -          1.7             -            1.7
                                           -----------       -----       ------        ------         ------

Balance, December 31, 1994                 164,408,185        16.4        260.2         (64.3)         212.3
       Net income                                    -           -            -          51.9           51.9
       Exercise of employee stock options    1,615,299          .2          3.1             -            3.3
       Common stock issued under
         other employee benefit plans          434,599           -          1.5             -            1.5
                                           -----------       -----       ------        ------         ------

Balance, December 31, 1995                 166,458,083       $16.6       $264.8        $(12.4)        $269.0
                                           ===========       =====       ======        ======         ======


               See notes to consolidated financial statements.
</TABLE>

Note 1 - Summary of Significant Accounting Policies

    Principles of Consolidation

    The consolidated financial statements include the accounts of Global
Marine Inc. and its majority-owned subsidiaries.  Unless the context
otherwise requires, the term "Company" refers to Global Marine Inc. and its
consolidated subsidiaries.  Intercompany accounts and transactions have been
eliminated.

    Cash Equivalents

    Cash equivalents consist of all highly liquid debt instruments
with remaining maturities of three months or less at the time of purchase.

    Properties and Depreciation

    Rigs and Drilling Equipment.  Rigs and drilling equipment are carried at
an amount equal to the fair market values of the rigs in the fleet as of
December 31, 1988, plus the cost of rig acquisitions and other additions and
improvements to the existing fleet thereafter.  Included in the cost of rigs and
drilling equipment is an allocation of the interest cost incurred during
the period required to construct or refurbish a rig.  Expenditures for
maintenance and repairs are charged to expense as incurred.  Costs of property
sold or retired and the related accumulated depreciation are removed from the
accounts; resulting gains or losses are included in income.

    Effective January 1, 1995, the Company increased to 25 years the estimated
useful lives of its jackups and increased to 20 years the estimated useful
lives of its semisubmersibles and drillship.  In addition, salvage values were
reduced to $500,000 per rig for jackups and $1,000,000 per rig for
semisubmersibles and the drillship.  The effect of the change in estimated
service lives and salvage values was to decrease 1995 depreciation expense by
approximately $11.2 million.

    Effective January 1, 1995, the Company adopted Statement of Financial
Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to Be Disposed Of," which requires that
certain long-lived assets be reviewed for impairment whenever events indicate
that the carrying amount of an asset may not be recoverable, and that an
impairment loss be recognized under certain circumstances in the amount by which
the carrying value exceeds the fair value of the asset.  The adoption of SFAS
No. 121 had no effect on the Company's results of operations or financial
position.

    Oil and Gas Properties.  The Company capitalizes all costs attributable
to the acquisition, exploration and development of oil and gas reserves under
the full cost method of accounting.  The depreciation, depletion and
amortization provision is computed using the units-of-production method. 
The depletable base consists of capitalized costs, estimated future costs to
develop proved reserves and estimated future dismantlement costs, and is reduced
by the aggregate net profit earned on the Company's turnkey drilling
contracts for wells drilled on properties in which the Company has working
interests.  In addition, the depletable base is reduced by proceeds from
sales of oil and gas properties, unless the sale involves a significant
quantity of reserves in relation to total reserves, in which case a gain or loss
would be recognized.  The costs of unproved properties and major development
projects are not subject to depreciation, depletion and amortization until they
are fully evaluated.  All unproved properties are reviewed at least annually to
ascertain if impairment has occurred.  Costs of proved oil and gas properties
which exceed the present value of estimated future net revenues are charged to
expense.  

    Revenue Recognition

    Contract drilling services are performed generally on a daily-rate basis
under individual contracts for either a stated period of time or the time
required to drill a well or number of wells.  Revenues from contract drilling
services and the related expenses are recognized on a per-day basis as the work
progresses.  Revenues from turnkey drilling contracts, which are classified
under drilling management revenues, are derived from the design and execution of
a specific offshore drilling program at a fixed price to the oil and gas
operator.  Revenues from turnkey drilling contracts and the related expenses are
recognized upon completion of the turnkey contract.

    Foreign Currency Translation

    The U.S. dollar is the functional currency for all of the Company's
operations.  Realized and unrealized foreign currency transaction gains and
losses are recorded in income.

    The Company may be exposed to the risk of foreign currency exchange
losses in connection with its foreign operations.  Such losses are the result of
holding net monetary assets (cash and receivables in excess of payables)
denominated in foreign currencies during periods of a strengthening U.S. dollar.
The Company's foreign exchange gains and losses, which are primarily
attributable to the British pound, have not been and are not expected to be
material.  This is because the Company's revenues are primarily denominated
in U.S. dollars, revenues in each foreign currency are approximately equal to
the Company's local expenses in that currency, and the Company does not
speculate in foreign currencies or maintain significant foreign currency cash
balances.

    Postemployment Benefits

    Effective January 1, 1994, the Company adopted Statement of Financial
Accounting Standards No. 112, "Employers' Accounting for Postemployment
Benefits."  SFAS No. 112 requires the recognition of expense for
postemployment benefits on an accrual basis rather than the cash basis used
previously.  Postemployment benefits include severance pay, disability-related
benefits and certain health care benefits during the period after termination
of employment but before retirement.  The cumulative effect of the change as
of January 1, 1994, was a charge to earnings in the amount of $3.5 million
($0.02 per share).  Other than the cumulative effect, the effect of the
change on earnings was not material.

Note 2 - Investments

    At December 31, 1995 and 1994, all of the Company's investments in cash
equivalents and marketable securities consisted of debt securities which were
classified as held-to-maturity and were carried at amortized cost.  A summary of
the estimated fair values of investments as of December 31 follows:
<TABLE>
                   
                                              1995        1994
                                             ------      ------
                                               (In millions)
  Cash equivalents:
     <S>                                     <C>         <C>
     Commercial paper                        $ 21.8      $ 26.1
     Eurodollar time deposits                   9.4         5.1
     Certificates of deposit                      -          .2
                                             ------      ------
                                             $ 31.2      $ 31.4
                                             ======      ======

  Marketable securities:
     Commercial paper                        $ 42.5      $ 13.7
     Eurodollar time deposits                  10.6         7.3
     U.S. Treasury obligations                   .2          .3
     Certificates of deposit                     .1         3.3
                                             ------      ------
                                             $ 53.4      $ 24.6
                                             ======      ======
</TABLE>
    The estimated fair values of investments approximated their amortized cost;
therefore, there were no unrealized gains or losses as of December 31, 1995
or 1994.

    The estimated fair values of investments as of December 31 grouped by
contractual maturities were as follows:
<TABLE>
                                              1995        1994
                                             ------      ------
                                                (In millions)      
        
  <S>                                        <C>         <C>
  Within three months or less                $ 31.2      $ 31.4
  After three months through one year          53.3        24.5
  After one year                                 .1          .1
                                             ------      ------
                                             $ 84.6      $ 56.0
                                             ======      ======
</TABLE>
    As of December 31, 1995, $42.1 million of the Company's marketable
securities was restricted from general use.  The restricted amount is comprised
of (i) $27.7 million in proceeds from asset sales and $11.6 million in excess
cash flow for 1995 which will become unrestricted only after and to the
extent not used in the offering to purchase Senior Secured Notes in the first
quarter of 1996 (see Note 3) and (ii) $2.8 million collateralizing outstanding
operating letters of credit.

Note 3 - Long-term Debt

    Long-term debt as of December 31, 1995 and 1994, consisted entirely of
12-3/4% Senior Secured Notes due 1999 (the "Senior Secured Notes") in the
aggregate principal amount of $225.0 million, due December 15, 1999.  Interest
on the Senior Secured Notes is payable semiannually each June and December.
The Senior Secured Notes do not require any payments of principal prior to their
stated maturity on December 15, 1999, but the Company is required to make
offers to purchase Senior Secured Notes upon the occurrence of certain events
defined in the indenture, such as asset sales, or a change of control, or if
the annual cash flow of the Company exceeds certain specified levels.  In the
first quarter of 1996, the Company will make an offer to purchase, at a price
of 100 percent of principal, $39.3 million aggregate principal amount of Senior
Secured Notes from the sum of the excess cash flow for 1995 and the proceeds of
asset sales that were not applied to the purchase of Replacement Assets as
defined in the Senior Secured Note indenture.  As of February 9, 1996, the
quoted market price of the Senior Secured Notes was 110 percent of principal,
which exceeds the price at which the Company is required to make its purchase
offer.  The amount of Senior Secured Notes the Company will purchase, if any,
is not expected to be material.  The portion of the $39.3 million of cash that
is not used to purchase Senior Secured Notes will become unrestricted and
available to the Company for general purposes upon termination of the Company's
purchase offer in the second quarter of 1996.

