MARINER ENERGY INC, 10-K405, 2000-03-30

MARINER ENERGY INC
10-K405, 2000-03-30
CRUDE PETROLEUM & NATURAL GAS

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

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999

COMMISSION FILE NUMBER 333-12707

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

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

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

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes No X
--- ---

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

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

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

As of March 20 2000, there were 1,378 shares of the registrant's common
stock outstanding.

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<PAGE> 2

TABLE OF CONTENTS

<TABLE>
<CAPTION>
Item Page
- ---- ----
<S> <C>
PART I.................................................................................3

ITEMS 1. AND 2. BUSINESS AND PROPERTIES.............................................3
(a) Overview.....................................................................3
(b) Competitive Strengths and Business Strategy..................................5
(c) Reserves.....................................................................7
(d) Oil and Gas Properties.......................................................7
(e) Production..................................................................11
(f) Productive Wells............................................................12
(g) Acreage.....................................................................12
(h) Drilling Activity...........................................................12
(i) Marketing, Customers and Hedging Activities.................................13
(j) Competition.................................................................14
(k) Royalty Relief..............................................................14
(l) Regulation..................................................................15
(m) Employees...................................................................17
ITEM 3. LEGAL PROCEEDINGS.........................................................17
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.......................17
ITEM 5. MARKET FOR REGISTRANT"S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS...................................................................18

PART II...............................................................................18

ITEM 6. SELECTED FINANCIAL DATA...................................................18
ITEM 7. MANAGEMENT"S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.....................................................19
(a) Introduction................................................................19
(b) General.....................................................................19
(c) Results of Operations......................................................20
(d) Liquidity and Capital Resources.............................................22
(e) Year 2000 Compliance........................................................25
(f) Recent Accounting Pronouncement.............................................25
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.................25
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA...............................26
INDEPENDENT AUDITORS' REPORT.......................................................27

PART III..............................................................................44

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......................44
ITEM 11. EXECUTIVE COMPENSATION...................................................46
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT...........50
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS.....................52

PART IV...............................................................................54

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K..........54
GLOSSARY...........................................................................57
</TABLE>

<PAGE> 3

PART I

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

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

Certain technical terms used in these Items are described or defined in the
Glossary presented on page 54 of this report.

(a) OVERVIEW

Mariner Energy, Inc. ("Mariner" or "Company") is an independent oil and
natural gas exploration, development and production company with principal
operations in the Gulf of Mexico and along the U.S. Gulf Coast. Our increasing
focus on Gulf water depths greater than 600 feet, or the deepwater, since the
early 1990s has made us one of the most experienced independent operators in the
deepwater Gulf. We have been an active explorer in the Gulf Coast area since the
mid-1980s, when we operated as Hardy Oil & Gas USA Inc., and have increased our
production and reserve base through the exploitation and development of
internally generated prospects, which we refer to as growth "through the
drillbit." Members of our senior management team, most of whom have worked
together for over 15 years, and an affiliate of Enron North America Corp. led a
buyout of Mariner from Hardy Oil & Gas, plc in April 1996.

Since beginning deepwater operations in 1994, we have:

o operated seven successful subsea development projects in water depths
of 400 feet to 2,700 feet;

o developed three deepwater exploitation projects acquired from major
oil companies, including our Pluto project;

o discovered seven new fields in 13 deepwater Gulf exploration tests,
including potentially significant discoveries at our Aconcagua and
Devils Tower prospects;

o acquired 64 deepwater Gulf lease blocks, most of which are free of
royalty payment obligations; and

o built an inventory of 14 exploration prospects as of December 31,
1999, including 13 prospects in the deepwater Gulf.

Ryder Scott Company estimated that we had proved reserves of 178.4 Bcfe
as of December 31, 1999, of which 67% were natural gas and 33% were oil and
condensate. For the year ended December 31, 1999, we produced 24.9 Bcfe.

We expect our production levels and operating cash flow to increase
significantly in 2000 based on production from our Dulcimer project, which began
in April 1999, and our Pluto project, which began in late December 1999 and is
currently producing approximately 47 Mmcfe per day to our net interest. We
expect further increases on commencement of production from our Apia and Black
Widow projects, currently scheduled for the second quarter and fourth quarter of
2000, respectively.

In 2000, the Company expects to drill four or five exploratory wells in
the Deepwater Gulf, with a partner paying Mariner's share of the cost for one of
the wells. Three wells are also planned to appraise the Company's potentially
significant deepwater exploratory successes at Aconcagua and Devils Tower, with
drilling currently in progress at Aconcagua and planned for the second quarter
on Devils Tower. Development activity in 2000 will include completing the Apia
and Black Widow projects.

<PAGE> 4

We anticipate capital expenditures for 2000, net of proceeds from
unproved property dispositions, to be approximately $75 million for leasehold
acquisition, exploration drilling and development projects, compared to our 1999
capital expenditures of approximately $61.7 million, net of proceeds from
property sales of $19.8 million. We expect to fund our capital expenditures by a
combination of internally generated cash flow, proceeds from sales of partial
interests in unproved properties, contributions from our parent company and
borrowings against our Revolving Credit Facility.

The following table sets forth certain summary information with respect
to our oil and gas activities and results during the five years ended December
31, 1999. 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. Year-end oil and gas prices do not include any impact
relating to hedging activities. See "Reserves" later in this item and Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations".

<TABLE>
<CAPTION>
Year ended December 31,
(dollars in millions unless otherwise indicated)
1999 1998 1997 1996(3) 1995(3)
------ ------ ------- -------- -------
<S> <C> <C> <C> <C> <C>
Proved reserves:
Oil (MMbbls) ............................................ 9.9 9.4 6.6 5.3 6.7
Natural gas (Bcf) ....................................... 118.8 128.9 121.4 92.3 98.3
Natural gas equivalent (Bcfe) ........................... 178.4 185.1 161.2 124.0 138.3

Present value of estimated future net revenues (1) ......... $211.2 $147.6 $176.5 $303.4 $173.4

Annual reserve replacement ratio (2) ...................... 1.3 2.0 2.6 1.2 1.2

Capital expenditures and disposal data:
Capital costs incurred (before proceeds from
property sales) ...................................... $ 81.5 $141.9 $ 68.9 $ 46.6 $ 41.8

Percentage attributable to:
Lease acquisition .................................... 12.8% 30.4% 36.0% 30.7% 11.0%
Exploratory drilling, geological and geophysical ..... 16.6% 25.1% 39.7% 48.7% 58.2%
Development and other ................................ 70.6% 44.5% 24.3% 20.6% 30.8%

Proceeds from property sales ............................ $ 19.8 -- -- $ 7.5 $ 20.7

Production:
Oil (MMbls) ............................................. 0.6 0.8 1.0 0.8 0.4
Natural gas (Bcf) ....................................... 21.1 19.5 18.0 20.4 13.8
Natural gas equivalents (Bcfe) .......................... 24.9 24.2 23.9 24.9 16.3

Average realized sales price per unit
(including the effects of hedging):
Oil ($/Bbl) ............................................. $13.65 $12.80 $18.48 $18.04 $17.10
Natural gas ($/Mcf) ..................................... 2.08 2.39 2.48 2.29 1.83
Gas equivalent ($/Mcfe) ................................. 2.11 2.34 2.63 2.42 1.99

Expenses ($/Mcfe):
Lease operating ......................................... 0.46 0.41 0.39 0.36 0.39
General and administrative, net ......................... 0.22 0.20 0.13 0.13 0.12
</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) In an acquisition effective April 1, 1996 for accounting purposes,
Mariner Holdings, Inc. acquired all the capital stock of the Company
from Hardy Holdings Inc. as part of a management-led buyout. In
connection with the acquisition, substantial intercompany indebtedness
and receivables and third-party indebtedness of the Company were
eliminated. The acquisition was accounted for using the purchase
method of accounting, and Mariner Holdings' cost of acquiring the
Company was allocated to the assets and liabilities of the Company
based on estimated fair values. As a result, the Company's financial
position and operating results subsequent to the acquisition reflect a
new basis of accounting and are not comparable to prior periods.
"Predecessor Company" refers to Mariner Energy, Inc. (formerly named
"Hardy Oil & Gas USA Inc.") prior to the effective date of the
acquisition.

<PAGE> 5

(b) COMPETITIVE STRENGTHS AND BUSINESS STRATEGY

COMPETITIVE STRENGTHS

We have several competitive strengths that we believe will allow us to
compete successfully in oil and natural gas exploration, production and
development activities in the Gulf:

EARLY ENTRY INTO THE DEEPWATER GULF. We began focusing in the deepwater
Gulf in 1992 as one of the first independent oil and natural gas companies to
recognize the opportunity for acquiring smaller deepwater discoveries not
meeting a large company's field size threshold and for partnering with major oil
companies to develop these discoveries. We believe our eight years in the
deepwater Gulf have provided us with the geophysical and geological skills,
operating expertise and relationships necessary to operate successfully in the
deepwater. Our deepwater Gulf expertise includes:

o a strong understanding of the geology and geophysics of the deepwater
Gulf;

o familiarity with challenges peculiar to operating in the deepwater
Gulf; and

o relationships with vendors, major oil companies and other partners
having complementary skills and knowledge of the area.

SUBSTANTIAL ACREAGE, SEISMIC DATA AND PROSPECT INVENTORY. Our Gulf
leasehold inventory as of December 31, 1999, consisted of 118 lease blocks,
including 72 in the deepwater. Our prospect inventory includes 14 exploration
prospects, 13 of which are in the deepwater Gulf. We expect to drill four or
five of our deepwater exploration prospects by the end of 2000. Our seismic
database includes 3-D seismic that covers approximately 7,800 square miles of
the Gulf and modern 2-D seismic that covers more than 250,000 miles of the
deepwater Gulf. We internally generate substantially all of our exploration and
exploitation prospects using 3-D seismic data.

