MARINER ENERGY INC, 10-K405, 1997-03-31

MARINER ENERGY INC
10-K405, 1997-03-31
CRUDE PETROLEUM & NATURAL GAS

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996

COMMISSION FILE NUMBER 0-___________

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 x No
----- -----

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

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

As of March 27, 1997, there were 1,000 shares of the registrant's
common stock outstanding.

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TABLE OF CONTENTS

DESCRIPTION

<TABLE>
<CAPTION>
Item Page
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<S> <C> <C>
PART I
1. BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
2. PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT . . . . . . . . . . . . . . . . . . . . . . . . . . 41
11. EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

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 forward-looking statements that involve risks and uncertainties. The
Company's actual results could differ materially. Some of the more important
Factors that could cause or contribute to such differences include those
discussed in Item 1 "Business", Item 7 "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and elsewhere in this report.

ITEM 1. BUSINESS

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

OVERVIEW

Mariner Energy, Inc. ("Mariner" or the "Company") is an independent
oil and gas exploration company with principal operations in three geographic
areas: the shallow water or "shelf" (water depths less than 600 feet) of the
Gulf of Mexico 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, 1996, approximately 84% 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 utilizes advanced
evaluation and, particularly in the Gulf, advanced completion technologies to
explore for and produce oil and natural gas.

The Company began its operations in 1983 as a subsidiary of Trafalgar
House plc, a large U.K. conglomerate. As such, the Company carried on the U.S.
oil and gas operations 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.

In an acquisition effective April 1, 1996, Mariner Holdings, Inc.
acquired all the capital stock of the Company from Hardy Holdings Inc. (the
"Acquisition") as part of a management-led buyout financed by an affiliate of
Enron Capital & Trade Resources Corp. ("ECT"). The aggregate purchase price
was approximately $185.5 million, including $14.5 million for net working
capital. In connection with the Acquisition, substantial intercompany
indebtedness and receivables and third-party indebtedness of the Company were
eliminated. See Item 6 for a presentation of selected historical financial
information for the predecessor company as of and for periods prior to the
Acquisition and for Mariner Energy, Inc. as of and for the nine months ended
December 31, 1996 and the selected proforma financial information for the years
ended December 31, 1995 and 1996, presented as if the Acquisition had occurred
on January 1, 1995.

As of December 31, 1996, the Company had proved reserves of 5.3
millions barrels (Mmbbl) of oil and condensate and 92.3 billion cubic feet
(Bcf) of natural gas, aggregating 124.1 Bcfe. Approximately 74% of the
Company's proved reserves were natural gas and approximately 84% were proved
developed. In addition to its properties holding proved reserves, the Company
had an inventory of 30 specific prospects, which it expects will account for
most of its exploratory and exploitation drilling activities over the next two
years. In the aggregate, the Company had a total undeveloped leasehold
inventory of approximately 152,000 net acres, including 71 undeveloped Gulf
blocks, and held under license or other arrangement approximately 6,100 square
miles of 3-D seismic data and approximately 196,000 linear miles of 2-D seismic
data.

From June 1, 1989 (when the Company began to focus its efforts on the
Gulf), through December 31, 1996, the Company drilled 234 gross (74.9 net)
wells, including 78 gross (25.6 net) exploratory and deepwater exploitation
wells. Of such wells, 25 were completed (22 in Gulf shallow water or onshore
and 3 in Gulf deepwater), representing a 32% success rate on its exploration
and deepwater exploitation activities. During the same period, the Company
completed approximately 92% of its development wells. At December 31, 1996, the
Company was in the process of drilling one gross (0.2 net) exploratory well and
one gross (0.8 net) development well.

From January 1, 1992 through December 31, 1996, the Company had
increases in annual average daily production of 175%, to approximately 68 Mmcfe
per day. During this period the Company replaced 144% of its annual production
through the drillbit at an average finding and development cost of $1.04 per
Mcfe of proved reserves. During the period, several property disposals were
completed to fund the drilling program. These disposals accounted for a 31.2
Bcfe reduction

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in proved reserves (20.3 Bcfe during 1996), or approximately 25% of the current
proved reserve base. Net of disposals, proved reserves have increased 5% over
the period.

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, 1996. 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 "Properties--Oil and
Natural Gas Reserves" and "Management's Discussion and Analysis of Financial
Condition and Results of Operations".

<TABLE>
<CAPTION>
Year ended December 31,
---------------------------------------------------------
1996 1995 1994 1993 1992
----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C>
Proved reserves:
Oil (Mbbls) . . . . . . . . . . . . . . . . . 5,280 6,669 6,900 6,128 6,190
Natural gas (Mmcf) . . . . . . . . . . . . . . 92,284 98,330 100,645 91,060 80,837
Natural gas equivalent (Mmcfe) . . . . . . . . 123,964 138,344 142,045 127,828 117,977
Present value of estimated future net revenues
(in thousands)(1) . . . . . . . . . . . . . . . . $303,363 $173,421 $ 95,318 $ 94,243 $100,064

Annual reserve replacement ratio(2) . . . . . . 1.2 1.2 2.0 1.7 1.9

Capital expenditures:
Capital costs incurred . . . . . . . . . . . . $ 45,731 $ 41,772 $ 36,923 $ 27,966 $ 27,770
Percentage attributable to:
Exploration, including leasehold and
seismic . . . . . . . . . . . . . . . . . 80.8% 41.8% 51.5% 44.0% 47.3%
Development and other . . . . . . . . . . . 19.2% 58.2% 48.5% 56.0% 52.7%

Proceeds from property sales . . . . . . . . . $ 7,528 $ 20,688 $ 3,480 $215 $ 2,381

Production:
Oil (Mbbls) . . . . . . . . . . . . . . . . . 750 424 459 470 525
Natural gas (Mmcf) . . . . . . . . . . . . . . 20,429 13,770 14,362 12,507 5,896
Natural gas equivalents (Mmcfe) . . . . . . . 24,929 16,314 17,116 15,327 9,046

Average realized sales price per unit:
Oil (per Bbl) . . . . . . . . . . . . . . . . $ 18.10 $ 17.19 $ 15.86 $ 17.07 $ 19.51
Natural gas (per Mcf) . . . . . . . . . . . . 2.39 1.76 1.99 2.10 1.82
Gas equivalent (per Mcfe) . . . . . . . . . . 2.50 2.04 2.09 2.24 2.32

Costs per Mcfe:
Lease operating expense . . . . . . . . . . . 0.43 0.45 0.42 0.51 0.70
General and administrative expense . . . . . . 0.13 0.12 0.11 0.15 0.22
Average finding and development cost(3) . . . 1.04 1.00 1.03 1.25 1.08
</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
future capital) related to properties which have been evaluated
for the rolling period by the ultimate reserve additions for the
same period. For the years ended December 31, 1996, 1995, 1994
and 1993, the rolling period is five years, which management
believes is the minimum period for meaningful presentation. A
four year rolling average has been used for the year ended
December 31, 1992, as less than five years data was available due
to the demerger of the Company in 1989.

STRATEGY

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

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The Company applies a "portfolio management" approach to its drilling
activities that is directed at balancing (i) its views as to the moderate risks
of its exploration program in the Gulf and near onshore areas, the relatively
lower risk of exploitation in Gulf deepwater and the still lower risk of
development of the Company's interests in the Permian Basin of West Texas with
(ii) its views as to the potential for adding significant value from such
activities, particularly in the shallow water and deepwater of the Gulf.

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, low
lease operating expenses and favorable leasehold costs. At December 31, 1996,
approximately 64% in value of the Company's reserves and 68% of the Company's
average daily production were located in Gulf shallow water and near onshore
fields.

Mariner's Gulf deepwater operations have been focused on the
exploitation of previously discovered reservoirs which the Company believes are
too small to be of interest to large oil companies. The Company believes that
its deepwater expertise and low operating costs enable it to develop small and
mid-size fields in deeper water of the Gulf profitably. At December 31, 1996,
approximately 20% in value of the Company's reserves and 26% of the Company's
average daily production were located in Gulf deepwater. During 1996, the
Company decided to expand its efforts in Gulf deepwater 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, (ii) the relative immaturity of these
exploration activities compared to other Gulf activities and (iii) the limited
competition for the Company's targeted reservoir sizes.

The Company's operations in the Spraberry Trend of the Permian Basin
of West Texas, which, at December 31, 1996, accounted for approximately 16% in
value of the Company's reserves and 6% of the Company's average daily
production, have been 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 19
offshore blocks in 1995 and 25 offshore blocks in 1996 through lease sales and
farm-ins, 17 of which were in the deepwater.

To aid in implementing its strategy, Mariner believes that the
following competitive advantages distinguish it 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 Gulf deepwater 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
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 which
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, 1996, approximately 85%
by value of the Company's reserves were located in six fields. 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

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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
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, 1996. 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 10-12 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 which provides overriding royalty interests in successful projects. The
Company believes that its overriding royalty program provides a strong
alignment of management's and investors' interests. In addition, the Company
believes that this program is a significant reason why the Company 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 mentioned above, certain members of management
and other key personnel of the Company also purchased approximately 4% of the
common stock of Mariner Holdings and acquired options to purchase an
additional 11% of the common stock of Mariner Holdings.

MARKETING AND HEDGING

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.
<TABLE>
<CAPTION>
Percentage of total revenues
For the year ended December 31
-------------------------------
Customer 1996 1995 1994
-------- ---- ---- ----
<S> <C> <C> <C>
Transco Energy Marketing Company 15% 20% -
Howell Crude Oil Company/Genesis 13% - -
Texaco Natural Gas, Inc. 13% - -
Seneca Resources Corporation 10% 20% -
Marathon Petroleum Company - 12% 11%
Union Oil Company of California - - 25%
Apache Corporation - - 13%
</TABLE>

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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.

From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to achieve a more
predictable cash flow, as well as to reduce its exposure to price fluctuations.
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 1996, approximately 64% of the Company's equivalent production was
subject to hedge positions, and hedging arrangements through October 1997 cover
approximately 33% of the Company's anticipated average daily production for
1997. 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 32) 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".

SEASONALITY

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

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.

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.