    The Senior Secured Notes are not redeemable at the option of the Company
prior to December 15, 1997.  On or after December 15, 1997, the Senior Secured
Notes are redeemable at the option of the Company, in whole at any time or in
part from time to time, at a price of 102 percent of principal if redeemed
during the twelve months beginning December 15, 1997, or at a price of 100
percent of principal if redeemed on or after December 15, 1998, in each case
together with interest accrued to the redemption date.  The Company presently
expects that, absent unforeseen circumstances, it will seek to retire the Senior
Secured Notes from the Company's cash and marketable securities, to the extent
available, and/or the proceeds of debt financing as early as December 1997.

    The Senior Secured Notes are collateralized by 22 rigs and all of the
capital stock of the Company's direct or indirect subsidiaries, excluding the
stock of Petdrill, Inc., and certain other subsidiaries as defined in the
indenture.  The indenture under which the Senior Secured Notes are issued
imposes significant operating and financial restrictions on the Company.
Such restrictions affect, and in many respects limit or prohibit, among other
things, the ability of the Company to incur additional indebtedness, make
capital expenditures, create liens, sell assets, engage in mergers or
acquisitions, and make dividends or other payments.

    In February 1996, the Company entered into an agreement to extend to
December 1998 its $25 million revolving credit and letter of credit facility
with a major international bank.  Under the credit facility, the Company may
borrow an amount of up to 80 percent of eligible accounts receivable. 
Borrowings under the facility would accrue interest at the lowest of three
market-based interest rates.  The unused portion of the line of credit is
subject to an annual commitment fee of .1875 percent.  There were no
borrowings or letters of credit outstanding under the facility as of
December 31, 1995 or 1994.  As of December 31, 1995, the Company was eligible
to borrow the full $25 million under the revolving credit facility.

Note 4 - Commitments and Contingencies

    The Company has numerous noncancelable operating leases for office
facilities and equipment.  The leases have remaining terms ranging up to six
years, some of which may be renewed at the Company's option.  Certain leases
are subject to rent revisions based on the Consumer Price Index or increases
in building operating costs.  Rent expense for 1995, 1994, and 1993 was $4.9
million, $6.9 million, and $6.1 million, respectively.

    Future minimum rental payments for the Company's lease obligations as of
December 31, 1995, were as follows:
<TABLE>
                                                                  
                                                    (In millions)
   Year ending December 31:
     <C>                                               <C>
     1996                                              $  2.4
     1997                                                 2.3
     1998                                                 2.2
     1999                                                 2.2
     2000                                                 2.1
     Later years                                           .6
                                                        -----
              Total future minimum rental payments      $11.8
                                                        =====
</TABLE>
     During 1995 the Company completed the purchase of a concrete island
drilling system ("CIDS"), the Glomar Beaufort Sea I, which was previously
chartered by the Company under a long-term lease.  The Company has agreed to pay
a purchase price of up to $9.3 million out of the rig's future cash flow or
proceeds from the sale of the rig, if any.  The full $9.3 million will be
paid only if the Company's share of future cash flow or rig sale proceeds
exceeds $48 million.  The Company will have no obligation to pay any amount if
the rig fails to generate any future cash flow.  The Glomar Beaufort Sea I is
a special-purpose mobile offshore rig designed for arctic operations and was
last under contract in 1990.

     The Company is involved in various lawsuits resulting from personal
injury and, from time to time, performance of services and property damage.
The Company maintains insurance coverage against certain general and marine
public liability, including liability for personal injury, in the amount of
$200 million, subject to a self-insured retention of no more than $250,000
per occurrence.  In addition, the Company's rigs and related equipment are
separately insured under hull and machinery policies against certain marine and
other perils, subject to a self-insured retention generally of no more than
$300,000 per occurrence.  The Company accrues for its share of the anticipated
cost of settlement of claims in the normal course of business; actual costs have
generally been within management's expectations.  In the opinion of management,
resolution of these matters will not have a material adverse effect on its
results of operations, financial position or cash flows.

     The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period.  Actual results could differ from those estimates.

Note 5 - Financial Instruments

   Concentrations of Credit Risk

   The market for the Company's services and products is the offshore oil and
gas industry, and the Company's customers consist primarily of major integrated
international oil companies and independent oil and gas producers.  The Company
performs ongoing credit evaluations of its customers and generally does not
require material collateral.  The Company maintains reserves for potential
credit losses, and such losses have been within management's expectations.

   At December 31, 1995 and 1994, the Company had cash deposits concentrated
primarily in four major banks.  In addition, the Company had certificates of
deposits, commercial paper and Eurodollar time deposits with a variety of
companies and financial institutions with strong credit ratings.  As a result
of the foregoing, the Company believes that credit risk in such instruments is
minimal.

   Fair Values of Financial Instruments

   The estimated fair value of the Company's $225.0 million carrying value of
long-term debt approximated $248.0 million and $240.8 million as of December 31,
1995 and 1994, respectively.  The estimates of fair values were based on quoted
market prices.  The fair values of the Company's cash equivalents, marketable
securities, trade receivables and trade payables approximated their carrying
values due to the short-term maturities of these instruments (see Note 2).

Note 6 - Capital Stock

    The Company is authorized to issue 300,000,000 shares of common stock,
$0.10 par value per share, and 10,000,000 shares of preferred stock, $0.01 par
value per share.  As of December 31, 1995, 133,541,917 shares of common stock
were unissued, including 13,541,852 shares reserved for issuance under stock
option and incentive plans.  None of the preferred stock was issued or
outstanding as of December 31, 1995.

    The indenture governing the Senior Secured Notes contains certain
restrictions with respect to the payment of dividends on the common stock
(other than stock dividends).  Specifically, the indenture restricts the payment
of dividends based on (i) availability of funds under a formula based on
previously unapplied cumulative net income since September 30, 1992 plus
certain stock sale proceeds after December 23, 1992 and (ii) satisfaction of the
then applicable minimum interest coverage ratio for debt incurrence.  Cumulative
net income for purposes of the test excludes gains or losses on asset sales and
certain other nonrecurring charges or credits specified in the indenture.
Although the Company was not prohibited from paying cash dividends under the
terms of the indenture as of December 31, 1995, management does not intend to
declare any cash dividends in the foreseeable future.

    The Company has three stock option plans, the Global Marine Inc. 1989 Stock
Option and Incentive Plan (the "Employee Plan"), the Global Marine Inc. 1994
Non-Employee Stock Option and Incentive Plan (the "Non-Employee Plan"), and the
1990 Non-Employee Director Stock Option Plan (the "Director Plan").  Under the
Employee Plan, incentive and non-qualified options to purchase shares of
common stock may be granted to key employees; under the Non-Employee Plan,
non-qualified options may be granted to certain non-employees; and under both
plans, shares of common stock may be sold at prices below the market price at
the time of the sale.  Under the Director Plan, non-qualified options to
purchase shares of common stock are automatically granted each year to
outside directors of the Company.  Under the Plans, one-half of each option
grant outstanding at December 31, 1995 was exercisable beginning one year after
the date of grant with the remainder exercisable after two years.  Options
expire ten years after the date of grant.  Options become exercisable in full if
more than 50 percent of the Company's outstanding common stock is acquired by
a person or a single group of persons.

    The following is a summary of stock option transactions:
<TABLE>
                                    Number         
                                   Of Shares        Option Price
                                 Under Option         Per Share
                                 ------------      -------------
  

<S>                               <C>              <C>      
Outstanding, December 31, 1992     7,500,400       $0.56 to $5.44
   Granted                         1,825,000       $3.00 to $4.63
   Exercised                        (779,500)      $0.56 to $4.81
   Canceled                         (183,200)      $1.69 to $5.44
                                  ----------

Outstanding, December 31, 1993      8,362,700      $0.56 to $5.44
   Granted                          1,761,900      $4.13 to $4.75
   Exercised                        (484,500)      $0.56 to $3.50 
   Canceled                         (414,900)      $4.44 to $5.44
                                  ----------

Outstanding, December 31, 1994     9,225,200       $0.56 to $5.44
   Granted                         2,236,500       $3.63 to $6.69
   Exercised                      (1,615,299)      $0.56 to $5.44
   Canceled                          (11,000)      $3.63 to $4.19
                                  ----------

Outstanding, December 31, 1995     9,835,401       $0.56 to $6.69
                                  ==========

Exercisable, December 31,
    1995                           6,753,201 
    1994                           6,586,550 
</TABLE>

    During 1995 and 1994, up to 262,500 and 200,000 shares of common stock,
respectively, were offered for conditional sale under the Employee Plan to
certain key employees at a price of $0.10 per share.  The exact number of shares
to be offered is dependent on the performance of the Company as measured
against certain long-term performance goals.  To the extent the performance
goals are met, shares offered in 1995 and 1994 will be issued in 1998 and 1997,
respectively.

