<PAGE>   1
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                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                   FORM 10-K



                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997

                        COMMISSION FILE NUMBER 333-12707

                              MARINER ENERGY, INC.
             (Exact name of registrant as specified in its charter)


       DELAWARE                                                86-0460233
(State or other jurisdiction of                             (I.R.S. Employer
incorporation or organization)                            Identification Number)

                      580 WESTLAKE PARK BLVD., SUITE 1300
                              HOUSTON, TEXAS 77079
          (Address of principal executive offices including Zip Code)

                                 (281) 584-5500
                        (Registrant's telephone number)


        SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE

        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      No   X
                                                 ----    ----

         Note: The Company is not subject to the filing requirements of the
Securities Exchange Act of 1934. This annual report is filed pursuant to
contractual obligations imposed on the Company by an Indenture, dated as of
August 1, 1996, under which the Company is the issuer of certain debt.

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

         The aggregate market value of the voting stock held by non-affiliates
of registrant is indeterminable, as there is no established public trading
market for the registrant's common stock.

         As of March 27, 1998, there were 1,000 shares of the registrant's
common stock outstanding.


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<PAGE>   2

                               TABLE OF CONTENTS

<TABLE>
<CAPTION>
Item                                                                                  Page
<S>                                                                                  <C>
PART I
      1.and 2.  Business and Properties
                     (a) Overview ....................................................   1
                     (b) Business Strategy ...........................................   3
                     (c) Reserves.....................................................   4
                     (d) Oil and Gas Properties ......................................   5
                     (e) Production  .................................................   8
                     (f) Productive Wells ............................................   8
                     (g) Acreage .....................................................   9
                     (h) Drilling Activity ...........................................   9
                     (i) Marketing, Customers and Hedging Activities .................  10
                     (j) Competition .................................................  10
                     (k) Regulation ..................................................  11
                     (l) Employees ...................................................  12
      3.    Legal Proceedings ........................................................  12
      4.    Submission of Matters to a Vote of Security Holders ......................  12

PART II
      5.    Market for Registrant's Common Equity and Related Stockholder Matters ....  13
      6.    Selected Financial Data ..................................................  13
      7.    Management's Discussion and Analysis of Financial Condition
                and Results of Operations
                     (a) Introduction ................................................  14
                     (b) General......................................................  14
                     (c) Results of Operations .......................................  15
                     (d) Liquidity and Capital Resources .............................  17
                     (e) Year 2000 Issues ............................................  20
      8.    Financial Statements and Supplementary Data ..............................  22
      9.    Changes in and Disagreements with Accountants on Accounting and
                Financial Disclosure .................................................  42

PART III
      10.   Directors and Executive Officers of the Registrant .......................  42
      11.   Executive Compensation ...................................................  44
      12.   Security Ownership of Certain Beneficial Owners and Management ...........  48
      13.   Certain Relationships and Related Transactions ...........................  49

PART IV
      14.   Exhibits, Financial Statement Schedules and Reports on Form 8-K ..........  53
            Glossary .................................................................  55
</TABLE>


<PAGE>   3

                                     PART I

         In addition to historical information, this Annual Report on Form 10-K
contains statements regarding future financial performance and results and
other statements which are not historical facts. These constitute
forward-looking statements which are subject to risks and uncertainties that
could cause the Company's actual results to differ materially. Such risks
include, but are not limited to, oil and gas price volatility, results of
future drilling, availability of drilling rigs, future production and costs and
other factors. Some of the more important factors that could cause or
contribute to such differences include those discussed in Items 1 and 2
"Business and Properties" and Item 7 "Management's Discussion and Analysis of
Financial Condition and Results of Operations" in this report.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

Certain technical terms used in these Items are described or defined in the
Glossary presented on page 55 of this report.

(a) OVERVIEW

         Mariner Energy, Inc. ("Mariner" or the "Company") is an independent
oil and gas exploration company with principal operations in three geographic
areas of the United States: the shallow water or "shelf" (water depths less
than 600 feet) of the Gulf of Mexico ("Gulf") and onshore areas near the Gulf;
the deeper waters of the Gulf (water depths greater than 600 feet); and the
Permian Basin of West Texas. At December 31, 1997, approximately 90% in value
(based on the present value of estimated future net revenues) of the Company's
oil and gas reserves and most of its current efforts were located in or near
the Gulf, which historically has been a prolific hydrocarbon producing area.
The Company uses advanced evaluation and completion technologies to explore for
and produce oil and natural gas, particularly in the Gulf.

         The Company began its operations in 1983 as a subsidiary of Trafalgar
House plc, a large U.K. conglomerate. As such, the Company conducted oil and
gas operations in the U.S. as part of the Trafalgar House group. In 1989,
Trafalgar House spun-off to its public shareholders its oil and gas operations
in a new company called Hardy Oil & Gas plc, of which the Company became a
subsidiary, and thereafter the Company carried on the U.S. oil and gas
operations of Hardy Oil & Gas plc. Management of the Company and an affiliate
of Enron Capital & Trade Resources ("ECT") formed Mariner Holdings, Inc., which
acquired all the capital stock of the Company from Hardy Holdings Inc. (the
"Acquisition") as part of a management-led buyout effective April 1, 1996.

         As of December 31, 1997, the Company had proved reserves of 161.1
Bcfe, of which 75% was natural gas and 25% was oil and condensate. In addition
to its proved reserves, the Company held an inventory of 23 specific prospects
at December 31, 1997, which it expects will account for most of its exploratory
and exploitation drilling activities over the next two years. The Company held
a total undeveloped leasehold inventory of approximately 170,000 net acres,
including 76 undeveloped Gulf blocks, and held under license or other
arrangement approximately 7,200 square miles of 3-D seismic data and
approximately 229,000 linear miles of 2-D seismic data. Also, at a Central Gulf
of Mexico Oil and Gas Lease Sale conducted by the U.S. Department of the
Interior's Minerals Management Service in March 1998, the Company was the
apparent successful bidder, solely or with others, on 9 additional blocks in
the Gulf deepwater.

         From June 1, 1989 (when the Company began to focus its efforts on the
Gulf), through December 31, 1997, the Company drilled 256 gross (83.2 net)
wells, including 89 gross (28.6 net) exploration and deepwater exploitation
wells. Of these wells, 29 were completed (24 in Gulf shallow water or onshore
and 5 in Gulf deepwater), representing a 33% success rate on its exploration
and deepwater exploitation activities. During the same period, the Company
completed approximately 93% of its development wells. At December 31, 1997, the
Company was in the process of drilling one gross (0.2 net) exploratory well.

         From January 1, 1993 through December 31, 1997, the Company had
increases in annual average daily production of 164%, to approximately 65 Mmcfe
per day. During this period the Company replaced 174% of its annual production
through the drillbit, primarily on Company-generated drilling prospects. During
the period, the Company sold some properties to partially fund the drilling
program. Net of disposals, proved reserves have increased 37% over the period.


                                       1
<PAGE>   4


         The following table sets forth certain summary information with
respect to the Company's oil and gas activities and results during the five
years ended December 31, 1997. Reserve volumes and values were determined under
the method prescribed by the Securities and Exchange Commission, which requires
the application of year-end oil and natural gas prices for each year, held
constant throughout the projected reserve life. See "Reserves" later in this
item and Item 7. "Management's Discussion and Analysis of Financial Condition
and Results of Operations".

<TABLE>
<CAPTION>

                                                                                  Year ended December 31,
                                                       ------------------------------------------------------------------------
                                                        1997             1996            1995            1994           1993
                                                        ----             ----            ----            ----           ----
<S>                                                      <C>              <C>              <C>             <C>            <C>
Proved reserves:
   Oil (Mbbls) ...............................           6,630            5,280            6,669           6,900          6,128
   Natural gas (Mmcf) ........................         121,366           92,284           98,330         100,645         91,060
   Natural gas equivalent (Mmcfe) ............         161,148          123,964          138,344         142,045        127,828
Present value of estimated future net revenues
(in thousands)(1) ............................       $ 183,829        $ 303,363        $ 173,421       $  95,318       $ 94,243
Annual reserve replacement  ratio(2) .........             2.6              1.2              1.2             2.0            1.7
Capital expenditures:
   Capital costs incurred ....................       $  68,868        $  46,399        $  41,772       $  36,923       $  27,966
   Percentage attributable to:
      Exploration, incl. leasehold and
       seismic ...............................            71.1%            79.3%            41.8%           51.5%           44.0%
      Development and other ..................            28.9%            20.7%            58.2%           48.5%           56.0%
   Proceeds from property sales ..............              --        $   7,528        $  20,688       $   3,480       $     215
Production:
   Oil (Mbbls) ...............................             977              750              424              459            470
   Natural gas (Mmcf) ........................          18,004           20,429           13,770           14,362         12,507
   Natural gas equivalents (Mmcfe) ...........          23,866           24,929           16,314           17,116         15,327
Average realized sales price per unit
(including the effects of hedging):
   Oil (per Bbl) .............................       $   18.53        $   18.10        $   17.19        $   15.86      $   17.07
   Natural gas (per Mcf) .....................            2.55             2.39             1.76             1.99           2.10
   Gas equivalent (per Mcfe) .................            2.68             2.50             2.04             2.09           2.24
Costs per Mcfe:
   Lease operating expense ...................            0.44             0.43             0.45             0.42           0.51
   General and administrative expense, net ...            0.13             0.13             0.12             0.11           0.15
   Average finding and development cost(3) ...            1.23             1.04             1.02             1.08           1.27
</TABLE>


     (1)  Discounted at an annual rate of 10%. See "Glossary" included
          elsewhere in this report for the definition of "present value of
          estimated future net revenues".

     (2)  The annual reserve replacement ratio for a year is calculated by
          dividing aggregate reserve additions, including revisions, on an Mcfe
          basis for the year by actual production on an Mcfe basis for such
          year.

     (3)  Average finding and development cost per Mcfe is a rolling average
          calculated by dividing capital expenditures (including estimated
          future capital) related to properties which have been evaluated for
          the rolling period by the ultimate reserve additions for the same
          period. The rolling period is seven years, which management believes
          is the minimum period for meaningful presentation, due to long
          investment cycle times, especially for projects in the Deepwater Gulf
          of Mexico. A six year average was used for the year ended December
          31, 1994 and a five year average was used for the year ended December
          31, 1993, as less than seven years data was available due to the
          demerger of the Company in 1989.


                                       2
<PAGE>   5

(b) BUSINESS STRATEGY

         Mariner's strategy is to increase reserves, production and cash flows
in a cost effective manner primarily "through the drillbit" -- emphasizing
internal growth through exploration, exploitation and development of internally
generated prospects. The Company prefers to operate the wells in which it
participates and to hold substantial working interests therein.

         The Company applies a "portfolio management" approach to its drilling
activities that is directed at balancing risk and potential returns, targeting
8 to 12 new exploration/exploitation prospects each year. Since the
management-led buyout in 1996, capital is generally dedicated to the Company's
exploration/exploitation effort in the following proportions.


     o    25% Deepwater Gulf Exploitation, consisting of low risk, moderate
          reward projects;

     o    50% Deepwater Gulf Exploration, consisting of moderate risk, high
          reward projects and;

     o    25% Shallow Gulf/Onshore Gulf Coast, consisting of high risk, high
          reward projects.

         In Gulf shallow water and near onshore fields, the Company focuses on
prospects with attractive value-adding potential and attractive rates of return
resulting from expected short production lead times, quick payout periods and
low lease operating expenses.

         Mariner's Gulf deepwater operations were initially focused on the
exploitation of previously discovered reservoirs which the Company believes are
usually smaller than the target size of larger oil companies. The Company
believes that its deepwater expertise, relatively low operating costs and
potential for royalty relief enable it to profitably develop small and mid-size
fields in deeper water of the Gulf. During 1996 and 1997, the Company also
expanded its efforts in the Deepwater Gulf to include moderate risk exploration
for undrilled reservoirs because of (i) the large reserve potential (relative
to the Company's size) that it believes can be found in deepwater areas
targeted by it and (ii) the relative immaturity of these exploration activities
compared to other Gulf activities.

         The Company also devotes a smaller portion of its capital resources to
low risk development operations in the Spraberry Trend of the Permian Basin of
West Texas, which continues to be important to the Company's internal growth
strategy by providing a consistent source of cash flow for use in the Company's
other activities.

         The Company currently plans to focus the majority of its prospect
acquisition, exploration, exploitation and development efforts in the shallow
water and deepwater of the Gulf. To support these plans, Mariner acquired 24
offshore blocks in 1995, 28 in 1996 and 19 in 1997 through lease sales and
farm-ins, 38 of which were in the deepwater. During 1997, the Company obtained
a majority interest and became operator of a potentially significant deepwater
exploitation project, located in four blocks in the Mississippi Canyon area of
the Gulf, know as the "Pluto" project. See section (d)(ii) under this Item and
Item 7 "Management's Discussion and Analysis of Financial Condition and Results
of Operations" for additional information.

         Mariner believes that the following competitive advantages distinguish
the Company from other independent oil and gas companies. These advantages are
responsible to a significant extent for the success of the Company's
exploration and exploitation efforts in recent years.

         Geographic Focus. A substantial portion of the Company's activities is
concentrated in the Gulf where the Company has been successful in developing
valuable reserves. The Company believes that exploration and development in
shallow water of the Gulf offer attractive returns because of short production
lead times, high production rates and relatively low capital and operating
costs. The Company believes that its activities in the Deepwater Gulf offer
attractive returns because of (i) large reserve potential, (ii) technological
developments, (iii) the early stages of development in the area and (iv) a
favorable competitive niche directed at exploiting small to moderate potential
fields previously discovered by large oil companies but bypassed for
exploitation by them as they search for larger fields -- a niche which few
other independent oil companies of Mariner's size are pursuing because of the
significant technological and capital expenditure requirements. With a
significant portion of its reserves in the Gulf, the Company benefits from the
lower lease operating expenses associated with offshore wells which are
generally more productive than typical onshore wells and allow for
concentration of labor and equipment. In addition, production from such wells
is not burdened by severance or ad valorem taxes, and royalties paid on Gulf
oil and gas production to the federal government are generally lower than


                                       3

<PAGE>   6

royalties paid in respect of onshore production to private landowners.
Moreover, gas produced in the Gulf and near onshore areas usually receives top
current prices because of its quality and proximity to competitive pipeline
transportation, and oil produced in the areas of the Company's geographic focus
is usually of good quality (as opposed to heavy crude or high sulfur content
crude oil which require special processing) and typically carries prices that
reflect such quality.

         Concentration of Reserves and Efficient Operations. The Company
actively manages its portfolio of producing reserves to optimize concentration
within its geographic areas of focus. At December 31, 1997, approximately 89%
by value of the Company's reserves were located in nine fields, including six
fields that were producing oil and gas as of that date. This concentration,
while increasing the Company's dependence on the economic performance of those
fields, enables the Company to achieve efficiencies in its operations and to
control its general and administrative expenses relative to competitors that
have more widespread operations. Consistent with its emphasis on reserve
concentration and low cost of operations, the Company regularly reviews its
properties and, when appropriate, sells properties that are marginally
profitable or outside of its areas of concentration.

         Application of Technology. The Company applies state-of-the-art proven
technology to minimize exploration risk and maximize returns. Although the
Company's database includes extensive 2-D and 3-D seismic data, virtually all
of the Company's exploration and exploitation prospects are generated using 3-D
seismic data. While 2-D seismic data, which historically has been used by oil
and gas exploration companies, is still an important exploration tool, the use
of 3-D data lowers the risk of dry holes and optimizes exploitation and
development spending. The Company also utilizes proven state-of-the-art subsea
production technology to reduce capital expenditures that might otherwise be
associated with deepwater developments (for example, the construction of
additional production platforms). The ability to utilize these and other
technologies often allows the Company economically to pursue attractive
projects below the size thresholds of large oil companies. The Company's
ability to retain personnel capable of using advanced technology is an
important factor in maintaining the Company's advantage in this area.

         Disciplined Approach to Exploration. The Company employs careful risk
analysis to determine its drilling priorities, balancing the required capital
outlay against the expected value of the well. Having confidence in its staff
of explorationists, the Company typically has generated its own prospects and
conducted its own risk analysis. The exploration, exploitation and development
of internally generated prospects accounted for 80% by value of the Company's
reserves at December 31, 1997. The Company attempts to focus its exploration
and exploitation efforts on prospects with high value-adding potential while at
the same time managing its risks by drilling approximately 8 to 12 exploitation
and exploratory wells per year. Furthermore, the Company generally keeps its
working interests at or below 50% by seeking industry participants in its
exploitation and exploration activities in order to reduce its exposure on any
single undertaking and to leverage its drilling program overhead cost through
reimbursements received from partners.

         Experienced Management with Significant Equity Incentives. The
management team has considerable expertise in the oil and gas industry and
significant experience working with the Company. All present key employees of,
and consultants to, the Company are eligible to participate in an incentive
program that provides overriding royalty interests in successful projects. The
Company believes its overriding royalty program provides a strong alignment of
management's and investors' interests. In addition, the Company believes this
program is a significant reason why it has been able to retain the services of
the members of its senior management team, most of whom have been working
together at the Company for over 10 years. In connection with the Acquisition,
certain members of management and other key personnel of the Company have
purchased approximately 4% of the common stock of Mariner Holdings and acquired
options to purchase an additional 12% of the common stock of Mariner Holdings.

(c) RESERVES

         The following table sets forth certain information with respect to the
Company's proved reserves by geographic area as of December 31, 1997. Reserve
volumes and values were determined under the method prescribed by the
Securities and Exchange Commission which requires the application of year-end
prices for each year, held constant throughout the projected reserve life. The
reserve information as of December 31, 1997, is based upon a reserve report
prepared by the independent petroleum consulting firm of Ryder Scott Company.
Producing oil and natural gas reservoirs generally are characterized by
declining production rates that vary depending upon reservoir characteristics
and other factors. Therefore, without reserve additions in excess of production
through successful exploration and development activities, the Company's
reserves and production will decline. See Note 10 to the Financial Statements
of the Company included elsewhere in this annual report for a discussion of the
risks inherent in oil and natural gas estimates and for certain additional
information concerning the proved reserves of the Company.



                                       4
<PAGE>   7

<TABLE>
<CAPTION>
                                                                  At December 31, 1997
                                         --------------------------------------------------------------------------
                                                                                        Present Value of
                                             Proved Reserve Quantities         Estimated Future Net Revenues (1)
                                         --------------------------------     -------------------------------------
                                            Oil  Natural Gas        Total     Developed     Undeveloped     Total
<S>                                     <C>           <C>          <C>        <C>           <C>          <C>
Geographic Area                          (MBbls)       (MMcf)      (MMcfe)       ($000)        ($000)       ($000)
---------------                          -------       ------      -------       ------        ------       ------
Gulf of Mexico Shelf and
      Gulf Coast Onshore..........         1,770       50,517       61,139     $104,696        $2,140      $106,836
Gulf of Mexico Deepwater.......            1,547       53,883       63,165       33,709        24,585        58,294
Permian Basin......................        3,313       16,966       36,844       13,514         5,185        18,699
                                           -----      -------      -------     --------       -------      --------
Total............................          6,630      121,366      161,148     $151,919       $31,910      $183,829
                                           =====      =======      =======     ========       =======      ========

    Proved Developed Reserves......        3,486       76,343       97,259     $151,919
                                           =====      =======      =======     ========
</TABLE>

(1)  Discounted (at 10%) present value as of December 31, 1997 (year-end prices
held constant). The amounts are before income taxes and therefore are not the
same as the "Standardized Measure" disclosed in Note 10 of the Notes to
Financial Statements.

         The Company's estimates of proved reserves set forth in the foregoing
table do not differ materially from those filed by the Company with other
federal agencies.

(d) OIL AND GAS PROPERTIES

         (I) SIGNIFICANT PRODUCING PROPERTIES

         The Company owns oil and gas properties, both producing and for future
exploration and development, onshore in Texas and offshore in the Gulf,
primarily in federal waters. The Company's six largest producing properties, as
shown in the following table, accounted for approximately 60% of the Company's
proved reserves as of December 31, 1997.

<TABLE>
<CAPTION>
                                                                                     As of December 31, 1997
                                                                         --------------------------------------------
                                                Mariner      Ownership   Producing      Net Average          Net Proved
                                                ----------------------                Daily Production        Reserves
                                                Working      Net Revenue   Wells   -----------------------
                                                Interest      Interest    (gross)  Oil (Bbls)    Gas (Mmcf)    (Mmcfe)
                                                --------     -----------  -------  ---------     ----------  ---------
<S>                                               <C>           <C>          <C>     <C>            <C>        <C>
Gulf Shallow Water and
       Near Onshore Areas:
  Sandy Lake ..........................           48.3%         36.0%        6       1,964          11.4       24,517
  Brazos A-105 ........................           12.5%          9.9%        5          15           9.4       15,955
  Matagorda Island 683/703 ............           25.0%         20.1%        4           2           4.3        5,469
Gulf of Mexico Deepwater:
  Green Canyon 136 ....................           25.0%         21.1%        2          30           7.5        5,666
  Garden Banks 240 ....................           33.0%         27.2%        1          47           5.4        8,401
Permian Basin of West Texas:
  Spraberry Aldwell Unit ..............           70.3%         54.4%       73         439            2.0       36,609
                                                                                                                ------
Totals - Principal Producing Properties                                                                         96,617
                                                                                                                ======
</TABLE>



                                       5

<PAGE>   8

        Following is additional information regarding the properties in the
table shown above.

Gulf Shallow Water and Near Onshore Areas

         SANDY LAKE. The Sandy Lake property, located onshore in the Pine
Island Bayou Field of the Texas Gulf Coast, was generated by the Company and
achieved initial production in 1994. The majority of the 4,870 acre property is
located within the city limits of Beaumont, Texas. The Company is the operator
of the property. Six producing wells have been drilled thus far. During 1997,
the Company increased the capacity of its gas processing facility at Sandy
Lake, which in effect controls production, by 60% -- a measure which increased
production from the Sandy Lake field significantly. The field has an estimated
remaining life of 5 years.

         BRAZOS A-105. Brazos A-105 was generated by the Company and achieved
initial production in 1993. The 4,320 acre block is located offshore Texas at a
water depth of approximately 190 feet. Union Oil Company of California is the
operator of the property, and five producing wells have been drilled thus far,
with no additional drilling currently planned. The field has an estimated
remaining life of 11 years.