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

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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 issued a new 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 very heavily
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.

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 an ad valorem, production or severance tax with respect to
production and sale of crude oil, natural gas and gas liquids within its
jurisdiction.

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 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

6
<PAGE> 9
owners or operators), to clean up contaminated property (including contaminated
groundwater) or to perform remedial plugging operations to prevent future
contamination.

EMPLOYEES

As of December 31, 1996, the Company had 48 full-time employees. The
Company's employees are not represented by any labor union. Relations between
the Company and its employees are considered to be satisfactory and the Company
has had no work stoppages or strikes.

ITEM 2. PROPERTIES

PRINCIPAL PRODUCING PROPERTIES

The Company owns oil and gas properties, both producing and for future
exploration, onshore in Texas and offshore in the Gulf, primarily in federal
waters. The Company currently has six principal producing properties, which in
the aggregate accounted for, as of December 31, 1996, 85% of the Company's
proved reserves.

<TABLE>
<CAPTION>
As of December 31, 1996
------------------------
Mariner Ownership Net Average
----------------- Producing Daily Production Net Proved
Working Net Revenue Wells ------------------------ Reserves
Interest Interest (gross) Oil (Bbls) Gas (Mmcf) (Mmcfe)
-------- -------- -------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C>
Gulf Shallow Water and
Near Onshore Areas:
Sandy Lake 48.0% 35.5% 5 1,412 7.9 28,337
Brazos A-105 12.5% 9.9% 5 16 10.5 15,985
Matagorda Island 683/703 25.0% 19.8% 3 2 4.3 5,595

Gulf of Mexico Deepwater:
Green Canyon 136 25.0% 21.7% 2 74 10.3 9,289
Garden Banks 240 33.0% 27.2% 1 52 5.6 10,468

Permian Basin of West Texas:
Spraberry Aldwell Unit 70.3% 59.3% 67 351 1.9 36,053
-------
Totals - Principal Producing 105,727
Properties =======

Totals - All Properties 123,964
Percentage of Principal Producing Properties to All Properties 85%
</TABLE>

Following is additional information regarding principal producing properties.

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 wells have been drilled thus far, five of which are
producing. At December 31, 1996, the Company was in the process of increasing
the capacity of its gas processing facility at Sandy Lake, which in effect
controls production, by 60% -- a measure which is expected to increase
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

7
<PAGE> 10
("UNOCAL") is the operator of the property, and five producing wells have been
drilled thus far, with the drilling of two development wells possible in the
future. The field has an estimated remaining life of 14 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 three producing wells have been
drilled thus far, with no additional drilling currently planned. The field has
an estimated remaining life of 10 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
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 7 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 to a production
platform operated by Chevron approximately 12 miles from the well site, and its
production is commingled and marketed with Chevron's production. The field has
an estimated remaining life of 9 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. An infill well
drilling program was implemented in 1987, and to date 53 wells have been
drilled, all of which are currently producing. The drilling of 30 to 43
additional infill wells (targeted at bringing into production proved
undeveloped reserves) is planned during the next three to four years at a
projected cost to the Company of approximately $215,000 per well. The field
has an estimated remaining life of 48 years.

OIL AND NATURAL GAS RESERVES

The following tables set forth certain information with respect to the
Company's reserves. 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, 1996, 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 Company's financial statements for a discussion of the risks
inherent in oil and natural gas estimates.

8
<PAGE> 11
The following table sets forth certain information regarding the
Company's estimated proved reserves for each of the periods indicated.
<TABLE>
<CAPTION>
Year ended December 31,
-------------------------------------------------------------------------------
1996 1995 1994
-------------------- -------------------- ---------------------
Oil Gas Oil Gas Oil Gas
(Mbbl) (Mmcf) (Mbbl) (Mmcf) (Mbbl) (Mmcf)
------ ------- ------ ------- ------ -------
<S> <C> <C> <C> <C> <C> <C>
Proved Reserves:
Beginning balance . . . . . 6,669 98,330 6,900 100,645 6,128 91,060
Revisions of previous
estimates . . . . . . . . 3 (518) 307 14,113 423 4,241
Extensions, discoveries,
improved recovery and
other additions . . . . 1,168 24,326 46 2,476 829 21,842
Sale of reserves . . . . . . (1,810) (9,425) (160) (5,134) (21) (2,136)
Production . . . . . . . . . (750) (20,429) (424) (13,770) (459) (14,362)
------ ------- ------ ------- ------ -------
Ending balance . . . . . . . 5,280 92,284 6,669 98,330 6,900 100,645
====== ======= ====== ======= ====== =======
Proved Developed Reserves:
Beginning balance . . . . . 4,357 87,843 4,037 83,192 3,653 67,263
Ending balance . . . . . . . 3,456 83,529 4,357 87,843 4,037 83,192
</TABLE>

The following table sets forth the present value of estimated future
net revenues from proved reserves as of the dates indicated.
<TABLE>
<CAPTION>
At December 31,
--------------------------------------
1996 1995 1994
-------- -------- -------
<S> <C> <C> <C>
Proved developed . . . . . . . . $279,245 $165,784 $81,354
Proved undeveloped . . . . . . . 24,118 7,637 13,964
-------- -------- -------
Total proved . . . . . . . . $303,363 $173,421 $95,318
======== ======== =======
</TABLE>

Since December 31, 1995, the Company has not filed any estimates of
total proved net oil or natural gas reserves with any federal authority or
agency. See Note 10 to the Financial Statements of the Company included
elsewhere in this annual report for certain additional information concerning
the proved reserves of the Company.

9
<PAGE> 12
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,
-----------------------------------------------------------
1996 1995 1994
-------------- -------------- -------------
<S> <C> <C> <C>
Production:
Oil (Mbbls) . . . . . . . . . . . . . . . . . . . 750 424 459
Natural gas (Mmcf) . . . . . . . . . . . . . . . . 20,429 13,770 14,362
Gas equivalent (per Mmcfe) . . . . . . . . . . . . 24,929 16,314 17,116

Average sales prices including effects of hedging:
Oil (per Bbl) . . . . . . . . . . . . . . . . . . $18.10 $17.19 $15.86
Natural gas (per Mcf) . . . . . . . . . . . . . . 2.39 1.76 1.99
Gas equivalent (per Mcfe) . . . . . . . . . . . . 2.50 2.04 2.09

Expenses (per Mcfe):
Lease operating . . . . . . . . . . . . . . . . . .43 .45 .42
General and administrative, net . . . . . . . . . .13 .12 .11
Depreciation, depletion and amortization . . . . . 1.25 .96 .95

Cash margin per Mcfe (1) . . . . . . . . . . . . . . 1.94 1.47 1.56
</TABLE>

(1) Average equivalent gas sales price minus lease operating and general and
administrative expenses.

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, 1996:

<TABLE>
<CAPTION>
Total Productive Wells
--------------------------------
Gross Net
----------- ---------
<S> <C> <C>
Oil . . . . . . . . . . . . . . 75 53.6
Gas . . . . . . . . . . . . . . 81 12.0
--- ----
Total . . . . . . . . . . 156 65.8
=== ====
</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.

10
<PAGE> 13
ACREAGE

The following table sets forth certain information with respect to the
developed and undeveloped acreage of the Company as of December 31, 1996.

<TABLE>
<CAPTION>
At December 31, 1996
-----------------------------------------------------
Developed Acres (1) Undeveloped Acres (2)
------------------- ---------------------
Gross Net Gross Net
----- --- ----- ---
<S> <C> <C> <C> <C>
Texas (Onshore) . . . . . . . . . . . . . 20,816 13,569 4,996 2,292
All other states (Onshore) . . . . . . . 1,495 232 8,632 1,526
Offshore . . . . . . . . . . . . . . . . 143,207 27,409 354,206 148,488
------- ------- ------- -------
Total . . . . . . . . . . . . . . . 165,518 41,210 367,834 152,306
======= ====== ======= =======
</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.

DRILLING ACTIVITY

Certain information with regard to the Company's drilling activity
during the years ended December 31, 1996, 1995 and 1994 is set forth below.
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------------------
1996 1995 1994
------------------- ------------------------ -------------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Exploratory wells:
Producing . . . . . . . . . . 3 0.78 - - 6 1.43
Dry . . . . . . . . . . . . . 4 1.40 6 2.38 7 3.26
-- ---- -- ---- -- ----
Total . . . . . . . . . . 7 2.18 6 2.38 13 4.69
== ==== == ==== == ====
Development wells:
Producing . . . . . . . . . . 5 1.73 3 0.85 6 1.97
Dry . . . . . . . . . . . . . - - - - 3 1.72
--- ---- --- ---- --- ----
Total . . . . . . . . . . 5 1.73 3 0.85 9 3.69
=== ==== == ==== === ====
Total wells:
Producing . . . . . . . . . . 8 2.51 3 0.85 12 3.40
Dry . . . . . . . . . . . . . 4 1.40 6 2.38 10 4.98
--- ---- --- ---- --- ----
Total . . . . . . . . . . 12 3.91 9 3.23 22 8.38
=== ==== === ==== === ====
</TABLE>

At December 31, 1996, the Company was in the process of drilling one
gross (0.2 net) exploratory well and one gross (0.8 net) development well.

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. 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.

11
<PAGE> 14
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.

ITEM 3. LEGAL PROCEEDINGS

The Company, in the ordinary course of business, is a claimant and/or a
defendant in various 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. 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) for an aggregate
purchase price of approximately $185.5 million, including $14.5 million for net
working capital. 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.