    Shares of common stock available for future option grants and incentive
stock sales under the option plans totaled 3,243,951 and 5,830,637 at December
31, 1995 and 1994, respectively.  

Note 7 - Net Income (Loss) per Common Share

    Primary and fully diluted net income per common share were computed by
dividing net income by the weighted average number of common shares outstanding
and, for those periods in which they had a dilutive effect, shares contingently
issuable due to outstanding employee stock options and incentive sales.  The
net loss per common share was computed by dividing the net loss by the weighted
average number of common shares outstanding.  

    Primary net income or loss per common share was based on 165,142,881
shares for 1995, 163,828,711 shares for 1994, and 151,984,669 shares for 1993. 
Primary shares excluded contingently issuable shares because their effect was
either immaterial or antidilutive.

    Fully diluted net income per common and common equivalent share was based on
172,540,316 and 166,996,378 shares for 1995 and 1994, respectively.

Note 8 - Income Taxes

    The provision for income taxes consisted of the following:
<TABLE>
                                        1995      1994      1993
                                       ------    ------    ------
                                             (In millions)         
        
<S>                                     <C>       <C>        <C>
Current - Foreign                       $ 2.3     $ .9       $ .8
        - U.S. federal                     .9      (.3)         -
        - State                             -        -        (.5)
                                        -----     ----       ----
    Provision for income taxes          $ 3.2     $ .6       $ .3
                                        =====     ====       ====
</TABLE>

    A reconciliation of the differences between income taxes computed at the
U.S. federal statutory rate of 35 percent and the Company's reported provision
for income taxes follows:
<TABLE>
<CAPTION>
                                                               1995        1994     1993 
                                                              ------      ------   ------
                                                                 (Dollars in millions)
        
<S>                                                           <C>         <C>       <C>
Income tax expense (benefit) at statutory rate                $ 19.3      $ 1.9     $(9.2)
Utilization of net operating loss carryforwards                (12.9)         -         -
Income (deductions) not recognized for financial net income     (7.8)      (1.9)      8.7
Foreign tax provision                                            2.3         .9        .8
Alternative minimum tax                                           .9          -         -
State tax provision                                                -          -       (.5)
Amortization of discount on note payable                           -          -        .3
Other, net                                                       1.4        (.3)       .2
                                                              ------      -----     -----
   Provision for income taxes                                 $  3.2      $  .6     $  .3
                                                              ======      =====     =====

   Effective tax rate                                            5.8%      11.1%      1.1%
                                                              ======      =====     =====
</TABLE>
    Deferred tax assets and liabilities are recorded in recognition of the
expected future tax consequences of events that have been recognized in the
Company's financial statements or tax returns.  The significant components of
the Company's deferred tax assets and liabilities as of December 31 were as
follows:
<TABLE>

<CAPTION>
                                                                   1995           1994
                                                                  ------         ------
                                                                        (In millions)
Deferred tax assets:
    <S>                                                              <C>         <C>
    Net operating and capital loss carryforwards                     $ 402.6     $ 415.5
    Investment tax credit carryforwards                                 28.7        29.0
    Accrued expenses not currently deductible                            7.9         1.2
                                                                      ------     -------
                                                                       439.2       445.7 
       Less: Valuation allowance                                      (381.8)     (395.8)
                                                                      ------     -------
Deferred tax assets, net of valuation allowance                         57.4        49.9 
                                                                      ------     -------

Deferred tax liabilities:
    Depreciation and depletion for tax in excess of book expense        28.0        19.2
    Tax benefit transfers                                               22.1        26.6
    Income recognized for book in excess of tax                          6.3         2.7
    Other                                                                1.0         1.4
                                                                      ------     -------
      Total deferred tax liabilities                                    57.4        49.9
                                                                      ------     -------

    Net deferred tax asset recognized in consolidated balance sheet   $    -     $     -
                                                                      ======     =======
</TABLE>
     The Company's ability to utilize the net operating loss carryforwards
and other deferred tax assets is dependent on the amount and timing of future
earnings.  Due to the uncertain nature of their ultimate realization, the
Company has recorded against the deferred tax assets a valuation allowance in
the amount of $381.8 million as of December 31, 1995.  The amount of the
valuation allowance is subject to periodic review.  A reasonable possibility
exists that the conditions which existed at December 31, 1995 giving rise to
the recognition of the valuation allowance as of that date may change in the
near term. If the allowance is reduced in a future period, the adjustment
would be recorded as a reduction to income tax expense.

     As of December 31, 1995, the Company had $1,134.2 million in net operating
loss carryforwards ("NOLs") and $28.7 million in investment tax credit
carryforwards ("Credits") expiring as follows:
<TABLE>
                                                          NOLs        Credits
                                                        -------       -------
                                                            (In millions)
     Year ending December 31:
              <C>                                       <C>             <C>
              1996                                                      $ 6.3
              1997                                                        5.3
              1998                                                        8.7
              1999                                                        8.1
              2000                                      $    46.8         0.3
              2001                                           62.4           -
              2002                                           31.3           -
              2003                                           24.3           -
              2004                                          424.1           -
              2005                                          418.9           -
              2006                                           66.2           -
              2007                                            4.8           -
              2008                                           35.8           -
              2009                                           19.6           -
                                                         --------       -----
                                                         $1,134.2       $28.7
                                                         ========       =====
</TABLE>
    The NOLs and Credits are subject to review and potential disallowance by the
Internal Revenue Service ("IRS") upon audit of the federal income tax returns of
the Company.  Section 382 of the Internal Revenue Code of 1986, as amended, may
impair the future availability of the NOLs and the Credits if there is a change
in ownership of more than 50 percent of the Company's common stock.  This
limitation, if it applied, would limit the utilization of the NOLs and the
Credits in each taxable year to an amount equal to the product of the federal
long-term tax-exempt bond rate prescribed monthly by the IRS and the fair market
value of all the Company's stock at the time of the ownership change.  The
interpretation of Section 382 is subject to numerous uncertainties.
Accordingly, while the Company believes its loss carryforwards are available to
it without limitation, such availability is not certain, nor is it certain that
such carryforwards, if presently available without limitation, will continue to
be available without limitation.

Note 9 - Industry Segment Information

   The Company provides offshore drilling services on a contract daily-rate
basis principally in the U.S. Gulf of Mexico, the North Sea, and offshore West
Africa and on a turnkey basis primarily in the U.S. Gulf of Mexico.  In
addition, the Company has oil and gas production interests principally in the
U.S. Gulf of Mexico.  In the industry segment data which follows, revenues from
turnkey drilling services are included in drilling management services.
Intersegment revenues are recorded at transfer prices which are intended to
approximate the prices charged to unaffiliated customers and have been
eliminated from consolidated revenues.  Operating income consists of revenues
less the related operating costs and expenses, excluding interest and
unallocated corporate expenses.  Adjustments and eliminations with respect
to operating income represent the reduction to drilling management services
operating income in the amount of the aggregate net profit earned in connection
with service contracts on oil and gas properties in which the Company has
economic interests.

<TABLE>
<CAPTION>
                             Drilling
                  Contract   Management                                Adjustments and
                  Drilling    Services    Oil and Gas     Corporate      Eliminations     Consolidated
                  --------   ----------   -----------  ---------------   ------------     ------------
                                                (In millions)
Revenues from unaffiliated customers
   <C>              <C>        <C>          <C>            <C>              <C>              <C>
   1995             $248.9     $209.3       $  9.8         $    -           $   -            $468.0
   1994              211.4      137.8          9.8              -               -             359.0
   1993              200.3       57.1         11.6              -               -             269.0

Intersegment revenues
   1995                9.5        3.5            -              -           (13.0)                -
   1994                4.0        5.0            -              -            (9.0)                -
   1993                2.8        2.8            -              -            (5.6)                -

Total revenues
   1995              258.4      212.8          9.8              -           (13.0)            468.0
   1994              215.4      142.8          9.8              -            (9.0)            359.0
   1993              203.1       59.9         11.6              -            (5.6)            269.0

Operating income 
   1995               54.6       17.3          3.4          (15.0)              -              60.3
   1994               25.6       16.5          3.7          (14.0)           (5.7)             26.1
   1993                4.5        9.8          5.3          (14.2)           (2.2)              3.2

Depreciation, depletion
  and amortization
   1995               27.4 (1)      -          3.0            0.6               -               31.0
   1994               34.9          -          1.9            0.6               -               37.4
   1993               32.0          -          3.3            0.6               -               35.9

Capital expenditures
   1995               66.0        0.3          5.1            2.1               -               73.5
   1994               70.2 (2)      -          4.9            0.8               -               75.9
   1993               36.7          -          3.1            0.8               -               40.6

Identifiable assets
   1995              456.2       22.0         10.6           74.2               -              563.0
   1994              390.4       24.3         19.1           78.6               -              512.4
   1993              379.6        5.4         43.2           64.7               -              492.9
______________________
(1)  Effective January 1, 1995, the Company increased the remaining lives of its
     offshore drilling rigs, resulting in a reduction of $11.2 million in
     depreciation expense for 1995.
(2)  Excludes $3.0 million of common stock issued in connection with the
     acquisition of two offshore drilling rigs.
</TABLE>
    In 1995 one customer provided $40.9 million of contract drilling revenues
and $10.3 million of drilling management revenues.  No single customer provided
more than ten percent of revenues for 1994.  In 1993 one customer provided $29.2
million of contract drilling revenues.  