EXPERIENCED OPERATIONS AND TECHNICAL STAFF AND MANAGEMENT. Our 12
geoscientists average more than 20 years of experience in the exploration and
production business, including extensive experience in the deepwater Gulf and
with major oil companies. Our 6 deepwater operations managers average over 25
years of experience with major oil companies and large independents around the
world. Most of our senior management team participated in our acquisition from
Hardy and have worked together for over 15 years. Management and other key
personnel currently own approximately 4% of the common shares of our parent
company and have options that, if exercised, would increase their ownership to
17%. We believe that management's ownership aligns its interests with those of
other shareholders.

STRATEGY

Our business strategy is to increase reserves, production and cash flow
by emphasizing growth through the drillbit in the deepwater Gulf, and consists
primarily of the following elements:

FOCUS ON THE DEEPWATER GULF. With our current prospect and seismic
inventory and many more deepwater Gulf lease blocks scheduled to become
available via lease sales, we believe we are well-positioned to increase our
deepwater Gulf activity and to continue to generate and exploit economically
attractive prospects. We intend to continue:

o exploring below the reserve potential threshold of the major oil
companies; and

o generating prospects and operating projects within our expertise but
beyond the capability of most independents.

PURSUE A BALANCED PORTFOLIO APPROACH TO OUR DRILLING PROGRAM. We target
four to eight new prospects each year, with a strong deepwater Gulf emphasis.
The program is designed to provide reserve replacement and production growth
through low-risk deepwater exploitation projects and opportunities for
substantial growth through moderate-risk exploration prospects that can
significantly increase our reserve base. We intend to use up to 90% of our
available capital on deepwater Gulf exploration and exploitation projects. We
focus on the deepwater Gulf because of:

o the potential for discovery of large hydrocarbon deposits;

<PAGE> 6

o relatively favorable reservoir characteristics;

o the prevalence of 3-D seismic direct hydrocarbon indicators;

o the relatively under-explored nature of the deepwater Gulf;

o the recent advances in deepwater production technology that reduce
development costs and expedite production; and

o the favorable operating margins resulting from generally favorable
prices for Gulf production and lower operating costs per unit. These
lower costs per unit are associated with prolific wells, concentration
of labor and equipment, absence of severance and ad valorem taxes and
generally lower royalties.

INTERNALLY GENERATE MOST OF OUR PROSPECTS. By internally generating
most of our prospects, we believe we have better control over the quality of the
prospects in which we participate, thereby increasing our chances for commercial
success. Almost all of our inventory of 14 exploration prospects as of December
31, 1999, were internally generated by our staff of 12 geoscientists, which has
extensive experience in the deepwater Gulf. Through our technical staff's
understanding of the geology and geophysics of the deepwater Gulf and our
inventory of leasehold blocks and seismic data, we intend to continue to
generate the majority of our prospects internally.

MANAGE DEEPWATER RISKS BY CONTROLLING COSTS. A key to our growth and
operations in the deepwater Gulf is controlling our costs. To control our costs,
we intend to continue to:

o target projects with gross drilling costs of less than $20 million;

o use 3-D seismic analysis to analyze direct hydrocarbon indicators;

o operate most of the wells in which we participate;

o limit projects generally to drilling depths of less than 10,000 feet
below the sea floor;

o use our expertise in existing technology, including subsea production
technology, to reduce our capital expenditures and accelerate the
commencement of production; and

o use the strong business relationships that we have developed with
service companies to reduce our costs.

MANAGE DEEPWATER RISKS THROUGH COMPLEMENTARY OPERATIONS AND RISK
SPREADING. A key to our strategy is managing our deepwater exploration risks
through complementary operations and risk spreading. To further this strategy,
we intend to continue to:

o complement our exploration activities by developing exploitation
projects, such as the Pluto project, and making strategic acquisitions
of additional deepwater interests;

o maximize production from our proved onshore and shallow water
properties to supplement our cash flow;

o maintain a risk-weighted, diversified portfolio of drilling
opportunities; and

o sell a portion of our working interests to industry partners,
typically on a promoted basis, where all or a portion of our costs are
paid by partners.

APPLY OUR DEEPWATER OPERATIONAL EXPERTISE. We intend to use our
deepwater staff's expertise to continue to:

o develop practical and proven technical solutions to drilling,
development and production problems; and

o shorten project cycle times and manage risks by using proven equipment
and procedures, matching the facilities to the reservoir, focusing on
full cycle costs and leveraging off the experience of our vendors.

<PAGE> 7

The following table sets forth certain information with respect to our
proved reserves by geographic area as of December 31, 1999. 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, 1999 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 9 to the Financial Statements included elsewhere in this
annual report for a discussion of the risks inherent in oil and natural gas
estimates and for certain additional information concerning the proved reserves.

<TABLE>
<CAPTION>
As of December 31, 1999
------------------------------------------------------------------
Present Value of
Estimated Future Net Revenues(1)
Proved Reserve Quantities -------------------------------
------------------------------- Dollars in millions
Oil Natural Gas Total -------------------------------
Geographic Area (MMBbls) (Bcf) (Bcfe) Developed Undeveloped Total
- --------------- -------- ----- ------ --------- ----------- ------
<S> <C> <C> <C> <C> <C> <C>
Deepwater Gulf ................. 4.3 62.5 88.4 $ 83.7 $ 34.9 $118.6
Gulf Shallow Water and
Gulf Coast Onshore ....... 0.8 32.7 37.5 49.9 4.3 54.2
Permian
Basin .......................... 4.8 23.6 52.5 20.1 18.3 38.4
------ ------ ------ ------ ------ ------
Total .......................... 9.9 118.8 178.4 $153.7 $ 57.5 $211.2
====== ====== ====== ====== ====== ======
Proved Developed Reserves ...... 3.8 82.8 105.6 $153.7
====== ====== ====== ======
</TABLE>

(1) Discounted (at 10%) present value as of December 31, 1999 (year-end prices
held constant excluding hedging activities).

Our estimates of proved reserves set forth in the foregoing table do
not differ materially from those filed by us with other federal agencies.

(d) OIL AND GAS PROPERTIES

(i) SIGNIFICANT PROPERTIES WITH PROVED RESERVES AS OF DECEMBER 31, 1999

We own oil and gas properties, both producing and for future
exploration and development, onshore in Texas and offshore in the Gulf,
primarily in federal waters. Our 11 largest producing properties, as shown in
the following table, accounted for approximately 90% of the Company's proved
reserves as of December 31, 1999.

<PAGE> 8

<TABLE>
<CAPTION>
DATE NET
MARINER APPROXIMATE PRODUCTION PROVED
WORKING WATER PRODUCING COMMENCED/ RESERVES
OPERATOR INTEREST DEPTH (FEET) WELLS EXPECTED (BCFE)
-------- -------- ------------ --------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
DEEPWATER GULF:
Mississippi Canyon 718
(Pluto) ........................... Mariner 37%/51%(1) 2,710 1 December 1999 26.6
Ewing Bank 966 (Black
Widow) ............................ Mariner 69% 1,850 -- Fourth quarter 2000 21.4
Garden Banks 73 (Apia) .............. Mariner 100% 700 -- Second quarter 2000 17.6
Garden Banks 367
(Dulcimer) ........................ Mariner 41.7% 1,100 1 April 1999 14.9
Garden Banks 240
(Mustique) ........................ Mariner 33% 830 1 January 1996 2.8
Green Canyon 136
(Shasta) .......................... Texaco 25% 1,040 1 November 1995 1.7
GULF SHALLOW WATER AND GULF
COAST ONSHORE:
Brazos A-105 ......................... Spirit Energy 12.5% 192 5 January 1993 11.1
Galveston 151
(Rembrandt) ....................... Mariner 33.3% 50 3 November 1996 6.8
Sandy Lake Field ..................... Mariner 50%/33%(2) Onshore 3 August 1994 3.9
Matagorda Island 683, 703 ............ Vastar 25% 112 4 March 1993 3.6
PERMIAN BASIN OF WEST TEXAS:
Spraberry Aldwell Unit ............... Mariner 70.3%(3) Onshore 82 1949 52.5
OTHER FIELDS ........................... -- -- -- -- -- 15.5
-----
TOTAL PROVED RESERVES .................. 178.4
-----
</TABLE>

- ----------

(1) We have a 37% working interest before project payout and a 51% working
interest after project payout.

(2) We have a 50% working interest in three production units in the Sandy Lake
Field, a 40% working interest in a fourth unit and a 33% interest in the
fifth unit.

(3) We operate the unit and own working interests in individual wells ranging
from approximately 33% to 84%.

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

PRINCIPAL OIL AND NATURAL GAS PROPERTIES

DEEPWATER GULF OF MEXICO

Mississippi Canyon 718 (Pluto). We acquired a 30% interest in this
project in 1997, two years after British Petroleum discovered gas on the
project. We later increased our ownership to 97%, acquiring operatorship and
gaining overall control of project planning and implementation. In 1998, we
increased our working interest to 100% and submitted a Deepwater Royalty Relief
application that was granted in July 1999. In June 1999, we sold a 63% working
interest in the project to Burlington Resources, Inc., reducing our working
interest to 37%. After project payout, our working interest increases to 51% and
Burlington's working interest decreases to 49%. We developed the field with a
single subsea well which is located in the deepwater Gulf approximately 150
miles southeast of New Orleans, Louisiana at a water depth of 2,700 feet and a
flow line tied back approximately 29 miles to a production platform on the
shelf. Production began on December 29, 1999, and production was reduced or
curtailed during January and February while start-up problems were resolved. As
of early March 2000, gross production was approximately 65 million cubic feet of
natural gas per day and 10,500 barrels of oil per day. As of December 31, 1999,
the field had estimated net proved reserves of 26.6 Bcfe, 72% of which was
natural gas.