<TABLE>
<CAPTION>
SELECTED HISTORICAL DATA Predecessor Company (1)
(ALL AMOUNTS IN THOUSANDS) ---------------------------------------------------------
Years ended December 31, 3 Mos. 9 Mos.
------------------------------------------- Ended Ended
1992 1993 1994 1995 3/31/96 12/31/96
-------- ------- ------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Total revenues $20,972 $34,295 $35,856 $33,309 $13,778 $48,522
Lease operating expenses 6,312 7,746 7,118 7,331 2,872 7,938
Depreciation, depletion and 8,572 15,607 16,221 15,635 6,309 24,747
amortization
Impairment of oil and gas properties - 6,296 6,257 - - 22,500
General and administrative expenses 1,948 2,242 1,830 2,028 712 2,406
------- ------- ------- -------- -------- -------
Operating income (loss) 4,140 2,404 4,430 8,315 3,885 (9,069)

Interest income 1,021 1,513 1,084 9,255 2,167 515
Interest expense (4,940) (7,358) (8,125) (12,772) (3,391) (7,746)
Write-off bridge loan fees - - - - - (2,392)
------- ------- ------- -------- -------- -------
Income (loss) before income taxes 221 (3,441) (2,611) 4,798 2,661 (18,692)
Provision for income taxes - - - 338 - -
------- ------- ------- -------- -------- -------
Net income (loss) $221 ($3,441) ($2,611) $4,460 $2,661 ($18,692)
======= ======= ======= ======== ======== ========
CAPITAL EXPENDITURE AND DISPOSAL DATA:
Exploration, incl. leasehold/seismic $13,131 $12,285 $19,016 $17,460 $4,852 $32,104
Development and other 14,639 15,681 17,907 24,312 2,643 6,132
------- ------- ------- -------- -------- -------
Total capital expenditures $27,770 $27,966 $36,923 $41,772 $7,495 $38,236
======= ======= ======= ======== ======== ========
Proceeds from disposals
$2,381 $215 $3,480 $20,688 - $7,528
======= ======= ======= ======== ======== ========

BALANCE SHEET DATA (AT END OF PERIOD):
Oil and gas properties, net, at full $102,938 $109,002 $120,135 $125,817 $127,095 $166,619
cost
Long-term receivable from affiliates 15,000 18,000 4,000 106,000 104,000 -
Total assets 125,532 138,435 138,202 250,726 254,301 196,749
Long-term debt, less current 105,000 109,000 105,500 162,500 162,500 99,525
maturities
Stockholder's equity 8,350 20,909 18,798 69,258 71,919 77,053
</TABLE>

(1) - "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
In order to provide a measure of comparability between annual results for
1995 and 1996, the following pro forma statements of operations are presented
as if the Acquisition mentioned above had occurred on January 1, 1995. The pro
forma adjustments are based upon available information and certain assumptions
that management of the Company believe are reasonable. The pro forma
statements of operations do not purport to represent what the Company's results
of operations would actually have been had the Acquisition occurred on January
1, 1995, nor do they purport to project results of operations for any future
period.

UNAUDITED PRO FORMA
STATEMENTS OF OPERATIONS
(ALL AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
Predecessor Company
--------------------------------------------------
3 Months 9 Months Year
Year ended December 31, 1995 Ended Ended Ended
-------------------------------------- 3/31/96 12/31/96 12/31/96
Historical Adjustments Pro Forma Historical Historical Adjustments Pro Forma
---------- ----------- --------- ---------- ---------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Total revenues $ 33,309 - $33,309 $13,778 $ 48,522 - $62,300
Lease operating expenses 7,331 - 7,331 2,872 7,938 - 10,810
Depreciation, depletion
and amortization 15,635 $ 1,430 (1) 17,065 6,309 24,747 $ 906 (1) 31,962
Impairment of oil and gas
properties - - - - 22,500 (22,500)(2) 0
General and administrative
expenses 2,028 - 2,028 712 2,406 - 3,118
-------- ------- ------- ------- -------- ------- -------
Operating income (loss) 8,315 (1,430) 6,885 3,885 (9,069) 21,594 16,410

Interest income 9,255 (8,472)(3) 783 2,167 515 (2,107)(3) 575
Interest expense (12,772) 3,486 (4) (9,286) (3,391) (7,746) 663 (4) (10,474)
Write-off bridge loan fees - - - - (2,392) 2,392 (5) 0
-------- ------- ------- ------- -------- ------- -------
Income (loss) before
income taxes 4,798 (6,416) (1,618) 2,661 (18,692) 22,542 6,511
Provision for income taxes 338 - 338 (6) - - - 0
-------- ------- ------- ------- -------- ------- -------
Net income (loss) $ 4,460 ($6,416) ($1,956) $ 2,661 ($18,692) $22,542 $ 6,511
======== ======= ======= ======= ======== ======= =======
</TABLE>

(1) Depreciation, depletion and amortization have been adjusted to reflect
the amount of the purchase price allocated to property and equipment.
(2) To eliminate the writedown of oil and gas properties resulting from the
Acquisition.
(3) Interest income has been eliminated on the intercompany notes receivable
that were repaid in connection with the Acquisition.
(4) Interest expense has been adjusted to reflect the following:
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------
1995 1996
-------- -------
(in thousands)
<S> <C> <C>
10 1/2% Senior Subordinated Notes Due 2006 . . . . . . . . $ 10,500 $ 6,504
Capitalized interest costs . . . . . . . . . . . . . . . . (1,579) (290)
Amortization of debt issuance costs . . . . . . . . . . . . 300 204
Amortization of Outstanding Note discount . . . . . . . . . 65 39
Elimination of historical interest expense . . . . . . . . (13,715) (7,081)
Elimination of historical capitalized interest . . . . . . 1,265 233
Elimination of historical amortization of debt issuance
costs . . . . . . . . . . . . . . . . . . . . . . . . . . (322) (272)
-------- -------
Pro forma interest expense adjustment . . . . . . . . $ (3,486) $ (663)
======== =======
</TABLE>

(5) To eliminate the write-off of debt fees resulting from the refinancing of
a portion of the JEDI Bridge Loan (see page 32) with the Revolving Credit
Facility (see page 20).
(6) Generally no income tax expense or benefit is recorded as a result of the
Company recording a full valuation allowance for the Company's net
deferred tax assets. The $338 thousand recorded in 1995 is the
alternative minimum taxes resulting from the gain (for tax purposes) on
the 1995 sale of the North Shongaloo Properties. A comparable sale has
not been made subsequent to 1995 nor is one anticipated.

14
<PAGE> 17

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

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, 1996. 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.

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 and borrowing
against a Revolving Credit Facility (see pages 20 and 32).

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.

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.

15
<PAGE> 18
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,
-----------------------------------------------------------
1996 1995 1994
-------------- -------------- -------------
<S> <C> <C> <C>
Production:
Oil (Mbbls) . . . . . . . . . . . . . . . . . . . 750 424 459
Natural gas (Mmcf) . . . . . . . . . . . . . . . . 20,429 13,770 14,362
Gas equivalent (per Mmcfe) . . . . . . . . . . . . 24,929 16,314 17,116

1996 COMPARED TO 1995

NOTE: Where revenue and expense items discussed below would have been
affected in a pro forma presentation of the acquisition by Mariner Holdings of
the stock of the Company (formerly "Hardy Oil & Gas USA, Inc."), the pro forma
impact on that item is discussed.

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 (18.1 Mmcf per
day), or 48%, to 20.4 Bcf from 13.8 Bcf. Increased gas production was due to
new production from Green Canyon 136 (10.8 Mmcf per day) and Garden Banks 240
(5.3 Mmcf per day), and the start-up of the Sandy Lake Central facility (6.9
Mmcf per day). These increases were partially offset by natural production
decline on other properties. Oil and condensate production in 1996 increased
326 Mbbls (893 Bbls per day), or 77%, to 750 Mbbls from 424 Mbbls, due
primarily to the start-up of the Sandy Lake Central facility (1,243 Bbl per
day) offset by the sale of several Spraberry properties (269 Bbl per day).

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 price of natural gas 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.

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.

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. On a pro forma basis, DD&A
would have increased by $0.9 million over the historical 1996, as the

16
<PAGE> 19
rate increased from $1.25 per Mcfe to $1.28 per Mcfe. DD&A for 1995 on a pro
forma basis would have been $1.4 million higher than historical 1995, as the
DD&A rate per mcfe increased from $0.96 to $1.05.

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. On a pro forma basis, the impairment charge recorded in
1996 would not have been required.

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.

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 32) as a result of refinancing a portion of the
amount with the Revolving Credit Facility (see pages 20 and 32). 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. On a pro forma basis, interest expense would have decreased
by $0.7 million from the historical 1996 amount, due to replacing average
outstanding debt of $113.2 million at 9.68% average interest with outstanding
debt of $100.0 million at 10.50% interest. The $2.4 million write-off of the
bridge loan fees would have been eliminated for the pro forma year ended
December 31, 1996, while interest income would have decreased by $2.1 million,
due to the elimination of interest income related to intercompany notes
receivable that were repaid in connection with 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. On a pro forma basis, the historical 1996 loss becomes income
of $6.5 million, after the elimination of the full cost ceiling writedown and
adjustments to interest income and expense, net of additional pro forma
depreciation. For 1995, historical income of $4.8 million becomes a loss of
$1.6 million, after the pro forma adjustments to interest income and expense
and recording additional DD&A expense.

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.

1995 COMPARED TO 1994

NET PRODUCTION decreased 5% to 16.3 Bcfe in 1995 from 17.1 Bcfe in 1994.
During 1995, natural gas production decreased by 0.6 Bcf, or 4%, to 13.8 Bcf
from 14.4 Bcf. Decreased gas production was due primarily to depletion of
existing fields and sale of non-strategic properties.

OIL AND GAS REVENUES for 1995 decreased by $2.5 million, or 7%, compared
to 1994. The decrease was primarily a result of lower natural gas prices and
production volumes, partially offset by higher crude oil prices and the $1.7
million settlement of a claim in bankruptcy against Columbia Gas Transmission
Company in 1995. The average realized price of natural gas decreased 12%, to
$1.76 per mcf in 1995 from $1.99 in 1994, while the realized oil sales price
increased 8%, to $17.19 per Bbl in 1995 from $15.86 per Bbl in 1994.

HEDGING ACTIVITIES of natural gas for 1995 had the effect of increasing
the average realized sales price received per Mcf by $0.07 and increasing
revenues by $1.0 million. In 1994, hedging activities increased the average
realized sales price received by $0.06 per mcf and revenues by $0.9 million.
During 1995, approximately 33% of the Company's equivalent production was
subject to hedge positions as compared to 39% in 1994.