    Export sales by geographic areas were as follows:
<TABLE>
                                        1995     1994      1993
                                       ------   ------    ------
                                            (In millions)

 <S>                                  <C>       <C>      <C>
 North Sea                            $  80.0   $ 39.2   $  62.9
 West Africa                             68.2     31.2      31.6
 Far East and Australia                  13.3     14.4      10.4
 Trinidad                                11.9     11.8       6.7
 Other                                   20.3      6.6       6.6
                                       ------   ------    ------
                                       $193.7   $103.2    $118.2
                                       ======   ======    ======
</TABLE>
Note 10 - Retirement Plans

    Pensions

    The Company has defined benefit pension plans covering substantially all of
its employees.  For the most part, benefits are based on the employee's
length of service and average earnings for the five highest consecutive calendar
years of compensation during the last fifteen years of service.  Substantially
all benefits are paid from funds previously provided to trustees.  The Company
is the sole contributor to the plans, and its funding objective is to fund
participants' benefits under the plans as they accrue, taking into consideration
future salary increases.  The components of net pension cost were as follows: 
<TABLE>
                                                         1995    1994    1993
                                                        ------  ------  ------
                                                             (In millions)
        
  <S>                                                    <C>     <C>     <C>
  Service cost - benefits earned during the period       $ 1.9   $ 2.1   $ 1.5
  Interest cost on projected benefit obligation            4.1     3.7     3.3
  Actual return on plan assets                            (9.5)    0.9    (2.9)
  Net amortization and deferral                            6.7    (3.5)    0.3
                                                         -----   -----   -----
   Net pension cost                                      $ 3.2   $ 3.2   $ 2.2
                                                         =====   =====   =====
</TABLE>
     The following table sets forth the funded status of the plans by plan type
(for federal income tax reporting purposes) and the amounts recognized in the
Company's consolidated balance sheet as of December 31:
<TABLE>
<CAPTION>
                                                       1995                           1994
                                               -------------------------      -------------------------
                                               Qualified    Nonqualified      Qualified    Nonqualified
                                               ---------    ------------      ---------    ------------
                                                                    (In millions)
  Actuarial present value of plan benefits:
   <S>                                          <C>           <C>              <C>             <C>
   Vested                                       $42.7         $  7.5           $ 33.6          $  6.2
   Nonvested                                      3.5             .3              2.6              .3
                                                -----         ------           ------          ------
     Accumulated benefit obligation              46.2            7.8             36.2             6.5
  Effect of projected salary increases            8.3            1.2              5.4             1.4
                                                -----         ------           ------          ------
     Projected benefit obligation                54.5            9.0             41.6             7.9
  Plan assets at fair value                      46.5            3.0             34.6             2.7
                                                -----         ------           ------          ------
     Projected benefit obligation in 
        excess of plan assets                     8.0            6.0              7.0             5.2
  Unrecognized net loss                          (7.3)          (1.9)            (4.9)           (1.3)
                                                -----         ------           ------          ------
   Accrued pension liability                    $  .7         $  4.1           $  2.1          $  3.9
                                                =====         ======           ======          ======
</TABLE>
     Plan assets consist primarily of listed stocks and bonds, fixed-income
investments and real estate. 

     The Company has established grantor trusts to provide funding for the
benefits payable under certain of the nonqualified plans.  The trusts are
irrevocable, and assets contributed to the trusts can only be used to pay
such benefits with certain exceptions.  Assets of the trusts consisted of
interest-bearing cash in the amount of $1.6 million and $0.5 million as of
December 31, 1995 and 1994, respectively, and were included in other assets on
the consolidated balance sheet.

     The expected long-term rate of return on plan assets used to compute
pension cost was 9.0 percent for 1995, 1994, and 1993.  The assumed rate of
increase in future compensation levels ranged from 5.5 percent to 6.5 percent
for each of 1995, 1994, and 1993.  The discount rate used to compute the
actuarial present value of the projected benefit obligation was 7.25 percent
for 1995, 8.25 percent for 1994 and 7.5 percent for 1993.

    The Company has a defined contribution savings plan in which substantially
all of the Company's domestic employees are eligible to participate.  Company
contributions to the savings plan are based on the amount of employee
contributions.  Charges to expense with respect to this plan totaled $0.6
million for 1995 and $0.5 million for each of 1994 and 1993.

    Other Postretirement Benefits

    The Company provides, for a period of two years following retirement,
health care benefits to retirees, their covered dependents and beneficiaries.
In addition, the Company provides term life insurance to retirees.  Generally,
employees who have reached the age of 55 and have rendered a minimum of five
years of service are eligible for such retirement benefits.  For the most
part, health care benefits are contributory while life insurance benefits are
noncontributory.

    Net postretirement life insurance and health care cost consisted of the
following components:
<TABLE>
<CAPTION>
                                                                      1995     1994     1993
                                                                      ----     ----     ----
                                                                           (In millions)

    <S>                                                               <C>      <C>      <C>
    Service cost - benefits earned during the period                  $0.1     $0.1     $0.1
    Interest cost on accumulated postretirement benefit obligation     0.2      0.2      0.2
                                                                      ----     ----     ----
      Net postretirement life insurance and health care cost          $0.3     $0.3     $0.3
                                                                      ====     ====     ====
</TABLE>
    Benefits under the Company's postretirement life insurance and health
care plans are not funded.  The status of the plans as of December 31 was as
follows:
<TABLE>
<CAPTION>
                                                                                 1995     1994
                                                                                 ----     ----
                                                                                 (In millions)
    Actuarial present value of accumulated postretirement benefit
obligation:

       <S>                                                                      <C>       <C>
       Retirees and dependents                                                  $ 1.2     $ 1.0 
       Active employees eligible for benefits                                     0.5       0.6 
       Active employees not yet eligible for benefits                             0.7       0.8 
       Unrecognized net gain (loss)                                               0.1      (0.1)
                                                                                -----     -----
          Accrued postretirement life insurance and health care liability       $ 2.5     $ 2.3
                                                                                =====     ===== 
</TABLE>
    The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 8.0 percent for 1996, gradually declining
to 6.0 percent by the year 2015 and remaining at that level thereafter.  The
effect of a one-percentage point increase in the assumed health care cost
trend rate for each future year on (i) the portion of the accumulated
postretirement benefit obligation applicable to health care benefits as of
December 31, 1995 and (ii) the net postretirement health care cost for the
year then ended would be immaterial.  The assumed discount rate used in
determining the accumulated postretirement benefit obligation was 7.0 percent
for 1995 and 1994.

Note 11 - Supplemental Cash Flow Information

    Cash interest payments totaled $28.7 million for 1995 and 1994 and $28.9
million for 1993.  Cash payments for income taxes totaled $3.6 million in 1995,
$1.1 million in 1994, and $5.4 million in 1993.

    During 1994, the Company acquired one offshore drilling rig in an
all-cash transaction and two other drilling rigs for $26.0 million in cash plus
750,000 shares of Global Marine Inc. common stock.

    In September 1993, the Company acquired a 100 percent ownership interest
in three offshore drilling rigs in exchange for a 100 percent ownership
interest in its offshore drilling rig, the Glomar Moray Firth I, plus $17.0
million in cash.

SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)

   The Company's estimated net proved reserves and proved developed reserves
of crude oil, natural gas and natural gas liquids are shown in the table below:
<TABLE>
<CAPTION>
                                            1995                         1994                           1993
                                  -------------------------    --------------------------    --------------------------- 
                                     Gas           Oil             Gas           Oil             Gas             Oil
                                  -----------  ------------   -----------    ------------    -----------    ------------
                                  Millions of  Thousands of    Millions of   Thousands of    Millions of    Thousands of
                                  Cubic Feet      Barrels      Cubic Feet      Barrels       Cubic Feet        Barrels
                                  ----------    -----------    -----------   ------------    -----------    ------------

Proved Reserves:
  <S>                               <C>            <C>           <C>           <C>            <C>              <C>
  Balance, January 1                11,837          655           10,588         368           11,816           948 
  Increase (decrease) during the
    year attributable to:
    Revisions of previous estimates    326          208            1,606         349            1,209           (55)
    Extensions, discoveries and  
       other additions               1,136           50            3,652          86            2,120            29
    Production                      (4,382)        (169)          (4,009)       (148)          (4,557)         (154)
    Sales of minerals in place           -            -                -           -                -          (400)
                                    ------         ----           ------        ----           ------          ----

  Balance, December 31               8,917          744           11,837         655           10,588           368
                                    ======         ====           ======        ====           ======          ====

Proved Developed Reserves:
  January 1                         11,674          631           10,588         368           11,816           948
                                    ======         ====           ======        ====           ======          ====

  December 31                        8,893          682           11,674         631           10,588           368
                                    ======         ====           ======        ====           ======          ====
</TABLE>
    Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" natural gas and crude oil reserves
is very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir.
The data for a given reservoir may also change substantially over time as a
result of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions.  Consequently,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the significance
of the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.