Ewing Bank 966 (Black Widow). We generated the Black Widow prospect and
acquired it at a federal offshore Gulf lease sale in March 1997. We operate and
have a 69% working interest in this project, which is located in the deepwater
Gulf approximately 130 miles south of New Orleans, Louisiana at a water depth of
approximately 1,850 feet. In early 1998, we drilled a successful exploration
well on the prospect. We expect the well to commence production in the fourth
quarter of 2000 via subsea tieback to an existing platform at an estimated rate
of 6,000 to 8,000 Bbls of oil per day. Estimated net proved reserves from Black
Widow were approximately 21.4 Bcfe, 85% of which was oil, as of December 31,
1999.

<PAGE> 9

Garden Banks 73 (Apia). We generated the Apia prospect and acquired it
in a federal offshore lease sale in August 1998. We operate and own a 100%
working interest in this project which is located offshore Louisiana in a water
depth of approximately 700 feet. In September of 1999 we drilled a successful
exploration well which encountered 102 net feet gas pay in a single zone. The
field is being developed by the single subsea well tied back to a host platform
approximately three miles from the well. We expect to initiate production in the
second quarter of 2000 at an estimated rate of 25 to 30 MMcf of natural gas per
day. The field had net proved reserves of 17.6 Bcfe, all of which was natural
gas, as of December 31, 1999.

Garden Banks 367 (Dulcimer). We generated the Dulcimer prospect and
acquired it at a federal offshore Gulf lease sale in September 1996. The well is
located in the deepwater Gulf approximately 170 miles south of Lake Charles,
Louisiana at a water depth of approximately 1,100 feet. We operate and have a
42% working interest in the property. In late 1997, we drilled a successful
exploration well in two productive intervals between 9,900 feet and 10,500 feet.
The well commenced production in April 1999, after tieback to a production
platform located approximately 14 miles from the well. As of December 31, 1999,
the field had produced 4.8 Bcfe net to us. The field had estimated net proved
reserves of 14.9 Bcfe, 99% of which was natural gas, as of December 31, 1999,
and had an estimated remaining life of approximately six years.

Garden Banks 240 (Mustique). We generated the Mustique prospect and
acquired it through a swap transaction with Shell Oil Company. Mustique is
located offshore Louisiana in a water depth of approximately 830 feet. We own a
33% working interest in and operate this single well subsea development. The
well is tied back via a subsea flowline to a Chevron-operated platform
approximately 11 miles from the wellsite, where its production is commingled and
marketed with Chevron's production. Initial production was in January 1996. As
of December 31, 1999, the field had produced 6.9 Bcfe net to us. Remaining net
proved reserves were estimated to be 2.8 Bcfe, 96% of which was natural gas, and
the estimated remaining field life was approximately five years.

Green Canyon 136 (Shasta). We generated the Shasta prospect and
obtained it in a farmout agreement with Texaco, Inc. Shasta is located offshore
Louisiana in water depths of 840 to 1,040 feet. We operated subsea development
of this project from planning through drilling and equipment installation until
the date of first production. Following completion of this development, Texaco
assumed operation of the project. We own a 25% working interest in this one-well
subsea development that is tied back via subsea flowline to a Texaco-operated
platform approximately ten miles from the well sites. At the platform,
production is commingled and marketed with Texaco's production. Initial
production was in November 1995. As of December 31, 1999, the field had produced
10.9 Bcfe net to us. Remaining net proved reserves were estimated to be 1.7
Bcfe, 99% of which was natural gas, and the estimated remaining field life was
approximately three years.

GULF SHALLOW WATER AND GULF COAST ONSHORE

Brazos A-105. We generated the Brazos A-105 prospect and own a 13%
working interest in this Spirit Energy-operated property, which commenced
production in January 1993. Five wells exploit a single reservoir. No additional
wells are currently anticipated. The field has produced 23.2 Bcfe net to us from
its inception through December 31, 1999. The field had an estimated remaining
economic life of eight years and estimated remaining net proved reserves of 11.1
Bcfe as of December 31, 1999.

Galveston 151 (Rembrandt). We generated the Rembrandt prospect and
acquired it at a federal offshore Gulf of Mexico lease sale in September 1995.
In late 1996, we drilled a successful exploration well on the prospect. In June
1998, we drilled a second successful well on the prospect in a separate fault
block adjacent to the initial discovery well. The second well commenced
production in August 1998. We drilled a third successful well in another fault
block on the prospect in 1998 and commenced production in November 1998. We
operate and have a 33% working interest in this project, which is located
offshore Texas at a water depth of approximately 50 feet. The field has produced
6.5 Bcfe net to us since its inception through December 31, 1999. The field had
estimated net proved reserves of 6.8 Bcfe, 79% of which was natural gas, as of
December 31, 1999, and the estimated remaining field life was approximately six
years.

Sandy Lake Field. We generated the Sandy Lake prospect, located in the
Pine Island Bayou Field, and commenced production there in August 1994. We
operate the field and own 33% to 50% working interest in the producing wells.
The majority of the 4,680-acre property is located within the city limits of
Beaumont, Texas. Nine productive wells have been drilled thus far, three of
which are producing. The field has produced a total of 34.0 Bcfe net to us as of
December 31, 1999. The estimated remaining field life is four years and
estimated net proved reserves are 3.9 Bcfe as of December 31, 1999.

<PAGE> 10

Matagorda Island 683,703. We acquired Matagorda Island blocks 683 and
703 as part of a bid group and commenced production in March 1993. We own a 25%
working interest in the two 5,760-acre, Vastar Resources, Inc.-operated blocks.
Four successful wells have been drilled on the property and no additional
drilling is currently planned. However, a significant portion of the field's
remaining reserves are non-producing. We expect to access these reserves by
workover operations in the next six to 12 months. The field has produced, as of
December 31, 1999, a total of 10.1 Bcfe net to us. The field had an estimated
remaining life of four years and estimated net proved reserves of 3.6 Bcfe.

PERMIAN BASIN OF WEST TEXAS

Spraberry Aldwell Unit. We acquired our interest in the Spraberry
Aldwell Unit, located in Reagan County, Texas, in 1985. The 18,250-acre unit is
located in the heart of the Spraberry Trend southeast of Midland, Texas and has
produced oil since 1949. We operate the unit and own working interests in
individual wells ranging from approximately 33% to 84%. We initiated an infill
drilling program in 1987 innovatively commingling the unitized Spraberry
formation with the non-unitized Dean formation. To date, 72 infill wells have
been drilled resulting in 71 productive wells. Currently there are a total of 82
producing wells in the unit. Depending on, among other things, the future prices
of oil and natural gas, we may drill 20 to 40 additional infill wells, bringing
proved undeveloped reserves into production, in the next two to four years at a
projected cost of approximately $340,000 to $400,000 per well. We estimate that
the field's remaining net proved reserves as of December 31, 1999 were 52.5
Bcfe. We believe that the field's potential for continued economic oil
production exceeds 40 years.

(ii) OTHER SIGNIFICANT PROPERTIES

No proved reserves had yet been recorded from the following
discoveries.

Mississippi Canyon 305 (Aconcagua). We generated the Aconcagua prospect
and acquired it at a federal offshore Gulf lease sale in March 1998. During the
first quarter of 1999, the operator, Elf Exploration, drilled a successful
exploration well on the prospect, on which our share of the drilling cost was
paid by one of our partners. The well logged multiple pay sands, which are
geological formations where deposits of oil or gas are found in commercial
quantities, and we encountered additional sands with productive potential. The
well is located 40 miles from the shelf edge in 7,100 feet of water
approximately 150 miles southeast of New Orleans. Elf Exploration began drilling
an appraisal well in March of 2000. We hold a 25% working interest in the block,
and we anticipate a determination of proved reserves and the development plan
when drilling of the appraisal well is completed, which is expected in the
second quarter of 2000.

Mississippi Canyon 773 (Devils Tower). We generated the Devils Tower
prospect and acquired it in the March 1998 federal lease sale. We are the
operator and we hold a 50% working interest in the prospect, which is located
approximately 140 miles southeast of New Orleans in 5,600 feet of water. During
the fourth quarter of 1999, we drilled a successful exploration well on the
prospect, encountering multiple hydrocarbon bearing zones. Casing was run in the
well and the well was temporarily suspended. Our share of the drilling cost for
the exploration well was paid by our partners in the prospect. Additional
drilling is necessary to determine the level of proved reserves on the prospect
and the appropriate development plan. The first of potentially two appraisal
wells on the prospect is expected to commence in the second quarter of 2000.

(iii) DISPOSITION OF PROPERTIES

We periodically evaluate and, when appropriate, sell certain of our
producing properties that we consider to be marginally profitable or outside of
our areas of concentration. Such sales enable us to maintain financial
flexibility, reduce overhead and redeploy the proceeds therefrom to activities
that we believe have a higher potential financial return. No property
dispositions of producing properties were made during 1999.

(iv) TITLE TO PROPERTIES

Our 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. We do not believe that
any of these burdens materially interferes with the use of such properties in
the operation of our business.

<PAGE> 11

We believe that we have satisfactory title to or rights in all of our
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. We believe
that title issues generally are not as likely to arise on offshore oil and gas
properties as on onshore properties.