LEASE OPERATING EXPENSES increased 3% to $7.3 million in 1995 from $7.1
million in 1994, primarily due to higher direct operating costs of $0.5 million
in 1995, partially offset by lower marketing expenses and production taxes of
$0.3 million.

DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE decreased 4% to $15.6
million in 1995, from $16.2 million in 1994, as a result of lower equivalent
volumes produced due to the sale of producing properties in late 1994 and early
1995,

17
<PAGE> 20
which was partially offset by an increase in the unit-of-production
depreciation, depletion and amortization rate to $0.96 per Mcfe in 1995 from
$.95 per Mcfe in 1994.

IMPAIRMENT OF OIL AND GAS PROPERTIES was zero in 1995 compared to $6.3
million in 1994.

GENERAL AND ADMINISTRATIVE EXPENSES increased 11% to $2.0 million in
1995 from $1.8 million in 1994, in part because general and administrative
expenses in 1994 were offset by a refund of state franchise taxes.

INTEREST EXPENSE increased 58% to $12.8 million in 1995 from $8.1
million in 1994, due to the issuance of $60 million of senior notes in January
1995. The average outstanding debt increased 52% to $165.1 million in 1995 from
$108.6 in 1994. The average interest rate paid on outstanding debt increased
15% to 8.19% in 1995 from 7.10% in 1994. Interest income increased 745% to
$9.3 million in 1995 from $1.1 million in 1994, due to the increase in the
long-term receivable from affiliate caused by the receipt of funds from the
issuance of $60 million of senior notes and a $46 million equity contribution
from the Company's parent company.

INCOME (LOSS) BEFORE INCOME TAXES was $4.8 million in 1995 compared to a
loss of $2.6 million in 1994. Included in 1995 net income was a $1.7 million
benefit from the proceeds received from the Columbia Gas bankruptcy settlement.
Additionally, the 1994 net loss included a $6.3 million impairment of oil and
gas properties for the writedown of the unamortized capital costs of the proved
properties to the present value of estimated future net revenues.

INCOME TAXES in 1995 were $0.3 million compared to no provision in 1994,
due to the imposition of alternative minimum taxes as a result of a gain on
sale of oil and gas properties in 1995.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Liquidity is defined as the Company's ability to generate cash to meet
its needs for cash. As of December 31, 1996, the Company had cash and cash
equivalents of approximately $10.8 million and working capital of approximately
$5.6 million. Primary sources of cash during the three year period ended
December 31, 1996 were funds generated from operations, proceeds from the
issuance of notes, bank borrowings, capital contributions by the Company's
former parent and proceeds from the sale of oil and gas properties. 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.

The Company had a net cash inflow of $10.8 million in 1996, a net cash
inflow of $1.1 million in 1995 and a net cash inflow of $2.9 million in 1994.
A discussion of the major components of cash flows for these years follows.

<TABLE>
<CAPTION>
1996 1995 1994
------ ------ ------
<S> <C> <C> <C>
Cash flows provided by operating activities (in millions)....... $ 44.3 $22.0 $22.5
</TABLE>

Cash flows provided by operating activities in 1996 increased by $22.3
million compared to 1995 primarily due to increased oil and gas production
volumes and prices. Cash flows from operating activities in 1995 decreased
$0.5 million from 1994 primarily due to lower production volumes and prices,
offset in part by the $1.7 million collection of a bankruptcy claim against
Columbia Gas Transmission Company.

<TABLE>
<CAPTION>
1996 1995 1994
------ ------ ------
<S> <C> <C> <C>
Cash flows used in investing activities (in millions)............. $221.8 $123.3 $19.6
</TABLE>

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 lower issuance of long-term receivable to the Company's former
affiliate. Comparing 1995 to 1994, cash flows used in investing activities
increased by $103.7 million, due primarily to a net increase in long-term
receivables to affiliate of $116.0 million and increased capital expenditures
of $4.9 million, offset in part by increased proceeds from the sale of oil and
gas properties of $17.2 million.

18
<PAGE> 21
<TABLE>
<CAPTION>
1996 1995 1994
------ ------ ------
<S> <C> <C> <C>
Cash flows provided by financing activities (in millions)........ $188.3 $102.4 $ -
</TABLE>

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. No funds were provided by or used for financing activities in
1994.

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 may also limit 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
--------------------------------
1996 1995 1994
--------- ------ -------
<S> <C> <C> <C>
Increase (decrease) in natural gas sales (in thousands)......... $(3,701) $1,020 $ 877
Increase (decrease) in oil sales (in thousands)................. (1,912) - -
Effect of hedging transactions on average gas sales price
(per Mcf)................................................. (0.18) 0.07 0.06
Effect of hedging transactions on average oil sales price
(per Bbl)................................................. (2.55) - -
</TABLE>

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, 1996.

<TABLE>
<CAPTION>
Natural Gas Crude Oil
------------------------------- -----------------------------------
Hedge Quantity Fixed Price Hedge Quantity Fixed Price
Mmbtu $/Mmbtu Bbls $/Bbl
---------------- ----------- ------------------- ------------
<S> <C> <C> <C> <C>
January 1997 . . . . . 1,128,400 $2.22 62,000 $18.55
February 1977 . . . . . 1,055,600 2.21 56,000 18.55
March 1997 . . . . . . 1,193,500 2.12 - -
April 1997 . . . . . . 750,000 2.61 - -
August 1997 . . . . . . 1,240,000 2.17 - -
September 1997 . . . . 1,200,000 2.17 - -
October 1997 . . . . . 1,240,000 2.17 - -
</TABLE>

CAPITAL EXPENDITURES AND CAPITAL RESOURCES

The following table presents major components of capital and exploration
expenditures for the three years ended December 31, 1996.
<TABLE>
<CAPTION>
1996 1995 1994
------ ------ ------
<S> <C> <C> <C>
Capital expenditures (in millions):
Leasehold acquisition $14.4 $ 4.6 $ 2.5
Oil and gas exploration 22.5 12.9 16.5
Oil and gas development and other 8.8 24.3 17.9
------ ----- -----

Total capital expenditures $45.7 $41.8 $36.9
===== ====== =====
</TABLE>

19
<PAGE> 22
Total capital expenditures for 1996 were $3.9 million more 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 ($9.8 million) and oil and gas exploration ($9.6
million), offset by a decrease in development expenditures. Total capital
expenditures in 1995 were $4.9 million greater than 1994, due primarily to an
increase in oil and gas development expenditures.

The Company currently plans to increase its 1997 capital expenditures to
approximately $66.7 million, to enable it to continue its exploration and
development program growth strategy. 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
1997 capital budget 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.

Mariner Holdings purchased all the capital stock of the Company from
Hardy Holdings Inc. effective April 1, 1996. The Company established a
revolving credit facility ("Revolving Credit Facility") with NationsBank of
Texas, N.A., carrying a borrowing base of $50 million as of December 31, 1996.
In August 1996, the Company issued $100,000,000 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 outstanding under the Company's Revolving Credit
Facility. The Company had no revolver debt outstanding as of December 31,
1996.

The Company expects to fund its activities in 1997 through a combination
of cash flow from operations and the use of its Revolving Credit Facility to
borrow funds required from time to time to supplement internal cash flows.
Based upon the Company's current level of operations and anticipated growth,
management of the Company believes that available cash, together with available
borrowings under the Revolving Credit Facility and cash provided by operating
activities, will be adequate to meet the Company's anticipated future
requirements for working capital, capital expenditures and scheduled payments
of principal and interest on its indebtedness. Moreover, there can be no
assurance that such anticipated growth will be realized, that the Company's
business will generate sufficient cash flow from operations or that future
borrowings will be available in an amount sufficient to enable the Company to
service its indebtedness or make necessary capital expenditures. In addition,
depending on the levels of its cash flow and capital expenditures (the latter
of which are, to a large extent, discretionary), the Company may need to
refinance a portion of the principal amount of its senior subordinated debt at
or prior to their maturity. However, there can be no assurance that the Company
would be able to obtain financing to complete a refinancing.

20
<PAGE> 23
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Independent Auditors' Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Balance Sheets at December 31, 1996 (Mariner Energy, Inc.)
and December 31, 1995 (Predecessor Company) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Statements of Operations for the nine months ended December 31, 1996
(Mariner Energy, Inc.), the three months ended March 31, 1996,
and the years ended December 31, 1995 and 1994
(Predecessor Company) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Statements of Stockholder's Equity for the nine months ended December 31, 1996
(Mariner Energy, Inc.), the three months ended March 31, 1996,
and the years ended December 31, 1995 and 1994
(Predecessor Company) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Statements of Cash Flows for the nine months ended December 31, 1996
(Mariner Energy, Inc.), the three months ended March 31, 1996,
and the years ended December 31, 1995 and 1994
(Predecessor Company) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Supplemental oil and gas reserve and standardized measure information (unaudited) . . . . . . . . . . . . . . 38
</TABLE>

21
<PAGE> 24

INDEPENDENT AUDITORS' REPORT

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

We have audited the accompanying financial statements of Mariner Energy, Inc.,
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, 1996 and 1995, and the results of its operations and cash flows
for the nine months ended December 31, 1996, the three months ended March 31,
1996, and each of the two years in the period ended December 31, 1995, in
conformity with generally accepted accounting principles.