    Proved reserves are estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.  All of the Company's proved
reserves are located in the United States.  Proved developed reserves are
those proved reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods.  

    The estimates of the Company's proved oil and gas reserves were prepared
by Ryder Scott Company Petroleum Engineers and were based on data supplied to
them by the Company.  Ryder Scott Company Petroleum Engineers has issued reports
that include descriptions of the bases used in preparing the reserve estimates.
These reports are filed as exhibits to the Company's Annual Report on Form 10-K.

    Capitalized costs of unproved oil and gas properties excluded from the
full cost amortization pool as of December 31, 1995 and 1994 totaled $0.7
million and $1.1 million, respectively.  Costs incurred related to oil and gas
activities consisted of the following:
<TABLE>
                                         1995     1994     1993 
                                        ------   ------   ------
                                             (In millions)

<S>                                     <C>      <C>       <C>
Exploration costs                       $ 4.1    $ 1.1     $ 2.2
Development costs                          .6      2.7        .3
Acquisition of properties                  .4      1.1        .6
                                        -----    -----     -----
    Total                               $ 5.1    $ 4.9     $ 3.1
                                        =====    =====     =====
</TABLE>
    The calculation of estimated future net cash flows in the following table
assumed the continuation of existing economic conditions.  Future net cash
inflows were computed by applying year-end prices (except for future price
changes as allowed by contract) of oil and gas to the expected future production
of proved reserves, less estimated future expenditures (based on year-end costs)
expected to be incurred in developing and producing such reserves.

    The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves as of December 31 follows:
<TABLE>
                                                  1995      1994       1993
                                                 ------    ------     ------
                                                        (In millions)
 
<S>                                             <C>        <C>        <C>
Future cash inflows                             $ 32.2     $ 30.8     $ 29.9

Future production and development costs           11.3       11.1        9.4
                                                ------     ------     ------

Future net cash flows                             20.9       19.7       20.5

Ten percent annual discount for estimated
 timing of cash flows                              3.5        2.8        4.2
                                                ------     ------     ------

Standardized measure of discounted
 future net cash flows relating to
 proved oil and gas reserves                    $ 17.4     $ 16.9     $ 16.3
                                                ======     ======     ======
</TABLE>
    Principal sources of changes in the standardized measure of discounted
future net cash flows follow:
<TABLE>
                                                   1995     1994      1993
                                                  ------   ------    ------
                                                         (In millions)

<S>                                               <C>      <C>      <C>
Balance, January 1                                $ 16.9   $ 16.3   $ 20.5

  Revisions:
     Quantity estimates and production rates         3.9      5.0      2.4
     Prices, net of lifting costs                     .6     (4.0)     (.1)
     Estimated future development costs              (.9)      .1      (.6)
     Accretion of ten percent discount               1.7      1.6      2.0
                                                  ------   ------   ------
      
  Net revisions                                      5.3      2.7      3.7

  Additions, extensions and discoveries
     plus improved recovery                          2.7      5.3      3.0
  Net sales of production                           (7.9)    (7.5)    (9.6)
  Sales and purchases of reserves in place             -        -     (2.5)
  Development costs incurred                          .4       .1      1.2
                                                  ------   ------   ------

Balance, December 31                              $ 17.4   $ 16.9   $ 16.3
                                                  ======   ======   ======
</TABLE>
  Results of operations from producing activities follow:
<TABLE>
                                                      1995       1994     1993
                                                     ------     ------   ------
                                                             (In millions)

<S>                                                  <C>         <C>      <C>
Revenues                                             $  9.8     $  9.8   $ 11.6
                                                     ------     ------   ------

Expenses
  Production costs                                      1.9        2.3      2.0
  Depreciation, depletion and amortization              3.0        1.9      3.3
  Technical support and other                           1.5        1.9      1.0
                                                     ------     ------   ------

                                                        6.4        6.1      6.3
                                                     ------     ------   ------

     Income before income taxes                         3.4        3.7      5.3

  Income tax expense (benefit)                           .1          -      (.5)
                                                     ------     ------   ------

  Results of operations from producing activities 
    (excluding corporate overhead and interest)      $  3.3     $  3.7   $  5.8
                                                     ======     ======   ======
</TABLE>

<TABLE>
CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unaudited)
(In millions, except per share data)
<CAPTION>
                                                          1995                                        1994
                                       ------------------------------------------    --------------------------------------
                                        First      Second      Third      Fourth      First     Second     Third    Fourth 
                                       Quarter     Quarter     Quarter    Quarter    Quarter    Quarter   Quarter   Quarter
                                       -------     -------     -------    -------    -------    -------   -------   ------- 

<S>                                     <C>         <C>         <C>        <C>       <C>         <C>       <C>       <C>
Revenues                                $116.1      $102.4      $135.8     $113.7    $ 68.0      $ 76.3    $91.4     $123.3

Operating income                           9.7        14.7        15.5       20.4       3.8         4.9      6.8       10.6

Income (loss):
  Before accounting change              $  4.5      $ 24.2      $  9.6     $ 13.6    $ (1.7)     $ (0.8)   $ 1.1     $  6.2
  Cumulative effect of change 
     in accounting principle                 -           -           -          -      (3.5)          -        -          -
                                        ------      ------      ------     -----     ------      ------    -----     ------
Net income (loss)                       $  4.5      $ 24.2      $  9.6     $ 13.6    $ (5.2)     $ (0.8)   $ 1.1     $  6.2
                                        ======      ======      ======     ======    ======      ======    =====     ======

Primary income (loss) per share:
  Before accounting change              $  .03      $  .14      $  .06     $  .08    $ (.01)     $  .00    $  .01    $  .04
  Cumulative effect of change
    in accounting principle                  -           -           -          -       (.02)         -         -         -
                                        ------      ------      ------     ------    -------     ------    ------    ------
Primary net income (loss) per share     $  .03      $  .14      $  .06     $  .08    $  (.03)    $  .00    $  .01    $  .04
                                        ======      ======      ======     ======    =======     ======    ======    ======

Price ranges of common stock:
    High                                 4-1/4       5-7/8       7-3/8      8-3/4      4-7/8      4-13/16   4-7/8    5
    Low                                  3-1/2       4-1/8       5-1/8      6          3-3/4      3-5/8     3-3/4    3-5/8
</TABLE>

    Net income for the second quarter of 1995 included a $14.7 million gain on
the sale of an offshore drilling rig.

    During the first quarter of 1994, the Company adopted Statement of
Financial Accounting Standards No. 112, "Employers' Accounting for
Postemployment Benefits."  The cumulative impact of the change as of January 1,
1994 was an increase in the net loss in the amount of $3.5 million ($0.02
per share).  Other than the cumulative effect, the effect of the accounting
change was not material.

    The net loss for the first quarter of 1994 also included $1.1 million in
dividend income.

    Net income for the fourth quarter of 1994 included interest income of
$0.8 million recognized in connection with the favorable settlement of the
Company's demobilization obligations with respect to a third-party owned rig
aboard the Glomar Beaufort Sea I.

    The Company did not declare any dividends on its common stock
in either 1995 or 1994.

                     REPORT OF INDEPENDENT ACCOUNTANTS



To the Board of Directors and Shareholders of Global Marine Inc.

Our report on the consolidated financial statements of Global Marine Inc. and
subsidiaries is included on page 28 of this Form 10-K.  In connection with our
audits of such financial statements, we have also audited the related
financial statement schedule listed in the index on page 56 of this Form 10-K.

In our opinion, the financial statement schedule referred to above, when
considered in relation to the basic financial statements taken as a whole,
presents fairly, in all material respects, the information required to be
included therein.



                                     /s/ Coopers & Lybrand L.L.P. 
        