(e) PRODUCTION

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

<TABLE>
<CAPTION>
Year ended December 31,
--------------------------------------
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Production:
Oil (MMbbls) ........................................ 0.6 0.8 1.0
Natural gas (Bcf) ................................... 21.1 19.5 18.0
Gas equivalent (Bcfe) ............................... 24.9 24.2 23.9

Average sales prices including effects of hedging:
Oil ($/Bbl) ......................................... $13.65 $12.80 $18.48
Natural gas ($/Mcf) ................................. 2.08 2.39 2.48
Gas equivalent ($/Mcfe) ............................. 2.11 2.34 2.63

Expenses ($/Mcfe):
Lease operating ..................................... 0.46 0.41 0.39
General and administrative, net (1) ................. 0.22 0.20 0.13
Depreciation, depletion and amortization (2) ........ 1.29 1.40 1.33

Cash margin ($/Mcfe) (3) ............................... 1.18 1.47 1.92
</TABLE>

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

(2) Excludes impairment of oil & gas properties of $50.8 million and $28.5
million for the years ended December 31, 1998 and 1997, respectively. No
impairment was necessary for the year ended December 31, 1999.

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

(f) PRODUCTIVE WELLS

The following table sets forth the number of productive oil and gas
wells in which we owned a working interest at December 31, 1999:

<TABLE>
<CAPTION>
Total Productive Wells
--------------------------
Gross Net
---------- ----------
<S> <C> <C>
Oil ................ 90 62.5
Gas ................ 65 14.0
---------- ----------

Total ......... 155 76.5
========== ==========
</TABLE>

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

<PAGE> 12

(g) ACREAGE

The following table sets forth certain information with respect to the
developed and undeveloped acreage as of December 31, 1999.

<TABLE>
<CAPTION>
Developed Acres(1) Undeveloped Acres (2)
--------------------- --------------------
Gross Net Gross Net
----- --- ----- ---
<S> <C> <C> <C> <C>
Texas (Onshore)........................... 21,512 13,800 3,431 1,748
All other states (Onshore)................ 671 212 644 196
Offshore.................................. 212,291 53,314 383,196 190,162
------- ------ ------- -------
Total................................ 234,474 67,326 387,271 192,106
======= ====== ======= =======
</TABLE>

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

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

(h) DRILLING ACTIVITY

Certain information with regard to our drilling activity during the
years ended December 31, 1999, 1998 and 1997 is set forth below.

<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------
1999 1998 1997
------------- -------------- ---------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Exploratory wells:
Producing...................... 3 1.75 3 1.10 4 1.37
Dry............................ 2 0.50 5 1.54 7 1.60
-- ---- -- ----- -- ----

Total...................... 5 2.25 8 2.64 11 2.97
== ==== == ===== == ====

Development wells:
Producing...................... 8 1.61 19 8.61 11 5.27
Dry............................ - - 3 1.13 - -
-- ---- -- ----- -- ----

Total...................... 8 1.61 22 9.74 11 5.27
== ==== == ===== == ====

Total wells:
Producing...................... 11 3.36 22 9.71 15 6.64
Dry............................ 2 0.50 8 2.67 7 1.60
-- ---- -- ----- -- ----

Total...................... 13 3.86 30 12.38 22 8.24
== ==== == ===== == ====
</TABLE>

<PAGE> 13

(i) MARKETING, CUSTOMERS AND HEDGING ACTIVITIES

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

Percentage of total revenues
For the year ended December 31
-------------------------------
Customer 1999 1998 1997
-------- ---- ---- ----
<S> <C> <C> <C>
Enron North America and affiliates
(An affiliate of the Company) 26% 15% 18%
Transco Energy Marketing Company 21% 16% 14%
Duke Energy 13% 29% 19%
Genesis Crude Oil LP (formerly
Howell Crude Oil Company) -- 10% 19%

</TABLE>

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

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

From time to time, we have utilized hedging transactions with respect
to a portion of our oil and gas production to reduce our exposure to price
fluctuations and to achieve a more predictable cash flow. We do not engage in
hedging activities for speculative purposes. We customarily conduct our hedging
strategy through the use of swap arrangements that establish an index-related
price above which we pay the hedging partner and below which we are paid by the
hedging partner. During 1999, approximately 85% of our equivalent production was
subject to hedge positions.

The following table sets forth our open hedge positions as of December
31, 1999.

PRICE
NOTIONAL --------------------------------
TIME PERIOD QUANTITIES FLOOR CEILING FIXED
----------- ---------- ----- ------- -----
<S> <C> <C> <C> <C>
NATURAL GAS (MMBTU)
January 1 - March 31, 2000
Collar purchased 5,460 $ 2.00 $ 2.70
Fixed price swap purchased 3,550 $2.18
Market sensitive swap sold (1,820) 2.60

April 1 - December 31, 2000
Collar purchased 2,263 2.25 $ 2.49
Fixed price swap purchased 7,445 2.18

January 1 - December 31, 2001
Fixed price swap purchased 4,501 2.18

January 1 - December 31, 2002
Fixed price swap purchased 1,831 2.18

CRUDE OIL (MBBLS)
January 1 - December 31, 2000
Fixed price swap purchased 1,482 18.66
</TABLE>

<PAGE> 14

Hedging arrangements for 2000, 2001 and 2002 cover approximately 65%,
10% and 3% of our anticipated equivalent production, respectively. Hedging
arrangements may expose us to the risk of financial loss in certain
circumstances, including instances where our production, which is in effect
hedged, is less than expected or where there is a sudden, unexpected event
materially impacting prices. Our Revolving Credit Facility (see Note 3 of the
financial statements) places certain restrictions on our use of hedging. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations"Changes in Prices and Hedging Activities".

(j) COMPETITION

We believe that the locations of our leasehold acreage, our
exploration, drilling and production capabilities, and our experience generally
enable us to compete effectively. However, our 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 our
larger competitors possess and employ financial and personnel resources
substantially greater than those available to us. 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 our financial or personnel resources permit. Our ability to
acquire additional prospects and to discover reserves in the future is dependent
upon our 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.

(k) ROYALTY RELIEF

The Outer Continental Shelf Deep Water Royalty Relief Act (the "RRA"),
signed into law on November 28, 1995, provides that all tracts in the Gulf of
Mexico west of 87 degrees, 30 minutes West longitude in water more than 200
meters deep offered for bid within five years of the RRA will be relieved from
normal federal royalties as follows:

<TABLE>
<CAPTION>
WATER DEPTH ROYALTY RELIEF
------------------- --------------
<S> <C>
200-400 meters.......................... no royalty payable on the first 105 Bcfe produced
400-800 meters.......................... no royalty payable on the first 315 Bcfe produced
800 meters or deeper.................... no royalty payable on the first 525 Bcfe produced
</TABLE>

The RRA also allows mineral interest owners the opportunity to apply
for royalty relief for new production on leases acquired before the RRA was
enacted. If the United State Minerals Management Service determines that new
production would not be economical without royalty relief, then a portion of the
royalty may be relieved to make the project economical.

The impact of royalty relief is significant, as normal royalties for
leases in water depths of 400 meters or less is 16.7% and normal royalties for
leases in water depths greater than 400 meters is 12.5%. Royalty relief can
substantially improve the economics of projects in deep water. We have acquired
50 new deepwater leases that are qualified for royalty relief and have received
royalty relief on the four lease blocks comprising the Pluto project.

(l) REGULATION

Our operations are subject to extensive and continually changing
regulation because 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 our cost of doing business and, consequently,
affects our profitability. However, we do not believe that it is affected in a
significantly different manner by these regulations than are our competitors in
the oil and natural gas industry.

<PAGE> 15

(i) TRANSPORTATION AND SALE OF NATURAL GAS

The FERC regulates interstate natural gas pipeline transportation rates
and service conditions, which affect the marketing of gas produced by us and the
revenues received by us for sales of such natural gas. In 1985, the FERC adopted
policies that make natural gas transportation accessible to natural gas buyers
and sellers on an open-access, non-discriminatory basis. The FERC issued Order
No. 636 on April 8, 1992, which, among other things, prohibits interstate
pipelines from tying sales of gas to the provision of other services and
requires pipelines to "unbundle" the services they provide. This has enabled
buyers to obtain natural gas supplies from any source and secure independent
delivery service from the pipelines. All of the interstate pipelines subject to
FERC's jurisdictions are now operating under Order No. 636 open access tariffs.
On July 29, 1998, the FERC issued a Notice of Proposed Rulemaking regarding the
regulation of short term natural gas transportation services. In a related
initiative, FERC issued a Notice of Inquiry on July 29, 1998 seeking input from
natural gas industry players and affected entities regarding virtually every
aspect of the regulation of interstate natural gas transportation services. As a
result, the FERC issued Order No. 637 (final rule on February 9, 2000) amending
its transportation regulation in response to the growing development of more
competitive markets for natural gas and the transportation of natural gas. Order
No. 637 revises the regulatory framework to improve the efficiency of the
natural gas market and provide captive customers with the opportunity to reduce
their cost of holding long-term pipeline capacity. The rate revises the FERC's
pricing policy to enhance market efficiency for short term released capacity and
permit pipelines to file for peak and off-peak and term differentiated rate
structures. Order No. 637 further improves the Commission's reporting
requirements and permits more effective monitoring of the natural gas market.

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. We cannot predict when or if any such
proposals might become effective or their effect, if any, on our operations. The
natural gas industry historically has been closely regulated; thus there is no
assurance that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue indefinitely into the future.