/s/ DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP

Houston, Texas
March 7, 1997

22
<PAGE> 25
MARINER ENERGY, INC.
BALANCE SHEETS
(IN THOUSANDS)

<TABLE>
<CAPTION>
Predecessor
Company
December 31, December 31,
ASSETS 1996 1995
------ ------------ ------------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents $ 10,819 $ 5,456
Receivables:
Trade 10,060 6,121
Joint owner and other 3,511 4,768
Affiliates - 745
Prepaid expenses 382 119
Lease and well equipment inventory 36 36
-------- --------
Total current assets 24,808 17,245
-------- --------

PROPERTY AND EQUIPMENT:
Oil and gas properties, at full cost:
Proved 169,728 334,120
Unproved, not subject to amortization 21,310 9,559
-------- --------
Total 191,038 343,679
Other property and equipment 1,671 1,954
Accumulated depletion, depreciation and amortization (24,600) (218,983)
-------- --------

Total property and equipment, net 168,109 126,650
-------- --------

LONG-TERM RECEIVABLE FROM AFFILIATES - 106,000

OTHER ASSETS, NET OF AMORTIZATION 3,832 831
-------- --------

TOTAL ASSETS $196,749 $250,726
======== ========
LIABILITIES AND STOCKHOLDER'S EQUITY
------------------------------------
CURRENT LIABILITIES:
Accounts payable $ 2,930 $ 1,604
Accrued liabilities 12,288 12,607
Accrued interest 3,996 1,011
Payable to affiliates - 129
Current portion of long-term debt - 3,000
-------- --------
Total current liabilities 19,214 18,351
-------- --------
ACCRUAL FOR FUTURE ABANDONMENT COSTS 957 617

LONG-TERM DEBT:
Subordinated notes 99,525 -
Affiliate - 23,500
Guaranteed senior notes - 139,000
-------- --------
Total long-term debt 99,525 162,500
-------- --------

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 95,744 81,094
Accumulated deficit (18,692) (11,837)
-------- --------
Total stockholder's equity 77,053 69,258
-------- --------

TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $196,749 $250,726
======== ========
</TABLE>

The accompanying notes are an integral part of these financial statements

23
<PAGE> 26
MARINER ENERGY, INC.
STATEMENTS OF OPERATIONS
(IN THOUSANDS)

<TABLE>
<CAPTION>
Predecessor Company
------------------------------------------------------

Nine Months Three Months Year Year
Ended Ended Ended Ended
December 31, March 31, December 31, December 31,
1996 1996 1995 1994
---------------- -------------- ----------------- -----------------
<S> <C> <C> <C> <C>
REVENUES:
Oil sales $9,934 $3,644 $7,288 $7,281
Gas sales 38,588 10,134 26,021 28,575
-------- ------ ------ -------
Total revenues 48,522 13,778 33,309 35,856
-------- ------ ------ -------
COSTS AND EXPENSES:
Lease operating expenses 7,938 2,872 7,331 7,118
Depreciation, depletion and amortization 24,747 6,309 15,635 16,221
Impairment of oil and gas properties 22,500 - - 6,257
General and administrative expenses 2,406 712 2,028 1,830
-------- ------ ------ -------
Total costs and expenses 57,591 9,893 24,994 31,426
-------- ------ ------ -------
OPERATING INCOME (LOSS) (9,069) 3,885 8,315 4,430
INTEREST:
Related party income - 57 8,472 989
Other income 515 2,110 783 95
Related party expense - (381) (1,610) (1,241)
Other expense (7,746) (3,010) (11,162) (6,884)
Write-off bridge loan fees (2,392) - - -
-------- ------ ------ -------
INCOME (LOSS) BEFORE INCOME TAXES (18,692) 2,661 4,798 (2,611)
PROVISION FOR INCOME TAXES - - 338 -
-------- ------ ------ -------
NET INCOME (LOSS) $(18,692) $2,661 $4,460 $(2,611)
======== ====== ====== =======
</TABLE>

The accompanying notes are an integral part of these financial statements

24
<PAGE> 27
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
--------- -------- ---------- ----------- -------------
<S> <C> <C> <C> <C> <C>
PREDECESSOR COMPANY:
Balance at January 1, 1994 1,000 $1 $34,594 $(13,686) $20,909

Capital contribution 500 500

Net loss (2,611) (2,611)
--------- -------- ---------- --------- ----------
Balance at December 31, 1994 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 14,650 9,176 23,826
Acquisition
Net loss (18,692) (18,692)
--------- -------- ---------- --------- ----------
Balance at December 31, 1996 1,000 $1 $95,744 $(18,692) $77,053
========= ======== ========== ========= ==========
</TABLE>

The accompanying notes are an integral part of these financial statements

25
<PAGE> 28
MARINER ENERGY, INC.
STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

<TABLE>
<CAPTION>
Predecessor Company
--------------------------------------------------

OPERATING ACTIVITIES:
Net income (loss) $(18,692) $2,661 $4,460 $(2,611)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization 27,706 6,437 16,183 16,637
Impairment of oil and gas properties 22,500 - - 6,257
Imputed interest 1,322 - - -
Changes in operating assets and liabilities:
Trade receivables (1,591) (2,348) (1,005) 1,469
Joint owner receivables 822 475 (1,742) (1,724)
Affiliates receivable - (2,109) (718) 99
Prepaid expenses and equipment inventory (317) (307) (1) 260
Accounts payable and accrued liabilities 6,955 832 5,060 1,969
Payables to affiliates - (11) (229) 241
------------ ------------ ------------ -----------
Net cash provided by operating activities 38,705 5,630 22,008 22,597
------------ ------------ ------------ -----------
INVESTING ACTIVITIES:
Purchase of Predecessor Company, net of cash of $5,438 (184,742) - - -
Additions to oil and gas properties (38,236) (7,495) (41,772) (36,923)
Additions to other property and equipment (741) (153) (211) (205)
Proceeds from sale of oil and gas properties 7,528 - 20,688 3,480
Issuance of long-term receivable to affiliates - (1,000) (107,000) -
Repayment of long-term receivable from affiliates - 3,000 5,000 14,000
------------ ------------ ------------ -----------
Net cash used in investing activities (216,191) (5,648) (123,295) (19,648)
------------ ------------ ------------ -----------
FINANCING ACTIVITIES:
Principal payments of long-term debt (92,000) - (3,000) -
Principal payments on debt to affiliates - - - (500)
Principal payments on revolving credit facility (50,000) - - -
Payments of debt issue costs (3,961) - (592) (43)
Issuance of guaranteed senior notes - - 60,000 -
Proceeds from Subordinated Notes 99,506 - - -
Proceeds from long-term debt 92,000 - - -
Proceeds from revolving credit facility 50,000 - - -
Additional capital contributed by Parent 92,150 - 46,000 500
Sale of common stock 610 - - -
------------ ------------ ------------ -----------
Net cash provided by financing activities 188,305 - 102,408 (43)
------------ ------------ ------------ -----------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 10,819 (18) 1,121 2,906
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD - 5,456 4,335 1,429
------------ ------------ ------------ -----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $10,819 $5,438 $5,456 $4,335
============ ============ ============ ============
</TABLE>

The accompanying notes are an integral part of these financial statements

26
<PAGE> 29
MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION -- For the years ended December 31, 1994, and 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"), 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 $22,500,000 and $6,257,000 was recorded during 1996 and 1994,
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 returns 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 basis of
assets and liabilities (see Note 8 to the Financial Statements).

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 $449,000, $1,265,000 and $558,000 for the years ended
December 31, 1996, 1995 and 1994, respectively.

27
<PAGE> 30
MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

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,
1996 and 1995, the estimated fair value of the Company's Senior Subordinated
Notes and Guaranteed Senior Notes was approximately $100,000,000 and
$142,366,000, respectively. These estimated fair values were determined based
on borrowing rates available at December 31, 1996 and 1995, respectively, for
debt with similar terms and maturities. The notes receivable and payable to
affiliates are of a related-party nature and the fair value is not practicable
to estimate. 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, 1996, crude oil and
natural gas market prices had fallen from the December 31, 1996 levels used by
the Company to establish price assumptions for the calculation of its oil and
gas reserve basis at December 31, 1996. The NYMEX average crude oil price was
$22.868 per Bbl for the month of February 1997, down from an average price of
$25.124 per Bbl for the month of December 1996. The final three day NYMEX
average price of natural gas for the month of February 1997 was $2.868 per
Mmbtu, down from the average for the month of December 1996 of $3.611 per
Mmbtu.

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.

28
<PAGE> 31
MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

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
======
</TABLE>

<TABLE>
<CAPTION>
Uses of Funds
(in millions)
<S> <C>
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 (see page 32) and $2.0
million of other transaction fees and expenses.

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.

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.

29
<PAGE> 32
MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

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:

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 and $989,000 on the receivable for the years ended December
31, 1995 and 1994, respectively (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).

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).

The current receivable from affiliates at December 31, 1995 represented
accrued interest related to the lending facilities (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%.

30
<PAGE> 33
MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

The agreement, as modified, contained certain restrictive covenants relating to
the maintenance of certain measures of financial position during the term of
the loan. As of December 31, 1995, the Company was in compliance with all such
covenants. The loan was to mature on June 1, 1998. (See Note 2 to the Financial
Statements).

The Company incurred interest expense of approximately $381,000 on the
debt during the three months ended March 31, 1996 and $1,610,000 and $1,241,000
on the debt during the years ended December 31, 1995 and 1994, respectively.

The current payable to affiliates at December 31, 1995 included
approximately $129,000 for accrued interest related to affiliated debt. (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 and $283,000 for the years
ended December 31, 1995 and 1994, respectively, 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, five 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.

4. LONG-TERM DEBT

PRE-ACQUISITION REVOLVING CREDIT FACILITY -- Effective January 21,
1991, Hardy plc entered into an $80,000,000 revolving credit facility (the
"Facility") with an international bank. Them Company was an original borrower
on the Facility and could draw down funds as long as the aggregate amount
borrowed by the original borrowers, which included Hardy plc and its affiliates
(the "group"), did not exceed amounts as detailed in the agreement ($67,000,000
at December 31, 1995).

31
<PAGE> 34
MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

The maturity date of the Facility would have been December 31, 1997, and
borrowings would have borne interest at the rate of LIBOR plus 0.725%. The
Company had no borrowings outstanding under the Facility at December 31, 1995.
(See Note 2 to the Financial Statements).

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.

POST-ACQUISITION 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 $50 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 10 1/2%
Senior Subordinated Notes.

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

32
<PAGE> 35
MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

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, 1996, 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 assumed in the Acquisition, and
(ii) to 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, 1996, 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 $7,623,000
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 and
$8,734,000 for the years ended December 31, 1995 and 1994, respectively.

5. STOCKHOLDER'S EQUITY

PRE-ACQUISITION CAPITAL CONTRIBUTIONS -- The Predecessor Company
received capital contributions of $46,000,000 and $500,000 from Hardy Holdings
Inc., which was ultimately contributed from Hardy plc, during the years ended
December 31, 1995 and 1994, respectively.