Houston, Texas
February 9, 1996
<TABLE>
                    GLOBAL MARINE INC. AND SUBSIDIARIES
              SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
                               (In millions)
<CAPTION>
                                         Additions
                                 -------------------------
                                 Balance at     Charged to    Charged to                     Balance
                                  Beginning     Costs and        Other                        at End
      Description                  of Year       Expenses       Accounts      Deductions     of Year
-----------------------------    ----------     ----------    ----------      ----------     -------

Year ended December 31, 1995:
   Allowance for doubtful 
      <S>                           <C>            <C>           <C>             <C>           <C>
      accounts receivable           $ 1.2          $  .1         $   -           $  .2         $ 1.1

Year ended December 31, 1994:
   Reserve for loss on
      operating lease               $ 8.4          $   -          $ 0.2 (a)      $  8.6 (b)    $    -
   Allowance for doubtful
      accounts receivable             1.2             .2              -              .2           1.2

Year ended December 31, 1993:
   Reserve for loss on
      operating lease               $19.6          $   -          $  .7 (a)      $ 11.9 (b)     $ 8.4
   Allowance for doubtful 
      accounts receivable             1.2             .5              -              .5           1.2

(a)  Represents unearned interest income which was charged to an escrow
     account for the lease of the Glomar Beaufort Sea I and which was classified
     as a noncurrent asset.

(b)  Represents lease payments for the Glomar Beaufort Sea I which were made
     from the escrow account described in (a) above.
</TABLE>

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE

     Not applicable.

                                 PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     As permitted by General Instruction G, the information called for by
this item with respect to the Company's directors is incorporated by reference
from the Company's definitive proxy statement to be filed pursuant to
Regulation 14A within 120 days after the end of the last fiscal year.
Information with respect to the Company's executive officers is set forth in
Part I of this Annual Report on Form 10-K under the caption "Executive Officers
of the Registrant."

ITEM 11.  EXECUTIVE COMPENSATION

    As permitted by General Instruction G, the information called for by this
item is incorporated by reference from the Company's definitive proxy statement
to be filed pursuant to Regulation 14A within 120 days after the end of the last
fiscal year.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     As permitted by General Instruction G, the information called for by
this item is incorporated by reference from the Company's definitive proxy
statement to be filed pursuant to Regulation 14A within 120 days after the
end of the last fiscal year.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

    As permitted by General Instruction G, the information called
for by this item is incorporated by reference from the Company's definitive
proxy statement to be filed pursuant to Regulation 14A within 120 days after the
end of the last fiscal year.

                                  PART IV

ITEM 14.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
<TABLE>
                                                                         Page
(a) Financial Statements, Schedules and Exhibits

  <C>    <S>                                                              <C>
   (1)    Financial Statements 
            Report of Independent Accountants                              28  
            Consolidated Statement of Operations                           29
            Consolidated Balance Sheet                                     30
            Consolidated Statement of Cash Flows                           32
            Consolidated Statement of Shareholders' Equity                 33
            Notes to Consolidated Financial Statements                     34
   (2)    Financial Statement Schedule
            Report of Independent Accountants                              53
            Schedule II - Valuation and Qualifying Accounts                54
</TABLE>
          Schedules other than those listed above are omitted for the reason
          that they are not applicable.

  (3)     Exhibits

          The following instruments are included as exhibits to this Annual
          Report on Form 10-K and are filed herewith unless otherwise indicated.
          Exhibits incorporated by reference are so indicated by parenthetical
          information.

 3(i).1   Restated Certificate of Incorporation of the Company as filed with the
          Secretary of State of Delaware on March 15, 1989, effective March 16,
          1989.  (Incorporated herein by this reference to Exhibit 3(i).1 of the
          Registrant's Annual Report on Form 10-K for the year ended December
          31, 1993.)

 3(i).2   Certificate of Amendment of the Restated Certificate of Incorporation
          of the Company as filed with the Secretary of State of Delaware on
          May 11, 1990.  (Incorporated herein by this reference to Exhibit
          3(i).2 of the Registrant's Annual Report on Form 10-K for the year
          ended December 31, 1993.)

 3(i).3   Certificate of Correction of the Restated Certificate of
          Incorporation of the Company as filed with the Secretary of State of
          Delaware on September 25, 1990.   (Incorporated herein by this
          reference to Exhibit 3(i).3 of the Registrant's Annual Report on Form
          10-K for the year ended December 31, 1993.)

3(i).4    Certificate of Amendment of the Restated Certificate of Incorporation
          of the Company as filed with the Secretary of State of Delaware on
          May 11, 1992.  (Incorporated herein by this reference to Exhibit
          3(i).4 of the Registrant's Annual Report on Form 10-K for the year
          ended December 31, 1993.)

3 (i).5   Certificate of Amendment of the Restated Certificate of Incorporation
          of the Company as filed with the Secretary of State of Delaware on
          May 12, 1994.  (Incorporated herein by this reference to Exhibit 4.5
          of the Registrant's Registration Statement on Form S-3 (No. 33-53691)
          filed with the Commission on May 18, 1994.)

 3(ii).1  By-laws of the Company as amended on May 10, 1989.  (Incorporated
          herein by this reference to Exhibit 3(ii).1 of the Registrant's
          Annual Report on Form 10-K for the year ended December 31, 1993.)

 4.1      Indenture, dated as of December 23, 1992, between the Company and
          Wilmington Trust Company, as Trustee, with respect to the Senior
          Secured Notes.  (Incorporated herein by this reference to Exhibit 4.5
          of Post-Effective Amendment No. 2 to the Registrant's Registration
          Statement on Form S-3 (No. 33-34013) filed with the Commission on
          January 22, 1993.)

 4.2      First Priority Naval Mortgage, dated April 29, 1993, from Global
          Marine Drilling Company to Wilmington Trust Company, as Trustee.
          (Incorporated herein by this reference to Exhibit 4.6 of the
          Registrant's Registration Statement on Form S-3 (No. 33-65272) filed
          with the Commission on June 30, 1993.)

 4.3      First Preferred Fleet Mortgage, dated December 23, 1992, from Global
          Marine Drilling Company to Wilmington Trust Company, as Trustee. 
          (Incorporated herein by this reference to Exhibit 4.7 of Post-
          Effective Amendment No. 2 to the Registrant's Registration Statement
          on Form S-3 (No. 33-34013) filed with the Commission on January 22,
          1993.)

 4.4      Release of Vessel from Lien of First Preferred Fleet Mortgage, dated
          April 30, 1993, by Wilmington Trust Company, as Trustee.
          (Incorporated herein by this reference to Exhibit 4.8 of the
          Registrant's Registration Statement on Form S-3 (No. 33-65272) filed
          with the Commission on June 30, 1993.)

 4.5      First Preferred Fleet Mortgage, dated December 23, 1992, from Global
          Marine Deepwater Drilling Inc. to Wilmington Trust Company, as
          Trustee.  (Incorporated herein by this reference to Exhibit 4.8 of
          Post-Effective Amendment No. 2 to the Registrant's Registration
          Statement on Form S-3 (No. 33-34013) filed with the Commission on
          January 22, 1993.)

 4.6      Release of Vessel from Lien of Mortgage, dated January 27, 1993,
          by Wilmington Trust Company, as Trustee.  (Incorporated herein by
          this reference to Exhibit 4.6 of the Registrant's Annual  Report on
          Form 10-K for the year ended December 31, 1993.)

 4.7      First Priority Naval Mortgage, dated March 17, 1993, from Global
          Marine Nautilus Inc. to  Wilmington Trust Company, as Trustee.
          (Incorporated herein by this reference to Exhibit 4.10 of the
          Registrant's Registration Statement on Form S-3 (No. 33-65272) filed
          with the Commission on June 30, 1993.)

 4.8      Release of Vessel from Lien of First Priority Naval Fleet Mortgage,
          dated September 8, 1993, by Wilmington Trust Company, as Trustee. 
          (Incorporated herein by this reference to Exhibit 4.8 of the
          Registrant's Annual Report on Form 10-K for the year ended December
          31, 1993.)

 4.9      Supplement No. 1, dated September 8, 1993, to First Priority Naval
          Fleet Mortgage from Global Marine Nautilus Inc. to Wilmington Trust
          Company, as Trustee.  (Incorporated herein by this reference to
          Exhibit 4.9 of the Registrant's Annual Report on Form 10-K for
          the year ended December 31, 1993.)

 4.10     Assumption Agreement and Supplement No. 2, dated December 16, 1993, to
          First Priority  Naval Fleet Mortgage among Global Marine Drilling
          Company and Wilmington Trust  Company, as Trustee.  (Incorporated
          herein by this reference to Exhibit 4.10 of the Registrant's Annual
          Report on Form 10-K for the year ended December 31, 1993.)

 4.11     First Preferred Fleet Mortgage, dated December 23, 1992, from 
          Global Marine West Africa Inc. to Wilmington Trust Company, as
          Trustee.  (Incorporated herein by this reference to Exhibit 4.10
          of Post-Effective Amendment No. 2 to the Registrant's Registration
          Statement on Form S-3 (No. 33-34013) filed with the Commission on
          January 22, 1993.)