(ii) REGULATION OF PRODUCTION

The production of oil and natural gas is subject to regulation under a
wide range of state and federal statutes, rules, orders and regulations. State
and federal statutes and regulations require permits for drilling operations,
drilling bonds and reports concerning operations. Most states in which we own
and operate 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 we can produce from our wells and to limit the number of wells or
the locations at which we can drill. Moreover, each state generally imposes a
production or severance tax with respect to production and sale of crude oil,
natural gas and gas liquids within its jurisdiction.

Most of our offshore operations are conducted on federal leases that
are administered by the United States Minerals Management Service (the "MMS")
and are required to comply with the regulations and orders promulgated by MMS.
Among other things, we are required to obtain prior MMS approval for our
exploration plans and our development and production plans for these leases. The
MMS regulations also establish construction requirements for production
facilities located on our federal offshore leases and govern the plugging and
abandonment of wells and the removal of production facilities from these leases.
Under certain circumstances, the MMS could require us to suspend or terminate
our operations on a federal lease.

In addition, a portion of our Sandy Lake Properties are located within
the boundaries of the Big Thicket National Preserve (the "BTNP"), which is under
the jurisdiction of the United States National Park Service (the "NPS"). Our
operations within the BTNP must comply with regulations of the NPS. In general,
these regulations require us to obtain NPS approval of a plan of operations for
any activity within the BTNP or to demonstrate that a waiver of a plan of
operations is appropriate. Compliance with these regulations increases our cost
of operations and may delay the commencement of specific operations.

<PAGE> 16

(iii) ENVIRONMENTAL REGULATIONS

GENERAL. Various federal, state and local laws and regulations
governing the discharge of materials into the environment, or otherwise relating
to the protection of the environment, affect our operations and costs. In
particular, our exploration, development and production operations, activities
in connection with storage and transportation of crude oil and other liquid
hydrocarbons and 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 our 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, we may generate waste that may fall within CERCLA's definition of a
"hazardous substance". We 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.

We currently own or lease, and have 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 we have 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 us 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 our control. These properties and
wastes disposed thereon may be subject to CERCLA and analogous state laws. Under
such laws, we could be required to remove or remediate previously disposed
wastes (including wastes disposed of or released by prior owners or operators),
to clean up contaminated property (including contaminated groundwater) or to
perform remedial plugging operations to prevent future contamination.

OIL POLLUTION ACT OF 1990. The Oil Pollution Act of 1990 (the "OPA")
and regulations thereunder impose liability on "responsible parties" for damages
resulting from crude oil spills into or upon navigable waters, adjoining
shorelines or in the exclusive economic zone of the United States. Liability
under the OPA is strict, joint and several, and potentially unlimited. A
"responsible party" includes the owner or operator of an onshore facility and
the lessee or permittee of the area in which an offshore facility is located.
The OPA also requires the lessee or permittee of the offshore area in which a
covered offshore facility is located to establish and maintain evidence of
financial responsibility in the amount of $35 million ($10 million if the
offshore facility is located landward of the seaward boundary of a state) to
cover liabilities related to a crude oil spill for which such person is
statutorily responsible. The amount of required financial responsibility may be
increased above the minimum amounts to an amount not exceeding $150 million
depending on the risk represented by the quantity or quality of crude oil that
is handled by the facility. The MMS has promulgated regulations that implement
the financial responsibility requirements of the OPA. A failure to comply with
the OPA's requirements or inadequate cooperation during a spill response action
may subject a responsible party to civil or criminal enforcement actions. We are
not aware of any action or event that would subject us to liability under the
OPA and we believe that compliance with the OPA's financial responsibility and
other operating requirements will not have a material adverse effect on us.

CLEAN WATER ACT. The Federal Water Pollution Control Act of 1972, as
amended (the "Clean Water Act"), imposes restrictions and controls on the
discharge of produced waters and other oil and gas wastes into navigable waters.
These controls have become more stringent over the years, and it is possible
that additional restrictions will be imposed in the future. Permits must be
obtained to discharge pollutants into state and federal waters. Certain state
regulations and the general permits issued under the Federal National Pollutant
Discharge Elimination System program prohibit the discharge of produced waters
and sand, drilling fluids, drill cuttings and certain other substances related
to the oil and gas industry into certain coastal and offshore water. The Clean
Water Act provides for civil, criminal and administrative penalties for
unauthorized discharges for oil and other hazardous substances and imposes
liability on parties responsible for those discharges for the costs of cleaning
up any environmental damage caused by the release and for natural resource
damages resulting from the release. Comparable state statutes impose liabilities
and authorize penalties in the case of an unauthorized discharge of petroleum or
its derivatives, or other hazardous substances, into state waters. We believe
that our operations comply in all material respects with the requirements of the
Clean Water Act and state statutes enacted to control water pollution.

<PAGE> 17

RESOURCES CONSERVATION RECOVERY ACT. The Resource Conservation Recovery
Act ("RCRA") is the principle federal statute governing the treatment, storage
and disposal of hazardous wastes. RCRA imposes stringent operating requirements,
and liability for failure to meet such requirements, on a person who is either a
"generator" or "transporter" of hazardous waste or an "owner" or "operator" of a
hazardous waste treatment, storage or disposal facility. At present, RCRA
includes a statutory exemption that allows most crude oil and natural gas
exploration and production waste to be classified as nonhazardous waste. A
similar exemption is contained in many of the state counterparts to RCRA. As a
result, we are not required to comply with a substantial portion of RCRA's
requirements because our operations generate minimal quantities of hazardous
wastes. At various times in the past, proposals have been made to amend RCRA to
rescind the exemption that excludes crude oil and natural gas exploration and
production wastes from regulation as hazardous waste. Repeal or modification of
the exemption by administrative, legislative or judicial process, or
modification of similar exemptions in applicable state statutes, would increase
the volume of hazardous waste we are required to manage and dispose of and would
cause us to incur increased operating expenses.

(m) EMPLOYEES

As of December 31, 1999, we had 74 full-time employees. Our employees
are not represented by any labor union. We consider relations with our employees
to be satisfactory. We have never experienced a work stoppage or strike.

ITEM 3. LEGAL PROCEEDINGS

During the fourth quarter of 1999, Noble Drilling Corporation filed a
lawsuit against us and Samedan Oil Corporation for breach of contract regarding
the use of Noble's newly converted semisubmersible deepwater drilling rig, the
Noble Homer Ferrington. Subsequent to year-end, we executed a settlement
agreement with Noble Drilling dismissing us from the lawsuit. Additionally, we
executed agreements with Noble Drilling whereby we agreed to use the Noble Homer
Ferrington for a minimum of 660 days over a five-year period at market-based day
rates for comparable drilling rigs in comparable water depths subject to a floor
day rate ranging from $65,000 to $125,000. In exchange for the market-based day
rates, Noble Drilling was assigned working interests in seven of our deepwater
exploration prospects. We will pay Noble Drilling's share of the costs of
drilling the initial test well on each of these prospects.

In the ordinary course of business, we are a claimant and/or a
defendant in various other legal proceedings, including proceedings as to which
we have insurance coverage, in which the exposure, individually and in the
aggregate, is not considered material to us.

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

None.

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

There is no established public trading market for our common stock, our
only class of equity securities.

PART II

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 for the periods indicated.

<PAGE> 18

<TABLE>
<CAPTION>
PREDECESSOR COMPANY (1)
-------------------------------------
(ALL AMOUNTS IN MILLIONS) YEAR YEAR YEAR 9 MOS. 3 MOS. YEAR
ENDED ENDED ENDED ENDED ENDED ENDED
STATEMENT OF OPERATIONS DATA: 12/31/99 12/31/98 12/31/97 12/31/96 12/31/96 12/31/95
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Total revenues $ 52.5 $ 56.7 $ 62.8 $ 47.1 $ 13.3 $ 32.3
Lease operating expenses 11.5 9.9 9.4 6.5 2.4 6.4
Depreciation, depletion and
amortization 32.1 33.8 31.7 24.8 6.3 15.6
Impairment of oil and gas properties -- 50.8 28.5 22.5 -- --
Provision for litigation -- 2.8 -- -- -- --
General and administrative expenses 5.4 4.8 3.2 2.4 0.7 2.0
-------- -------- -------- -------- -------- --------
Operating income (loss) 3.5 (45.4) (10.0) (9.1) 3.9 8.3

Interest income -- 0.3 0.5 0.5 2.2 9.3
Interest expense (13.5) (13.3) (10.7) (7.7) (3.4) (12.8)
Write-off of bridge loan fees -- -- -- (2.4) -- --
-------- -------- -------- -------- -------- --------
Income (loss) before income taxes (10.0) (58.4) (20.2) (18.7) 2.7 4.8
Provision for income taxes -- -- -- -- -- 0.3
-------- -------- -------- -------- -------- --------
Net income (loss) $ (10.0) $ (58.4) $ (20.2) $ (18.7) $ 2.7 $ 4.5
======== ======== ======== ======== ======== ========

CAPITAL EXPENDITURE AND DISPOSAL DATA:
Exploration, incl. leasehold/seismic $ 24.0 $ 78.8 $ 49.0 $ 31.9 $ 4.9 $ 17.5
Development and other 57.5 63.1 19.9 7.0 2.6 24.3
-------- -------- -------- -------- -------- --------
Total capital expenditures $ 81.5 $ 141.9 $ 68.9 $ 38.9 $ 7.5 $ 41.8
======== ======== ======== ======== ======== ========
Proceeds from disposals $ 19.8 -- -- 7.5 -- $ 20.7
======== ======== ======== ======== ======== ========

BALANCE SHEET DATA (AT END OF PERIOD):
Oil and gas properties, net, at full
cost $ 263.6 $ 233.3 $ 175.7 $ 166.6 $ 127.1 $ 125.8
Long-term receivable from affiliates -- -- -- -- 104.0 106.0
Total assets 297.5 262.3 212.6 196.8 254.3 250.7
Long-term debt, less current 167.3 124.6 113.6 99.5 162.5 162.5
maturities
Stockholder's equity 65.0 27.5 57.2 77.1 71.9 69.3
</TABLE>

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

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

(a) INTRODUCTION

The following discussion is intended to assist in an understanding of
our financial position and results of operations for each of the three years in
the period that began January 1, 1997 and ended December 31, 1999. This
discussion should be read in conjunction with the information contained in the
financial statements 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 our financial position, business strategy, plans and objectives of
management for future operations and industry conditions, are forward-looking
statements. Although we believe that the expectations reflected in such
forward-looking statements are reasonable, it can give no assurance that such
expectations will prove to have been correct.