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

33
<PAGE> 36
MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

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, 1996, options (the "Options") to purchase 128,331 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 FASB Statement 123, the Company's net loss for the nine
months ended December 31, 1996 would have increased $356,000 from $18,692,000
to $19,048,000. 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 14,469 at December 31, 1996. No stock
options were exercisable at December 31, 1996.

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 1996, 1995 and
1994, the Company contributed $165,000, $163,000 and $159,000, respectively, to
the Plan. This plan is a continuation of a plan provided by the Predecessor
Company.

OVERRIDING ROYALTY INTERESTS -- Pursuant to agreements, certain
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.

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, 1996 are as follows (in thousands):

<TABLE>
<S> <C> <C>
1997................................................................................ $ 537
1998................................................................................ 533
1999................................................................................ 523
2000................................................................................ 523
2001................................................................................ 262
------

Total......................................................................... $2,378
======
</TABLE>

Rental expense, before capitalization, was approximately $427,000,
$391,000 and $377,000 for the years ended December 31, 1996, 1995 and 1994,
respectively.

34
<PAGE> 37
MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

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,
------------------------------------------------------
1996 1995 1994
-------------- ------------- ------------
<S> <C> <C> <C>
Natural gas quantity hedged (Mmbtu) . . . . . . . 13,482,900 5,890,000 7,407,000

Increase (decrease) in natural gas sales . . . . (3,701,000) 1,020,000 877,000

Crude oil quantity hedged (Bbls) . . . . . . . . 428,000 - -

Increase (decrease) in crude oil sales . . . . . (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, 1996.

<TABLE>
<CAPTION>
Crude Oil Natural Gas
---------------------- -------------------------
Weighted Weighted
BBLS Average Price MMBTU Average Price
----- ------------- ----- -------------
<S> <C> <C> <C> <C>
January - February 1997 . . . . . 118,000 $18.55 2,184,000 $2.22

March 1997 . . . . . . . . . . . - - 1,193,500 2.12

April 1997 . . . . . . . . . . . - - 750,000 2.61

August - October 1997 . . . . . . - - 3,680,000 2.17
</TABLE>

At December 31, 1996 the "approximate break-even price" (the weighted average
of the monthly settlement prices of the applicable futures contracts which
would result in no settlement being due to or from the Company) with respect to
such contracts is approximately $2.22 per MMBTU and $18.55 per BBL.

35
<PAGE> 38

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 (in thousands):

<TABLE>
<CAPTION>
Predecessor Company
----------------------------------------------------------
Year Ended December 31,
9 Months Ended 3 Months Ended -------------------------------------
12/31/96 3/31/96 1995 1994
----------------- --------------- -------------------------------------
$ % $ % $ % $ %
----- --- ----- --- ----- --- ----- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Income (loss) before income taxes (18,692) -- 2,661 -- 4,798 -- (2,611) --
Income tax expense (benefit)
computed at statutory rates . . . (6,542) (35) 931 35 1,679 35 (914) (35)
Change in valuation allowance . . 8,089 43 (3,597) (135) (1,261) (26) 898 34
Other . . . . . . . . . . . . . . (1,547) (8) 2,666 100 (80) (2) 16 1
------- ----- ------ ---- ------ --- ------ ----
Tax Expense . . . . . . . . . . . -- -- -- -- 338 7 -- --
======= ===== ====== ==== ====== === ====== ====
</TABLE>

Federal income tax paid by the Company during the year ended December
31, 1995 was $338,000. No federal income taxes were paid by the Company during
the nine months ended December 31, 1996, the three months ended March 31, 1996
and the year ended December 31, 1994.

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 1994 and 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 1996 that bears no relation to the deferred tax position of
the Predecessor for 1994 or 1995. Significant components of the deferred tax
assets and liabilities are as follows (in thousands):
<TABLE>
<CAPTION>
Predecessor Company
--------------------------------
1996 1995 1994
------------ ------------ -------------
<S> <C> <C> <C>
Deferred tax assets:
Net operating loss carryforwards . . . . . . . . . . . $4,644 $28,157 $26,668
Alternative minimum tax credit carryforward . . . . . -- 321 --
Other . . . . . . . . . . . . . . . . . . . . . . . . -- 959 964
Differences between book and tax basis of properties . 3,445 -- --
------------ ------------ -------------
8.089 29,437 27,632
Valuation allowance . . . . . . . . . . . . . . . . . . . . (8,089) (9,383) (10,644)
------------ ------------ -------------

Total net deferred tax assets . . . . . . . . . . . . . . . -- 20,054 16,988
------------ ------------ -------------
Deferred tax liabilities --
Differences between book and tax basis of properties . -- (20,054) (16,988)
------------ ------------ -------------
Total net deferred taxes . . . . . . . . . . . . $ -- $ -- $ --
============= ============= =============
</TABLE>

36
<PAGE> 39
MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

As of December 31, 1996, the Company has a cumulative net operating loss
carryforward ("NOL") for federal income tax purposes of approximately $13.3
million, which expires in the year 2012. 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

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

<TABLE>
<CAPTION>
Predecessor Company
----------------------------------------------
Year ended December 31,
Nine months ended Three months ended -------------------------
December 31, 1996 March 31, 1996 1995 1994
----------------- ------------------ ---------- ----------
<S> <C> <C> <C> <C>
Oil and gas sales . . . . . . . . . . . $48,522 $13,778 $33,309 $35,856
Production costs . . . . . . . . . . . (7,938) (2,872) (7,331) (7,118)
Depletion, depreciation, and (24,747) (6,309) (15,635) (16,221)
amortization . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . -- -- (338) --
------- ------- ------- -------
$15,837 $4,597 $10,005 $12,517
======= ====== ======= =======
</TABLE>

Costs incurred in oil and gas producing activities are as follows (in
thousands, except per equivalent mcf amounts):

<TABLE>
<CAPTION>
Predecessor Company
----------------------------------------------
Year ended December 31,
Nine months ended Three months ended -------------------------
December 31, 1996 March 31, 1996 1995 1994
----------------- ------------------ ---------- ----------
<S> <C> <C> <C> <C>
Property acquisition costs . . . . . . $13,477 $949 $4,594 $2,521
Exploration costs . . . . . . . . . . . 18,627 3,903 12,866 16,495
Development costs . . . . . . . . . . . 6,132 2,643 24,312 17,907
Production costs . . . . . . . . . . . 7,938 2,872 7,331 7,118
Depletion, depreciation, and
amortization rate per
equivalent mcf....................... 1.33 1.00 .96 .95

</TABLE>

All of the Company's oil and gas revenues are from proved developed
properties located in the United States.

The Company capitalizes internal costs, associated with exploration
activities. These capitalized costs approximated $4,362,000, $4,264,000 and
$3,479,000, for the years ended December 31, 1996, 1995 and 1994, respectively.

37
<PAGE> 40
MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

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. During the year ended
December 31, 1994, sales of oil and gas to three purchasers accounted for 25%,
13% and 11% of total revenues. Management believes that the loss of these
purchasers would not have a material impact on the Company's financial
condition or results of operations.

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.

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 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.

38
<PAGE> 41

MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

Estimated Quantities of Proved Reserves
(in thousands)

<TABLE>
<CAPTION>
Oil (Bbl) Gas (Mcf)
---------- ---------
<S> <C> <C>
December 31, 1993 6,128 91,060
Extensions 829 21,842
Revisions of previous estimates 423 4,241
Production (459) (14,362)
Sales of reserves in place (21) (2,136)
--------- ---------

December 31, 1994 6,900 100,645
Extensions 46 2,476
Revisions of previous estimates 307 14,113
Production (424) (13,770)
Sales of reserves in place (160) (5,134)
--------- ---------

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

December 31, 1996 5,280 92,284
========= =========
</TABLE>

Estimated Quantities of Proved Developed Reserves
(in thousands)

<TABLE>
<CAPTION>
Oil (Bbl) Gas (Mcf)
--------- ---------
<S> <C> <C>
December 31, 1993 3,653 67,263
December 31, 1994 4,037 83,192
December 31, 1995 4,357 87,843
December 31, 1996 3,456 83,529
</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.

39
<PAGE> 42
MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

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

<TABLE>
<CAPTION>
Year ended December 31,
-------------------------------------------
1996 1995 1994
---------- ---------- ------------
<S> <C> <C> <C>
Future cash inflows. . . . . . . . . . . . . . . . . $548,451 $370,471 $285,823

Future production and development costs . . . . . . . (124,190) (125,936) (138,185)

Future income taxes . . . . . . . . . . . . . . . . . (90,971) (37,518) (8,819)
--------- ---------- -----------
Future net cash flows . . . . . . . . . . . . . . . . 333,290 207,017 138,819

Discount of future net cash flows at 10% per annum . (78,914) (46,502) (49,215)
--------- ---------- -----------
Standardized measure of discounted future net cash
flows . . . . . . . . . . . . . . . . . . . . . . . $254,376 $160,515 $89,604
========= ========== ===========
</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, 1996, 1995 and 1994,
used in the above table, were $25.16, $18.08, and $16.46 per Bbl, respectively,
and $4.50, $2.54, and $1.71 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,
--------------------------------------------
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>

Sales and transfers of oil and gas
produced, net of production costs . . . . . . . . . $(51,505) $(25,963) $(28,738)
Net changes in prices and production costs. . . . . 120,843 64,363 (5,655)
Extensions and discoveries, net of future
development and production costs . . . . 62,551 5,712 27,509
Revision of previous quantity estimates . . . . . . (1,293) 18,076 4,324
Sales of reserves in place . . . . . . . . . . . . (10,813) (6,141) (475)
Net change in income taxes . . . . . . . . . . . . (36,082) (7,191) (2,130)
Accretion of discount before income taxes . . . . . 17,342 9,532 9,424
Changes in production rates (timing) and
other . . . . . . . . . . . . . . . . . . (7,182) 12,523 (5,312)
------- -------- -------
Net change . . . . . . . . . . . . . . . . . . . . $93,861 $70,911 $(1,053)
======= ======== =======
</TABLE>

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

None

40
<PAGE> 43

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, 1997. 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 44 Chairman of the Board, President and Chief Executive Officer
Richard R. Clark 41 Senior Vice President of Production and Director
Michael W. Strickler 41 Senior Vice President of Exploration and Director
James M. Fitzpatrick 46 Vice President of Land and Legal, Corporate Secretary
Gregory K. Harless 47 Vice President of Oil and Gas Marketing
W. Hunt Hodge 41 Vice President of Administration
Frank A. Pici 41 Vice President of Finance and Chief Financial Officer
Clinton D. Smith 42 Vice President of Operations
David S. Huber 46 Consultant and Deep Water Projects Manager
Richard B. Buy 45 Director
James V. Derrick, Jr. 52 Director
Gene E. Humphrey 49 Director
Jere C. Overdyke, Jr. 45 Director
Frank Stabler 44 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 Company 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.