         MATAGORDA ISLAND 683/703. Matagorda Island blocks 683 and 703 were
acquired by several companies in a bid group, including the Company, and
achieved initial production in 1993. The two 5,760 acre blocks are located
offshore Texas at a water depth of approximately 125 feet. Vastar Resources,
Inc. is the operator of the property, and four producing wells have been
drilled thus far, with no additional drilling currently planned. The field has
an estimated remaining life of 7 years.

Gulf of Mexico Deepwater

         GREEN CANYON 136. Green Canyon 136 was generated by the Company,
acquired through a farmout transaction with Texaco, Inc. ("Texaco") and
achieved initial production in 1995. The 5,760 acre block is located offshore
Louisiana in water depths of approximately 840 to 1,040 feet. The Company
operated the property to the date of first production when Texaco became the
operator. Two producing wells have been drilled thus far, with no additional
drilling currently planned. Green Canyon 136 is tied back, by a specially laid
subsea pipeline and connecting system, to a production platform operated by
Texaco approximately 10 miles from the well sites, and its production is
commingled and marketed with Texaco's production. The field has an estimated
remaining life of 4 years.

         GARDEN BANKS 240. Garden Banks 240 was generated by the Company,
acquired through a swap transaction with Shell Oil Company and achieved initial
production in January 1996. The 5,760 acre block is located offshore Louisiana
at a water depth of approximately 830 feet. The Company is the operator of the
property. One producing well has been drilled thus far, with no additional
drilling currently planned. Garden Banks 240 is tied back by a subsea pipeline
and connecting system to a production platform operated by Chevron
approximately 12 miles from the well site, where its production is commingled
and marketed with Chevron's production. The field has an estimated remaining
life of 7 years.

The Permian Basin of West Texas

         SPRABERRY ALDWELL UNIT. In 1985, the Company acquired its interest in
the Aldwell Unit property, which has been producing since 1949. The 15,776 acre
fieldwide unit is located within the Spraberry Trend and produces from the
unitized Spraberry Formation and non-unitized Dean Formation in Reagan County
in West Texas. The Company is the operator of the property and its working
interest in individual wells ranges from approximately 33% to 84%. An infill
well drilling program was implemented in 1987, and to date 59 wells have been
drilled, all of which are currently producing. The drilling of 20 to 40
additional infill wells (targeted at bringing into production proved
undeveloped reserves) is planned during the next two to four years at a
projected gross cost of approximately $440,000 per well. The field has an
estimated remaining life of 48 years.

         (ii) OTHER SIGNIFICANT PROPERTIES

         In addition to the producing properties described above, the Company
also owns interests in three other properties which, while not producing at
December 31, 1997, represented a significant portion of proved reserves as of
that date. Those properties are described below.


                                       6
<PAGE>   9

         GARDEN BANKS 367. Garden Banks 367 was generated by the Company and
acquired at a federal offshore Gulf of Mexico lease sale in September 1996. In
late 1997, a successful exploration well was drilled on this 5,760 acre block
located offshore Louisiana at a water depth of approximately 1,100 feet. The
Company is the operator of the property and has a 41.7% working interest and a
40.7% net revenue interest. No additional drilling is currently planned. Garden
Banks 367 is expected to commence production in the first quarter of 1999,
after being tied back by a subsea pipeline and connecting system to a
production platform located approximately 14 miles from the well site. The
field has an estimated life of approximately 6 years after the start of
production, and net proved reserves of 15.7 Bcfe, 96% natural gas, were
included by the Company at December 31, 1997.

         MISSISSIPPI CANYON 357. In 1996, the Company participated as a working
interest owner in a successful exploration well that was drilled on this 3,800
acre block, located offshore Louisiana at a water depth of approximately 450
feet. In 1997, the Company purchased an additional 16.2% working interest in
the property, bringing its working interest to 29.3% with a net revenue
interest of 24.0%. Mariner also became the operator of the property for the
completion, tie-in and operating phase. One producing well has been drilled
thus far, with no additional drilling currently planned. Mississippi Canyon 357
is tied back by a subsea pipeline and connecting system to a production
platform operated by Newfield Exploration Company approximately 2 miles from
the well site, and production commenced in the first quarter of 1998. The field
has an estimated life of approximately 5 years after the start of production,
and net proved reserves of 5.4 Bcfe, 89% natural gas, were included by the
Company at December 31, 1997.

         MISSISSIPPI CANYON 673, 674, 717 AND 718 ("PLUTO"). During 1997, the
Company purchased a 30% working interest in this Deepwater exploitation project
from BHP Petroleum (GOM) Inc. and acquired a 37% working interest in the
project through a farmout transaction with BP Exploration & Oil, Inc.
Subsequent to the acquisitions of interest, the Company was named the operator
of the project, located offshore Louisiana in 2,800 feet of water. Two
exploration and appraisal wells had been drilled in this project prior to the
Company's ownership, encountering pay zones in two separate horizons. Further
drilling of one or two additional production wells, and the installation of a
20 to 25 mile flow line/umbilical system to a host platform on the shelf will
be necessary to fully develop the discovery. Drilling of the first additional
well is expected to commence in early 1999 with concurrent infrastructure
installation, and first production is planned for the fourth quarter of 1999.
Ultimately, the Company expects to own a working interest in the project
between 50% and 75%. The field has an estimated life of approximately 8 years
after the start of production, and net proved reserves of 25.1 Bcfe (69%
natural gas), reflecting a 50% working interest, were included by the Company
at December 31, 1997.

         (iii) DISPOSITION OF PROPERTIES

         The Company periodically evaluates, and, when appropriate, sells,
certain of its producing properties that it considers to be marginally
profitable or outside of its areas of concentration. Such sales enable the
Company to maintain financial flexibility, reduce overhead and redeploy the
proceeds therefrom to activities that the Company believes have a higher
potential financial return. No property dispositions were made by the Company
during 1997. During 1996, the Company sold nonstrategic oil and natural gas
properties located in the Spraberry Trend in Texas for an aggregate amount of
$7.5 million.

         (iv) TITLE TO PROPERTIES

         The Company's properties are subject to customary royalty interests,
liens incident to operating agreements, liens for current taxes and other
burdens, including other mineral encumbrances and restrictions. The Company
does not believe that any of these burdens materially interferes with the use
of such properties in the operation of its business.

         The Company believes that it has satisfactory title to or rights in
all of its producing properties. As is customary in the oil and natural gas
industry, minimal investigation of title is made at the time of acquisition of
undeveloped properties. Title investigation is made, and title opinions of
local counsel are generally obtained, only before commencement of drilling
operations. The Company believes that title issues generally are not as likely
to arise on offshore oil and gas properties as on onshore properties.


                                       7
<PAGE>   10

(e) PRODUCTION

         The following table presents certain information with respect to oil
and natural gas production attributable to the Company's properties, average
sales price received and expenses per unit of production during the periods
indicated.

<TABLE>
<CAPTION>
                                                                              Year ended December 31,
                                                               -------------------------------------------------
                                                                 1997                1996                1995
                                                               -------             --------            ---------
<S>                                                           <C>                   <C>               <C>
Production:
   Oil (Mbbls)                                                    977                 750                 424
   Natural gas (Mmcf)                                          18,004               20,429              13,770
   Gas equivalent (per Mmcfe)                                  23,866               24,929              16,314
Average sales prices including effects of hedging:
   Oil (per Bbl)                                               $18.53              $ 18.10             $ 17.19
   Natural gas (per Mcf)                                         2.55                 2.39                1.76
   Gas equivalent (per Mcfe)                                     2.68                 2.50                2.04
Expenses (per Mcfe):
   Lease operating                                                .44                  .43                 .45
   General and administrative, net (1)                            .13                  .13                 .12
   Depreciation, depletion and amortization                      1.33                 1.25                 .96

Cash margin per Mcfe (2)                                         1.92                 1.77                1.21

</TABLE>

 (1) Net of overhead reimbursements received by the Company from other working
interest owners and amounts capitalized under the full cost accounting method.

(2) Average equivalent gas sales price (including the effects of hedging),
minus lease operating and gross general and administrative expenses.



(f) PRODUCTIVE WELLS

         The following table sets forth the number of productive oil and gas
wells in which the Company owned a working interest at December 31, 1997:

<TABLE>
<CAPTION>

                  Total Productive Wells
                  ----------------------
                  Gross             Net
<S>               <C>             <C>
Oil ...........      81            58.2
Gas ...........      86            13.3
                    ---            ----
     Total ....     167            71.5
                    ===            ====
</TABLE>

         Productive wells consist of producing wells and wells capable of
production, including gas wells awaiting pipeline connections. The Company has
6 wells that are completed in more than one producing horizon; those wells have
been counted as single wells.



                                       8

<PAGE>   11

(g) ACREAGE

         The following table sets forth certain information with respect to the
developed and undeveloped acreage of the Company as of December 31, 1997.

<TABLE>
<CAPTION>
                                Developed Acres (1)    Undeveloped Acres (2)
                               -------------------     --------------------
                                Gross         Net       Gross        Net
                               -------     -------     -------     -------
<S>                             <C>         <C>          <C>         <C>
Texas (Onshore) ..........      20,748      11,427       6,616       3,109
All other states (Onshore)         671         212         644         196
Offshore .................     200,966      46,009     394,820     166,843
                               -------     -------     -------     -------
     Total ...............     222,385      57,648     402,080     170,148
                               =======     =======     =======     =======
</TABLE>

         (1)      Developed acres are acres spaced or assigned to productive
                  wells.

         (2)      Undeveloped acres are acres on which wells have not been
                  drilled or completed to a point that would permit the
                  production of commercial quantities of oil and natural gas
                  regardless of whether such acreage contains proved reserves.

(h) DRILLING ACTIVITY

         Certain information with regard to the Company's drilling activity
during the years ended December 31, 1997, 1996 and 1995 is set forth below.

<TABLE>
<CAPTION>
                                    Year ended December 31,
                      ------------------------------------------------------
                            1997              1996                 1995
                            ----              ----                 ----
                      Gross       Net   Gross      Net       Gross      Net
                      -----       ---   -----      ---       -----      ---
<S>                     <C>      <C>      <C>      <C>       <C>       <C>
Exploratory wells:
   Producing .....      4        1.37     3        0.78       --         --
   Dry ...........      7        1.60     4        1.40        6        2.38
                       --        ----    --        ----       --        ----
       Total .....     11        2.97     7        2.18        6        2.38
                       ==        ====    ==        ====       ==        ====

Development wells:
   Producing .....     11        5.27     5        1.73        3        0.85
   Dry ...........     --          --    --          --       --          --
                       --        ----    --        ----       --        ----
       Total .....     11        5.27     5        1.73        3        0.85
                       ==        ====    ==        ====       ==        ====

Total wells:
   Producing .....     15        6.64     8        2.51        3        0.85
   Dry ...........      7        1.60     4        1.40        6        2.38
                       --        ----    --        ----       --        ----
       Total .....     22        8.24    12        3.91        9        3.23
                       ==        ====    ==        ====       ==        ====
</TABLE>

                                       9

<PAGE>   12


(i) MARKETING, CUSTOMERS AND HEDGING ACTIVITIES

         The Company markets substantially all of the oil and gas production
from Company-operated properties, and from properties operated by others where
Mariner's interest is significant. The majority of the Company's natural gas,
oil and condensate production is sold to a variety of purchasers under
short-term (less than 12 months) contracts, usually at market-sensitive prices.
As to gas produced from the Spraberry Aldwell Unit, the Company has a long-term
agreement as to the sale of such gas and the processing thereof which the
Company believes to be competitive. Similarly, the Company has a gas processing
agreement on its gas production from Sandy Lake which the Company believes has
the effect of pricing its gas production favorably compared to market prices at
that location. The following table lists customers accounting for more than 10%
of the Company's total revenues for the year indicated (a "-" indicates that
revenues from the customer accounted for less than 10% of the Company's total
revenues for that year).

<TABLE>
<CAPTION>
                                        Percentage of total revenues
                                       For the year ended December 31
                                       -----------------------------
Customer                                 1997      1996      1995
--------                                 ----      ----      ----
<S>                                      <C>       <C>       <C>
Genesis Crude Oil LP (formerly
     Howell Crude Oil Company)            19%       13%       --
Panenergy Marketing Co.                   19%       --        --
Enron Capital & Trade Resources Corp.     18%       --        --
Transco Energy Marketing Company          14%       15%       20%
Texaco Natural Gas, Inc.                  --        13%       --
Seneca Resources Corporation              --        10%       20%
Marathon Petroleum Company                --        --        12%
</TABLE>

         Due to the nature of the markets for oil and natural gas, the Company
does not believe that the loss of any one of these customers would have a
material adverse effect on the Company's financial condition or results of
operations.

         Historically, demand for natural gas has been seasonal in nature, with
peak demand and typically higher prices occurring during the colder winter
months.

         From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to reduce its exposure to
price fluctuations and to achieve a more predictable cash flow. The Company
does not engage in hedging activities for speculative purposes. The Company
customarily conducts its hedging strategy through the use of swap arrangements
that establish an index-related price above which the Company pays the hedging
partner and below which the Company is paid by the hedging partner. During
1997, approximately 60% of the Company's equivalent production was subject to
hedge positions, and hedging arrangements through October 1998 cover
approximately 37% of the Company's anticipated equivalent production for 1998.
Hedging arrangements may expose the Company to the risk of financial loss in
certain circumstances, including instances where the Company's production,
which is in effect hedged, is less than expected or where there is a sudden,
unexpected event materially impacting prices. The Company's Revolving Credit
Facility (see pages 20 and 33) places certain restrictions on the Company's use
of hedging. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Changes in Prices and Hedging Activities".

(j) COMPETITION

         The Company believes that the locations of its leasehold acreage, its
exploration, drilling and production capabilities, and the experience of its
management generally enable it to compete effectively. However, the Company's
competitors include major integrated oil and natural gas companies and numerous
independent oil and natural gas companies, individuals and drilling and income
programs. Many of the Company's larger competitors possess and employ financial
and personnel resources substantially greater than those available to the
Company. Such companies may be able to pay more for productive oil and natural
gas properties and exploratory prospects and to define, evaluate, bid for and
purchase a greater number of properties and prospects than the Company's
financial or personnel resources permit. The Company's ability to acquire
additional prospects and to discover reserves in the future is dependent upon
its ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. In addition, there is
substantial competition for capital available for investment in the oil and
natural gas industry.


                                      10

<PAGE>   13


(k) REGULATION

         The Company's operations are subject to extensive and continually
changing regulation, as legislation affecting the oil and natural gas industry
is under constant review for amendment and expansion. Many departments and
agencies, both federal and state, are authorized by statute to issue and have
issued rules and regulations binding on the oil and natural gas industry and
its individual participants. The failure to comply with such rules and
regulations can result in substantial penalties. The regulatory burden on the
oil and natural gas industry increases the Company's cost of doing business
and, consequently, affects its profitability. However, the Company does not
believe that it is affected in a significantly different manner by these
regulations than are its competitors in the oil and natural gas industry.

         (i) TRANSPORTATION AND SALE OF NATURAL GAS

         The FERC regulates interstate natural gas pipeline transportation
rates and service conditions, which affect the marketing of gas produced by the
Company, as well as the revenues received by the Company for sales of such
natural gas. Since the latter part of 1985, the FERC has adopted policies
intended to make natural gas transportation more accessible to gas buyers and
sellers on an open and nondiscriminatory basis. The FERC issued Order No. 636
on April 8, 1992, reflecting the FERC's finding that, under the then-existing
regulatory structure, interstate pipelines and other gas merchants, including
producers, did not compete on a "level playing field" in selling gas. Order No.
636 instituted individual pipeline services restructuring proceedings, designed
specifically to "unbundle" those services provided by many interstate pipelines
(for example, transportation, sales and storage) so that buyers of natural gas
may secure supplies and delivery services from the most economical source,
whether interstate pipelines or other parties. The FERC has issued final orders
in all of the restructuring proceedings, and all of the interstate pipelines
are now operating under new open access tariffs. In addition, the FERC has
announced its intention to reexamine certain of its transportation related
policies, including the appropriate manner in which interstate pipelines
release transportation capacity under Order No. 636 and, more recently, the
price that shippers can charge for released capacity. The FERC also has
established a policy regarding the use of nontraditional methods of setting
rates for interstate gas pipelines in certain circumstances as alternatives to
cost-of-service based rates. A number of pipelines have obtained FERC
authorization to charge negotiated rates as one such alternative.

         Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Company cannot predict when or if any
such proposals might become effective or their effect, if any, on the Company's
operations. The natural gas industry historically has been closely regulated;
thus there is no assurance that the less stringent regulatory approach recently
pursued by the FERC and Congress will continue indefinitely into the future.

         (ii) REGULATION OF PRODUCTION

         The production of oil and natural gas is subject to regulation under a
wide range of state and federal statutes, rules, orders and regulations. State
and federal statutes and regulations require permits for drilling operations,
drilling bonds and reports concerning operations. Most states in which the
Company owns and operates properties have regulations governing conservation
matters, including provisions for the unitization or pooling of oil and natural
gas properties, the establishment of maximum rates of production from oil and
natural gas wells and the regulation of the spacing, plugging and abandonment
of wells. Many states also restrict production to the market demand for oil and
natural gas and several states have indicated interest in revising applicable
regulations. The effect of these regulations is to limit the amount of oil and
natural gas the Company can produce from its wells and to limit the number of
wells or the locations at which the Company can drill. Moreover, each state
generally imposes a production or severance tax with respect to production and
sale of crude oil, natural gas and gas liquids within its jurisdiction.

         (iii) ENVIRONMENTAL REGULATIONS

         GENERAL. Various federal, state and local laws and regulations
governing the discharge of materials into the environment, or otherwise
relating to the protection of the environment, affect the Company's operations
and costs. In particular, the Company's exploration, development and production
operations, its activities in connection with storage and transportation of
crude oil and other liquid hydrocarbons and its use of facilities for treating,
processing or otherwise handling hydrocarbons and wastes therefrom are subject
to stringent environmental regulation. As with the industry



                                      11

<PAGE>   14

generally, compliance with existing regulations increases the Company's overall
cost of business. Such areas affected include unit production expenses
primarily related to the control and limitation of air emissions and the
disposal of produced water, capital costs to drill exploration and development
wells resulting from expenses primarily related to the management and disposal
of drilling fluids and other oil and gas exploration wastes and capital costs
to construct, maintain and upgrade equipment and facilities.

         SUPERFUND. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as "Superfund", imposes liability, without
regard to fault or the legality of the original act, on certain classes of
persons that contributed to the release of a "hazardous substance" into the
environment. These persons include the "owner" or "operator" of the site and
companies that disposed or arranged for the disposal of the hazardous
substances found at the site. CERCLA also authorizes the Environmental
Protection Agency and, in some instances, third parties to act in response to
threats to the public health or the environment and to seek to recover from the
responsible classes of persons the costs they incur. In the course of its
ordinary operations, the Company may generate waste that may fall within
CERCLA's definition of a "hazardous substance". The Company may be jointly and
severally liable under CERCLA for all or part of the costs required to clean up
sites at which such wastes have been disposed.

         The Company currently owns or leases, and has in the past owned or
leased, numerous properties that for many years have been used for the
exploration and production of oil and gas. Although the Company has utilized
operating and disposal practices that were standard in the industry at the
time, hydrocarbons or other wastes may have been disposed of or released on or
under the properties owned or leased by the Company or on or under other
locations where such wastes have been taken for disposal. In addition, many of
these properties have been operated by third parties whose actions with respect
to the treatment and disposal or release of hydrocarbons or other wastes were
not under the Company's control. These properties and wastes disposed thereon
may be subject to CERCLA and analogous state laws. Under such laws, the Company
could be required to remove or remediate previously disposed wastes (including
wastes disposed of or released by prior owners or operators), to clean up
contaminated property (including contaminated groundwater) or to perform
remedial plugging operations to prevent future contamination.

(l) EMPLOYEES

         As of December 31, 1997, the Company had 48 full-time employees. The
Company's employees are not represented by any labor union. The Company
considers relations with its employees to be satisfactory. The Company has
never experienced a work stoppage or strike.


ITEM 3.  LEGAL PROCEEDINGS

         In December, 1996, ETOCO, Inc., which owns a 20% working interest in
one producing well operated by the Company, filed a lawsuit against the Company
in the district court of Hardin County, Texas, alleging damages due to the
Company's refusal to drill an additional well. The plaintiffs currently are
seeking $8.2 million in damages, plus costs. Attempts to settle the claim have
been unsuccessful, and a trial on the matter is scheduled to commence on April
6, 1998. The Company intends to defend itself vigorously against this claim.
Although no assurances can be given, the Company believes that the ultimate
outcome of the above litigation will not have a material adverse effect on the
Company's financial position.

         The Company, in the ordinary course of business, is a claimant and/or
a defendant in various other legal proceedings, including proceedings as to
which it has insurance coverage, in which its exposure, individually and in the
aggregate, is not considered material to the Company.


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

         None.


                                      12

<PAGE>   15


                                    PART II

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

         There is no established public trading market for the Company's common
stock, its only class of equity securities.

ITEM 6.  SELECTED FINANCIAL DATA

         The information below should be read in conjunction with Item 7
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the financial statements included in Item 8 of this report. The
following table sets forth selected financial data of the Company for the
periods indicated.