(b) GENERAL

We are an independent oil and natural gas exploration, development and
production company with principal operations in the Gulf and along the U.S. Gulf
Coast. Our strategy is to increase reserves, production and cash flow primarily
through the drillbit with a heavy emphasis on the deepwater Gulf.

During 1999 we:

<PAGE> 19

o drilled five exploratory wells, with three successes, in the deepwater
Gulf of Mexico, including our potentially significant Aconcagua and
Devils Tower prospects, making us seven of twelve in deepwater Gulf
exploratory test wells drilled since the acquisition from Hardy;

o commenced production from two significant deepwater projects; Dulcimer
in April 1999 and Pluto in December 1999;

o sold a 63% interest in the Pluto deepwater exploitation project to
Burlington Resources, retaining a 37% working interest, which will
increase to 51% after payout;

o added proved reserves of 31.5 Bcfe before the partial sale of the
Pluto project, which were approximately 127% of our 1999 production of
24.9 Bcfe;

o added three deepwater blocks from success at the March 1999 Gulf lease
sale, giving us 118 blocks in the Gulf with 72 in the deepwater Gulf
as of December 31, 1999.

We expect capital expenditures for 2000, net of proceeds from unproved
property dispositions, to be approximately $75 million, which we intend to use
to explore, develop and continue to build our prospect inventory. We expect to
fund our capital expenditures by a combination of internally generated cash
flow, proceeds from sales of partial interests in unproved properties,
contributions from our parent company and borrowings against our Revolving
Credit Facility.

Our revenue, profitability, access to capital and future rate of growth
are heavily influenced by the price we receive for our production. The markets
for oil, natural gas and natural gas liquids have been historically volatile and
may continue to be volatile in the future. We regularly enter into hedging
transactions for our oil and natural gas production and intend to continue doing
so. These transactions may limit our potential gains if oil and natural gas
prices were to rise substantially over the price established by the hedges.
These hedges also may expose us to the risk of financial loss in some
circumstances, including possibly instances in which our production is less than
expected or there is an unexpected event materially affecting prices.

Another significant factor affecting us will be competition, both from
other sources of energy such as electricity and from within the industry. Many
of our larger competitors possess and employ financial and personnel resources
substantially greater than those available to us, which can be particularly
important in deepwater Gulf activities. These 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 our financial or personnel resources permit.

We use the full cost method of accounting for our investments in oil
and natural gas properties. Under this methodology, all costs of exploration,
development and acquisition of oil and natural gas reserves are capitalized into
a "full cost pool" as incurred and properties in the pool are depleted and
charged to operations using the unit-of-production method based on a ratio of
current production to total proved oil and natural gas reserves. To the extent
that capitalized costs less deferred applicable taxes exceed the present value,
using a 10% discount rate, of estimated future net cash flows from proved oil
and natural gas reserves and the lower of cost or fair market value of unproved
properties, the excess costs are charged to operations. Capitalized costs are
net of accumulated depreciation, depletion and amortization. If a writedown were
required, it would result in a charge to earnings but would not have an impact
on cash flows.

Our results of operations may vary significantly from year to year
based on the factors discussed above and on 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 we receive from co-owners. Therefore, the results of any one year may not
be indicative of future results.

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.

<PAGE> 20

<TABLE>
<CAPTION>
Year ended December 31
------------------------------------

1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Production:
Oil (MMbbls) ................................................. 0.6 0.8 1.0
Natural gas (Bcf) ............................................ 21.1 19.5 18.0
Gas equivalent (Bcfe) ........................................ 24.9 24.2 23.9

Average sales prices including effects of hedging:
Oil ($/Bbl) .................................................. $ 13.65 $ 12.80 $ 18.48
Natural gas ($/Mcf) .......................................... 2.08 2.39 2.48
Gas equivalent ($/Mcfe) ...................................... 2.11 2.34 2.63

Expenses ($/Mcfe):
Lease operating .............................................. 0.46 0.41 0.39
General and administrative, net .............................. 0.22 0.20 0.13
Depreciation, depletion and amortization
(excluding impairments) ...................................... 1.29 1.40 1.33
</TABLE>

(i) 1999 COMPARED TO 1998

NET PRODUCTIOn increased 3% to 24.9 Bcfe for 1999 from 24.2 Bcfe for
1998. Production from our offshore Gulf properties increased to 18.2 Bcfe in
1999 from 13.1 Bcfe in 1998, as a result of production commencing from a new
well in the Dulcimer field located in Garden Banks block 367 and two new wells
in the Rembrandt field located in Galveston block 151. This increase was offset
by less than expected production from our Sandy Lake field onshore Texas.

HEDGING ACTIVITIES in 1999 decreased our average realized natural gas
price received by $0.32 per Mcf and revenues by $6.7 million, compared with an
increase of $0.12 per Mcf and revenues of $2.3 million in 1998. Our hedging
activities with respect to crude oil during 1999 reduced the average sales price
received by $3.42 per Bbl and revenues by $2.2 million. There were no oil hedges
in 1998.

OIL AND GAS REVENUES decreased 7% to $52.5 million for 1999 from $56.7
million for 1998, due to a 10% decrease in realized prices to $2.11 per Mcfe in
1999 from $2.34 per Mcfe in 1998.

LEASE OPERATING EXPENSES increased 16% to $11.5 million for 1999 from
$9.9 million for 1998 due to the higher offshore production discussed above and
well workovers on three offshore wells and two wells in our Sandy Lake field.

DEPRECIATION, DEPLETION, AND AMORTIZATION EXPENSE decreased 5% to $32.1
million for 1999 from $33.8 million for 1998 as a result of the decrease in the
unit-of-production depreciation, depletion and amortization rate to $1.29 per
Mcfe from $1.40 per Mcfe. This decrease was offset in part by a 3% increase in
equivalent volumes produced. The lower rate for 1999 was primarily due to the
$50.8 million non-cash full cost ceiling test impairment recorded in 1998. No
impairment was necessary for 1999.

GENERAL AND ADMINISTRATIVE EXPENSES, which are net of overhead
reimbursements we received from other working interest owners, increased 14% to
$5.4 million for 1999 from $4.7 million for 1998 due to increased
personnel-related costs in 1999 required for us to pursue our deepwater Gulf
exploration and development plan.

INTEREST EXPENSE for 1999 increased 1% to $13.5 million from $13.4
million for 1998.

INCOME (LOSS) BEFORE INCOME TAXES decreased to a loss of $10.0 million
for 1999 from a loss of $58.4 million in 1998 as a result of a $50.8 million
full cost ceiling test impairment, offset in part by oil and gas revenue
decreases and increased expenses discussed above.

(ii) 1998 COMPARED TO 1997

NET PRODUCTION increased 1% to 24.2 Bcfe in 1998 from 23.9 Bcfe in
1997. Natural gas production increased by 1.4 Bcf, or 8%, to 19.5 Bcf from 18.0
Bcf. Gas production from offshore properties decreased 0.3 Bcf or 3%, primarily
due to the natural production decline offset by the addition of two offshore
properties, while gas production from onshore properties increased 1.8 Bcf or
32%.

<PAGE> 21

OIL AND GAS REVENUES for 1998 decreased by $6.1 million, or 10%,
compared to 1997 due to decreased oil and gas sales prices partially offset by
the production increase described above. The average realized sales price of
natural gas decreased 4%, to $2.39 per Mcf in 1998 from $2.48 per Mcf in 1997,
while the average realized oil sales price decreased by 31% to $12.80 per Bbl in
1998 from $18.48 per Bbl in 1997.

HEDGING ACTIVITIES in 1998, with respect to the average realized
natural gas sales price received, increased by $0.12 per Mcf and revenues by
$2.3 million. In 1997, natural gas hedging activities decreased the average
realized natural gas sales price received by $0.22 per mcf and revenues by $3.9
million. There were no hedging activities for oil in 1998. Our hedging
activities with respect to crude oil during 1997 reduced the average sales price
received by $0.63 per Bbl and revenues by $0.6 million. During 1998,
approximately 40% of our equivalent production was subject to hedge positions
compared to 60% in 1997.

LEASE OPERATING EXPENSES increased 5% to $9.9 million for 1998 from
$9.4 million for 1997. Lease operating expense per Mcfe increased to $0.41 per
Mcfe for 1998 from $0.39 per Mcfe for 1997, due to higher fixed costs associated
with offshore properties.

DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE (DD&A) increased 7% to
$33.8 million for 1998, from $31.7 million for 1997, as a result of a 5%
increase in the unit-of-production depreciation, depletion and amortization rate
to $1.40 per Mcfe from $1.33 per Mcfe, due to increased drilling and completion
costs, and a 1% increase in equivalent volumes produced.