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.

41
<PAGE> 44
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 Vice President in Enron Capital
Management. Prior to joining ECT Mr. Buy was a Vice President at Bankers Trust
in the Energy Group. Mr. Buy serves on the board of directors of Coda Energy,
Inc.

Mr. Derrick has served as a director since May 1996. He is currently
Senior Vice President and General Counsel of Enron. He serves on the Management
Committee of Enron and is a director of Enron Global Power & Pipelines LLC, a
New York Stock Exchange-listed entity that owns interests in certain
international pipeline and power projects. Mr. Derrick also serves on the board
of directors of Coda Energy, Inc., an oil and gas exploration and production
company in which JEDI owns 98.5% of the common stock. He has been associated
with Enron since 1991. Prior to that he was for many years engaged in the
private practice of law 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 a Managing Director. 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, currently serving as a Managing Director. Mr. Overdyke
has approximately 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
Vice President of ECT 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 48.

42
<PAGE> 45
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 two fiscal years ended December 31, 1996. 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 1996 $236,000 $6,000 $421,311 $306
President and 1995 232,350 6,000 216,585 306
Chief Executive Officer

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

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

Clinton D. Smith 1996 131,500 5,154 96,447 306
Vice President of Operations 1995 127,525 4,944 67,764 306

Gregory K. Harless 1996 121,600 4,760 82,851 522
Vice President of 1995 118,000 4,560 53,523 522
Oil & Gas Marketing
</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; in 1995 proceeds of such sales were as follows for
the individuals indicated: Mr. Henderson ($301,307), Mr. Clark ($153,086), Mr.
Strickler ($353,061), Mr. Smith ($0) and Mr. Harless ($155,000). See
"--Overriding Royalty Interests". No such sales were made in 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. Smith and
Harless. 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.
Smith and Harless, 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 $236,000,
$166,500, $150,000, $131,500 and $121,600 for Messrs. Henderson, Clark,
Strickler, Smith and Harless, 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

43
<PAGE> 46
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".

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.
Smith and Harless), (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.
Smith and Harless, 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 48.

44
<PAGE> 47
The following table sets forth certain information with respect to
individual grants of options by Mariner Holdings to the named executive
officers during 1996.

Potential Realizable
Value at Assumed Annual
Number of Percentage Rates of Stock Price
Securities of Total Appreciation for
Underlying Granted to Exercise Option Term
Options Granted Employees or Base Expiration -------------------------
Name (# of shares)(1) in 1996 Price ($/Sh) Date 5% ($)(2) 10% ($)(2)
- ---- ------------------ ----------- ----------- ------------- --------- -----------
<S> <C> <C> <C> <C> <C> <C>
Robert E. Henderson 19,885 15.5% $100.00 6/27/03 $809,519 $1,886,524
Richard R. Clark 13,994 10.9% 100.00 6/27/03 569,696 1,327,635
Michael W. Strickler 13,994 10.9% 100.00 6/27/03 569,696 1,327,635
Clinton D. Smith 8,925 7.0% 100.00 6/27/03 363,337 846,730
Gregory K. Harless 3,570 2.8% 100.00 6/27/03 145,335 338,692
</TABLE>

(1) Options to purchase Mariner Holdings common stock were granted as part
of a stock purchase by management, which was paid for by assigning
certain overriding royalty interests and by relinquishing rights under
change of control agreements held by these named executive officers.
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 1996
to each of these executive officers was calculated by multiplying those
options by the excess of (a) the assumed value, at June 27, 2003, 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, 1997 would be
$138,732,602, which would be an increase of $40,137,902 from the assumed
value of such shares at the close of business on December 31, 1996. At
$194.87, the total value of the shares of Common Stock outstanding on
March 1, 1997 would be $192,131,492, which would be an increase of
$93,536,792 from the assumed value of such shares at the close of
business on December 31, 1996. 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.

45
<PAGE> 48
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
Received in 1996(1) Program in 1996
------------------- ---------------
Name
----
<S> <C> <C>
Robert E. Henderson 9 $421,311
Richard R. Clark 9 247,971
Michael W. Strickler 9 258,731
Clinton D. Smith 9 96,447
Gregory K. Harless 9 82,851
</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.

46
<PAGE> 49
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,
1997. As of March 1, 1997, there were 985,947 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 96.4%
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.
JEDI's limited partner is CalPERS. Each partner has a 50% interest in JEDI. The
general partner of JEDI exercises sole voting and investment power with respect
to such shares.

47
<PAGE> 50
The table appearing below sets forth information as of March 1, 1997,
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, 1996, 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 *

Gregory K. Harless . . . . . . . . . . . . 1,000 *

Clinton D. Smith . . . . . . . . . . . . 2,500 *

David S. Huber . . . . . . . . . . . . . . 3,795 *

James V. Derrick, Jr. . . . . . . . . . . . 0 *

Richard B. Buy . . . . . . . . . . . . . . 0 *

Gene E. Humphrey . . . . . . . . . . . . . 0 *

Jere C. Overdyke, Jr. . . . . . . . . . . . 0 *

Frank Stabler . . . . . . . . . . . . . . . 0 *

All directors and executive officers and key

consultant as a group (14 persons) . . . 24,918 4%
</TABLE>

* Less than one percent.

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

In June 1996, in accordance with the terms of the Stockholders'
Agreement, 24 individuals who are employees of or consultants to the Company
received options to purchase an aggregate of 128,331 shares of the common stock
of Mariner Holdings. In addition, the Stockholders' Agreement provides for
certain preemptive and registration rights. See "Certain Relationships and
Related Transactions -- Stockholders' Agreement and Related Matters" below.

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 the 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.

In May 1996, in accordance with the terms of the Stockholders'
Agreement, JEDI purchased 950,000 shares of the common stock of Mariner
Holdings for an aggregate consideration of $95.0 million; JEDI and Mariner
Holdings entered into the JEDI Bridge Loan; Mariner Holdings borrowed $92.0
million under the JEDI Bridge Loan; and Mariner Holdings purchased the stock of
the Company. Mariner Holdings has since repaid the JEDI Bridge Loan in full,
and it has terminated according to its terms.

48
<PAGE> 51
In June 1996, in accordance with the terms of the Stockholders'
Agreement, the Management Stockholders purchased an aggregate of 35,947 shares
of the common stock of Mariner Holdings, received options to purchase an
additional 128,331 shares of the common stock of Mariner Holdings and entered
into new or amended employment or consulting agreements with the Company. The
aggregate purchase price for those shares was valued at approximately $4.0
million, which the Management Stockholders paid by means of cash or assignments
of a portion of their overriding royalty interests held under the terms of
their then-existing employment or consulting arrangements with the Company. In
addition, in accordance with the terms of the Stockholders' Agreement, the
Management Stockholders who had Change of Control Agreements relinquished their
rights thereunder. Concurrently with the purchase of shares of Mariner
Holdings, each Management Stockholder (other than Messrs. Henderson, Clark,
Strickler and Huber, who were already parties) became a party to the
Stockholders' Agreement.

As a result of these transactions, 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 164,278 shares, which would represent
approximately 15% of all shares that would be outstanding, and JEDI would own
approximately 85% of all outstanding shares on that basis. The stock options
granted to the Management Stockholders are not currently exercisable, are
subject to vesting schedules and are more fully described under the caption
"Management -- Employment, Consulting and Stock Option Agreements".

Under the Stockholders' Agreement, Mariner Holdings paid or agreed to
pay certain amounts, including (i) an arrangement fee and facility fee payable
to JEDI, as the lender under the JEDI Bridge Loan, (ii) a fee payable to an
affiliate of ECT equal to 2.5% of the total principal amount of any refinancing
or substitution for the JEDI Bridge Loan if an affiliate of ECT is the sole
placement agent or financial advisor in connection with the refinancing or
substitution and otherwise a fee that would be commercially reasonable for a
transaction of the nature of the refinancing or substitution and (iii) 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. In addition, in connection with
JEDI's purchase of Mariner Holdings stock, JEDI received a fee equal to 3% of
the total purchase price paid by JEDI. 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
"Management -- Overriding Royalty Interests". 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.

49
<PAGE> 52
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".

The Stockholders' Agreement requires that any transfer or issuance of
shares of Mariner Holdings stock be made in compliance with applicable
securities laws. Subject to those laws, JEDI may transfer its shares of Mariner
Holdings stock at any time. Also subject to those laws, after June 2001, a
Management Stockholder may transfer shares, but before that time a Management
Stockholder may not voluntarily transfer shares unless they are transferred to
a family member or to another Management Stockholder, although a Management
Stockholder may make a bona fide pledge or mortgage of shares. In addition, if
any stockholder or group of stockholders of Mariner Holdings proposes to sell
or exchange Mariner Holdings stock in one transaction or a series of related
transactions that will result in any person who is not a "financial
participant" (as defined below), together with that person's affiliates or
members of a group, beneficially owning at least 30% of the outstanding Mariner
Holdings stock, then the Management Stockholders will have a right (a "tagalong
right") to participate in the transaction on the same terms as the stockholder
or group of stockholders that is proposing the transaction. If the transaction
will result in ownership by the acquiring persons of more than 30% but less
than 50% of the outstanding Mariner Holdings stock, then each Management
Stockholder is permitted to transfer or exchange a number of shares
representing the Management Stockholder's proportion of all shares owned by, or
acquirable pursuant to stock options of, the Management Stockholder, over the
sum of all shares owned by all stockholders and all shares acquirable pursuant
to all stock options; if, however, the proposed transaction will result in
ownership by the acquiring persons of 50% or more of the outstanding Mariner
Holdings stock, a Management Stockholder may sell or exchange all of his
shares, unless JEDI, ECT or affiliates controlled by them remain as
stockholders, in which case a Management Stockholder must retain a proportion
of his shares equal to the number of shares retained by JEDI, ECT or affiliates
controlled by them over the total number of shares of Mariner Holdings stock
acquired by JEDI pursuant to the Stockholders' Agreement in May 1996.
Management Stockholders electing to exercise their tagalong rights may exercise
their stock options to do so, even if the options have not vested. A "financial
participant" is an entity which has represented in writing that (i) as to any
part of the entity's business engaged in or relating to the oil and gas
industry, the entity is primarily engaged in investing in other entities and
(ii) the entity is not the operator of any oil or gas wells and does not have a
significant oil and gas management team, including geologists and production
engineers. The Management Stockholders' tagalong rights do not apply if the
acquiring person is Mariner Holdings or ECT or any entity controlled by either
of them or if Mariner Holdings has consummated an initial public offering.