<TABLE>
<CAPTION>

                                                           Predecessor Company (1)
(All amounts in thousands)                    -------------------------------------------------
                                                    Years Ended December 31,            3 Mos.         9 Mos.        Year
                                              ------------------------------------      Ended          Ended        Ended
                                                1993         1994          1995         3/31/96       12/31/96     12/31/97
                                             ---------     ---------     ---------     ---------     ---------     ---------
<S>                                           <C>         <C>          <C>         <C>             <C>          <C>
STATEMENT OF OPERATIONS DATA:
  Total revenues                             $  34,295     $  35,856     $  33,309     $  13,778     $  48,522     $  64,050
  Lease operating expenses                       7,746         7,118         7,331         2,872         7,938        10,655
  Depreciation, depletion and
    amortization                                15,607        16,221        15,635         6,309        24,747        31,719
  Impairment of oil and gas properties           6,296         6,257            --            --        22,500        28,514
  General and administrative expenses            2,242         1,830         2,028           712         2,406         3,195
                                             ---------     ---------     ---------     ---------     ---------     ---------
      Operating income (loss)                    2,404         4,430         8,315         3,885        (9,069)      (10,033)

  Interest income                                1,513         1,084         9,255         2,167           515           467
  Interest expense                              (7,358)       (8,125)      (12,772)       (3,391)       (7,746)      (10,644)
  Write-off of bridge loan fees                     --            --            --            --        (2,392)           --
                                             ---------     ---------     ---------     ---------     ---------     ---------
      Income (loss) before income taxes         (3,441)       (2,611)        4,798         2,661       (18,692)      (20,210)
  Provision for income taxes                        --            --           338            --            --            --
                                             ---------     ---------     ---------     ---------     ---------     ---------
      Net income (loss)                      ($  3,441)    ($  2,611)    $   4,460     $   2,661     ($ 18,692)    ($ 20,210)
                                             =========     =========     =========     =========     =========     =========

CAPITAL EXPENDITURE AND DISPOSAL DATA:
  Exploration, incl. leasehold/seismic       $  12,285     $  19,016     $  17,460     $   4,926     $  31,885     $  48,933
  Development and other                         15,681        17,907        24,312         2,545         7,043        19,935
                                             ---------     ---------     ---------     ---------     ---------     ---------
    Total capital expenditures               $  27,966     $  36,923     $  41,772     $   7,471     $  38,928     $  68,868
                                             =========     =========     =========     =========     =========     =========
  Proceeds from disposals                    $     215     $   3,480     $  20,688            --     $   7,528            --
                                             =========     =========     =========     =========     =========     =========

BALANCE SHEET DATA (AT END OF PERIOD):
  Oil and gas properties, net, at full
    cost                                     $ 109,002     $ 120,135     $ 125,817     $ 127,095     $ 166,619     $ 175,668
  Long-term receivable from affiliates          18,000         4,000       106,000       104,000            --            --
  Total assets                                 138,435       138,202       250,726       254,301       196,749       212,577
  Long-term debt, less current maturities      109,000       105,500       162,500       162,500        99,525       113,574
  Stockholder's equity                          20,909        18,798        69,258        71,919        77,053        57,174
</TABLE>


(1) - In an acquisition effective April 1, 1996 for accounting purposes,
Mariner Holdings, Inc. acquired all the capital stock of the Company from Hardy
Holdings Inc. as part of a management-led buyout. In connection with the
acquisition, substantial intercompany indebtedness and receivables and
third-party indebtedness of the Company were eliminated. The acquisition was
accounted for using the purchase method of accounting, and Mariner Holdings'
cost of acquiring the Company was allocated to the assets and liabilities of
the Company based on estimated fair values. As a result, the Company's
financial position and operating results subsequent to the acquisition reflect
a new basis of accounting and are not comparable to prior periods. "Predecessor
Company" refers to Mariner Energy, Inc. (formerly named "Hardy Oil & Gas USA
Inc.") prior to the effective date of the acquisition.


                                       13
<PAGE>   16

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

(a) INTRODUCTION

        The following discussion is intended to assist in an understanding of
the Company's financial position and results of operations for each of the
three years in the period ended December 31, 1997. This discussion should be
read in conjunction with the information contained in the financial statements
of the Company included elsewhere in this annual report. All statements other
than statements of historical fact included in this annual report, including,
without limitation, statements contained in this "Management's Discussion and
Analysis of Financial Condition and Results of Operations" regarding the
Company's financial position, business strategy, plans and objectives of
management of the Company for future operations and industry conditions, are
forward-looking statements. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable, it can give no
assurance that such expectations will prove to have been correct.

(b) GENERAL

        A key component of the Company's strategy is based upon growth "through
the drill bit", with heavy emphasis on the exploration, exploitation and
development of prospects in the shallow and deeper waters of the Gulf of
Mexico. This strategy is supported by a capital expenditures plan which
increases over the next several years while the Company builds its prospect
inventory, then levels out to provide an appropriate mix of exploratory and
development spending. Capital resources to support this plan are expected to be
provided by a combination of internally generated cash flows, borrowing against
the Company's Revolving Credit Facility and equity capital contributions (see
pages 20 and 33).

        During 1997, the Company achieved the following in support of its
growth strategy:

         o        Proved reserves of 61.2 Bcfe were added, primarily as a
                  result of (1) drilling 4 successful exploratory wells,
                  including 2 in the Deepwater Gulf and (2) acquiring control
                  of the "Pluto" Deepwater Gulf exploitation project (see page
                  7 for additional information regarding the "Pluto" project).

         o        The Company increased its prospect inventory, adding 19 new
                  blocks in the Gulf of Mexico covering 13 prospects, including
                  17 blocks in the Deepwater Gulf covering 11 prospects.

        Also, at a Central Gulf of Mexico Oil and Gas Lease Sale conducted by
the U.S. Department of the Interior's Minerals Management Service in March
1998, the Company was the apparent successful bidder, solely or with others, on
9 additional blocks in the Gulf deepwater.

        This growth and an increased capital expenditures plan for 1998 may
cause the Company to exceed its available sources of cash flow from internal
sources and its Revolving Credit Facility. In March 1998, Mariner Holdings,
Inc. reached an agreement in principle with management shareholders and an
affiliate of Enron Corp. to contribute approximately $28.0 million to $28.8
million of net equity capital, which is expected to be used to reduce
borrowings on the Company's revolving credit facility and to supplement funding
of the Company's 1998 capital expenditure plan. Closing of this transaction is
expected to occur in April 1998. See further discussion of this transaction
under Item 13 "Certain Relationships and Related Transactions - Planned 1998
Equity Investment". After including the additional equity investment, the
Company's capital resources still may not be sufficient to meet its capital
requirements for 1998 and 1999, and other sources and debt or equity capital
may be necessary for the Company to continue its planned growth strategy.

        The Company's revenue, profitability, access to capital and future rate
of growth are heavily influenced by prevailing prices for natural gas, oil and
condensate, which are dependent upon numerous factors beyond the Company's
control, such as economic, political and regulatory developments. Energy market
prices have been extremely volatile in recent years, and are expected to
continue to be volatile in the future. While the Company uses hedging
transactions from time to time to reduce its exposure to price fluctuations, a
substantial or extended decline in oil and gas prices could have a material
adverse effect on the Company's financial position, results of operations,
future exploration and development plans and access to capital. Subsequent to
December 31, 1997, prices for oil have declined significantly. However, since
the source of approximately 75% of the Company's revenue is from natural gas
production, management believes the current oil price decrease will not
significantly impact the Company's future plans.



                                      14
<PAGE>   17

        Another significant factor affecting the Company will be competition,
both from other sources of energy such as electricity, and from within the
industry. For example, activity in the prolific Gulf of Mexico has accelerated
in recent years, resulting in increased competition for offshore leases,
drilling rigs and services, which is resulting in higher costs to find and
develop reserves in the Gulf Coast area.

        The Company's results of operations may vary significantly from year to
year based upon the factors discussed above and by other factors such as
exploratory and development drilling success, curtailments of production due to
workover and recompletion activities and the timing and amount of reimbursement
for overhead costs received by the Company from its co-owners. Therefore, the
results of any one year may not be indicative of future results.

(c) RESULTS OF OPERATIONS

        The following table repeats certain operating information found in Item
2. of this report with respect to oil and natural gas production, average sales
price received and expenses per unit of production during the periods
indicated.

<TABLE>
<CAPTION>
                                                                Year ended December 31,
                                                         ----------------------------------
                                                            1997         1996        1995
                                                         -------        -------     -------
<S>                                                          <C>           <C>         <C>
Production:
   Oil (Mbbls)                                               977           750         424
   Natural gas (Mmcf)                                     18,004        20,429      13,770
   Gas equivalent (Mmcfe)                                 23,866        24,929      16,314
Average sales prices including effects of hedging:
   Oil (per Bbl)                                         $ 18.53       $ 18.10     $ 17.19
   Natural gas (per Mcf)                                    2.55          2.39        1.76
   Gas equivalent (per Mcfe)                                2.68          2.50        2.04
Expenses (per Mcfe):
   Lease operating                                           .44           .43         .45
   General and administrative, net                           .13           .13         .12
   Depreciation, depletion and amortization                 1.33          1.25         .96
</TABLE>

        (i) 1997 COMPARED TO 1996

        NET PRODUCTION decreased 4% to 23.9 Bcfe in 1997 from 24.9 Bcfe in
1996. Natural gas production decreased by 2.4 Bcf, or 12%, to 18.0 Bcf from
20.4 Bcf. Gas production from offshore properties decreased 3.8 Bcf or 23%,
primarily due to natural production decline, while gas production from onshore
properties increased 1.4 Bcf or 34%, due primarily to the capacity expansion of
the Sandy Lake Central facility, which became operational in the first quarter
of 1997. Oil and condensate production increased by 227 Mbbls to 977 Mbbls from
750 Mbbls, also due primarily to the expansion of the Sandy Lake Central
facility, offset in part by a decrease in other onshore oil production
resulting from the sale of non-core Permian Basin properties in early 1996. The
Company expects net production to increase by 7% to 10% in 1998 over 1997, as
the result of the commencement of production from several 1996 and 1997
discoveries.

        OIL AND GAS REVENUES for 1997 increased by $1.8 million, or 3%,
compared to 1996. The increase was primarily the result of increased oil and
gas sales prices, offset in part by the production decrease described above.
The average realized sales price of natural gas increased 7%, to $2.55 per Mcf
in 1997 from $2.39 per Mcf in 1996, while the realized oil sales price
increased by 2% to $18.53 per Bbl in 1997 from $18.10 per Bbl in 1996.

        HEDGING ACTIVITIES of natural gas for 1997 reduced the average realized
sales price received by $0.22 per Mcf and revenues by $3.9 million. In 1996,
natural gas hedging activities decreased the average realized sales price
received by $0.18 per mcf and revenues by $3.7 million. Hedging activities of
crude oil during 1997 reduced the average sales price received by $0.63 per Bbl
and revenues by $0.6 million, compared with a reduction in the average realized
sales price of $2.55 per Bbl and revenues of $1.9 million during 1996. During
1997, approximately 60% of the Company's equivalent production was subject to
hedge positions compared to 64% in 1996. See "Changes in Prices and Hedging
Activities" below for a summary of 1998 hedging positions as of the date of
this annual report.


                                      15
<PAGE>   18

        LEASE OPERATING EXPENSES decreased 1% to $10.7 million for 1996, from
$10.8 million for 1996. Lease operating expense per Mcfe increased to $0.44 for
1997 from $0.43 for 1996, due primarily to relatively fixed operating expenses
spread over reduced production volumes.

        DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE (DD&A) increased 2% to
$31.7 million for 1997, from $31.1 million for 1996, as a result of a 6%
increase in the unit-of-production depreciation, depletion and amortization
rate to $1.33 per Mcfe from $1.25 per Mcfe, due primarily to increased drilling
and completion costs, partially offset by a 4% reduction in equivalent volumes
produced.

        IMPAIRMENT OF OIL AND GAS PROPERTIES amounting to $28.5 million was
recorded in the first quarter of 1997 for a non-cash full cost ceiling test
impairment using prices in effect at March 31, 1997. Price increases subsequent
to March 31, 1997 were sufficient to avoid the impairment charge, but given the
unpredictable volatility of future prices, the Company elected to record the
charge in order to more conservatively state the book value of its assets.
During the second quarter of 1996, a $22.5 million full cost ceiling writedown
was recorded in conjunction with Mariner Holdings' acquisition of the Company.

        GENERAL AND ADMINISTRATIVE EXPENSES, which are net of overhead
reimbursements received by the Company from other working interest owners,
increased 3% to $3.2 million in 1997, up from $3.1 million in 1996, due
primarily to higher employment and office costs in 1997 which were almost
entirely offset by increased overhead reimbursements during 1997. Accordingly,
there was no change in general and administrative expense per Mcfe of $0.13 for
both 1997 and 1996.

        INTEREST EXPENSE decreased 5% to $10.6 million for 1997, from $11.1
million for 1996, due primarily to the 9% decrease in average outstanding debt
to $103.2 million, from $113.2 million, which was partially offset by a 7%
increase in the average interest rate paid on outstanding debt to 10.38%, from
9.68%. During 1996, the Company wrote off $2.4 million of loan fees related to
debt incurred in connection with the Company's management-led buyout in the
second quarter of 1996. Interest income also decreased 83% to $0.5 million for
1997, from $2.7 million for 1996, due primarily to the retirement of
receivables from affiliates resulting from the acquisition by Mariner Holdings
of the stock of the Company.

        INCOME (LOSS) BEFORE INCOME TAXES decreased to a loss of $20.2 million
for 1997, from a $16.0 million loss for 1996, as a result of the factors
described above.

        (ii) 1996 COMPARED TO 1995

        NET PRODUCTION increased 53% to 24.9 Bcfe in 1996 from 16.3 Bcfe in
1995. During 1996, natural gas production increased by 6.6 Bcf, or 48%, to 20.4
Bcf from 13.8 Bcf. Increased gas production was due to new production from
Green Canyon 136 and Garden Banks 240, and the start-up of the Sandy Lake
Central facility. These increases were partially offset by natural production
decline on other properties. Oil and condensate production in 1996 increased
326 Mbbls, or 77%, to 750 Mbbls from 424 Mbbls, due primarily to the start-up
of the Sandy Lake Central facility offset by the sale of several Spraberry
properties.

        OIL AND GAS REVENUES for 1996 increased by $29.0 million, or 87%,
compared to 1995. The increase was primarily the result of increased oil and
gas production and increased sales prices for oil and gas. The average realized
natural gas sales price increased 36%, to $2.39 per Mcf in 1996 from $1.76 per
Mcf in 1995, while the realized oil sales price increased by 5% to $18.10 per
Bbl in 1996 from $17.19 per Bbl in 1995.

        HEDGING ACTIVITIES of natural gas for 1996 reduced the average realized
sales price received per Mcf by $0.18 and revenues by $3.7 million. In 1995,
hedging activities increased the average realized sales price received by $0.07
per mcf and revenues by $1.0 million. Hedging activities of crude oil which
commenced during 1996 reduced the average sales price received per Bbl by $2.55
and revenues by $1.9 million. During 1996, approximately 64% of the Company's
equivalent production was subject to hedge positions as compared to 33% in
1995.



                                      16
<PAGE>   19

        LEASE OPERATING EXPENSES increased 48% to $10.8 million for 1996, from
$7.3 million for 1995, due primarily to the Green Canyon 136 and Garden Banks
240 fields that began production in late 1995 and early 1996 and start-up of
the Sandy Lake central facility in late 1995. Lease operating expenses per Mcfe
decreased to $0.43 from $0.45 in 1996, due to relatively fixed expenses spread
over increased production.

        DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE (DD&A) increased 99%
to $31.1 million for 1996, from $15.6 million for 1995, as a result of 53%
higher equivalent volumes produced due to initial production on three major
properties at the end of 1995 and to a 30% increase in the unit-of-production
depreciation, depletion and amortization rate to $1.25 per Mcfe from $0.96 per
Mcfe, primarily due to the upward adjustment in oil and gas properties to
allocate the purchase price in the Acquisition.

        IMPAIRMENT OF OIL AND GAS PROPERTIES amounting to $22.5 million in 1996
was recorded in conjunction with a full cost ceiling writedown relating to
Mariner Holdings' acquisition of the Company. No impairment charge was
necessary in 1995.

        GENERAL AND ADMINISTRATIVE EXPENSES, which are net of overhead
reimbursements received by the Company from other working interest owners,
increased 55% to $3.1 million for 1996, from $2.0 million for 1995, due
primarily to expenses incurred in the first quarter of 1996 in connection with
the sale of the predecessor company, the office relocation and lower overhead
recovery due to the completion of three major projects at the end of 1995.
General and administrative expense per Mcfe increased to $0.13 from $0.12 in
1995, due to the higher net expenses described above spread over increased
production.

        INTEREST EXPENSE decreased 13% to $11.1 million for 1996, from $12.8
million for 1995, due primarily to the 31% decrease in average outstanding debt
to $113.2 million, from $165.1 million, which was partially offset by an 18%
increase in the average interest rate paid on outstanding debt to 9.68%, from
8.19%. During 1996, the Company wrote off $2.4 million of loan fees related to
the JEDI Bridge Loan (see page 33) as a result of refinancing a portion of the
amount with the Revolving Credit Facility (see pages 20 and 33). Interest
income also decreased 71% to $2.7 million for 1996, from $9.3 million for 1995,
due primarily to the retirement of receivables from affiliates resulting from
the Acquisition.

        INCOME (LOSS) BEFORE INCOME TAXES decreased to a loss of $16.0 million
for 1996, from $4.8 million income for 1995, as a result of the factors
described above.

        PROVISION FOR INCOME TAXES in 1996 is zero, compared to $0.3 million of
tax payments in 1995 due to the imposition of alternative minimum taxes as a
result of a gain on sale of oil and gas properties in that year.

(d) LIQUIDITY AND CAPITAL RESOURCES

        (i) CASH FLOWS

        Liquidity is a company's ability to generate cash to meet its needs for
cash. As of December 31, 1997, the Company had cash and cash equivalents of
approximately $9.1 million and negative working capital of approximately $8.6
million, compared with cash of $10.8 million and positive working capital of
$5.6 million as of December 31, 1996. The decrease in working capital from 1996
to 1997 was caused by an increase in accounts payable and accrued liabilities,
due to higher levels of drilling activity in late 1997 compared to late 1996.
As of February 28, 1998, the Company's working capital had returned to a
positive position, as a result of increased accounts receivable from partners
due to the increased drilling activity in late 1997 and early 1998.

        Primary sources of cash during the three year period ended December 31,
1997 were funds generated from operations, proceeds from the sale of oil and
gas properties, proceeds from the issuance of notes, bank borrowings and
capital contributions by the Company's former and present parent companies.
Primary uses of cash for the same period were funds used in exploration and
production expenditures, repayment of notes and bank debt, and the purchase of
Hardy Oil & Gas USA, Inc.


                                      17
<PAGE>   20

        The Company had a net cash outflow of $1.7 million in 1997, compared to
a net cash inflow of $10.8 million in 1996 and a net cash inflow of $1.1
million in 1995. A discussion of the major components of cash flows for these
years follows.

<TABLE>
<CAPTION>
                                                                 1997      1996      1995
                                                                ------    ------    -----
<S>                                                             <C>       <C>       <C>
Cash flows provided by operating activities (in millions).......$ 52.9     $ 44.3    $ 22.0
</TABLE>

        Cash flows provided by operating activities in 1997 increased by $8.6
million compared to 1996 primarily due to increased oil and gas prices and
changes in working capital. Cash flows from operating activities in 1996
increased by $22.3 million from 1995 primarily due to increased production
volumes and prices.

<TABLE>
<CAPTION>
                                                                   1997      1996      1995
                                                                  ------    ------    -----
<S>                                                             <C>       <C>       <C>
Cash flows used in investing activities (in millions)............. $ 68.9    $221.8    $123.3
</TABLE>

        Cash flows used in investing activities in 1997 decreased by $152.9
million compared to 1996 primarily because in 1996 cash was used to fund the
acquisition of Hardy Oil & Gas USA, Inc. for $184.7 million, offset by an
increase of $22.6 million for capital expenditures for oil and gas properties
in 1997 over 1996 and $7.5 million lower proceeds from the sale of oil and gas
properties from 1996 to 1997. Cash flows used in investing activities in 1996
increased by $98.5 million compared to 1995 primarily due to cash used to fund
the acquisition of Hardy Oil & Gas USA, Inc. for $184.7 million, an increase of
$3.9 million for capital expenditures for oil and gas properties and $13.2
million lower proceeds from the sale of oil and gas properties, offset in part
by a $106.0 million decrease in issuance of long-term receivables to the
Company's former affiliate.

<TABLE>
<CAPTION>
                                                                 1997      1996      1995
                                                                ------    ------    -----
<S>                                                             <C>       <C>       <C>
Cash flows provided by financing activities (in millions).......$ 14.3     $188.3   $102.4
</TABLE>

        Cash flows provided by financing activities in 1997 decreased by $174.0
million compared to 1996 primarily because in 1996 cash was provided by $92.2
million of equity contributed by the Company's shareholders and the issuance of
$99.5 million of senior subordinated notes, offset in part by proceeds of
borrowings from the revolving credit facility in 1997 of $14.0 million. Cash
flows provided by financing activities in 1996 increased by $85.9 million
compared to 1995 primarily due to $92.2 million of equity contributed by the
Company's shareholders and the issuance of $99.5 million of senior subordinated
notes in 1996, compared to issuance of $60.0 million of senior notes and $46.0
million capital contributions by the Company's former parent during 1995.

        (ii) CHANGES IN PRICES AND HEDGING ACTIVITIES

        The energy markets have historically been very volatile, and there can
be no assurance that oil and gas prices will not be subject to wide
fluctuations in the future. In an effort to reduce the effects of the
volatility of the price of oil and natural gas on the Company's operations,
management has adopted a policy of hedging oil and natural gas prices from time
to time through the use of commodity futures, options and swap agreements.
While the use of these hedging arrangements limits the downside risk of adverse
price movements, it also limits future gains from favorable movements.

        The following table sets forth the increase (decrease) in the Company's
oil and gas sales as a result of hedging transactions and the effects of
hedging transactions on prices during the periods indicated.

<TABLE>
<CAPTION>

                                                                         Year Ended December 31
                                                                -------------------------------------
                                                                    1997         1996         1995
                                                                ----------    ---------     ---------
<S>                                                             <C>           <C>          <C>
Increase (decrease) in natural gas sales (in thousands) .       $  (3,931)    $  (3,701)    $   1,020
Increase (decrease) in oil sales (in thousands) .........            (614)       (1,912)           --
Effect of hedging transactions on average gas sales price
      (per Mcf) .........................................           (0.22)        (0.18)         0.07
Effect of hedging transactions on average oil sales price
      (per Bbl) .........................................           (0.63)        (2.55)           --
</TABLE>



                                      18
<PAGE>   21

        The following table sets forth the Company's open hedging contracts for
oil and natural gas and the weighted average prices hedged under various swap
agreements as of December 31, 1997.