IMPAIRMENT OF OIL AND GAS PROPERTIES of $50.8 million was recorded in
the fourth quarter of 1998 for a non-cash full cost ceiling test impairment
using prices in effect at December 31, 1998. During the first quarter of 1997, a
$28.5 million non-cash full cost ceiling writedown was also recorded due to low
commodity prices in effect as of the end of that period.

GENERAL AND ADMINISTRATIVE EXPENSES, which are net of overhead
reimbursements received by us from other working interest owners on properties
operated by us, increased 49% to $4.7 million in 1998, up from $3.2 million in
1997, due primarily to higher employment levels to build the necessary expertise
for Deepwater Gulf projects and related office costs in 1998. General and
administrative expense increased $0.07 per Mcfe from 1997 to 1998. In addition,
during 1998 the Company recognized a one-time charge of $2.8 million relating to
litigation expense.

INTEREST EXPENSE increased 26% to $13.4 million for 1998, from $10.6
million for 1997, due primarily to the 47% increase in average outstanding debt
to $151.4 million in 1998, from $103.2 million in 1997, which was partially
offset by a 10.1% decrease in the average interest rate paid on outstanding debt
to 9.33%, from 10.38%.

INCOME (LOSS) BEFORE INCOME TAXES decreased to a loss of $58.4 million
for 1998, from a loss of $20.2 million loss for 1997, as a result of the factors
described above.

(d) LIQUIDITY AND CAPITAL RESOURCES

(i) CASH FLOWS

Liquidity is a company"s ability to generate cash to meet its needs for
cash. As of December 31, 1999, we had a working capital deficit of approximately
$32.3 million, compared with a working capital deficit of $83.8 million as of
December 31, 1998. The decreased working capital deficit was a result of the
reclassification during 1999 of our Revolving Credit Facility to a long-term
liability, based on its revised maturity date of October 1, 2002. This decrease
was offset in part by increased accounts payable at year-end compared to the
prior year due to a higher level of drilling and completion activity.

We will require a significant amount of capital to develop our
properties in order to achieve higher levels of production and cash flow. To
obtain the necessary funds to reduce the working capital deficit and continue
our planned capital expenditure program, in March 2000, our parent company,
Mariner Energy LLC (LLC), agreed to a financing arrangement with Enron North
America Corp. (ENA). As part of that arrangement, LLC will provide $55 million
of equity capital to us to allow us to repay an existing $25 million short-term
credit facility with ENA and to provide approximately $30 million of additional
capital. Our remaining capital needs are expected to be met by a combination of
internally generated cash flows, proceeds from the sale of partial interests in
unproved properties and borrowings against our Revolving Credit Agreement. There
can be no assurances, however, that our access to capital will be sufficient to
meet our capital needs.

<PAGE> 22

We had a net cash inflow of $121,000 in 1999, compared to a net cash
outflow of $9.1 million in 1998 and a net cash inflow of $1.7 million in 1997. A
discussion of the major components of cash flows for these years follows.

<TABLE>
<CAPTION>
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Cash flows provided by operating activities (in millions)....... $ 24.4 $ 39.6 $ 52.9
</TABLE>

Cash flows provided by operating activities in 1999 decreased by $15.2
million compared to 1998 due to decreased oil and gas prices and increased lease
operating and general and administrative expenses. Cash flows from operating
activities in 1998 decreased by $13.3 million from 1997 primarily due to
decreased oil and gas prices.

<TABLE>
<CAPTION>
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Cash flows used in investing activities (in millions).....$ 61.8 $141.9 $ 68.9
</TABLE>

Cash flows used in investing activities in 1999 decreased by $80.1
million compared to 1998 due to decreased capital expenditures and the sell down
of a 63% interest in our Pluto Project. Cash flows used in investing activities
in 1998 increased by $73 million compared to 1997 due to increased capital
expenditures to acquire leasehold inventory.

<TABLE>
<CAPTION>
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Cash flows provided by financing activities (in millions)........$ 37.5 $ 93.2 $ 14.3
</TABLE>

Cash flows provided by financing activities in 1999 decreased by $55.7
million compared to 1998 due to a $10.8 million net reduction in borrowings
against our Revolving Credit Facility as compared to a $39.4 million increase in
borrowings against that facility for the previous year. Cash flows provided by
financing activities in 1998 increased by $78.9 million as compared to 1997 due
to receiving approximately $28.8 million in equity contributions and $64.4
million from borrowings against our various credit facilities.

(ii) CHANGES IN PRICES AND HEDGING ACTIVITIES

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

The following table sets forth the increase or decrease in our 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
---------------------------
1999 1998 1997
------ ------- -------
<S> <C> <C> <C>
Increase (decrease) in natural gas sales (in millions) .......... $ (6.7) $ 2.3 $ (3.9)
Increase (decrease) in oil sales (in millions).................... (2.2) -- (0.6)
Effect of hedging transactions on average gas sales price
(per Mcf).................................................. (0.32) 0.12 (0.22)
Effect of hedging transactions on average oil sales price
(per Bbl)................................................... (3.42) -- (0.63)
</TABLE>

Hedging arrangements for 1999 covered approximately 85% of our
equivalent production for the year. Hedging arrangements for 2000, 2001 and 2002
cover approximately 65%, 10% and 3% of our anticipated equivalent production,
respectively.

<PAGE> 23

The following table sets forth our open hedge positions as of December
31, 1999.

<TABLE>
<CAPTION>
PRICE
NOTIONAL -------------------------------
TIME PERIOD QUANTITIES FLOOR CEILING FIXED FAIR VALUE
----------- ---------- ----- ------- ----- ----------
(in millions)
<S> <C> <C> <C> <C> <C>
NATURAL GAS (MMBtu)
January 1 - March 31, 2000
Collar purchased 5,460 $2.00 $ 2.70 --
Fixed price swap purchased 3,550 $ 2.18 (0.6)
Market sensitive swap sold (1,820) 2.60 (0.5)

April 1 - December 31, 2000
Collar purchased 2,263 2.25 $ 2.49 --
Fixed price swap purchased 7,445 2.18 (1.7)

January 1 - December 31, 2001
Fixed price swap purchased 4,501 2.18 (1.3)

January 1 - December 31, 2002
Fixed price swap purchased 1,831 2.18 (0.5)

CRUDE OIL (MBbls)
January 1 - December 31, 2000
Fixed price swap purchased 1,482 18.66 (5.6)
</TABLE>

The fair value for our hedging instruments was determined based on
brokers' forward price quotes and NYMEX forward price quotes as of December 31,
1999. As of December 31, 1999, a commodity price increase of 10% would have
resulted in an unfavorable change in the fair value of our hedging instruments
of $7.4 million and a commodity price decrease of 10% would have resulted in a
favorable change in the fair value of our hedging instruments of $7.3 million.

Our senior subordinated notes have a fixed rate and, therefore, do not
expose us to risk of earnings loss due to changes in market interest rates.
However, we are subject to interest rate risk under our Revolving Credit
Facility and our short-term credit facility with ENA. For example a 100 basis
point increase in the London Interbank Offered Rate would have increased our
1999 interest expense by $0.7 million. The carrying value of our Revolving
Credit Facility and our short-term credit facility with ENA approximates market
since these instruments have floating interest rates. The market value of the
senior subordinated notes was approximately $92.0 million based on borrowing
rates available at December 31, 1999.

(iii) CAPITAL EXPENDITURES AND CAPITAL RESOURCES

CAPITAL EXPENDITURES AND CAPITAL RESOURCES

The following table presents major components of our capital and
exploration expenditures for each of the three years in the period ended
December 31, 1999.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------
1999 1998 1997
------- -------- --------
<S> <C> <C> <C>
CAPITAL EXPENDITURES (IN MILLIONS):
Leasehold acquisition-- unproved properties.............. $ 3.0 $ 43.1 $ 21.6
Leasehold acquisition-- proved properties................ - - 3.2
Oil and natural gas exploration.......................... 13.5 35.7 27.4
Oil and natural gas development and other................ 45.2 63.1 16.7
------- -------- --------
TOTAL CAPITAL EXPENDITURES, NET OF PROCEEDS FROM SALES..... $ 61.7 $ 141.9 $ 68.9
======= ======== ========
</TABLE>

Our capital expenditures for 1999 were $81.5 million, excluding the
$19.8 million related to our sale of a 63% working interest in the Pluto
project, which was $60.4 million less than 1998. The decrease was primarily a
result of lower leasehold acquisition, geological and geophysical, exploratory
drilling and development costs as we operated with reduced access to capital.
Excluding the Pluto sale, our 1999 capital expenditures included $24.0 million
for exploration activities, $48.1 million for development activities and $9.4
million of capitalized indirect costs. Included in exploration expenditures was
$8.9 million for lease bonus payments on three deepwater Gulf blocks awarded to
us in the March 1999 Central Gulf lease sale.

Our total capital expenditures for 1998 were $73 million more than
1997. The increase was due primarily to our continued focus on building and
evaluating our exploration and exploitation prospect inventory, as evidenced by
the increase in both leasehold acquisition of unproved properties and oil and
gas exploration, and increased development related spending, both to acquire
additional interests in existing proved properties and to develop successful
exploratory prospects.

<PAGE> 24

We expect capital expenditures for 2000, net of proceeds from unproved
property dispositions, to be approximately $75 million. We anticipate drilling
three or four exploratory wells in the Deepwater Gulf, with a partner paying our
share of the cost for one of the wells. Three wells are also planned to appraise
our potentially significant deepwater exploratory successes at Aconcagua and
Devils Tower, with drilling currently in progress at Aconcagua and planned for
the second quarter on Devils Tower.