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 also provides for certain registration
rights. First, at any time after the expiration of 90 days after Mariner
Holdings has consummated an initial public offering, JEDI may request Mariner
Holdings to register its stock under federal securities laws. If that request
is made, the other stockholders of Mariner Holdings have the right to register
their shares as well. Mariner Holdings is obligated to so register its stock on
three occasions only and is not obligated to so register its stock if the board
of directors determines that to do so would materially adversely affect a
pending or proposed public offering, acquisition, merger, recapitalization,
reorganization or similar transaction or negotiations with respect thereto.
Second, if Mariner Holdings has not consummated an initial public offering by
June 2001, then JEDI or an assignee of JEDI, if it owns at least 30% of the
outstanding stock of Mariner Holdings, may request Mariner Holdings to register
its stock under federal securities laws. If that request is made, the other
stockholders of Mariner Holdings will have the right to register their shares
as well. Mariner Holdings is obligated to so register its stock on one occasion
only and is not obligated to so register its stock if its board of directors
determines that to do so would materially adversely affect a pending or
proposed public offering, acquisition, merger, recapitalization, reorganization
or similar transaction or negotiations with respect thereto. Finally, if
Mariner Holdings proposes to register its shares of stock under federal
securities laws at any time (excluding registrations relating to employee
benefit plans or certain business combinations), it will use its best efforts
to permit its stockholders to include their shares in the registration if they
so request.

50
<PAGE> 53
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.

The Stockholders' Agreement prohibits any transfer of Mariner Holdings
stock or any issuance of Mariner Holdings stock unless the transferee or person
to whom the stock is proposed to be issued has become a party to the
Stockholders' Agreement. Amendments to the Stockholders' Agreement require the
approval by the holders of two-thirds of the outstanding Mariner Holdings
stock, the approval of each stockholder who owns at least 10% of the
outstanding Mariner Holdings stock, a majority of the Management Directors and
at least one Management Director who became a stockholder in June 1996.
However, no amendment may impose any additional material obligation on any
party to the Stockholders' Agreement without that party's written consent. The
Stockholders' Agreement terminates on the earliest of the following events: (i)
Mariner Holdings' bankruptcy or dissolution, (ii) the occurrence of an event
that reduces the number of stockholders to one, (iii) the merger or
consolidation of Mariner Holdings with another corporation if Mariner Holdings
is not the surviving corporation and if the stockholders do not hold at least
50% of the outstanding voting stock of the surviving corporation, (iv) the sale
of substantially all of the assets of Mariner Holdings or of the Company, (v)
the acquisition by one person or group of affiliated persons not affiliated
with ECT of more than two-thirds of the outstanding stock (unless the holders
of at least 90% of the outstanding stock elect not to terminate the
Stockholders' Agreement and the non-termination is approved by the Management
Directors), (vi) the consummation of an initial public offering, (vii) the
consummation of a business combination pursuant to which Mariner Holdings
becomes a reporting company under federal securities laws and (viii) May 2006;
however, the registration rights provided for in the Stockholders' Agreement
will survive any termination as a result of the consummation of an initial
public offering, and Mariner Holdings' obligations to reimburse the Management
Stockholders for any tax liabilities resulting from paying for stock by
assignments of overriding royalty interests (as discussed above) will survive
any termination due to any of the above-described events.

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, five of the Company's directors are officers of Enron or
affiliates of Enron: Mr. Derrick is Senior Vice President and General Counsel
of Enron and holds other positions with affiliates of Enron; Messrs. Buy,
Humphrey and Overdyke are Managing Directors of ECT; and Mr. Stabler is a Vice
President of ECT.

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.

ECT Securities Corp. is an indirect subsidiary of Enron and,
accordingly, is an affiliate of ECT, JEDI, Mariner Holdings and the Company. In
connection with the Acquisition and the offering of the Company's senior
subordinated debt securities, the Company and Mariner Holdings, in the
aggregate, have paid ECT affiliates arrangement and financial services fees of
approximately $2.9 million. In addition, pursuant to the JEDI Bridge Loan,
Mariner Holdings has paid JEDI approximately $2.6 million in arrangement and
facility fees. Of the net proceeds of the Note Offering, $42.0 million was used
to pay a dividend to Mariner Holdings, which in turn used the dividend to repay
the remaining balance of the JEDI Bridge Loan.

JEDI, an affiliate of Enron, owns approximately 96% of the capital stock
of Mariner Holdings. In May 1996, JEDI provided the JEDI Bridge Loan to Mariner
Holdings. Mariner Holdings borrowed $92.0 million under the JEDI Bridge Loan,
which has been repaid in full and terminated according to its terms in August
1996.

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

51
<PAGE> 54
and practices. The Revolving Credit Facility excludes from this covenant (i)
any transaction permitted by the Stockholders' Agreement, (ii) any transaction
permitted by the JEDI Bridge Loan, (iii) the grant of options to purchase or
sales of equity securities to directors, officers, employees and consultants of
the Company and Mariner Holdings and (iv) the assignment of any overriding
royalty interest pursuant to an employee incentive compensation plan. See "The
Transactions", "Management -- Overriding Royalty Interests" and "Description of
Revolving Credit Facility".

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 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.

JEDI BRIDGE LOAN

In connection with the Acquisition and pursuant to the requirements of
the Stockholders' Agreement, Mariner Holdings and JEDI entered into a Credit,
Subordination and Further Assurances Agreement dated as of May 16, 1996,
pursuant to which JEDI provided a loan commitment to Mariner Holdings for the
JEDI Bridge Loan. Mariner Holdings borrowed $92.0 million pursuant to the JEDI
Bridge Loan to partially fund the Acquisition. There is no outstanding balance
under the JEDI Bridge Loan, and it has terminated according to its terms.

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PART IV

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

(A) DOCUMENTS INCLUDED IN THIS REPORT:

1. FINANCIAL STATEMENTS and 2. FINANCIAL STATEMENT SCHEDULES

These documents are listed in the Index to Financial Statements in Item 8
hereof.

3. EXHIBITS

Exhibits designated by the symbol * are filed with this Annual Report on
Form 10-K. All exhibits not so designated are incorporated by reference
to a prior filing as indicated.

Exhibits designated by the symbol + are management contracts or
compensatory plans or arrangements that are required to be filed with
this report pursuant to this Item 14.

The Company undertakes to furnish to any stockholder so requesting a
copy of any of the following exhibits upon payment to the Company of the
reasonable costs incurred by Company in furnishing any such exhibit.

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* 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.

10.1(a) Stock Purchase Agreement, effective as of April 1, 1996, among
Hardy Oil & Gas plc, Hardy Holdings, Inc., Millennium Oil &
Gas, Inc. (the Registrant) and Enron Capital & Trade Resources
Corp.

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

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<PAGE> 56
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.

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(a) 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(a) 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.

10.18(a) Letter Agreement, dated September 26, 1996, between the
Registrant and Gary M. Pedlar.

10.19*+ 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.

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<PAGE> 57
(B) REPORTS ON FORM 8-K:

The Company filed no reports on Form 8-K during the quarter ended
December 31, 1996.

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.

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<PAGE> 58
"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.

"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.

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<PAGE> 59
"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.

"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

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SIGNATURES

Pursuant to the requirements of Section 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

March 27, 1997

Mariner Energy, Inc.

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

Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.

<TABLE>
<CAPTION>
Signature Title Date
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
/s/ Robert E. Henderson Chairman of the Board, President and March 27, 1997
- ----------------------------------- Chief Executive Officer
Robert E. Henderson (Principal Executive Officer)

/s/ Frank A. Pici Vice President of Finance and March 27, 1997
- ----------------------------------- Chief Financial Officer
Frank A. Pici (Principal Financial Officer and
Principal Accounting Officer)

/s/ Richard R. Clark Senior Vice President of Production March 27, 1997
- ----------------------------------- and Director
Richard R. Clark

/s/ Michael W. Strickler Senior Vice President of Exploration March 27, 1997
- ----------------------------------- and Director
Michael W. Strickler

/s/ Richard B. Buy Director March 27, 1997
- -----------------------------------
Richard B. Buy

/s/ James V. Derrick, Jr. Director March 27, 1997
- -----------------------------------
James V. Derrick, Jr.

/s/ Gene E. Humphrey. Director March 27, 1997
- -----------------------------------
Gene E. Humphrey

/s/ Jere C. Overdyke, Jr. Director March 27, 1997
- -----------------------------------
Jere C. Overdyke, Jr.

/s/ Frank Stabler Director March 27, 1997
- -----------------------------------
Frank Stabler
</TABLE>

<PAGE> 61
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> 62

INDEX TO EXHIBITS

Exhibits designated by the symbol * are filed with this Annual Report on
Form 10-K. All exhibits not so designated are incorporated by reference
to a prior filing as indicated.

Exhibits designated by the symbol + are management contracts or
compensatory plans or arrangements that are required to be filed with
this report pursuant to this Item 14.

EXHIBIT
NUMBER DESCRIPTION
------ -----------