<TABLE>
<CAPTION>
                                  Natural Gas                              Crude Oil
                       -----------------------------------   --------------------------------------
                        Hedge Quantity       Fixed Price      Hedge Quantity         Fixed Price
                             Mmbtu             $/Mmbtu              Bbls                $/Bbl
                       ---------------       --------------   ----------------       --------------
<S>                       <C>                 <C>                 <C>                    <C>
April 1998                 1,200,000           $2.33                 -                    -
May 1998                   1,240,000            2.33                 -                    -
June 1998                  1,200,000            2.33                 -                    -
July  1998                 1,240,000            2.33                 -                    -
August 1998                1,240,000            2.33                 -                    -
September 1998             1,200,000            2.33                 -                    -
October 1998               1,240,000            2.33                 -                    -
</TABLE>

        Subsequent to December 31, 1997, the Company entered into additional
commodity price hedging contracts under swap agreements covering 1,240,000
Mmbtu of March 1998 natural gas production at an average fixed price of $2.18
per Mmbtu. Hedging arrangements through October 1998 cover approximately 37% of
the Company's anticipated equivalent production for 1998.

        (iii) CAPITAL EXPENDITURES AND CAPITAL RESOURCES

        The following table presents major components of capital and
exploration expenditures for each of the three years ended December 31.

<TABLE>
<CAPTION>
                                                     1997       1996      1995
                                                     ----       ----      ----
<S>                                                 <C>       <C>       <C>
Capital Expenditures (in millions):
      Leasehold acquisition-unproved properties     $  21.6   $  14.3   $   4.6
      Leasehold acquisition-proved properties           3.2        --        --
      Oil and gas exploration                          27.4      22.5      12.9
      Oil and gas development and other                16.7       9.6      24.3
                                                    -------   -------   -------
      Total capital expenditures                    $  68.7   $  46.4   $  41.8
                                                    =======   =======   =======
</TABLE>

        Total capital expenditures for 1997 were $22.5 million more than 1996.
The increase was due primarily to (1) the Company's continued focus on building
and evaluating its exploration and exploitation prospect inventory, as
evidenced by the increase in both leasehold acquisition-unproved properties
($7.3 million) and oil and gas exploration ($4.9 million) and (2) increased
development-related spending, both to acquire additional interest in an
existing proved property ($3.2 million) and in development expenditures on
successful exploratory prospects ($7.1 million) . Total capital expenditures in
1996 were $4.6 million greater than 1995. The increase was due primarily to the
Company's increased focus on building and evaluating its prospect inventory, as
evidenced by the increase in both leasehold acquisition ($9.7 million) and oil
and gas exploration ($9.6 million), offset by a decrease in development
expenditures.

        The Company's board of directors has approved a plan to increase its
1998 capital expenditures to approximately $95.7 million, including
approximately $7.0 million of capitalized interest and indirect costs, an
increase of 39% from $68.9 million in 1997. Exploration spending, including
leasehold acquisition of unproved properties, is planned at $53.8 million for
1998, up 10% from $49.0 million in 1997. Planned exploration expenditures
include $20 million to augment the Company's leasehold position and seismic
database, principally in the Deepwater Gulf of Mexico. The remainder



                                      19
<PAGE>   22

of the exploration budget is slated for exploration and exploitation drilling
of 11 or 12 wells, including 5 or 6 in the Deepwater Gulf of Mexico, 5 in the
shallow waters of the Gulf and 1 onshore Gulf Coast. Planned development and
other spending is $41.9 million, up 111% from $19.9 million in 1997. The 1998
development plan includes development expenditures for 4 exploratory
discoveries made in 1997, 2 of which were in the Deepwater Gulf, and initial
work on Mariner's "Pluto" Deepwater Gulf exploitation project. Also, at a
Central Gulf of Mexico Oil and Gas Lease Sale conducted by the U.S. Department
of the Interior's Minerals Management Service in March 1998, the Company was
the apparent successful bidder, solely or with others, on 9 additional blocks
in the Gulf deepwater. The Company's share of its apparent high bids was $29.2
million, net of partner reimbursements. After the award of these additional
lease blocks, which is expected to occur in the second quarter of 1998, the
Company's Deepwater Gulf of Mexico leasehold position and related 1998 capital
expenditures are expected to exceed amounts anticipated in the Company's 1998
budget.

        Capital spending plans will be continuously evaluated throughout the
year. Actual levels of capital expenditures may vary significantly due to a
variety of factors, including drilling results, oil and gas prices, industry
conditions including drilling rig availability, future acquisitions and
availability of capital. Though the 1998 capital expenditures plan does not
include any acquisitions, the Company expects to selectively pursue acquisition
opportunities for proved reserves where it believes significant operating
improvement or exploration potential exists.

        The Company has used its Revolving Credit Facility with NationsBank of
Texas, N.A. (see Note 4 to the Financial Statements) to partially fund its
expenditures. The Revolving Credit Facility, which provides for a maximum $150
million revolving credit loan, carried a borrowing base of $58.0 million as of
December 31, 1997, and $14.0 million of debt was outstanding as of December 31,
1997. The borrowing base is subject to semi-annual redetermination as of June
30 and December 31 of each year, and one additional redetermination per year
may be requested by either NationsBank or the Company.

         In August 1996, the Company issued $100.0 million in 10 1/2% Senior
Subordinated Notes Due 2006. Of the net proceeds of this issuance, $42.0
million was used to pay a dividend to Mariner Holdings, which in turn used the
dividend to repay indebtedness incurred in connection with the Acquisition, and
$50.0 million was used to repay all indebtedness then outstanding under the
Company's Revolving Credit Facility.

        Equity capital has represented a significant source of capital for the
Company. In 1996, $95.0 million was contributed to finance part of the
Acquisition. In March 1998, Mariner Holdings, Inc. reached an agreement in
principle with management shareholders and an affiliate of Enron Corp. to
contribute approximately $28.0 million to $28.8 million of net equity capital,
which is expected to be used to reduce borrowings on the Company's revolving
credit facility and to supplement funding of the Company's 1998 capital
expenditure plan. Closing of this transaction is expected to occur in April
1998. See further discussion of this transaction under Item 13. "Certain
Relationships and Related Transactions - Planned 1998 Equity Investment".

        The Company expects to fund its activities in 1998 through a
combination of cash flow from operations, the use of its Revolving Credit
Facility to borrow funds required from time to time to supplement internal cash
flows and by the equity financing mentioned above. However, after including the
additional equity investment, the Company's capital resources still may not be
sufficient to meet the Company's anticipated future requirements for working
capital, capital expenditures and scheduled payments of principal and interest
on its indebtedness. There can be no assurance that anticipated growth will be
realized, that the Company's business will generate sufficient cash flow from
operations or that future borrowings or equity capital will be available in an
amount sufficient to enable the Company to service its indebtedness or make
necessary capital expenditures.

(e) YEAR 2000 ISSUES

        Year 2000 issues result from the inability of computer programs or
computerized equipment to accurately calculate, store or use a date subsequent
to December 31, 1999. The erroneous date can be interpreted in a number of
different ways; typically the year 2000 is represented as the year 1900. This
could result in a system failure or miscalculations causing disruptions of
operations, including, among other things, a temporary inability to process
transactions, send invoices or engage in similar normal business transactions.


                                      20

<PAGE>   23

        The Company has reviewed the majority of its mission-critical software
systems with the vendors from which the software was purchased, and the Company
believes that these systems will be in compliance during 1998. Further
assessment of less critical software systems is continuing and should be
completed before the end of 1998. The Company believes that the potential
impact, if any, of these systems not being Year 2000 compliant should not
impact the Company's ability to continue exploration, drilling, production and
sales activities. Based on software reviews conducted to date and other
preliminary information, costs of addressing potential problems are not
expected to have a material adverse impact on the Company's financial position,
results of operations, or cash flows in future periods. If, however, the
Company, its customers or vendors are unable to adequately resolve such
processing issues in a timely manner, the Company's operations and financial
results may be adversely affected.


                                      21
<PAGE>   24

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA





                         Index to Financial Statements
<TABLE>
<CAPTION>
                                                                                         PAGE
<S>                                                                                       <C>
Independent Auditors' Report .........................................................     23


Balance Sheets at December 31, 1997 and 1996 (Mariner Energy, Inc.) ..................     24


Statements of Operations for the year ended December 31, 1997, the nine months
      ended December 31, 1996 (Mariner Energy, Inc.), the three months ended
      March 31, 1996, and the year ended December 31, 1995 (Predecessor Company) .....     25


Statements of Stockholder's Equity for the year ended December 31, 1997, the
      nine months ended December 31, 1996 (Mariner Energy, Inc.), the three months
      ended March 31, 1996, and the year ended December 31, 1995 (Predecessor
      Company) .......................................................................     26


Statements of Cash Flows for the year ended December 31, 1997, the nine
      months ended December 31, 1996 (Mariner Energy, Inc.), the three
      months ended March 31, 1996, and the year ended December 31, 1995
      (Predecessor Company) ..........................................................     27


Notes to Financial Statements ........................................................     28


Supplemental oil and gas reserve and standardized measure information (unaudited) ....     39
</TABLE>


                                      22
<PAGE>   25


INDEPENDENT AUDITORS' REPORT



Board of Directors and Stockholder
Mariner Energy, Inc.
Houston, Texas

We have audited the accompanying financial statements of Mariner Energy, Inc.
(the "Company"), formerly Hardy Oil & Gas USA Inc. (the"Predecessor Company"),
as listed in the Index to Financial Statements in Item 8. 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 audits 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 financial position of Mariner Energy, Inc. as of
December 31, 1997 and 1996, and the results of its operations and cash flows
for the year ended December 31, 1997, the nine months ended December 31, 1996,
the three months ended March 31, 1996, and the year ended December 31, 1995, in
conformity with generally accepted accounting principles.




/s/ DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP


Houston, Texas
March 20, 1998


                                      23
<PAGE>   26

                              MARINER ENERGY, INC.
                                 BALANCE SHEETS
                                 (IN THOUSANDS)

<TABLE>
<CAPTION>


                                                              December  31,    December 31,
                                                                  1997             1996
                                                              -------------    ------------
              ASSETS
              ------
<S>                                                              <C>            <C>
CURRENT ASSETS:
    Cash and cash equivalents                                    $   9,131      $  10,819
    Receivables                                                     18,585         13,571
    Prepaid expenses and other                                       3,628            418
                                                                 ---------      ---------
                    Total current assets                            31,344         24,808
                                                                 ---------      ---------

PROPERTY AND EQUIPMENT:
              Oil and gas properties, at full cost:
              Proved                                               222,829        169,728
              Unproved, not subject to amortization                 36,526         21,310
                                                                 ---------      ---------
                    Total                                          259,355        191,038
    Other property and equipment                                     2,222          1,671
    Accumulated depreciation, depletion and amortization           (84,236)       (24,600)
                                                                 ---------      ---------

                    Total property and equipment,  net             177,341        168,109
                                                                 ---------      ---------

OTHER ASSETS, Net of Amortization                                    3,892          3,832
                                                                 ---------      ---------

TOTAL ASSETS                                                     $ 212,577      $ 196,749
                                                                 =========      =========

              LIABILITIES AND STOCKHOLDER'S EQUITY
              ------------------------------------

CURRENT LIABILITIES:
    Accounts payable                                             $   5,556      $   2,930
    Accrued liabilities                                             29,908         12,288
    Accrued interest                                                 4,443          3,996
                                                                 ---------      ---------
                    Total current liabilities                       39,907         19,214
                                                                 ---------      ---------
ACCRUAL FOR FUTURE ABANDONMENT COSTS                                 1,922            957

LONG-TERM DEBT:
    Subordinated notes                                              99,574         99,525
    Revolving Credit Facility                                       14,000             --
                                                                 ---------      ---------
                    Total long-term debt                           113,574         99,525
                                                                 ---------      ---------

COMMITMENTS AND CONTINGENCIES (Note 7)                                  --             --

STOCKHOLDER'S EQUITY:
    Common stock, $1 par value; 1,000 shares authorized,
        issued and outstanding                                           1              1
    Additional paid-in-capital                                      96,075         95,744
    Accumulated deficit                                            (38,902)       (18,692)
                                                                 ---------      ---------
                    Total stockholder's equity                      57,174         77,053
                                                                 ---------      ---------

TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY                       $ 212,577      $ 196,749
                                                                 =========      =========
</TABLE>


The accompanying notes are an integral part of these financial statements


                                      24
<PAGE>   27


                              MARINER ENERGY, INC.
                            STATEMENTS OF OPERATIONS
                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                        Predecessor Company
                                                                      -------------------------
                                              Year       Nine Months  Three Months     Year
                                             Ended         Ended          Ended        Ended
                                          December 31,   December 31,   March 31,   December 31,
                                              1997          1996          1996          1995
                                          ------------   -----------  ------------  ------------
<S>                                         <C>           <C>           <C>           <C>
REVENUES:
   Oil sales                                $ 18,110      $  9,934      $  3,644      $  7,288
   Gas sales                                  45,940        38,588        10,134        26,021
                                            --------      --------      --------      --------
          Total revenues                      64,050        48,522        13,778        33,309
                                            --------      --------      --------      --------
COSTS AND EXPENSES:
   Lease operating expenses                   10,655         7,938         2,872         7,331
   Depreciation, depletion and
        amortization                          31,719        24,747         6,309        15,635
   Impairment of oil and gas properties       28,514        22,500            --            --
   General and administrative expenses         3,195         2,406           712         2,028
                                            --------      --------      --------      --------
          Total costs and expenses            74,083        57,591         9,893        24,994
                                            --------      --------      --------      --------
OPERATING INCOME (LOSS)                      (10,033)       (9,069)        3,885         8,315
INTEREST:
   Related party income                           --            --            57         8,472
   Other income                                  467           515         2,110           783
   Related party expense                          --            --          (381)       (1,610)
   Other expense                             (10,644)       (7,746)       (3,010)      (11,162)
   Write-off of Bridge Loan fees                  --        (2,392)           --            --
                                            --------      --------      --------      --------
INCOME (LOSS) BEFORE INCOME TAXES            (20,210)      (18,692)        2,661         4,798
PROVISION FOR INCOME TAXES                        --            --            --           338
                                            --------      --------      --------      --------
NET INCOME (LOSS)                           $(20,210)     $(18,692)     $  2,661      $  4,460
                                            ========      ========      ========      ========
</TABLE>

   The accompanying notes are an integral part of these financial statements


                                      25
<PAGE>   28
                              MARINER ENERGY, INC.
                       STATEMENTS OF STOCKHOLDER'S EQUITY
                    (IN THOUSANDS, EXCEPT NUMBER OF SHARES)

<TABLE>
<CAPTION>
                                            COMMON STOCK        Additional                    TOTAL
                                        ----------------------   Paid-in       ACCUMULATED  STOCKHOLDER'S
                                         Shares      AMOUNT      Capital        DEFICIT       EQUITY
                                        ---------   ----------  ----------     -----------  -------------
PREDECESSOR COMPANY:
<S>                                     <C>        <C>           <C>          <C>           <C>
     Balance at January 1, 1995          1,000      $      1      $ 35,094     $(16,297)     $ 18,798

          Capital contribution              --            --        46,000           --        46,000

          Net income                        --            --            --        4,460         4,460
                                      --------      --------      --------     --------      --------
     Balance at December 31, 1995        1,000             1        81,094      (11,837)       69,258

          Net income                        --            --            --        2,661         2,661
                                      --------      --------      --------     --------      --------
     Balance at March 31, 1996           1,000             1        81,094       (9,176)       71,919

POST ACQUISITION:

          Adjustments due to
            Acquisition                     --            --        14,650        9,176        23,826

          Net loss                          --            --            --      (18,692)      (18,692)
                                      --------      --------      --------     --------      --------
     Balance at December 31, 1996        1,000             1        95,744      (18,692)       77,053

          Capital contribution              --            --           331           --           331

          Net loss                          --            --            --      (20,210)      (20,210)
                                      --------      --------      --------     --------      --------
     Balance at December 31, 1997        1,000      $      1      $ 96,075     $(38,902)     $ 57,174
                                      ========      ========      ========     ========      ========
</TABLE>


   The accompanying notes are an integral part of these financial statements


                                      26

<PAGE>   29

                              MARINER ENERGY, INC.
                            STATEMENTS OF CASH FLOWS
                                 (IN THOUSANDS)
<TABLE>
<CAPTION>

                                                                                        Predecessor Company
                                                                                      -------------------------
                                                            Year       Nine Months    Three Months      Year
                                                            Ended         Ended          Ended         Ended
                                                        December 31,    December 31,   March 31,    December 31,
                                                            1997           1996           1996          1995
                                                        ------------   -------------  ------------  -----------
<S>                                                     <C>            <C>            <C>            <C>
OPERATING ACTIVITIES:
Net income (loss)                                       $ (20,210)     $ (18,692)     $   2,661      $   4,460
Adjustments to reconcile net income (loss) to net
  cash provided by operating activities:
  Depreciation, depletion and amortization                 32,588         27,706          6,437         16,183
  Impairment of oil and gas properties                     28,514         22,500             --             --
  Imputed interest                                             --          1,322             --             --
Changes in operating assets and liabilities:
  Receivables                                              (5,014)          (769)        (1,873)        (2,747)
  Receivables from affiliates                                  --             --         (2,109)          (718)
  Other current assets                                     (3,210)          (317)          (307)            (1)
  Other assets                                               (483)            --             --             --
  Accounts payable and accrued liabilities                 20,693          6,955            832          5,060
  Payables to affiliates                                       --             --            (11)          (229)
                                                        ---------      ---------      ---------      ---------
    Net cash provided by operating activities              52,878         38,705          5,630         22,008
                                                        ---------      ---------      ---------      ---------
INVESTING ACTIVITIES:
  Purchase of Predecessor Company, net of
    cash of $5,438                                            --       (184,742)            --             --
  Additions to oil and gas properties                     (68,317)       (38,236)        (7,495)       (41,772)
  Additions to other property and equipment                  (551)          (741)          (153)          (211)
  Proceeds from sale of oil and gas properties                 --          7,528             --         20,688
  Issuance of long-term receivable to affiliates               --             --         (1,000)      (107,000)
  Repayment of long-term receivable from affiliates            --             --          3,000          5,000
                                                        ---------      ---------      ---------      ---------
    Net cash used in investing activities                 (68,868)      (216,191)        (5,648)      (123,295)
                                                        ---------      ---------      ---------      ---------
FINANCING ACTIVITIES:
  Principal payments of long-term debt                         --        (92,000)            --         (3,000)
  Principal payments on revolving credit facility              --        (50,000)            --             --
  Payments of debt issue costs                                (29)        (3,961)            --           (592)
  Issuance of guaranteed senior notes                          --             --             --         60,000
  Proceeds from Senior Subordinated Notes                      --         99,506             --             --
  Proceeds from long-term debt                                 --         92,000             --             --
  Proceeds from revolving credit facility                  14,000         50,000             --             --
  Additional capital contributed by Parent                     --         92,150             --         46,000
  Sale of common stock of parent                              331            610             --             --
                                                        ---------      ---------      ---------      ---------
    Net cash provided by financing activities              14,302        188,305             --        102,408
                                                        ---------      ---------      ---------      ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS           (1,688)        10,819            (18)         1,121
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD           10,819             --          5,456          4,335
                                                        ---------      ---------      ---------      ---------
CASH AND CASH  EQUIVALENTS AT END OF PERIOD             $   9,131      $  10,819      $   5,438      $   5,456
                                                        =========      =========      =========      =========
</TABLE>


The accompanying notes are an integral part of these financial statements


                                      27

<PAGE>   30

                              MARINER ENERGY, INC.

                         NOTES TO FINANCIAL STATEMENTS
              FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995

1.      SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

        ORGANIZATION -- For the year ended December 31, 1995, and for the three
months ended March 31, 1996, Hardy Oil & Gas USA Inc., (the "Predecessor
Company"), was a wholly owned subsidiary of Hardy Holdings Inc., which is a
wholly owned subsidiary of Hardy Oil & Gas plc ("Hardy plc"), a public company
incorporated in the United Kingdom. Pursuant to a stock purchase agreement
dated April 1, 1996, Joint Energy Development Investments Limited Partnership
("JEDI"), which is an affiliate of Enron Capital & Trade Resources Corp.
("ECT"),together with members of management of the Predecessor Company, formed
Mariner Holdings, Inc. ("Mariner Holdings"), which then purchased from Hardy
Holdings Inc. all of the issued and outstanding stock of the Predecessor
Company for a purchase price of approximately $185.5 million effective April 1,
1996 for financial accounting purposes (the "Acquisition"). (See Notes 2 and 3
to the Financial Statements.) As a result of the sale of Hardy Oil & Gas USA
Inc.'s common stock, the Predecessor Company changed its name to Mariner
Energy, Inc. (the "Company"). Additionally, ECT and Mariner Holdings entered
into agreements with certain members of the Predecessor Company's management
providing for a continued role of management in the Company after the
Acquisition. The Company is primarily engaged in the exploration and
exploitation for and development and production of oil and gas reserves, with
principal operations both onshore and offshore Texas and Louisiana.

        CASH AND CASH EQUIVALENTS -- All short-term, highly liquid investments
that have an original maturity date of three months or less are considered cash
equivalents.

        ACCOUNTS RECEIVABLE -- Substantially all of the Company's accounts
receivable arise from sales of oil or natural gas, or from reimbursable
expenses billed to the other participants in oil and gas wells for which the
Company serves as operator.

        OIL AND GAS PROPERTIES -- Oil and gas properties are accounted for
using the full-cost method of accounting. All direct costs and certain indirect
costs associated with the acquisition, exploration and development of oil and
gas properties are capitalized. Amortization of oil and gas properties is
provided using the unit-of-production method based on estimated proved oil and
gas reserves. No gains or losses are recognized upon the sale or disposition of
oil and gas properties unless the sale or disposition represents a significant
quantity of oil and gas reserves. The net carrying value of proved oil and gas
properties is limited to an estimate of the future net revenues (discounted at
10%) from proved oil and gas reserves based on period-end prices and costs plus
the lower of cost or estimated fair value of unproved properties. As a result
of this limitation, a permanent impairment of oil and gas properties of
approximately $28,514,000 and $22,500,000 was recorded during 1997 and 1996,
respectively. Unproved properties are reviewed for impairment annually.

        OTHER PROPERTY AND EQUIPMENT -- Depreciation of other property and
equipment is provided on a straight-line basis over their estimated useful
lives which range from five to seven years.

        DEFERRED LOAN COSTS -- Deferred loan costs, which are included in other
assets, are stated at cost and amortized straight-line over their estimated
useful lives, not to exceed the life of the related debt.