 4.12     First Preferred Ship Mortgage, dated December 23, 1992, from Global
          Marine Adriatic Inc. to Wilmington Trust Company, as Trustee.
          (Incorporated herein by this reference to Exhibit 4.11 of Post-
          Effective Amendment No. 2 to the Registrant's Registration Statement
          on Form S-3 (No. 33-34013) filed with the Commission on January 22,
          1993.)

 4.13     Assumption Agreement and Supplement No.1, dated March 4, 1993, to
          First Preferred Ship Mortgage among Global Marine Adriatic Inc., as
          Original Mortgagor, Global Marine Drilling Company, as Assuming
          Mortgagor, and Wilmington Trust Company, as Trustee.  (Incorporated
          herein by this reference to Exhibit 4.13 of the Registrant's
          Registration Statement on Form S-3 (No. 33-65272) filed with the
          Commission on June 30, 1993.)

 4.14     First Preferred Ship Mortgage, dated December 23, 1992, from Global
          Marine Australia Inc. to Wilmington Trust Company, as Trustee.
          (Incorporated herein by this reference to Exhibit 4.12 of Post-
          Effective Amendment No. 2 to the Registrant's Registration Statement
          on Form S-3 (No. 33-34013) filed with the Commission on January 22,
          1993.)

 4.15     Release of Vessel from Lien of Mortgage, dated May 19, 1995, by
          Wilmington Trust Company, as Trustee.

 4.16     First Preferred Ship Mortgage, dated December 23, 1992, from Global
          Marine Bismarck Sea Inc. to Wilmington Trust Company, as Trustee. 
          (Incorporated herein by this reference to Exhibit 4.13 of Post-
          Effective Amendment No. 2 to the Registrant's Registration Statement
          on Form S-3 (No. 33-34013) filed with the Commission on January 22,
          1993.)

 4.17     First Priority Naval Mortgage, dated March 17, 1993, from Global
          Marine North Sea Inc. to Wilmington Trust Company, as Trustee.
          (Incorporated herein by this reference to Exhibit 4.16 of the
          Registrant's Registration Statement on Form S-3 (No. 33-65272 ) filed
          with the Commission on June 30, 1993.)

 4.18     Subsidiary Pledge Agreement, dated December 23, 1992, between
          Global Marine Adriatic Inc. and Wilmington Trust Company, as Trustee. 
          (Incorporated herein by this reference to Exhibit 4.15 of Post-
          Effective Amendment No. 2 to the Registrant's Registration Statement
          on Form S-3 (No. 33-34013) filed with the Commission on January 22,
          1993.)

 4.19     Subsidiary Pledge Agreement, dated December 23, 1992, between Global
          Marine Australia Inc. and Wilmington Trust Company, as Trustee. 
          (Incorporated herein by this reference to Exhibit 4.16 of Post-
          Effective Amendment No. 2 to the Registrant's Registration Statement
          on Form S-3 (No. 33-34013) filed with the Commission on January 22,
          1993.)

 4.20     Subsidiary Pledge Agreement, dated December 23, 1992, between Global
          Marine Bismarck Sea Inc. and Wilmington Trust Company, as Trustee. 
          (Incorporated herein by this reference to Exhibit 4.17 of Post-
          Effective Amendment No. 2 to the Registrant's Registration
          Statement on Form S-3 (No. 33-34013) filed with the Commission on
          January 22, 1993.)

 4.21     Subsidiary Pledge Agreement, dated December 23, 1992, between
          Global Marine Deepwater Drilling Inc. and Wilmington Trust Company,
          as Trustee.  (Incorporated herein by this reference to Exhibit 4.18 of
          Post-Effective Amendment No. 2 to the Registrant's Registration
          Statement on Form S-3 (No. 33-34013) filed with the Commission on
          January 22, 1993.)

 4.22     Subsidiary Pledge Agreement, dated December 23, 1992, between 
          Global Marine Drilling Company Inc. and Wilmington Trust Company,
          as Trustee.  (Incorporated herein by this reference to Exhibit 4.19
          of Post-Effective Amendment No. 2 to the Registrant's Registration
          Statement on Form S-3 (No. 33-34013) filed with the Commission on
          January 22, 1993.)

 4.23     Subsidiary Pledge Agreement, dated December 23, 1992, between
          Global Marine Nautilus Inc. and Wilmington Trust Company, as Trustee.
          (Incorporated herein by this reference to Exhibit 4.20 of Post-
          Effective Amendment No. 2 to the Registrant's Registration Statement
          on Form S-3 (No. 33-34013) filed with the Commission on January 22,
          1993.)

 4.24     Subsidiary Pledge Agreement, dated December 23, 1992, between
          Global Marine North Sea Inc. and Wilmington Trust Company, as
          Trustee.  (Incorporated herein by this reference to Exhibit 4.21
          of Post-Effective Amendment No. 2 to the Registrant's Registration
          Statement on Form S-3 (No. 33-34013) filed with the Commission on
          January 22, 1993.)

 4.25     Subsidiary Pledge Agreement, dated December 23, 1992, between Global
          Marine West Africa Inc. and Wilmington Trust Company, as Trustee. 
          (Incorporated herein by this reference to Exhibit 4.22 of Post-
          Effective Amendment No. 2 to the Registrant's Registration
          Statement on Form S-3 (No. 33-34013) filed with the Commission on
          January 22, 1993.)

 4.26     Subsidiary Pledge Agreement, dated December 21, 1995, between
          Global Marine International Services Corporation and Wilmington
          Trust Company, as Trustee. 

10.1      Credit Agreement, dated June 24, 1993, among Global Marine Inc.,
          Global Marine Drilling Company, Global Marine Australia Inc.,
          Global Marine Baltic Inc., Global Marine Deepwater Drilling Inc. and
          Societe Generale, New York Branch.  (Incorporated herein by this
          reference to Exhibit 10.1 of the Registrant's Registration
          Statement on Form S-3 (No. 33-65272) filed with the Commission on
          June 30, 1993.)

10.2      Amendment No. 1, dated February 26, 1996, to Credit Agreement among
          Global Marine Inc., Global Marine Drilling Company, Global Marine
          Australia Inc., Global Marine Baltic Inc., Global Marine Deepwater
          Drilling Inc. and Societe Generale, New York Branch.

10.3      Memorandum of Agreement, dated June 6, 1993, between Global Marine
          Inc. and Transocean Drilling AS, and Amendment No. 1 thereto dated
          June 16, 1993.  (Incorporated herein by this reference to Exhibit
          99.1 of the Registrant's Registration Statement on Form S-3
          (No. 33-65272) filed with the Commission on June 30, 1993.)

10.4      Letter of Intent in Order to Form a Joint Venture, dated June 6,
          1993, between Global Marine Inc. and Transocean Drilling AS.
          (Incorporated herein by this reference to Exhibit 99.2 of the
          Registrant's Registration Statement on Form S-3 (No. 33-65272)
          filed with the Commission on June 30, 1993.)

10.5      Purchase and Sale Agreement, dated August 24, 1993, between Global
          Marine Inc. and Transocean Drilling AS.  (Incorporated herein by
          this reference to Exhibit 10.3 of the Registrant's Quarterly Report
          on Form 10-Q for the quarter ended September 30, 1993.)

10.6      Management Agreement (relating to Glomar Moray Firth I), dated
          September 10, 1993, between Global Marine Nautilus Inc. and
          Transocean Drilling AS.  (Incorporated herein by this reference
          to Exhibit 10.4 of the Registrant's Quarterly Report on Form 10-Q
          for the quarter ended September 30, 1993.)

10.7      Management Agreement (relating to Transocean No. 5), dated
          September 10, 1993, between Global Marine Nautilus Inc. and
          Transocean Drilling AS.  (Incorporated herein by this
          reference to Exhibit to 10.5 of the Registrant's Quarterly
          Report on Form 10-Q for the quarter ended September 30, 1993.)

* 10.8    Letter Employment Agreement dated February 14, 1995, between the
          Company and C. Russell Luigs.  (Incorporated herein by this reference
          to Exhibit 10.7 of the Registrant's  Annual Report on Form 10-K for
          the year ended December 31, 1994.)

* 10.9    Consulting Agreement dated February 14, 1986, between Challenger
          Minerals Inc. and  Donald B. Brown.  (Incorporated herein by this
          reference to Exhibit 10.2 of the Registrant's Annual Report on Form
          10-K for the year ended December 31, 1987.)

* 10.10   Form of Letter Severance Agreement dated February 7, 1989, between
          the Company and six executive officers, respectively.  (Incorporated
          herein by this reference to Exhibit 10.5 of the Registrant's Annual
          Report on Form 10-K for the year ended December 31, 1988.)