        INCOME TAXES -- The Predecessor Company's and the Company's taxable
income are included in a consolidated United States income tax return with
Hardy Holdings Inc. and Mariner Holdings Inc., respectively. The intercompany
tax allocation policy provides that each member of the consolidated group
compute a provision for income taxes on a separate return basis. The Company
records its income taxes in accordance with Statement of Financial Accounting
Standards ("SFAS") No. 109, "Accounting for Income Taxes." Under SFAS No. 109,
an asset and liability approach is required which results in the recognition of
deferred tax assets and liabilities for the expected future tax consequences of
temporary differences between the book carrying amounts and the tax bases of
assets and liabilities (see Note 8 to the Financial Statements).


                                      28

<PAGE>   31

                              MARINER ENERGY, INC.

                         NOTES TO FINANCIAL STATEMENTS - (Continued)

        CAPITALIZED INTEREST COSTS -- The Company capitalizes interest based on
the cost of major development projects which are excluded from current
depreciation, depletion, and amortization calculations. Capitalized interest
costs approximated $729,000, $449,000 and $1,265,000 for the years ended
December 31, 1997, 1996 and 1995, respectively.

        ACCRUAL FOR FUTURE ABANDONMENT COSTS -- Provision is made for
abandonment costs calculated on a unit-of-production basis, representing the
Company's estimated liability at current prices for costs which may be incurred
in the removal and abandonment of production facilities at the end of the
producing life of each property.

        HEDGING PROGRAM -- The Company enters into swap agreements to reduce
the effects of the volatility of the price of natural gas on the Company's
operations. During 1996, the Company extended its hedging program to include
its production of crude oil. These agreements involve the receipt of fixed
price amounts in exchange for variable payments based on NYMEX prices and
specific volumes. The differential to be paid or received is accrued in the
month of the related production and recognized as a component of gas and oil
revenues.

         REVENUE RECOGNITION -- The Company recognizes oil and gas revenue from
its interests in producing wells as oil and gas from those wells is produced
and sold. Oil and gas sold is not significantly different from the Company's
share of production.

         FINANCIAL INSTRUMENTS -- The Company's financial instruments consist
of cash and cash equivalents, receivables, payables, and debt. At December 31,
1997 and 1996, the estimated fair value of the Company's Senior Subordinated
Notes was approximately $100,000,000. The estimated fair value was determined
based on borrowing rates available at December 31, 1997 and 1996, respectively,
for debt with similar terms and maturities. The carrying amount of the
Company's other financial instruments approximates fair value.

         USE OF ESTIMATES IN THE PREPARATION OF FINANCIAL STATEMENTS -- 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 amount of revenues and expenses during the reporting period.
Actual results could differ from these estimates.

         PRICE FLUCTUATIONS -- Subsequent to December 31, 1997, crude oil and
natural gas market prices had fallen from the December 31, 1997 levels used by
the Company to establish price assumptions for the calculation of its oil and
gas reserve basis at December 31, 1997. The NYMEX crude oil contract price was
$16.15 per Bbl for the month of March 1998, down from an average price of
$18.320 per Bbl for the month of December 1997. The final three day NYMEX
average price of natural gas for the month of March 1998 was $2.227 per Mmbtu,
down from the average for the month of December 1997 of $2.682 per Mmbtu.

         MAJOR CUSTOMERS -- During the year ended December 31, 1997, sales of
oil and gas to four purchasers accounted for 19%, 19%, 18% and 14% of total
revenues. During the year ended December 31, 1996, sales of oil and gas to four
purchasers accounted for 15%, 13%, 13% and 10% of total revenues. During the
year ended December 31, 1995, sales of oil and gas to three purchasers
accounted for 20%, 20% and 12% of total revenues. Management believes that the
loss of any of these purchasers would not have a material impact on the
Company's financial condition or results of operations.



                                      29
<PAGE>   32

                              MARINER ENERGY, INC.

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

2.  THE ACQUISITION

        Effective April 1, 1996, Mariner Holdings, Inc. acquired all the
capital stock of the Company from Hardy Holdings Inc. for an aggregate purchase
price of approximately $185.5 million, including $14.5 for net working capital.
In connection with the Acquisition, substantial intercompany indebtedness and
receivables and third-party indebtedness of the Company were eliminated.

        The sources and uses of funds related to financing the Acquisition (See
Note 1 to the Financial Statements) were as follows:

<TABLE>
<CAPTION>
                          Sources of Funds
                            (in millions)
<S>                                                     <C>
      Bridge loan provided by JEDI(1) ..............     $   92.0
      Common stock purchased by JEDI(2) ............         95.0
      Working capital provided by the Company ......          6.0
                                                         --------
      Total ........................................     $  193.0
                                                         ========
                           Uses of Funds
                           (in millions)

Acquisition purchase price .........................     $  185.5
Acquisition costs and other expenses(3) ............          7.5
                                                         --------
      Total ........................................     $  193.0
                                                         ========
</TABLE>

         (1)      The JEDI Bridge Loan (see page 32) was incurred by Mariner
                  Holdings to fund a portion of the consideration paid in the
                  Acquisition, which has been pushed down for accounting
                  purposes to the Company.

         (2)      As contemplated in connection with the Acquisition and
                  shortly after the consummation thereof, certain members of
                  the Company's management purchased approximately 4% of the
                  capital stock of Mariner Holdings (and thereby acquired
                  beneficial ownership of approximately 4% of the capital stock
                  of the Company) for an aggregated consideration valued at
                  approximately $3.6 million. Such consideration consisted of
                  approximately $0.6 million in cash and approximately $3.0
                  million of overriding royalty interests, which amounts are
                  not included in the above sources and uses of funds related
                  to the Acquisition.

         (3)      Includes $2.9 million of fees and expenses paid to JEDI
                  associated with the purchase of the common stock by JEDI,
                  $2.6 million of expenses paid to JEDI associated with the
                  implementation of the JEDI Bridge Loan and $2.0 million of
                  other transaction fees and expenses (See Note 4 to the
                  financial statements).

        The Acquisition has been accounted for using the purchase method of
accounting. As such, JEDI's cost to acquire the Company, including transaction
costs, have been allocated to the assets and liabilities acquired based on
estimated fair values. As a result, the Company's financial position and
operating results subsequent to the date of the Acquisition reflect a new basis
of accounting and are not comparable to prior periods. In addition, $1.3
million of interest was imputed for the period from April 1, 1996 to the date
of closing.


                                      30

<PAGE>   33

                              MARINER ENERGY, INC.

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

        The allocation of JEDI's purchase price to the assets and liabilities
of the Company resulted in a significant increase in the carrying value of the
Company's oil and gas properties. Under the full cost method of accounting, the
carrying value of oil and gas properties is generally not permitted to exceed
the sum of the present value (10% discount rate) of estimated future net cash
flows from proved reserves, based on current prices and costs, plus the lower
of cost or estimated fair value of unproved properties (the "cost center
ceiling"). Based upon the allocation of JEDI's purchase price, estimated proved
reserves and product prices in effect at the date of the Acquisition, the
purchase price allocated to oil and gas properties was in excess of the cost
center ceiling by approximately $22.5 million. The resulting writedown was a
non-cash charge and was included in the results of operations for the nine
months ended December 31, 1996.

        The allocation of the purchase price (including fees and expenses) is
summarized as follows (in millions of dollars):

<TABLE>
<S>                                          <C>
Current assets .........................     $   18.3
Property and equipment .................        181.4
Other noncurrent assets ................          2.6
Liabilities assumed ....................        (12.2)
                                             --------
      Total ............................     $  190.1
                                             ========
</TABLE>

        The following unaudited pro forma financial data have been prepared
assuming that the Acquisition and the related financing were consummated on
January 1, 1995. Amounts are in thousands:

<TABLE>
<CAPTION>

                                   Year Ended December 31,
                                   -----------------------
                                     1996         1995
                                   --------     --------
<S>                                <C>          <C>
Revenues .....................     $ 62,300     $ 33,309

Net income (loss) ............     $  6,511     $ (1,956)
</TABLE>

3.      RELATED-PARTY TRANSACTIONS

        RECEIVABLES FROM AFFILIATES -- Effective May 26, 1993, the Company
entered into a $20 million lending facility with Hardy Petroleum Limited. At
December 31, 1995, $1 million was outstanding under this lending facility.
Advances bore interest at 7.88% and the Company earned interest income of
approximately $3,000 on the receivable for the three months ended March 31,
1996, and $314,000 on the receivable for the year ended December 31, 1995. (See
Note 2 to the Financial Statements).

        Effective January 10, 1995, the Company entered into a $23 million
lending facility with Hardy plc. At December 31, 1995, $23 million was
outstanding under this lending facility. The maturity date of May 31, 2001
could be extended to May 31, 2003 at the election of either party, and advances
bore interest at 7.77%. The Company earned interest income of approximately
$452,000 on the receivable for the three months ended March 31, 1996 and
$1,762,000 on the receivable for the year ended December 31, 1995. (See Note 2
to the Financial Statements).


                                      31
<PAGE>   34
                              MARINER ENERGY, INC.

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

        Effective January 11, 1995, the Company entered into a $23 million
lending facility with Hardy plc which bore interest on advances at 7.07% and
matured on November 30, 1997. At December 31, 1995, $23 million was outstanding
under this lending facility. The Company earned interest income of
approximately $411,000 on the receivable for the three months ended March 31,
1996, and $1,599,000 on the receivable for the year ended December 31, 1995.
(See Note 2 to the Financial Statements).

        Effective January 12, 1995, the Company entered into a $59 million
lending facility with Hardy plc. At December 31, 1995, $59 million was
outstanding under this lending facility. The maturity date of November 30, 2000
could be extended to November 30, 2004 at the election of either party, and
advances bore interest at 8.46%. The Company earned interest income of
approximately $1,244,000 on the receivable for the three months ended March 31,
1996, and $4,780,000 on the receivable for the year ended December 31, 1995.
(See Note 2 to the Financial Statements).

        DEBT TO AFFILIATE -- At December 31, 1995, the Company had $23,500,000
outstanding under a $45 million loan facility with Hardy plc. The borrowed
amount bore interest at the London Interbank Offered Rate ("LIBOR") plus 0.75%.
The agreement, as modified, contained certain restrictive covenants relating to
the maintenance of certain measures of financial position during the term of
the loan. At December 31, 1995, the Company was in compliance with all such
covenants. The loan was to mature on June 1, 1998. The Company incurred
interest expense of approximately $381,000 on the debt during the three months
ended March 31, 1996 and $1,610,000 on the debt during the year ended December
31, 1995. (See Note 2 to the Financial Statements).

        GENERAL AND ADMINISTRATIVE EXPENSES -- Prior to April 1, 1996, the
Company paid an affiliate for various administrative support services. Included
in general and administrative expenses was approximately $29,000 for the three
months ended March 31, 1996, and $230,000 for the year ended December 31, 1995,
for such services. In management's opinion, such allocated expenses reasonably
represented expenses incurred by the affiliate on behalf of the Company.

        AFFILIATE TRANSACTIONS SUBSEQUENT TO THE ACQUISITION -- Enron Corp. is
the parent of ECT, and an affiliate of Enron and ECT is the general partner of
JEDI. Accordingly, Enron may be deemed to control JEDI, Mariner Holdings and
the Company. In addition, six of the Company's directors are officers of Enron
or affiliates of Enron. Enron and certain of its subsidiaries and other
affiliates collectively participate in many phases of the oil and natural gas
industry and are, therefore, competitors of the Company. In addition, ECT and
JEDI have provided, and may in the future provide, and ECT Securities Corp. has
assisted, and may in the future assist, in arranging financing to
non-affiliated participants in the oil and natural gas industry who are or may
become competitors of the Company. Because of these various conflicting
interests, ECT, the Company, JEDI and the members of the Company's management
who are also stockholders of Mariner Holdings have entered into an agreement
that is intended to make clear that Enron and its affiliates have no duty to
make business opportunities available to the Company.

        The Company expects that from time to time it will engage in various
commercial transactions and have various commercial relationships with Enron
and certain affiliates of Enron, such as holding and exploring, exploiting and
developing joint working interests in particular prospects and properties,
engaging in hydrocarbon price hedging arrangements and entering into other oil
and gas related or financial transactions. For example, there are several
prospects in which both an affiliate of Enron and the Company have working
interests. Such interests were acquired in the ordinary course of business
pursuant to bids, joint or otherwise. Any wells drilled will be subject to
joint operating agreements relating to exploration and possible production and
will be subject to customary business terms. Furthermore, the Company has
entered into several agreements with Enron or affiliates of Enron for the
purpose of hedging oil and natural gas prices on the Company's future
production. Certain of the Company's debt instruments restrict the Company's
ability to engage in transaction with its affiliates, but those restrictions
are subject to significant exceptions. See "Item 13 Certain Relationships and
Related Transactions -- Enron". The Company believes that its current
agreements with Enron and its affiliates are, and anticipates that any future
agreements with Enron and its affiliates will be, on terms no less favorable to
the Company than would be contained in an agreement with a third party.


                                      32

<PAGE>   35

4.      LONG-TERM DEBT

        GUARANTEED SENIOR NOTES -- Effective June 1, 1992, the Company issued
to institutional investors 9.05% Guaranteed Senior Notes, Series A ("Series
A"), and 8.45% Guaranteed Senior Notes, Series B ("Series B"), in the aggregate
amounts of $45,000,000 and $15,000,000 due June 1, 2002 and 1999, respectively.
The Series A and Series B notes were guaranteed by Hardy Holdings Inc. and
Hardy plc. In addition to paying the entire outstanding principal amount and
the interest due on the maturity dates of the Series A and Series B notes, the
Company was required to prepay the lesser of (a) $9,000,000 and $3,000,000,
respectively, or (b) the principal amount of the notes then outstanding on June
1 of each year, commencing June 1, 1998 and 1995, respectively. (See Note 2 to
the Financial Statements).

        Effective May 1, 1993, the Company issued to institutional investors
7.88% Guaranteed Senior Notes in the aggregate principal amount of $25,000,000
due June 1, 2003. The notes were guaranteed by Hardy Holdings Inc. and Hardy
plc. In addition to paying the entire outstanding principal amount and the
interest due on the notes on the respective maturity date, the Company was
required to prepay the lesser of (a) $5,000,000 or (b) the principal amount of
the notes then outstanding on June 1 of each year, commencing June 1, 1999.
(See Note 2 to the Financial Statements).

        Effective January 11, 1995, the Company issued to institutional
investors 8.46% Guaranteed Senior Notes in the aggregate principal amount of
$60,000,000 due June 1, 2004. The notes were guaranteed by Hardy Holdings Inc.
and Hardy plc. In addition to paying the entire principal amount and the
interest due on the notes on the respective maturity date, the Company was
required to prepay the lesser of (a) $12,000,000 or (b) the principal amount of
the notes then outstanding on December 1 of each year, commencing December 1,
2000. The entire remaining principal amount of the notes was due and payable on
December 1, 2004. (See Note 2 to the Financial Statements).

        The Guaranteed Senior Notes required, among other things, that the
Company meet certain financial ratios and maintain a minimum tangible net
worth. As of December 31, 1995, the Company was in compliance with all such
requirements.

        JEDI BRIDGE LOAN -- In connection with the Acquisition, JEDI and
Mariner Holdings entered into a Credit, Subordination and Further Assurances
Agreement dated May 16, 1996, pursuant to which JEDI provided a loan commitment
to Mariner Holdings of $105 million. Under this commitment Mariner Holdings
borrowed $92 million (the "JEDI Bridge Loan") to partially fund the
Acquisition. The JEDI Bridge Loan bore interest at 6% above LIBOR. The JEDI
Bridge Loan was repaid with proceeds from dividends paid by the Company to
Mariner Holdings; the Company used proceeds of $50 million from borrowings
under the Revolving Credit Facility (see below) and $42 million from the
issuance of the 10 1/2% Senior Subordinated Notes (see below) to pay such
dividends. As a result of the repayments, the JEDI Bridge Loan was terminated.
In connection with the $92 million repayment, $2.4 million of the JEDI Bridge
Loan debt fees were written off during the nine months ended December 31, 1996.

        REVOLVING CREDIT FACILITY -- On June 28, 1996, the Company entered into
a revolving credit facility (the "Revolving Credit Facility") with NationsBank
of Texas, N.A. as agent for a group of lenders (the "Lenders"). The Revolving
Credit Facility provides for a maximum $150 million revolving credit loan and
matures on June 28, 1999. The borrowing base under the Revolving Credit
Facility is currently $58 million and is subject to periodic redetermination.
The Revolving Credit Facility is unsecured. On June 28, 1996, the Company
borrowed $50 million under the Revolving Credit Facility and used the proceeds
to pay a dividend to Mariner Holdings, which was used by Mariner Holdings to
partially repay the JEDI Bridge Loan. During August 1996, the outstanding
balances of both the Revolving Credit Facility and the JEDI Bridge Loan were
repaid with the proceeds from the issuance of the Company's 10 1/2% Senior
Subordinated Notes.


                                      33
<PAGE>   36

                              MARINER ENERGY, INC.

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

        Borrowings under the Revolving Credit Facility bear interest, at the
option of the Company, at either (i) LIBOR plus 0.75% to 1.25% (depending upon
the level of utilization of the Borrowing Base) or (ii) the higher of (a) the
agent's prime rate or (b) the federal funds rate plus 0.5%. The Company incurs
a quarterly commitment fee ranging from 0.25% to 0.375% per annum on the
average unused portion of the Borrowing Base, depending upon the level of
utilization.

        The Revolving Credit Facility contains various restrictive covenants
which, among other things, restrict the payment of dividends, limit the amount
of debt the Company may incur, limit the Company's ability to make certain
loans and investments, limit the Company's ability to enter into certain hedge
transactions and provide that the Company must maintain a specified
relationship between cash flow and fixed charges and cash flow and interest on
indebtedness. As of December 31, 1997, the Company was in compliance with all
such requirements.

        10 1/2% SENIOR SUBORDINATED NOTES -- On August 14, 1996 the Company
completed the sale of $100 million principal amount of 10 1/2% Senior
Subordinated Notes Due 2006, (the "Notes"). The proceeds of the Notes were used
by the Company to (i) pay a dividend to Mariner Holdings, which used the
dividend to fully repay the JEDI Bridge Loan incurred in the Acquisition, and
(ii) repay the Revolving Credit Facility. The Notes bear interest at 10 1/2%
payable semiannually in arrears on February 1 and August 1 of each year. The
Notes are unsecured obligations of the Company, and are subordinated in right
of payment to all senior debt (as defined in the indenture governing the Notes)
of the Company, including indebtedness under the Revolving Credit Facility.

        The indenture pursuant to which the Notes are issued contains certain
covenants that, among other things, limit the ability of the Company to incur
additional indebtedness, pay dividends, redeem capital stock, make investments,
enter into transactions with affiliates, sell assets and engage in mergers and
consolidations. As of December 31, 1997, the Company was in compliance with all
such requirements.

        The Notes are redeemable at the option of the Company, in whole or in
part, at any time on or after August 1, 2001, initially at 105.25% of their
principal amount, plus accrued interest, declining ratably to 100% of their
principal amount, plus accrued interest, on or after August 1, 2003. In
addition, at the option of the Company, at any time prior to August 1, 1999, up
to an aggregate of 35% of the original principal amount of the Notes will be
redeemable from the net proceeds of one or more public equity offerings, at
110.5% of their principal amount, plus accrued interest, provided that any such
redemption shall occur within 60 days of the date of the closing of such public
equity offering.

        In the event of a change of control of the Company (as defined in the
indenture pursuant to which the Notes are issued), each holder of the Notes
(the "Holder") will have the right to require the Company to repurchase all or
any portion of such Holder's Notes at a purchase price equal to 101% of the
principal amount thereof, plus accrued interest.

        As required in the indenture, in January 1997 the Company exchanged all
of the Notes for Series B notes with substantially the same terms as to
principal amount, interest rate, maturity and redemption rights. If the
exchange offer had not been consummated, the interest rate on the Notes would
have increased by 0.5% per annum.

        The Company paid interest on all outstanding indebtedness of
$10,926,000 for the year ended December 31, 1997 and $10,656,000 for the nine
months ended December 31, 1996, and the Predecessor Company paid $466,000 for
the three months ended March 31, 1996 and $13,670,000 for the year ended
December 31, 1995.


5.      STOCKHOLDER'S EQUITY

        PRE-ACQUISITION CAPITAL CONTRIBUTIONS -- The Predecessor Company
received capital contributions of $46,000,000 from Hardy Holdings Inc., which
was ultimately contributed from Hardy plc, during the year ended December 31,
1995.


                                      34
<PAGE>   37

                              MARINER ENERGY, INC.

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

        STOCK OPTION PLAN -- During June 1996, Mariner Holdings established the
Mariner Holdings, Inc. 1996 Stock Option Plan (the "Plan") providing for the
granting of stock options to key employees and consultants. Options granted
under the Plan will not be less than the fair market value of the shares at the
date of grant. The maximum number of shares of Mariner Holdings common stock
that may be issued under the Plan is 142,800.

        At December 31, 1997, options (the "Options") to purchase 140,169
shares had been granted at an exercise price of $100 per share. The Options
generally become exercisable as to one-fifth on each of the first five
anniversaries of the date of grant. The Options expire seven years after the
date of grant.

        The Company applies APB Opinion 25 and related interpretations in
accounting for the Plan. Accordingly, no compensation cost has been recognized
for the Plan. Had compensation cost for the Company's Plan been determined
based on the fair value at the grant date for awards under the Plan consistent
with the method of Financial Accounting Standards Board Statement 123 ("FAS
123"), the Company's net loss for the year ended December 31, 1997 and for the
nine months ended December 31, 1996 would have increased $777,000 and $356,000,
respectively to $20,987,000 and $19,048,000 respectively. The effects of
applying FAS 123 in this pro forma disclosure are not indicative of future
amounts. The fair value of each option grant is estimated on the date of grant
using a present value calculation, risk free interest of 6.6%, no dividends and
expected life of 5 years. Stock options available for future grant amounted to
2,631 shares at December 31, 1997. Exercisable stock options amounted to 25,666
shares at December 31, 1997.

        SUBSEQUENT EVENT: PLANNED 1998 EQUITY INVESTMENT -- In March 1998,
Mariner Holdings, Inc. reached an agreement in principle with management
shareholders and an affiliate of Enron Corp. to contribute approximately $28.0
million to $28.8 million of net equity capital, which is expected to be used to
reduce borrowings on the Company's revolving credit facility and to supplement
funding of the Company's 1998 capital expenditure plan.
Closing of this transaction is expected to occur in April 1998.


6.      EMPLOYEE BENEFIT AND ROYALTY PLANS

        EMPLOYEE CAPITAL ACCUMULATION PLAN -- The Company provides all
full-time employees participation in the Employee Capital Accumulation Plan
(the "Plan") which is comprised of a contributory 401(k) savings plan and a
discretionary profit sharing plan. Under the 401(k) feature, the Company, at
its sole discretion, may contribute an employer-matching contribution equal to
a percentage not to exceed 50% of each eligible participant's matched salary
reduction contribution as defined by the Plan. Under the discretionary profit
sharing contribution feature of the Plan, the Company's contribution, if any,
shall be determined annually and shall be 4% of the lesser of the Company's
operating income or total employee compensation and shall be allocated to each
eligible participant pro rata to his or her compensation. During 1997, 1996 and
1995, the Company contributed $200,000, $165,000 and $163,000, respectively, to
the Plan. This plan is a continuation of a plan provided by the Predecessor
Company.

        OVERRIDING ROYALTY INTERESTS -- Pursuant to agreements, certain key
employees and consultants are entitled to receive, as incentive compensation,
overriding royalty interests ("Overriding Royalty Interests") in certain oil
and gas prospects acquired by the Company. Such Overriding Royalty Interests
entitle the holder to receive a specified percentage of the gross proceeds from
the future sale of oil and gas (less production taxes), if any, applicable to
the prospects.


                                      35

<PAGE>   38
7.      COMMITMENTS AND CONTINGENCIES

        MINIMUM FUTURE LEASE PAYMENTS -- The Company leases certain office
facilities and other equipment under long-term operating lease arrangements.
Minimum rental obligations under the Company's operating leases in effect at
December 31, 1997 are as follows (in thousands):

<TABLE>
<S>                                          <C>
1998 ...................................     $  548
1999 ...................................        537
2000 ...................................        537
2001 ...................................        269
2002 ...................................         --
                                             ------

      Total ............................     $1,891
                                             ======
</TABLE>

        Rental expense, before capitalization, was approximately $544,000,
$427,000 and $391,000 for the years ended December 31, 1997, 1996 and 1995,
respectively.

        HEDGING PROGRAM -- The Company conducts a hedging program with respect
to its sales of crude oil and natural gas using various instruments whereby
monthly settlements are based on the differences between the price or range of
prices specified in the instruments and the settlement price of certain crude
oil and natural gas futures contracts quoted on the open market. The
instruments utilized by the Company differ from futures contracts in that there
is no contractual obligation which requires or allows for the future delivery
of the product.

        The following table sets forth the results of hedging transactions
during the periods indicated:

<TABLE>
<CAPTION>
                                                      Year Ended December 31,
                                              --------------------------------------------
                                                 1997             1996              1995
                                              ----------       ----------        ---------
<S>                                           <C>              <C>               <C>
Natural gas quantity hedged (Mmbtu)           13,573,500       13,482,900        5,890,000
Increase (decrease) in natural gas sales     ($3,931,000)     ($3,701,000)      $1,020,000
Crude oil quantity hedged (Bbls)                 118,000          428,000               --
Increase (decrease) in crude oil sales         ($614,000)     ($1,912,000)              --
</TABLE>

        The following table sets forth the Company's open hedging contracts for
oil and natural gas and the weighted average prices fixed under various swap
agreements entered into as of December 31, 1997.

<TABLE>
<CAPTION>
                                                        Natural Gas
                                          ------------------------------------
                                                     Weighted      Fair Market
                                          MMBTU    Average Price     Value(1)
                                          -----    -------------   ------------
<S>                                     <C>           <C>          <C>
April - October 1998 ................   8,560,000     $ 2.33       $1.6 million
</TABLE>

(1) The fair market value was calculated using prices derived from NYMEX futures
contract prices and related basis swap contract prices existing at December 31,
1997.


                                      36

<PAGE>   39


                                                MARINER ENERGY, INC.

                                    NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

8.      INCOME TAXES


         The following table sets forth a reconciliation of the statutory
federal income tax with the income tax provision:

<TABLE>
<CAPTION>
(Thousands of dollars)                                                                    Predecessor Company
                                                                                 --------------------------------------
                                      Year Ended                                                         Year Ended
                                      December 31          9 Months Ended         3 Months Ended        December 31,
                                         1997                12/31/96                 3/31/96               1995
                                   ------------------    -----------------       -----------------    -----------------
                                       $         %           $        %              $        %           $        %
                                   ----------  ------    ----------  -----       ---------  ------    ---------  ------
<S>                                 <C>                  <C>                      <C>                    <C>
Income (loss) before income taxes     (20,210)     --       (18,692)    --           2,661      --        4,798      --
Income tax expense (benefit)
computed at statutory rates            (7,074)    (35)       (6,542)   (35)            931      35        1,679      35
Change in valuation allowance           6,871      34         8,125     43          (3,597)   (135)      (1,261)    (26)
Other                                     203       1        (1,583)    (8)          2,666     100          (80)     (2)
                                   ----------  ------    ----------  -----       ---------  ------    ---------  ------
Tax Expense                                --      --            --     --              --      --          338       7
                                   ==========  ======    ==========  =====       =========  ======    =========  ======
</TABLE>

         No federal income taxes were paid by the Company during the year ended
December 31, 1997, the nine months ended December 31, 1996, or the three months
ended March 31, 1996. Federal income tax paid by the Company during the year
ended December 31, 1995 was $338,000.

         The Company's deferred tax position reflects the net tax effects of
the temporary differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used for income
tax reporting. The deferred tax position for 1995 relates to the Predecessor.
For tax purposes, a new entity was deemed to have been created as a result of
an election made in accordance with Internal Revenue Code Section 338 (h)(10)
to treat the stock acquisition of Hardy Oil & Gas USA Inc. as a deemed asset
acquisition whereby the acquired assets and liabilities were revalued to their
fair market value for tax purposes. As a result, the Company has a deferred tax
position for 1997 and 1996 that bears no relation to the deferred tax position
of the Predecessor for 1995. Significant components of the deferred tax assets
and liabilities are as follows (in thousands):

<TABLE>
<CAPTION>
                                                                                        Predecessor
                                                                                           Company
                                                                                        -----------
                                                                1997          1996          1995
                                                              --------      --------      --------
<S>                                                           <C>           <C>           <C>
Deferred tax assets:
     Net operating loss carryforwards                         $ 10,410      $  6,323      $ 28,157
     Alternative minimum tax credit carryforward                    --            --           321
     Other                                                          --            --           959
     Differences between book and tax bases of properties        4,586         1,802            --
                                                              --------      --------      --------
                                                                14,996         8,125        29,437
Valuation allowance                                            (14,996)       (8,125)       (9,383)
                                                              --------      --------      --------
Total net deferred tax assets                                       --            --        20,054
                                                              --------      --------      --------
Deferred tax liabilities --
     Differences between book and tax bases of properties           --            --       (20,054)
                                                              ========      ========      ========
          Total net deferred taxes                            $     --      $     --      $     --
                                                              ========      ========      ========
</TABLE>


                                       37
<PAGE>   40

                              MARINER ENERGY, INC.

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)


         As of December 31, 1997, the Company has a cumulative net operating
loss carryforward ("NOL") for federal income tax purposes of approximately
$30.6 million, which expires in the year 2012 or after. SFAS No. 109 requires
that a valuation allowance be recorded against tax assets which are not likely
to be realized. Because of the uncertain nature of their ultimate realization,
as well as past performance and the NOL expiration date, the Company has
established a valuation allowance against this NOL carryforward benefit and for
all net deferred tax assets in excess of net deferred tax liabilities.

9.      OIL AND GAS PRODUCING ACTIVITIES AND CAPITALIZED COSTS

         The results of operations from the Company's oil and gas producing
activities were as follows (in thousands):

<TABLE>
<CAPTION>
                                                                                              Predecessor Company
                                                                                     --------------------------------------
(Note: All of the Company's oil and gas     Year ended       Nine months ended       Three months ended      Year ended
revenues were from proved developed     December 31, 1997    December 31, 1996         March 31, 1996     December 31, 1995
properties located in the United        -------------------  -------------------     -------------------  -----------------
States.)
<S>                                          <C>                  <C>                     <C>                <C>
Oil and gas sales                             $ 64,050           $ 48,522                  $ 13,778           $ 33,309
Production costs                               (10,655)            (7,938)                   (2,872)            (7,331)
Depreciation, depletion and amortization       (31,719)           (24,747)                   (6,309)           (15,635)
Impairment of oil and gas properties           (28,514)           (22,500)                       --                 --
Income tax expense                                  --                 --                        --               (338)
                                              --------           --------                  --------           --------
    Results of operations                     $ (6,838)          $ (6,663)                 $  4,597           $ 10,005
                                              ========           ========                  ========           ========
</TABLE>

         Costs incurred in property acquisition, exploration and development
activities were as follows (in thousands, except per equivalent mcf amounts):

<TABLE>
<CAPTION>
                                                                                              Predecessor Company
                                                                                     --------------------------------------
                                           Year ended        Nine months ended        Three months ended      Year ended
                                          December 31,         December 31,             March 31, 1996       December 31,
                                              1997                  1996                                         1995
                                        -----------------  ----------------------    ---------------------  ---------------
<S>                                          <C>                <C>                        <C>                <C>
Property acquisition costs
     Unproved properties                     $21,569              $13,477                    $   949             $ 4,594
     Proved properties                         3,250                   --                         --                  --
Exploration costs                             27,364               18,627                      3,903              12,866
Development costs                             16,133                6,132                      2,643              24,312
                                             -------              -------                    -------             -------
    Total costs                              $68,316              $38,236                    $ 7,495             $41,772
                                             =======              =======                    =======             =======
Depreciation, depletion and
amortization rate per equivalent mcf         $  1.33              $  1.33                    $  1.00             $  0.96
</TABLE>

         The Company capitalizes internal costs associated with exploration
activities. These capitalized costs approximated $4,418,000, $4,362,000 and
$4,264,000, for the years ended December 31, 1997, 1996 and 1995, respectively.


                                      38
<PAGE>   41

                              MARINER ENERGY, INC.

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

         The following table summarizes costs related to unevaluated properties
which have been excluded from amounts subject to amortization at December 31,
1997. The Company regularly evaluates these costs to determine whether
impairment has occurred. The majority of these costs are expected to be
evaluated and included in the amortization base within three years.

<TABLE>
<CAPTION>
                                                                                Predecessor Company
                                                                  --------------------------------------------
                                                 Nine months      Three months
                                 Year ended         ended             ended        Year ended                          Total at
                                December 31,     December 31,        March 31,     December 31,         Prior         December 31,
                                    1997             1996              1996           1995              Years             1997
                                ------------     ------------      -----------     ------------        -------        ------------
<S>                                <C>              <C>              <C>              <C>              <C>              <C>
Property
 Acquisition costs ......          $18,707          $ 8,489          $    88          $ 1,687          $   511          $29,482
Exploration costs .......            5,789              497              352              164               70            6,872
Development costs .......              172               --               --               --               --              172
                                   -------          -------          -------          -------          -------          -------
    Total ...............          $24,668          $ 8,986          $   440          $ 1,851          $   581          $36,526
                                   =======          =======          =======          =======          =======          =======
</TABLE>

         Approximately 79% of excluded costs at December 31, 1997 relate to
activities in the Deepwater Gulf of Mexico and the remaining 21% relates to
activities in the Gulf of Mexico shallow waters and onshore areas near the
Gulf.


10.     SUPPLEMENTAL OIL AND GAS RESERVE AND STANDARDIZED MEASURE INFORMATION
        (UNAUDITED)

         Estimated proved net recoverable reserves as shown below include only
those quantities that can be expected to be commercially recoverable at prices
and costs in effect at the balance sheet dates under existing regulatory
practices and with conventional equipment and operating methods. Proved
developed reserves represent only those reserves expected to be recovered
through existing wells. Proved undeveloped reserves include those reserves
expected to be recovered from new wells on undrilled acreage or from existing
wells on which a relatively major expenditure is required for recompletion.
Also included in the Company's proved undeveloped reserves as of December 31,
1997 were reserves expected to be recovered from wells for which certain
drilling and completion operations had occurred as of that date, but
significant future capital expenditures were required to bring the wells into
commercial production.

         Reserve estimates are inherently imprecise and may be expected to
change as additional information becomes available. Furthermore, estimates of
oil and gas reserves, of necessity, are projections based on engineering data,
and there are uncertainties inherent in the interpretation of such data as well
as the projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured
exactly, and the accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and
judgment. Accordingly, estimates of the economically recoverable quantities of
oil and natural gas attributable to any particular group of properties,
classifications of such reserves based on risk of recovery and estimates of the
future net cash flows expected therefrom prepared by different engineers or by
the same engineers at different times may vary substantially. There also can be
no assurance that the reserves set forth herein will ultimately be produced or
that the proved undeveloped reserves set forth herein will be developed within
the periods anticipated. It is likely that variances from the estimates will be
material. In addition, the estimates of future net revenues from proved
reserves of the Company and the present value thereof are based upon certain
assumptions about future production levels, prices and costs that may not be
correct when judged against actual subsequent experience. The Company
emphasizes with respect to the estimates prepared by


                                      39
<PAGE>   42

                              MARINER ENERGY, INC.

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

independent petroleum engineers that the discounted future net cash flows
should not be construed as representative of the fair market value of the
proved reserves owned by the Company since discounted future net cash flows are
based upon projected cash flows which do not provide for changes in oil and
natural gas prices from those in effect on the date indicated or for escalation
of expenses and capital costs subsequent to such date. The meaningfulness of
such estimates is highly dependent upon the accuracy of the assumptions upon
which they were based. Actual results will differ, and are likely to differ
materially, from the results estimated.


                    Estimated Quantities of Proved Reserves
                                 (in thousands)
<TABLE>
<CAPTION>
                                                   Oil (Bbl)           Gas (Mcf)
                                                    --------           --------
<S>                                                <C>               <C>
December 31, 1994                                      6,900            100,645
  Revisions of previous estimates                        307             14,113
  Extensions, discoveries and other additions             46              2,476
  Sales of reserves in place                            (160)            (5,134)
  Production                                            (424)           (13,770)
                                                    --------           --------

December 31, 1995                                      6,669             98,330
  Revisions of previous estimates                          3               (518)
  Extensions, discoveries and other additions          1,168             24,326
  Sales of reserves in place                          (1,810)            (9,425)
  Production                                            (750)           (20,429)
                                                    --------           --------

December 31, 1996                                      5,280             92,284
  Revisions of previous estimates                        210             (1,817)
  Extensions, discoveries and other additions          2,062             46,166
  Purchase of reserves in place                           55              2,737
  Production                                            (977)           (18,004)
                                                    --------           --------

December 31, 1997                                      6,630            121,366
                                                    ========           ========
</TABLE>

               Estimated Quantities of Proved Developed Reserves
                                 (in thousands)

<TABLE>
<CAPTION>
                                                     Oil (Bbl)         Gas (Mcf)
                                                     --------          --------
<S>                                                     <C>             <C>
December 31, 1994                                      4,037            83,192
December 31, 1995                                      4,357            87,843
December 31, 1996                                      3,456            83,529
December 31, 1997                                      3,486            76,343
</TABLE>

         The following is a summary of a standardized measure of discounted net
cash flows related to the Company's proved oil and gas reserves. The
information presented is based on a valuation of proved reserves using
discounted cash flows based on year-end prices, costs and economic conditions
and a 10% discount rate. The additions to proved reserves from new discoveries
and extensions could vary significantly from year to year; additionally, the
impact of changes to reflect current prices and costs of reserves proved in
prior years could also be significant. Accordingly, the information presented
below should not be viewed as an estimate of the fair value of the Company's
oil and gas properties, nor should it be considered indicative of any trends.


                                      40
<PAGE>   43

                              MARINER ENERGY, INC.

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)


            Standardized Measure of Discounted Future Net Cash Flows
                                 (in thousands)

<TABLE>
<CAPTION>
                                                                    Year ended December 31,
                                                             ---------------------------------------
                                                                1997           1996           1995
                                                             ---------      ---------      ---------
<S>                                                          <C>            <C>            <C>
Future cash inflows                                          $ 447,681      $ 548,451      $ 370,471
Future production costs                                       (109,405)      (103,777)      (108,980)
Future development costs                                       (73,568)       (20,413)       (16,956)
Future income taxes                                            (35,346)       (90,971)       (37,518)
                                                             ---------      ---------      ---------
Future net cash flows                                          229,362        333,290        207,017
Discount of future net cash flows at 10% per annum             (52,903)       (78,914)       (46,502)
                                                             ---------      ---------      ---------
Standardized measure of discounted future net cash flows     $ 176,459      $ 254,376      $ 160,515
                                                             =========      =========      =========
</TABLE>

         During recent years, there have been significant fluctuations in the
prices paid for crude oil in the world markets and in the United States,
including the posted prices paid by purchasers of the Company's crude oil. The
weighted average prices of oil and gas at December 31, 1997, 1996 and 1995,
used in the above table, were $16.43, $25.16 and $18.08 per Bbl, respectively,
and $2.79, $4.50 and $2.54 per Mcf, respectively.

         The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in thousands):

<TABLE>
<CAPTION>
                                                                         Year ended December 31,
                                                                 ----------------------------------------
                                                                     1997           1996           1995
                                                                  ---------      ---------      ---------
<S>                                                              <C>            <C>             <C>
Sales and transfers of oil and gas produced,
   net of production costs ..................................     $ (53,395)     $ (51,505)     $ (25,963)

 Net changes in prices and production costs .................      (132,658)       120,843         64,363

 Extensions and discoveries, net of future
  development and production costs ..........................        42,717         62,551          5,712

 Development costs during period ............................         4,188             --             --

 Revision of previous quantity estimates ....................          (730)        (1,293)        18,076

 Purchases of reserves in place .............................         6,071             --             --

 Sales of reserves in place .................................            --        (10,813)        (6,141)

 Net change in income taxes .................................        29,619        (36,082)        (7,191)

 Accretion of discount before income taxes ..................        30,336         17,342          9,532

 Changes in production rates (timing) and
  other .....................................................        (4,065)        (7,182)        12,523
                                                                  ---------      ---------      ---------
 Net change .................................................     $ (77,917)     $  93,861      $  70,911
                                                                  =========      =========      =========
</TABLE>


                                      41

<PAGE>   44


                              MARINER ENERGY, INC.

                  NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

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

         None


                                    PART III


ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

         Set forth below are the names, ages and positions of the executive
officers and directors of the Company and a key consultant to the Company as of
March 1, 1998. All directors are elected for a term of one year and serve until
their successors are elected and qualified. All executive officers hold office
until their successors are elected and qualified.

<TABLE>
<CAPTION>
   Name                   Age                 Position with the Company
   ----                   ---                 -------------------------
<S>                      <C>     <C>
Robert E. Henderson       45     Chairman of the Board, President and Chief Executive Officer
Richard R. Clark          42     Senior Vice President of Production and Director
Michael W. Strickler      42     Senior Vice President of Exploration and Director
James M. Fitzpatrick      47     Vice President of Land and Legal, Corporate Secretary
Gregory K. Harless        48     Vice President of Oil and Gas Marketing
W. Hunt Hodge             42     Vice President of Administration
Frank A. Pici             42     Vice President of Finance and Chief Financial Officer
Clinton D. Smith          43     Vice President of Operations
David S. Huber            47     Consultant and Deep Water Projects Manager
Richard B. Buy            46     Director
Mark E. Haedicke          43     Director
Stephen R. Horn           40     Director
Gene E. Humphrey          50     Director
Jere C. Overdyke, Jr.     46     Director
Frank Stabler             45     Director
</TABLE>

         Mr. Henderson has been Chairman of the Board of the Company since May
1996, President and Chief Executive Officer since 1987 and a director since
1985. From 1984 to 1987, he served the Co mpany or predecessors as Vice
President of Finance and Chief Financial Officer. From 1976 to 1984, he held
various positions with ENSTAR Corporation. Additionally, Mr. Henderson served
as the Company's Chief Financial Officer from August 1996, when the former
Chief Financial Officer ceased to serve in that position, through November
1996.

         Mr. Clark has served the Company in various engineering and operations
activities since 1984 and has been Senior Vice President of Production since
1991 and a director since 1988. Prior to joining the Company he worked as a
Production Engineer in the Offshore Production Group of Shell Oil Company.

         Mr. Strickler joined the Company in 1984 and has served the Company
since such time in its geological and exploration activities. He has served as
Senior Vice President of Exploration of the Company since 1991 and a director
since 1989.

         Mr. Fitzpatrick joined the Company in 1984 and has served as Vice
President of Land and Legal since 1990 and Corporate Secretary since May 1996.
Prior to joining the Company he had been a petroleum landman for Pend Oreille
Oil and Gas Company and for Exxon Company U.S.A.

         Mr. Harless has served as Vice President of Oil and Gas Marketing of
the Company since 1990. Prior to joining the Company in 1988, he was Vice
President of Marketing and Regulatory Affairs of Enron Oil and Gas Company.

         Mr. Hodge has served as Vice President of Administration of the
Company since 1991. Prior to joining the Company in 1985, he was Purchasing
Manager of Santa Fe Minerals Company.


                                      42

<PAGE>   45

         Mr. Pici became Vice President of Finance and Chief Financial Officer
in December 1996. Prior to joining the Company, Mr. Pici was employed by Cabot
Oil & Gas Corporation holding several positions since 1989, including Corporate
Controller since 1994.

         Mr. Smith joined the Company in 1987 and has served as Vice President
of Operations since 1991. Prior to joining the Company he worked on both
domestic and international assignments for Phillips Oil Company and Eaton
Engineering.

         Mr. Huber, a consultant to the Company, serves the Company in a number
of respects, particularly with respect to exploration, exploitation and
development of deepwater prospects, in which he has significant expertise, and
is regarded by the Company as a key personnel resource. Mr. Huber is an
independent project management consultant and is the Company's deepwater
project manager. The Company has engaged the services of Mr. Huber from time to
time since 1991. Mr. Huber was employed by Hamilton Oil Corporation (which was
acquired by BHP Petroleum in 1991) in the North Sea from 1981 to 1991, holding
the positions of production manager, planning and economics manager, and
engineering manager. He was the deepwater drilling engineering supervisor for
Esso Exploration, Inc. from 1974 to 1980.

         Mr. Buy has served as a director since January 1997. Since 1994 he has
been an employee of ECT, currently serving as a Managing Director of Enron
Capital Management, a division of Enron Corp. Prior to joining ECT Mr. Buy was
a Vice President at Bankers Trust in the Energy Group.