* 10.11   Letter Severance Agreement dated May 7, 1992,between the Company
          and one executive officer.  (Incorporated herein by this reference
          to Exhibit 10.5 of the Registrant's Annual Report on Form 10-K for
          the year ended December 31, 1992.)

* 10.12   Global Marine Inc. 1989 Stock Option and Incentive Plan. 
          (Incorporated herein by this reference to Exhibit 10.6 of the
          Registrant's Annual Report on Form 10-K for the year ended
          December 31, 1988.)

* 10.13   First Amendment to Global Marine Inc. 1989 Stock Option and
          Incentive Plan. (Incorporated herein by this reference to Exhibit
          10.6 of the Registrant's Annual Report on  Form 10-K for the year
          ended December 31, 1990.)

* 10.14   Second Amendment to Global Marine Inc. 1989 Stock Option and
          Incentive Plan. (Incorporated herein by this reference to Exhibit
          10.7 of the Registrant's Annual Report on Form 10-K for the year ended
          December 31, 1991.)

* 10.15   Third Amendment to Global Marine Inc. 1989 Stock Option and Incentive
          Plan. (Incorporated herein by this reference to Exhibit 10.19 of
          the Registrant's Annual Report on  Form 10-K for the year ended
          December 31, 1993.)

* 10.16   Fourth Amendment to Global Marine Inc. 1989 Stock Option and
          Incentive Plan. (Incorporated herein by this reference to Exhibit
          10.16 of the Registrant's Annual Report on  Form 10-K for the year
          ended December 31, 1994.)

* 10.17   Form of Incentive Stock Sale Agreement dated February 14, 1995,
          between the Company and nine executive officers, respectively. 
          (Incorporated herein by this reference to Exhibit 10.18 of the
          Registrant's Annual Report on Form 10-K for the year ended
          December 31, 1994.)

* 10.18   Form of Incentive Stock Sale Agreement dated February 20, 1996,
          between the Company and two executive officers, respectively.

* 10.19   Form of Performance Stock Memorandum dated June 7, 1994, regarding
          conditional opportunity to acquire Company stock granted to six
          executive officers, respectively.  (Incorporated herein by this
          reference to Exhibit 10.1 of the Registrant's Quarterly Report
          on Form 10-Q for the quarter ended June 30, 1994.)

* 10.20   Form of Performance Stock Memorandum dated February 14, 1995,
          regarding conditional opportunity to acquire Company stock granted
          to six executive officers, respectively.  (Incorporated herein by
          this reference to Exhibit 10.20 of the Registrant's Annual Report on
          Form 10-K for the year ended December 31, 1994.)

* 10.21   Form of Performance Stock Memorandum dated February 20, 1996,
          regarding conditional opportunity to acquire Company stock granted
          to six executive officers, respectively.

* 10.22   Executive Life Insurance Plan.  (Incorporated herein by this
          reference to Exhibit 10.5 of the Registrant's Annual Report on
          Form 10-K for the year ended December 31, 1988.)

* 10.23   Global Marine Inc. Executive Supplemental Retirement Plan of 1990.
          (Incorporated herein by this reference to Exhibit 10.8 of the
          Registrant's Annual Report on Form 10-K for the year ended
          December 31, 1990.)

* 10.24   Global Marine Executive Deferred Compensation Trust as established
          effective January 1, 1995.

* 10.25   Global Marine Benefit Equalization Retirement Plan effective
          January 1, 1990.  (Incorporated herein by this reference to Exhibit
          10.8 of the Registrant's Annual Report on Form 10-K for the year
          ended December 31, 1989.)

* 10.26   Global Marine Benefit Equalization Retirement Trust as established
          effective January 1, 1990.  (Incorporated herein by this reference to
          Exhibit 10.9 of the Registrant's Annual Report on Form 10-K for the
          year ended December 31, 1989.)

* 10.27   Form of Indemnification Agreement entered into between the Company and
          each of its directors and officers.  (Incorporated herein by this
          reference to Exhibit 10.12 of the Registrant's  Annual Report on Form
          10-K for the year ended December 31, 1986.)

* 10.28   Resolutions dated August 3, 1994 regarding Directors' Compensation.

* 10.29   Amended and Restated Retirement Plan for Outside Directors.
          (Incorporated herein by this reference to Exhibit 10.12 of the
          Registrant's Annual Report on Form 10-K for the year ended December
          31, 1990.)

* 10.30   Global Marine Inc. 1990 Non-Employee Director Stock Option Plan
          (Incorporated herein by this reference to Exhibit 10.18 of the
          Registrant's Annual Report on Form 10-K for the year ended
          December 31, 1991.)

* 10.31   First Amendment to Global Marine Inc. 1990 Non-Employee Director
          Stock Option Plan (Incorporated herein by this reference to Exhibit
          10.1 of the Registrant's Quarterly Report  on Form 10-Q for the
          quarter ended June 30, 1995.)

* 10.32   Global Marine Inc. 1995 Management Incentive Award Plan. 
          (Incorporated herein by this reference to Exhibit 10.29 of the
          Registrant's Annual Report on Form 10-K for the year ended
          December 31, 1994.)

* 10.33   Global Marine Inc. 1996 Management Incentive Award Plan.

  11.1    Computation of Earnings Per Common Share.

  21.1    List of Subsidiaries.

  23.1    Consent of Coopers & Lybrand L.L.P., Independent Accountants.

  23.2   Consent of Independent Petroleum Engineers (Ryder Scott Company
         Petroleum Engineers).

  27.1   Financial Data Schedule.  (Exhibit 27.1 is being submitted
         as an exhibit only in the electronic format of this Annual Report on
         Form 10-K being submitted to the Securities and Exchange Commission.
         Exhibit 27.1 shall not be deemed filed for purposes of Section 11
         of the Securities Act of 1933, Section 18 of the Securities Exchange
         Act of 1934 or Section 323 of the Trust Indenture Act, or otherwise be
         subject to the liabilities of such sections, nor shall it be deemed a
         part of any registration statement to which it relates.)

  99.1   Report of Independent Petroleum Engineers dated February 8, 1996.

  99.2   Report of Independent Petroleum Engineers dated February 8, 1995.
         (Incorporated herein by this reference to Exhibit 99.1 of the
         Registrant's Annual Report on Form 10-K for the year ended December 31,
         1994.)

  99.3   Reports of Independent Petroleum Engineers dated February 7, 1994.
         (Incorporated herein  by this reference to Exhibit 99.1 of the
         Registrant's Annual Report on Form 10-K for the year ended December 31,
         1993.)

---------------------------                                
*  Management contract or compensatory plan or arrangement.

     The Company hereby undertakes, pursuant to Regulation S-K, Item 601(b),
     paragraph (4) (iii), to furnish to the Securities and Exchange Commission
     on request agreements defining the rights of holders of long-term debt of
     the Company and its consolidated subsidiaries not filed herewith in
     accordance with said Item.

(b)  Reports on Form 8-K

     The Company did not file any Current Reports on Form 8-K during the last
     quarter of 1995.

SIGNATURES REQUIRED FOR FORM 10-K

     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 MARINE INC.
                                                    (REGISTRANT)

Date:  February 28, 1996                     By:        J. C. MARTIN
                                                 ---------------------------
                                                       (J. C. Martin)
                                                    Senior Vice President
                                                 and Chief Financial 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 and on the dates indicated.

Signature              Title                               Date
---------              -----                               ----

C. R. LUIGS            Chairman of the Board,              February 28, 1996
-------------------    President and Chief
(C. R. Luigs)          Executive Officer

J. C. MARTIN           Senior Vice President and            February 28, 1996
-------------------    Chief Financial Officer
(J. C. Martin)         (Principal Financial
                       Officer) and Director 

THOMAS R. JOHNSON      Vice President and                   February 28, 1996
-------------------    Corporate Controller
(Thomas R. Johnson)    (Principal Accounting Officer)

                        Director
------------------- 
(Patrick M. Ahern)

DONALD B. BROWN         Director                             February 28, 1996
-------------------   
(Donald B. Brown)

E. J. CAMPBELL          Director                             February 28, 1996
-------------------
(E. J. Campbell)

THOMAS CASON             Director                             February 28, 1996
-------------------
(Thomas Cason)

PETER T. FLAWN           Director                             February 28, 1996
-------------------
(Peter T. Flawn)

JOHN M. GALVIN            Director                             February 28, 1996
-------------------
(John M. Galvin)

L. L. LEIGH               Director                             February 28, 1996
-------------------
(L. L. Leigh)

PAUL J. POWERS            Director                             February 28, 1996
-------------------
(Paul J. Powers)

SIDNEY A. SHUMAN          Director                             February 28, 1996
-------------------
(Sidney A. Shuman)

W. R. THOMAS              Director                             February 28, 1996
-------------------
(W. R. Thomas)