         Mr. Haedicke has served as a director since October 1997. He is
currently Managing Director, Legal, of ECT. Mr. Haedicke also serves on the
board of directors of the International Swaps and Derivatives Association, Inc.
and he holds a seat on the New York Mercantile Exchange. He has been associated
with ECT since its inception in 1990.

         Mr. Horn has served as a director since November 1997. Since 1996, he
has been as employee and Vice President, Equity Investments, of ECT. Prior to
joining ECT, Mr. Horn was a principal in Yellowstone Energy Partners, a private
equity investing firm in Houston, Texas.

         Mr. Humphrey has served as a director since May 1996. Since 1990 he
has been an employee of ECT, currently serving as Vice Chairman. Prior to
joining ECT Mr. Humphrey was a Vice President in Citibank's Petroleum
Department.

         Mr. Overdyke has served as a director since May 1996. Since 1991 he
has been an employee of ECT or one of its affiliates, currently serving as a
Managing Director of Enron International, Inc. Mr. Overdyke has over 20 years
of experience in the energy sector and has held various financial and
management positions with public and private independent exploration and
production companies.

         Mr. Stabler has served as a director since May 1996. He is currently a
Managing Director of Enron International, Inc. and has held positions with ECT
since 1992. From 1989 to 1992, Mr. Stabler served as Manager of Investor
Services for American Exploration Company.

         The Stockholders' Agreement requires that the Board of Directors of
the Company include at least three nominees of the Management Stockholders.
Currently, those three representatives are Messrs. Henderson, Clark and
Strickler. The remaining board members are to include nominees of JEDI. See
"Certain Relationships and Related Transactions -- Stockholders' Agreement and
Related Matters" on page 49.


                                      43

<PAGE>   46


ITEM 11. EXECUTIVE COMPENSATION

SUMMARY COMPENSATION TABLE

         The following table sets forth the annual compensation for the
Company's Chief Executive Officer and the four other most highly compensated
executive officers for the three fiscal years ended December 31, 1997. These
individuals are sometimes referred to as the "named executive officers".

<TABLE>
<CAPTION>
                                                                                     Long-Term
                                                     Annual Compensation           Compensation
                                                ------------------------------     Received from
                                                                Other Annual     Overriding Royalty         All Other
Name and Principal Position                       Salary       Compensation(1)       Program(2)        Compensation(3)
------------------------------                   --------      ---------------  ---------------------  ---------------
<S>                                  <C>         <C>             <C>                 <C>                    <C>
Robert E. Henderson                  1997        $255,000        $  6,000            $394,136               $  315
President and                        1996         236,000           6,000             421,311                  306
Chief Executive Officer              1995         232,350           6,000             216,585                  306

Richard R. Clark                     1997         185,000           6,000             237,982                  306
Senior Vice President                1996         166,500           6,000             247,971                  306
of Production                        1995         161,625           6,000             142,040                  306

Michael W. Strickler                 1997         165,000           6,000             234,603                  306
Senior Vice President                1996         150,000           5,880             258,731                  306
of Exploration                       1995         145,500           5,640             151,512                  306

Frank A. Pici                        1997         146,000           2,747                   0                  306
Vice President of Finance and        1996          12,167               0                   0                   26
Chief Financial Officer              1995               0               0                   0                    0

Clinton D. Smith                     1997         140,700           5,367              60,449                  306
Vice President of Operations         1996         131,500           5,154              96,447                  306
                                     1995         127,525           4,944              67,764                  306
</TABLE>

         (1) Amounts shown reflect the Company's contribution under the
discretionary profit sharing feature of its Employee Capital Accumulation Plan.
See "-- 401(k) Plan". For each of the named executive officers, the aggregate
amount of perquisites and other personal benefits did not exceed the lesser of
$50,000 or 10% of the officer's total annual salary and bonus and information
with respect thereto is not included.
         (2) Does not include amounts received as a result of sales of
overriding royalty interests by individuals, normally in connection with sales
of properties by the Company. No such sales were made in 1997 or 1996.
         (3) Amounts shown reflect insurance premiums paid by the Company with
respect to term life insurance for the benefit of the named executive officers.

EMPLOYMENT AGREEMENTS

         The Company and each of the named executive officers have entered into
employment agreements (each, an "Employment Agreement" and collectively, the
"Employment Agreements") for initial terms of five years in the case of Messrs.
Henderson, Clark and Strickler and three years in the case of Messrs. Pici and
Smith. The Employment Agreements then extend for six months in the case of
Messrs. Henderson, Clark and Strickler and three months in the case of Messrs.
Pici and Smith, unless notice of termination is given by either the Company or
the named executive officer at least three or six months before the end of the
term. Under the Employment Agreements, the annual salaries are $255,000,
$185,000, $165,000, $146,000 and $140,700 for Messrs. Henderson, Clark,
Strickler, Pici and Smith, respectively, which the Company may in its
discretion increase. The named executive officers are eligible for
participation in any medical, dental, life and accidental death and
dismemberment insurance programs and retirement, pension, deferred compensation
and other benefit programs instituted by the Company from time to time. The
employees are also entitled to vacation, reimbursement of certain expenses and,
depending upon the Employment Agreement, either an automobile allowance or a
leased vehicle of the Company's choice and reimbursement for expenses related
to the use of that leased vehicle. As incentive compensation, the named
executive officers are entitled to overriding royalty interests in certain oil
and gas prospects acquired by the Company. See "Overriding Royalty Program".


                                      44

<PAGE>   47

         If a named executive officer's Employment Agreement is terminated by
the Company, with or without Cause (as defined in each Employment Agreement) or
by the named executive officer for Good Reason (as defined in each Employment
Agreement), the named executive officer will be entitled to, among other
things, (i) his or her salary and other benefits through the end of the initial
term or extended term of the Employment Agreement (to be paid in a lump sum
cash payment in the case of termination by the Company without Cause or
termination by the named executive officer for Good Reason), (ii) a lump sum
cash payment equal to six, nine or 12 months' salary, depending upon the
Employment Agreement (12 months in the case of Mr. Henderson, nine months in
the case of Messrs. Clark and Strickler, and six months in the case of Messrs.
Pici and Smith), (iii) a lump sum cash payment equal to all vacation time
carried forward from a previous year and all earned and unused vacation time
for the then current year and (iv) an assignment of vested overriding royalty
interests. See "-- Overriding Royalty Interests". If a named executive
officer's Employment Agreement is terminated by the named executive officer
without Good Reason, he will be entitled to the amounts specified in the
preceding sentence except that he will not be entitled to the lump sum cash
payment described in clause (ii). Any amounts paid on termination of an
Employment Agreement will be grossed-up to cover any applicable taxes.

         Each named executive officer has agreed that during the term of his
Employment Agreement, and for 12 months thereafter in the case of Messrs.
Henderson, Clark and Strickler and six months thereafter in the case of Messrs.
Pici and Smith, if the named executive officer's Employment Agreement is
terminated by the Company for Cause or by the named executive officer other
than for Good Reason, he will not compete with the Company for business or hire
away the Company's employees.

STOCK OPTION PLAN

         Under the Mariner Holdings, Inc. 1996 Stock Option Plan (the "Stock
Option Plan"), a committee of the board of directors of Mariner Holdings (the
"Committee") is authorized to grant options to purchase shares of Mariner
Holdings common stock, including options qualifying as "incentive stock
options" under Section 422 of the Code ("ISOs") and options that do not so
qualify ("NSOs"), to employees and consultants as additional compensation for
their services to Mariner Holdings and its subsidiaries. The Stock Option Plan
is intended to promote the long-term financial interests of Mariner Holdings
and its subsidiaries by providing a means whereby designated employees and
consultants may develop a sense of proprietorship and personal involvement in
the development and financial success of Mariner Holdings and its subsidiaries,
and to encourage them to remain with and devote their best efforts to the
business of Mariner Holdings and its subsidiaries, thereby advancing the
interests of Mariner Holdings and its stockholders.

         The aggregate number of shares of Mariner Holdings common stock that
may be issued under options granted under the Stock Option Plan is 142,800
shares, subject to adjustment in the event of a stock split, stock dividend or
other change in the Mariner Holdings common stock or the capital structure of
Mariner Holdings.

         Subject to the provisions of the Stock Option Plan, the Committee is
authorized to determine who may participate in the Stock Option Plan, the
number of shares that may be issued under each option and the terms, conditions
and limitations applicable to each grant. Subject to certain limitations, the
board of directors of Mariner Holdings is authorized to amend, alter or
terminate the Stock Option Plan.

         Shares of Mariner Holdings common stock purchased pursuant to the
exercise of an Option are subject to the terms of the Stockholders' Agreement.
See "Certain Relationships and Related Transactions--Stockholders' Agreement
and Related Matters" on page 49.



                                      45

<PAGE>   48


         The following table sets forth certain information with respect to
individual grants of options by Mariner Holdings to the named executive
officers during 1997.

<TABLE>
<CAPTION>
                                                                                     Potential Realizable
                                                                                    Value at Assumed Annual
                              Number of     Percentage of                           Rates of Stock Price
                             Securities    Total Options                              Appreciation for
                             Underlying     Granted to      Exercise                    Option Term
                          Options Granted   Employees        or Base    Expiration ----------------------
Name                      (# of shares)(1)   in 1997       Price ($/Sh)     Date   5%   ($)(2) 10%  ($)(2)
----                      ---------------- --------------  ------------ ---------- ----------- -----------
<S>                               <C>      <C>             <C>        <C>          <C>           <C>
Robert E. Henderson               0           --                 --          --     $      0     $      0
Richard R. Clark                  0           --                 --          --            0            0
Michael W. Strickler              0           --                 --          --            0            0
Frank A. Pici                 6,090           51.4%          100.00      7/01/04      247,924      577,758
Clinton D. Smith                  0           --                 --          --            0            0
</TABLE>


(1)       Options to purchase Mariner Holdings common stock were granted as
          part of a stock purchase by management. One fifth of the options vest
          and become exercisable on each of the first five anniversaries of the
          date of grant; the options become fully exercisable upon the
          occurrence of certain other events, including the completion of an
          initial public offering by the Company.

(2)       The potential realizable value of the options, if any, granted in
          1997 to each of these executive officers was calculated by
          multiplying those options by the excess of (a) the assumed value, at
          July 1, 2004, of Mariner Holdings' Common Stock if the value of
          Mariner Holdings' Common Stock were to increase 5% or 10% in each
          year of the option's 7 year term over (b) the base price shown. This
          calculation does not take into account any taxes or other expenses
          which might be owed. There is no market whatsoever for Mariner
          Holdings' Common Stock. For purposes of this chart, the Company has
          assumed a value of $100 per share based on the exercise price of the
          options. The Company makes no representation as to the actual value
          of Mariner Holdings' Common Stock. The assumed value at a 5% assumed
          annual appreciation rate over the 7 year term is $140.71 and such
          value at a 10% assumed annual appreciation rate over that term is
          $194.87. At $140.71 the total market value of the shares of Mariner
          Holdings' Common Stock outstanding on March 1, 1998 would be
          $139,199,197, which would be an increase of $40,272,897 from the
          assumed value of such shares at the close of business on December 31,
          1997. At $194.87, the total value of the shares of Common Stock
          outstanding on March 1, 1997 would be $192,777,681, which would be an
          increase of $93,851,381 from the assumed value of such shares at the
          close of business on December 31, 1997. The 5% and 10% appreciation
          rates are set forth in the Securities and Exchange Commission rules
          and no representation is made that the Common Stock will appreciate
          at these assumed rates or at all.

OVERRIDING ROYALTY PROGRAM

         Pursuant to agreements, the named executive officers are entitled to
receive from the Company, as incentive compensation, overriding royalty
interests ("Overriding Royalty Interests") in certain oil and gas prospects
("Prospects") acquired by the Company. These agreements generally apply to
Prospects acquired by the Company on or after April 18, 1996. Under similar
predecessor agreements that pre-date these agreements, certain of the named
executive officers became entitled to receive Overriding Royalty Interests in
respect of Prospects that were acquired by the Company during various periods
before April 18, 1996. Under these agreements, the aggregate percentage of all
Overriding Royalty Interests affecting the Company's working interests in
Prospects does not exceed 3% before well payout, or 7.5% after well payout, of
the Company's working interest in such Prospects.

         Each Employment Agreement provides that the named executive officer is
entitled to receive, as incentive compensation, Overriding Royalty Interests
equal to certain specified undivided percentages of the Company's working
interest percentage in Prospects acquired by the Company within the United
States and its coastal waters while the Employee is employed by the Company and
during the term or extended term of the Employment Agreement. For purposes of
each Employment Agreement, oil and gas prospects acquired by the Company on or
after April 18, 1996 are deemed to have been acquired by the Company during the
term of the Employment Agreement.



                                      46
<PAGE>   49

         The Overriding Royalty Interest percentage of the Company's working
interest percentage to which each named executive officer is entitled with
respect to each well drilled on a Prospect, for the period before well payout,
is one-fourth of that named executive officer's Overriding Royalty Interest
percentage for the period after well payout. These percentages range from
0.09375% to 0.23250% before payout and from 0.375% to 0.93000% after payout for
the named executive officers.

         In instances in which all or a portion of the Company's working
interest in a Prospect will be sold or farmed out to unaffiliated third
parties, and the Company determines in good faith that the Company's interest
will not be marketable on satisfactory terms if marketed subject to the named
executive officer's Overriding Royalty Interest affecting such Prospect, the
Company, as a general rule, may elect to adjust the named executive officer's
Overriding Royalty Interest in such Prospect. In such instances, a committee
designated by the Board of Directors of the Company (at least half of the
members of which are required to be individuals who have been granted an
Overriding Royalty Interest by the Company) are to exercise discretion on
behalf of the Company in reducing or modifying the named executive officer's
Overriding Royalty Interest in such Prospect in accordance with certain
parameters set forth in the Employment Agreement. Certain decisions of the
committee require the approval of the Board of Directors of the Company. Such
modifications or reductions of the named executive officer's Overriding Royalty
Interest apply only to the portion of the Company's working interest sold or
farmed out to such third party and do not affect the named executive officer's
Overriding Royalty Interest in any interest retained by the Company.

         In addition to the provisions for reduction or other adjustment of the
Employee's Overriding Royalty Interest as mentioned above, the Company may also
elect in its sole discretion, within 60 days after the end of each fiscal year
of the Company, to reduce the named executive officer's Overriding Royalty
Interest set forth in the Employment Agreement with respect to all Prospects
subject to the Employment Agreement that were acquired by the Company during
such fiscal year, based upon certain levels of exploration and development
costs actually incurred by the "Company Group" (which consists of the Company
and certain other entities affiliated with the Company or anticipated to
participate in exploration prospects with the Company) during such fiscal year
in respect of all Prospects subject to the Employment Agreement. Further, with
respect to certain deepwater types of Prospects, the Company may elect in its
sole discretion to make other reductions and adjustments to the Employee's
Overriding Royalty Interest based upon certain levels of exploration and
development costs estimated to be incurred by the Company Group in respect of
such deepwater types of Prospects.

         The Company retains a right of first refusal to purchase any
Overriding Royalty Interest assigned to a named executive officer pursuant to
an Employment Agreement. This right applies to any third party offer received
by the named executive officer during the term or within one year from the
expiration of an Employment Agreement.

         Set forth below is certain information relating to the participation
of the named executive officers in the overriding royalty program.

<TABLE>
<CAPTION>
                                Total Number of        Aggregate cash
                               Prospects in which      amounts received
                               overriding royalty      as a result of
                               interests were         overriding program
       Name                    received in 1997(1)         in 1997
       ----                    -------------------    ------------------
<S>                                      <C>             <C>
Robert E. Henderson                      12              $394,136

Richard R. Clark                         12               237,982

Michael W. Strickler                     12               234,603

Frank A. Pici                             3                     0

Clinton D. Smith                         12                60,449
</TABLE>


         (1) At the time overriding royalty interests are received, they have
only a nominal value because no reserves have been proven on the prospects at
such time.


                                      47
<PAGE>   50



DIRECTORS' COMPENSATION

         Members of the Board of Directors of the Company do not receive
compensation for any services provided in their capacities as directors, other
than the reimbursement of reasonable expenses incurred in connection with
attending meetings of the Board of Directors.

401(k) PLAN

         The Company has an Employee Capital Accumulation Plan that is intended
to be a Section 401(k) plan under the Code. All employees of the Company,
including the named executive officers of the Company, are eligible to
participate in the plan. Employees may make contributions to the plan under a
salary reduction program. The Company may, in its discretion, make "profit
sharing" contributions to the plan on behalf of the plan participants.
Contributions by both employees and the Company to the plan are restricted in
number and amount, and the aggregate contributions by the Company are not
significant. This plan is a continuation of a plan provided by the Predecessor
Company. See Note 5 to the Financial Statements of the Company.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

         Until the Acquisition in April 1996, the Company was a wholly owned
subsidiary of Hardy plc, which through its board of directors and officers set
the compensation of the executive officers of the Company. As a director of
Hardy plc until the Acquisition, Mr. Henderson participated in deliberations
concerning the compensation of executive officers of the Company. After the
Acquisition, the Board of Directors of the Company set the compensation of the
executive officers, and Mr. Henderson participated in deliberations on those
matters. In January 1997, the Board of Directors established a Compensation
Committee, composed of Messrs. Henderson, Buy and Stabler.


ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

         The Company is a wholly owned subsidiary of Mariner Holdings. The
following table sets forth the name and address of the only stockholder of
Mariner Holdings that is known by the Company to beneficially own more than 5%
of the outstanding shares of common stock of Mariner Holdings, the number of
shares beneficially owned by such stockholder, and the percentage of
outstanding shares of common stock of Mariner Holdings so owned, as of March 1,
1998. As of March 1, 1998, there were 989,263 shares of common stock of Mariner
Holdings outstanding.

<TABLE>
<CAPTION>
                                                                Amount and
                               Name and Address                  Nature of          Percent
Title of Class               of Beneficial Owner            Beneficial Ownership    of Class
--------------               -------------------            --------------------    --------
<S>                    <C>                                  <C>                     <C>
Common Stock of         Joint Energy Development             950,000                  96.0%
Mariner Holdings        Investments Limited Partnership(1)
                        1400 Smith Street
                        Houston, Texas 77002
</TABLE>

         (1) JEDI primarily invests in and manages certain natural gas and
energy related assets. JEDI's general partner is Enron Capital Management
Limited Partnership, a Delaware limited partnership, whose general partner is
Enron Capital Corp., a Delaware corporation and a wholly owned subsidiary of
ECT. The general partner of JEDI exercises sole voting and investment power
with respect to such shares.


                                      48

<PAGE>   51

         The table appearing below sets forth information as of March 1, 1998,
with respect to shares of common stock of Mariner Holdings beneficially owned
by each of the Company's directors, the Company's Chief Executive Officer and
the four other most highly compensated executive officers for the fiscal year
ended December 31, 1997, a key consultant of the Company and all directors and
executive officers and such key consultant as a group, and the percentage of
outstanding shares of common stock of Mariner Holdings so owned by each.

<TABLE>
<CAPTION>
       Directors, Key Consultant and            Amount and Nature of     Percent
          Named Executive Officers            Beneficial Ownership (1)  of Class
         -------------------------           ------------------------   --------
<S>                                                    <C>                 <C>
Robert E. Henderson ....................               5,570                 *
Richard R. Clark .......................               3,920                 *
Michael W. Strickler ...................               3,920                 *
Frank A. Pici ..........................               1,706                 *
Clinton D. Smith .......................               2,500                 *
David S. Huber .........................               3,795                 *
Richard B. Buy .........................                   0                 *
Mark E. Haedicke .......................                   0                 *
Stephen R. Horn ........................                   0                 *
Gene E. Humphrey .......................                   0                 *
Jere C. Overdyke, Jr ...................                   0                 *
Frank Stabler ..........................                   0                 *
All directors and executive officers and
  key consultant as a group (15 persons)              26,624                 3%

* Less than one percent ................
</TABLE>

(1) All shares are owned directly by the named person and such person has sole
voting and investment power with respect to such shares.


ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

STOCKHOLDERS' AGREEMENT AND RELATED MATTERS

         Mariner Holdings, ECT, JEDI and each other stockholder of Mariner
Holdings is a party to a Stockholders' Agreement ("Stockholders' Agreement").
The Stockholders' Agreement was originally entered into by ECT, Mariner
Holdings, and Messrs. Henderson, Clark, Strickler and Huber in contemplation of
Mariner Holdings' acquisition of all of the outstanding shares of stock of the
Company. Mariner Holdings was formed by ECT for the purpose of acquiring the
Company. The Stockholders' Agreement provides for the capitalization of Mariner
Holdings by ECT, its affiliates and certain employees and consultants of the
Company, certain aspects of Mariner Holdings' organization and management and
certain rights and obligations of the stockholders of Mariner Holdings.

         The Management Stockholders and JEDI own approximately 4% and
approximately 96%, respectively, of the outstanding shares of Mariner Holdings
stock. On a fully diluted basis (assuming that all options granted to the
Management Stockholders pursuant to the Stockholders' Agreement have been
exercised), the Management Stockholders would own or have the right to acquire
an aggregate of 179,432 shares, which would represent approximately 16% of all
shares that would be outstanding, and JEDI would own approximately 84% of all
outstanding shares on that basis. The stock options granted to the Management
Stockholders generally vest and become exercisable as to one-fifth on each of
the first five anniversaries of the date of grant, and 25,666 shares were
exercisable as of December 31, 1997.


                                      49
<PAGE>   52

         Under the Stockholders' Agreement, Mariner Holdings paid or agreed to
pay certain amounts, including payment or reimbursement to ECT, JEDI and the
Management Stockholders for all reasonable fees and expenses of third parties
incurred by them in connection with the Stockholders' Agreement, the JEDI
Bridge Loan and Mariner Holdings' purchase of the stock of the Company. In
addition, Mariner Holdings agreed to reimburse each Management Stockholder who
paid for shares of Mariner Holdings stock by assignment of overriding royalty
interests for any additional taxes and related costs incurred by such
Management Stockholder to the extent, if any, that the transfer of the
overriding royalty interests does not qualify as a tax-free exchange under
federal tax laws. Of the amounts agreed to be paid by Mariner Holdings,
approximately $5.0 million was, or will be, paid by the Company. In addition,
Mariner Holdings has certain ongoing obligations pursuant to the Stockholders'
Agreement. Since Mariner Holdings has no independent cash flow and no assets
other than its interest in the Company, it will be dependent upon dividends,
distributions or advances from the Company to meet any cash requirements
flowing from such obligations.

         Under the terms of the Stockholders' Agreement, each Management
Stockholder entered into a new or amended employment or consulting agreement
with the Company. See "Management -- Employment, Consulting and Stock Option
Agreements". These agreements, among other things, afford the Management
Stockholders the benefits of the Company's overriding royalty program. See
"Overriding Royalty Program". In addition, the Company must keep certain
employee benefit plans in effect until June 1999.

         The Stockholders' Agreement requires that the board of directors of
Mariner Holdings (as well as the board of directors of each subsidiary of
Mariner Holdings, including the Company) will include at least three Management
Directors. Currently, those three representatives are Messrs. Henderson, Clark
and Strickler. The Stockholders' Agreement requires that the remaining board
members consist of nominees of JEDI. See "Management -- Executive Officers and
Directors". In addition, any executive committee of the board of directors must
include at least two members who are Management Directors and any compensation
committee of the board of directors must include at least one member who is a
Management Director; however, no Management Director is to be appointed to any
audit committee. The Stockholders' Agreement also requires that certain
provisions be included in the certificate of incorporation and bylaws of
Mariner Holdings (as well as each of its subsidiaries, including the Company)
to ensure that the Management Directors are elected to the board and that
certain provisions indemnifying the officers, directors and employees of
Mariner Holdings and of the Company are maintained.

         Under the terms of the Stockholders' Agreement, Enron and its
affiliates (which include, without limitation, ECT and JEDI) are specifically
permitted to compete with Mariner Holdings and the Company, and neither Enron
nor any of its affiliates has any obligation to bring any business opportunity
to Mariner Holdings or the Company. Similarly, Mariner Holdings and the Company
may compete with Enron and its affiliates and do not have any obligation to
bring any business opportunity to Enron or any affiliate of Enron, including,
without limitation, ECT and JEDI. See "Enron".

         Under the terms of the Stockholders' Agreement, the stockholders of
Mariner Holdings have the preemptive right to acquire additional securities
proposed to be issued by Mariner Holdings to any other party, on the same terms
proposed to be applicable to the other party. Each stockholder has the right to
acquire a number of shares representing his or her proportionate interest in
all of the outstanding shares of Mariner Holdings, but to the extent a
stockholder does not exercise any preemptive rights, the remaining stockholders
have the right to acquire the shares offered to the non-acquiring stockholder.

         The Stockholders' Agreement provides for indemnification by Mariner
Holdings of Messrs. Henderson, Clark, Strickler and Huber for any expenses they
incur in an action based on their participation in the transactions described
in the Stockholders' Agreement brought by or in the right of the Company's
former parent, Hardy plc.


                                      50

<PAGE>   53

ENRON

         Enron Corp. ("Enron") is the parent of ECT, and an affiliate of Enron
and ECT is the general partner of JEDI. Accordingly, Enron may be deemed to
control JEDI, Mariner Holdings and the Company. See "Ownership of Securities."
In addition, six of the Company's directors are officers of Enron or affiliates
of Enron: Mr. Buy is a Managing Director of Enron Capital Management, Mr.
Haedicke is a Managing Director of ECT, Mr. Humphrey is Vice Chairman of ECT,
Mr. Horn is a Vice President of ECT and Messrs. Overdyke and Stabler are
Managing Directors of Enron International, Inc.

         Enron and certain of its subsidiaries and other affiliates
collectively participate in nearly all phases of the oil and natural gas
industry and are, therefore, competitors of the Company. In addition, ECT and
JEDI have provided, and may in the future provide, and ECT Securities Corp. has
assisted, and may in the future assist, in arranging financing to
non-affiliated participants in the oil and natural gas industry who are or may
become competitors of the Company. Because of these various conflicting
interests, ECT, the Company, JEDI and the Management Stockholders have entered
into an agreement that is intended to make clear that Enron and its affiliates
have no duty to make business opportunities available to the Company.

         Under the Revolving Credit Facility, the Company has covenanted that
neither it nor Mariner Holdings nor any subsidiary of either will engage in any
transaction with any of its affiliates (including Enron, ECT, JEDI and
affiliates of such entities) providing for the rendering of services or sale of
property unless such transaction is as favorable to such party as could be
obtained in an arm's-length transaction with an unaffiliated party in
accordance with prevailing industry customs and practices. The Revolving Credit
Facility excludes from this covenant (i) any transaction permitted by the
Stockholders' Agreement, (ii) the grant of options to purchase or sales of
equity securities to directors, officers, employees and consultants of the
Company and Mariner Holdings and (iii) the assignment of any overriding royalty
interest pursuant to an employee incentive compensation plan.

         The Indenture, dated as of August 1, 1996, between the Company and
United States Trust Company of New York (the "Indenture"), under which the
Company's 10 1/2% Senior Subordinated Notes Due 2006 were issued, contains
similar restrictions. Under the Indenture, the Company has covenanted not to
engage in any transaction with an affiliate unless the terms of that
transaction are no less favorable to the Company than could be obtained in an
arm's-length transaction with a nonaffiliate. Further, if such a transaction
involves more than $1 million, it must be approved in writing by a majority of
the Company's disinterested directors, and if such a transaction involves more
than $5 million, it must be determined by a nationally recognized banking firm
to be fair, from a financial standpoint, to the Company. However, this covenant
is subject to several significant exceptions, including, among others, (i)
certain industry-related agreements made in the ordinary course of business
where such agreements are approved by a majority of the Company's disinterested
directors as being the most favorable of several bids or proposals, (ii)
transactions under employment agreements or compensation plans entered into in
the ordinary course of business and consistent with industry practice and (iii)
transactions described in this Item 13.

         The Company expects that from time to time it will engage in various
commercial transactions and have various commercial relationships with Enron
and certain affiliates of Enron, such as holding and exploring, exploiting and
developing joint working interests in particular prospects and properties,
engaging in hydrocarbon price hedging arrangements and entering into other oil
and gas related or financial transactions. For example, there are several
prospects in which both an affiliate of Enron and the Company have working
interests. Such interests were acquired in the ordinary course of business
pursuant to bids, joint or otherwise. Any wells drilled will be subject to
joint operating agreements relating to exploration and possible production and
will be subject to customary business terms. Furthermore, the Company has
entered into several agreements with Enron or affiliates of Enron for the
purpose of hedging oil and natural gas prices on the Company's future
production. The Company believes that its current agreements with Enron and its
affiliates are, and anticipates that, but can provide no assurances that, any
future agreements with Enron and its affiliates will be, on terms no less
favorable to the Company than would be contained in an agreement with a third
party.

         Pursuant to a Participation Agreement dated as of May 16, 1996 (the
"Participation Agreement") by and between Hardy plc and Mariner Holdings, Hardy
plc has an option to purchase participation rights in certain prospects
generated by the Company until May 16, 1999. This option entitles Hardy plc to
acquire up to 25% of any leasehold or working interest the Company holds in any
exploitation prospect that (i) is located in the Gulf, (ii) the Company, in its
reasonable


                                      51
<PAGE>   54

judgment, plans to develop, (iii) the Company reasonably expects to exploit
using a floating production facility or a subsea tieback system that will
require estimated gross capital expenditures in excess of $150.0 million and
(iv) is generated by the Company and is expected to be operated by the Company.
The Company is required to provide notice to Hardy plc within ten days of
acquiring an interest, or a contractual right to acquire an interest, in such a
prospect. Hardy plc must exercise its option with respect to such prospect
within ten days of receiving such notice from the Company. If Hardy plc
exercises its participation right as to any prospect, it must pay the Company a
ratable portion of the Company's costs and expenses in generating and acquiring
the prospect, including a ratable portion of a $250,000 prospect fee. In
addition to the interest in the prospect it acquires from the Company, Hardy
plc would then have the right to copy any geological and geophysical data owned
by the Company and pertaining to the prospect in which it is participating,
unless the Company is restricted from doing so by another agreement.

PLANNED 1998 EQUITY INVESTMENT

         In March 1998, Mariner Holdings, Inc. reached an agreement in
principle with certain of its existing stockholders, including JEDI, pursuant
to which its stockholders will purchase additional shares of Mariner Holdings
for approximately $175.00 per share, for an aggregate investment of $30.0
million. The Company expects to pay approximately $1.2 million as a structuring
fee, on a pro rata basis, to existing stockholders participating in this
transaction. Approximately $1.0 million of this fee is expected to be paid to
ECT Securities Corp., an affiliate of JEDI. The Company expects to close this
transaction in April 1998.


                                      52
<PAGE>   55

                                    GLOSSARY

         The terms defined in this glossary are used throughout this annual
report.

         Bbl. One stock tank barrel, or 42 U.S. Gallons liquid volume, used
herein in reference to crude oil, condensate or other liquid hydrocarbons.

         Bcf.  One billion cubic feet of natural gas.

         Bcfe. One billion cubic feet of natural gas equivalent (see Mcfe for
equivalency).

         "behind the pipe" Hydrocarbons in a potentially producing horizon
penetrated by a well bore the production of which has been postponed pending
the production of hydrocarbons from another formation penetrated by the well
bore. These hydrocarbons are classified as proved but non-producing reserves.

         2-D. (Two-Dimensional Seismic) -- geophysical data that depicts the
subsurface strata in two dimensions.

         3-D. (Three-Dimensional Seismic) -- geophysical data that depicts the
subsurface strata in three dimensions. 3-D seismic typically provides a more
detailed and accurate interpretation of the subsurface strata than can be
achieved using 2-D seismic.

         "development well" A well drilled within the proved boundaries of an
oil or natural gas reservoir with the intention of completing the stratigraphic
horizon known to be productive.

         "exploitation well" Ordinarily considered to be a development well
drilled within a known reservoir. The Company uses the word to refer to
deepwater wells which are drilled on offshore leaseholds held (usually under
farmout agreements) where a previous exploratory well showing the existence of
potentially productive reservoirs was drilled, but the reservoir was by-passed
for development by the owner who drilled the exploratory well; thus the Company
distinguishes its development wells on its own properties from such
exploitation wells.

         "exploratory well" A well drilled in unproven or semi-proven territory
for the purpose of ascertaining the presence underground of a commercial
petroleum deposit and which can be contrasted with a "development well".

         "farm-in" A term used to describe the action taken by the person to
whom a transfer of an interest in a leasehold in an oil and gas property is
made pursuant to a farmout agreement.

         "farmout" The term used to describe the action taken by the person
making a transfer of a leasehold interest in an oil and gas property pursuant
to a farmout agreement.

         "farmout agreement" A common form of agreement between oil and gas
operators pursuant to which an owner of an oil and gas leasehold interest who
is not desirous of drilling at the time agrees to assign the leasehold
interest, or some portion of it, to another operator who is desirous of
drilling the tract. The assignor in such a transaction may retain some interest
in the property such as an overriding royalty interest or a production payment
and, typically, the assignee of the leasehold interest has an obligation to
drill one or more wells on the assigned acreage as a prerequisite to completion
of the transfer to it.

         "finding and development cost" Generally, the cost of finding and
developing commercial oil and gas including all costs involved in acquiring
acreage, seismic survey costs and the cost of drilling, completion and other
development activities.

         "generate" Generally refers to the creation of an exploration or
exploitation idea after evaluation of seismic and other available data.

         "infill well" A well drilled between known producing wells to better
exploit the reservoir.


                                       55
<PAGE>   56

         "lease operating expenses" The expenses of lifting oil or gas from a
producing formation to the surface, and the transportation and marketing
thereof, constituting part of the current operating expenses of a working
interest, and also including labor, superintendence, supplies, repairs,
short-lived assets, maintenance, allocated overhead costs, ad valorem taxes and
other expenses incidental to production, but not including lease acquisition,
drilling or completion expenses or other "finding costs".

         Mbbls.  One thousand barrels of crude oil or other liquid hydrocarbons.

         Mcf.  One thousand cubic feet of natural gas.

         Mcfe. One thousand cubic feet of natural gas equivalent (converting
one barrel of oil to six Mcf of natural gas based on commonly accepted rough
equivalency of energy content).

         MMBTU.  One million British thermal units.

         Mmcf.  One million cubic feet of natural gas.

         Mmcfe. One million cubic feet of natural gas equivalent (see Mcfe for
equivalency).

         NYMEX.  New York Mercantile Exchange.

         "payout" Generally refers to the recovery by the incurring party to an
agreement of its costs of drilling, completing, equipping and operating a well
before another party's participation in the benefits of the well commences or
is increased to a new level.

         "present value of estimated future net revenues" An estimate of the
present value of the estimated future net revenues from proved oil and gas
reserves at a date indicated after deducting estimated production and ad
valorem taxes, future capital costs and operating expenses, but before
deducting any estimates of federal income taxes. The estimated future net
revenues are discounted at an annual rate of 10%, in accordance with Securities
and Exchange Commission practice, to determine their "present value". The
present value is shown to indicate the effect of time on the value of the
revenue stream and should not be construed as being the fair market value of
the properties. Estimates of future net revenues are made using oil and natural
gas prices and operating costs at the date indicated and held constant for the
life of the reserves.

         "producing well" or "productive well" A well that is producing oil or
natural gas or that is capable of production without further capital
expenditure.

         "proved developed reserves" Proved developed reserves are those
quantities of crude oil, natural gas and natural gas liquids that, upon
analysis of geological and engineering data, are expected with reasonable
certainty to be recoverable in the future from known oil and natural gas
reservoirs under existing economic and operating conditions. This
classification includes: (a) proved developed producing reserves, which are
those expected to be recovered from currently producing zones under
continuation of present operating methods; and (b) proved developed
non-producing reserves, which consist of (i) reserves from wells that have been
completed and tested but are not yet producing due to lack of market or minor
completion problems that are expected to be corrected, and (ii) reserves
currently behind the pipe in existing wells which are expected to be productive
due to both the well log characteristics and analogous production in the
immediate vicinity of the well.

         "proved reserves" The estimated quantities of crude oil, natural gas
and other hydrocarbon 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.

         "proved undeveloped reserves" Proved reserves that may be expected to
be recovered from existing wells that will require a relatively major
expenditure to develop or from undrilled acreage adjacent to productive units
that are reasonably certain of production when drilled.


                                      56
<PAGE>   57

         "royalty interest" An interest in an oil and gas lease that gives the
owner of the interest the right to receive a portion of the production from the
leased acreage for the proceeds of the sale thereof, but generally does not
require the owner to pay any portion of the costs of drilling or operating the
wells on the leased acreage. Royalty interests may be either landowner's
royalty interests, which are reserved by the owner of the leased acreage at the
time the lease is granted, or overriding royalty interests, which are usually
carved from the leasehold interest pursuant to an assignment to a third party
or reserved by an owner of the leasehold in connection with a transfer of the
leasehold to a subsequent owner.

         "subsea tieback" A productive well that has its wellhead equipment
located on the sea floor and is connected by control and flow lines to an
existing production platform located in the vicinity.

         "unitized" or "unitization" Terms used to denominate the joint
operation of all or some portion of a producing reservoir, particularly where
there is separate ownership of portions of the rights in a common producing
pool in order that it may be economically feasible to carry on certain
production techniques, maximize reservoir production and serve conservation
interests.

         "working interest" The interest in an oil and gas property (normally a
leasehold interest) that gives the owner the right to drill, produce and
conduct oil and gas operations on the property and to a share of production,
subject to all royalties, overriding royalties and other burdens and to all
costs of exploration, development and operations and all risks in connection
therewith.


                                      57
<PAGE>   58
                                   SIGNATURES

         The registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.

March 27, 1998

         MARINER ENERGY, INC.



         by: /s/ Robert E. Henderson
            ------------------------
             Robert E. Henderson,
             Chairman of the Board, President and Chief Executive Officer


         This report has been signed below by the following persons on behalf
of the registrant and in the capacities and on the dates indicated.

<TABLE>
<CAPTION>
Signature                                        Title                            Date
---------                                        -----                            ----
<S>                                <C>                                         <C>
/s/ Robert E. Henderson            Chairman of the Board, President and        March 27, 1998
---------------------------          Chief Executive Officer
Robert E. Henderson                  (Principal Executive Officer)

/s/ Frank A. Pici                  Vice President of Finance and               March 27, 1998
---------------------------          Chief Financial Officer
Frank A. Pici                        (Principal Financial Officer and Principal Accounting Officer)

/s/ Richard R. Clark               Senior Vice President of Production         March 27, 1998
---------------------------           and Director
Richard R. Clark

/s/ Michael W. Strickler           Senior Vice President of Exploration        March 27, 1998
---------------------------           and Director
Michael W. Strickler

/s/ Richard B. Buy                    Director                                 March 27, 1998
---------------------------
Richard B. Buy

/s/ Mark E. Haedicke                  Director                                 March 27, 1998
---------------------------
Mark E. Haedicke

/s/ Stephen R. Horn                   Director                                 March 27, 1998
---------------------------
Stephen R. Horn

/s/ Gene E. Humphrey                  Director                                 March 27, 1998
---------------------------
Gene E. Humphrey

/s/ Jere C. Overdyke, Jr.             Director                                 March 27, 1998
---------------------------
Jere C. Overdyke, Jr.

/s/ Frank Stabler                     Director                                 March 27, 1998
---------------------------
Frank Stabler
</TABLE>

<PAGE>   59


    SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO
  SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES
                       PURSUANT TO SECTION 12 OF THE ACT


         No annual report covering the Registrant's last fiscal year or proxy
statement, form of proxy or other proxy soliciting material with respect to any
annual or other meeting of security holders has been sent to the Company's
security holders.


<PAGE>   60
                                 EXHIBIT INDEX


          3.1(a)   Amended and Restated Certificate of Incorporation of the
                  Registrant, as amended.

          3.2(a)   Bylaws of Registrant, as amended.

          4.1(a)   Indenture, dated as of August 1, 1996, between the Registrant
                   and United States Trust Company of New York, as Trustee.

          4.2(d)   First Amendment to Indenture, dated as of January 31, 1997,
                   between the Registrant and United States Trust Company of New
                   York, as Trustee.

          4.3(a)   Credit Agreement, dated June 28, 1996, among the Registrant,
                   NationsBank of Texas, N.A., as Agent, and the financial
                   institutions listed on schedule 1 thereto, as amended by
                   First Amendment to Credit Agreement, dated August 12, 1996,
                   among the Registrant, NationsBank of Texas, N.A., as Agent,
                   Toronto Dominion (Texas), Inc., as Co-agent, and the
                   financial institutions listed on schedule 1 thereto.

          4.4(a)   Note, dated August 12, 1996, in the principal amount of up to
                   $45,000,000, made by the Registrant in favor of NationsBank
                   of Texas, N.A.

          4.5(a)   Note, dated August 12, 1996, in the principal amount of up to
                   $45,000,000, made by the Registrant in favor of Toronto
                   Dominion (Texas), Inc.

          4.6(a)   Note, dated August 12, 1996, in the principal amount of up to
                   $30,000,000, made by the Registrant in favor of The Bank of
                   Nova Scotia.

          4.7(a)   Note, dated 12, 1996, in the principal amount of up to
                   $30,000.000, made by the Registrant in favor of ABN AMRO
                   Bank, N.V., Houston Agency.

          4.8(a)   Form of the Registrant's 10 1/2% Senior Subordinated Note Due
                   2006, Series B.

          10.2(a)  Participation Agreement, dated as of May 16, 1996, between
                   Hardy Oil & Gas plc. and Mariner Holdings, Inc.

          10.3(c)  Stockholders' Agreement, dated April 2, 1996, among Enron
                   Capital & Trade Resources Corp., Mariner Holdings, Inc.
                   (formerly Mystery Acquisition, Inc.), Joint Energy
                   Development Investments Limited Partnership and the other
                   stockholders of Mariner Holdings, Inc., as amended May 16,
                   1996, and as of May 31, 1996.




<PAGE>   61

         10.4(a)+ Amended and Restated Employment Agreement, dated June 27,
                  1996, between the Registrant and Robert E. Henderson.

         10.5(a)+ Amended and Restated Employment Agreement, dated June 27,
                  1996, between the Registrant and Richard R. Clark.

         10.6(a)+ Amended and Restated Employment Agreement, dated June 27,
                  1996, between the Registrant and Michael W. Strickler.

         10.7(a)+ Amended and Restated Employment Agreement, dated June 27,
                  1996, between the Registrant and James M. Fitzpatrick.

         10.8(a)+ Amended and Restated Employment Agreement, dated June 27,
                  1996, between the Registrant and Gregory K. Harless.

         10.9(b)+ Amended and Restated Employment Agreement, dated June 27,
                  1996, between the Registrant and W. Hunt Hodge.

         10.10(a)+Amended and Restated Employment Agreement, dated June 27,
                  1996, between the Registrant and Clinton D. Smith.

         10.11(a)+Amended and Restated Consulting Services Agreement, dated
                  June 27, 1996, between the Registrant and David S. Huber.

         10.12(a)+Mariner Holdings, Inc. 1996 Stock Option Plan.

         10.13(a)+Form of Incentive Stock Option Agreement (pursuant to the
                  Mariner Holdings, Inc. 1996 Stock Option Plan).

         10.14*   List of executive officers who are parties to an Incentive
                  Stock Option Agreement.

         10.15(a)+Form of Nonstatutory Stock Option Agreement (pursuant to the
                  Mariner Holdings, Inc. 1996 Stock Option Plan).

         10.16*   List of executive officers who are parties to a Nonstatutory
                  Stock Option Agreement.

         10.17(a)+Nonstatutory Stock Option Agreement, dated June 27, 1996,
                  between the Registrant and David S. Huber.

         10.19(d) Employment Agreement, dated as of December 2, 1996, between
                  the Registrant and Frank A. Pici.

         23.1*    Consent of Ryder Scott Company.

         27.1*     Financial Data Schedule.
---------------------------

(a)      Incorporated by reference to the Company's Registration Statement on
         Form S-4 (Registration No. 333-12707), filed September 25, 1996.
(b)      Incorporated by reference to Amendment No. 1 to the Company's
         Registration Statement on Form S-4 (Registration No. 333-12707), filed
         December 6, 1996.
(c)      Incorporated by reference to Amendment No. 2 to the Company's
         Registration Statement on Form S-4 (Registration No. 333-12707), filed
         December 19, 1996.
(d)      Incorporated by reference to the Company's Annual Report on Form 10-K
         for the year ended December 31, 1996 (Registration No. 333-12707)
         filed March 31, 1997.