Our long-term debt outstanding as of December 31, 1999 was
approximately $167.3 million, including $99.7 million of senior subordinated
notes, $42.6 million drawn on our Revolving Credit Facility, and $25 million on
our senior credit facility. Following our semi-annual borrowing base
redetermination completed in October 1999, our borrowing base under the
Revolving Credit Facility was reaffirmed at $60 million. Our senior credit
facility with ENA will be repaid on April 30, 2000 with proceeds from an equity
contribution from our parent company.

Our Revolving Credit Facility and the senior subordinated notes contain
various restrictive covenants that, among other things, restrict the payment of
dividends, limit the amount of debt we may incur, limit our ability to make
certain loans, investments, enter into transactions with affiliates, sell
assets, enter into mergers, limit our ability to enter into certain hedge
transactions and provide that we must maintain specified relationships between
cash flow and fixed charges and cash flow and interest on indebtedness. In
addition, restrictions in the Revolving Credit Facility and the senior
subordinated notes effectively restrict us from using our assets or cash flow to
satisfy interest or principal payments for our parent's credit facility with
Enron.

In March 2000, the Company received from Mariner Energy LLC a cash
contribution of approximately $30 million. This contribution was made from the
proceeds of Mariner Energy LLC's three year $112 million term loan with Enron
North America Corp. Due to certain restrictions with the Company's Indenture,
neither cash flow from operations or from assets sales would be available to
repay any portion of this term loan.

In the second quarter of 1998, management shareholders and an affiliate
of Enron contributed $28.8 million of net equity capital, which was used to
reduce borrowings on our revolving credit facility and to supplement funding of
our 1998 capital expenditure plan.

In future periods, our capital resources may not be sufficient to meet
our anticipated future requirements for working capital, capital expenditures
and scheduled payments of principal and interest on our indebtedness. We cannot
assure you that anticipated growth will be realized, that our business will
generate sufficient cash flow from operations or that future borrowings or
equity capital will be available in an amount sufficient to enable us to service
our indebtedness or make necessary capital expenditures. In addition, depending
on the levels of our cash flow and capital expenditures, we may need to
refinance a portion of the principal amount of our senior subordinated debt at
or prior to maturity. However, we cannot assure you that we would be able to
obtain financing on acceptable terms to complete a refinancing.

We expect to fund our activities for 2000 through a combination of cash
flow from operations, borrowings under our Revolving Credit Facility, sales of
partial interests in unproved properties, and equity contributions from our
parent. However, we cannot assure you that we will realize our anticipated
growth, that our business will generate sufficient cash flow from operations or
that future borrowings or equity capital will be available in an amount
sufficient to enable us to service our indebtedness or make necessary capital
expenditures.

(e) YEAR 2000 COMPLIANCE

We were not and do not expect to be impacted by any Year 2000 compliant
issues.

(f) RECENT ACCOUNTING PRONOUNCEMENT

In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities" which was amended in June 1999 by
SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities -
Deferral of the Effective Date of FASB Statement No. 133 - an amendment of FASB
Statement No. 133." SFAS No. 133, as amended, is effective for fiscal years
beginning after June 15, 2000 and establishes accounting and reporting standards
for derivative instruments and for hedging activities. We will adopt this
statement no later than January 1, 2001.

<PAGE> 25

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

See Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations - (d) (ii) Changes in Prices and Hedging Activities.

<PAGE> 26

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Financial Statements

PAGE
----
<S> <C>
Independent Auditors' Report................................................................................27

Balance Sheets at December 31, 1999 and 1998................................................................28

Statements of Operations for the years ended December 31, 1999, 1998 and 1997...............................29

Statements of Stockholder's Equity for the years ended December 31, 1999, 1998 and 1997.....................30

Statements of Cash Flows for the years ended December 31, 1999, 1998 and 1997...............................31

Notes to Financial Statements...............................................................................32
</TABLE>

26
<PAGE> 27

INDEPENDENT AUDITORS' REPORT

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

We have audited the accompanying balance sheets of Mariner Energy, Inc. (the
"Company") as of December 31, 1999 and 1998 and the related statements of
operations, stockholder's equity and cash flows for each of the three years in
the period ended December 31, 1999. 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, 1999 and 1998, and the results of its operations and cash flows for
each of the three years in the period ended December 31, 1999, in conformity
with generally accepted accounting principles.

/s/ DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP

Houston, Texas
March 28, 2000

27
<PAGE> 28

MARINER ENERGY, INC.
BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)

<TABLE>
<CAPTION>
December 31, December 31,
1999 1998
-------------- --------------
<S> <C> <C>
ASSETS

CURRENT ASSETS:
Cash and cash equivalents $ 123 $ 2
Receivables 23,683 16,387
Prepaid expenses and other 4,891 7,234
-------------- --------------
Total current assets 28,697 23,623
-------------- --------------

PROPERTY AND EQUIPMENT:
Oil and gas properties, at full cost:
Proved 379,301 316,056
Unproved, not subject to amortization 81,897 84,076
-------------- --------------
Total 461,198 400,132
Other property and equipment 3,982 3,300
Accumulated depreciation, depletion and amortization (199,233) (167,846)
-------------- --------------

Total property and equipment, net 265,947 235,586
-------------- --------------

OTHER ASSETS, net of amortization 2,868 3,133
-------------- --------------

TOTAL ASSETS $ 297,512 $ 262,342
============== ==============
LIABILITIES AND STOCKHOLDER'S EQUITY

CURRENT LIABILITIES:
Accounts payable $ 30,269 $ 20,375
Accrued liabilities 25,389 29,082
Accrued interest 5,329 4,503
Revolving credit facility -- 53,400
-------------- --------------

Total current liabilities 60,987 107,360
-------------- --------------
ACCRUAL FOR FUTURE ABANDONMENT COSTS 4,226 2,824
LONG-TERM DEBT:
Subordinated notes 99,673 99,624
Revolving credit facility 42,600 --
ENA credit facility -- 25,000
Senior credit facility 25,000 --
-------------- --------------
Total long-term debt 167,273 124,624
-------------- --------------

COMMITMENTS AND CONTINGENCIES (Note 6)

STOCKHOLDER'S EQUITY:
Common stock, $1 par value; 2,000 and 1,000 shares
authorized, 1,378 and 1,000 shares were issued and
outstanding at December 31, 1999 and 1998, respectively 1 1
Additional paid-in-capital 172,318 124,856
Accumulated deficit (107,293) (97,323)
-------------- --------------
Total stockholder's equity 65,026 27,534
-------------- --------------

TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $ 297,512 $ 262,342
============== ==============
</TABLE>

The accompanying notes are an integral part of these financial statements

28
<PAGE> 29

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

<TABLE>
<CAPTION>
Year Year Year
Ended Ended Ended
December 31, December 31, December 31,
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
REVENUES:

Oil sales $ 8,600 $ 10,066 $ 18,061

Gas sales 43,868 46,624 44,710
--------- --------- ---------

Total revenues 52,468 56,690 62,771
--------- --------- ---------

COSTS AND EXPENSES:

Lease operating expenses 11,453 9,858 9,376

Depreciation, depletion and amortization 32,121 33,833 31,719

Impairment of oil and gas properties -- 50,800 28,514

Provision for litigation -- 2,800 --

General and administrative expenses 5,396 4,749 3,195
--------- --------- ---------

Total costs and expenses 48,970 102,040 72,804
--------- --------- ---------

OPERATING INCOME (LOSS) 3,498 (45,350) (10,033)

INTEREST:

Income 36 313 467

Related party expense (1,580) (993) --

Expense (11,924) (12,391) (10,644)
--------- --------- ---------

INCOME (LOSS) BEFORE INCOME TAXES (9,970) (58,421) (20,210)

PROVISION FOR INCOME TAXES -- -- --
--------- --------- ---------

NET INCOME (LOSS) $ (9,970) $ (58,421) $ (20,210)
========= ========= =========
</TABLE>

The accompanying notes are an integral part of these financial statements

29
<PAGE> 30

MARINER ENERGY, INC.
STATEMENTS OF STOCKHOLDER"S EQUITY
(IN THOUSANDS, EXCEPT NUMBER OF SHARES)

<TABLE>
<CAPTION>
ADDITIONAL TOTAL
COMMON STOCK PAID-IN ACCUMULATED STOCKHOLDER'S
SHARES AMOUNT CAPITAL DEFICIT EQUITY
--------- --------- --------- ----------- -------------

<S> <C> <C> <C> <C> <C>
Balance at December 31, 1996 1,000 $ 1 $ 95,744 $ (18,692) $ 77,053

Capital contribution -- -- 331 -- 331

Net loss -- -- -- (20,210) (20,210)
--------- --------- --------- --------- ---------

Balance at December 31, 1997 1,000 1 96,075 (38,902) 57,174

Capital contribution
proceeds from the
sale of commonstock
of Parent -- -- 28,781 -- 28,781

Net loss -- -- -- (58,421) (58,421)
--------- --------- --------- --------- ---------

Balance at December 31, 1998 1,000 1 124,856 (97,323) 27,534

Capital contribution 378 -- 47,462 -- 47,462

Net loss -- -- -- (9,970) (9,970)
--------- --------- --------- --------- ---------

Balance at December 31, 1999 1,378 $ 1 $ 172,318 $(107,293) $ 65,026
========= ========= ========= ========= =========
</TABLE>

The accompanying notes are an integral part of these financial statements

30
<PAGE> 31
MARINER ENERGY, INC.
STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

<TABLE>
<CAPTION>
Year Year Year
Ended Ended Ended
December 31, December 31, December 31,
1999 1998 1997
------------ ------------ ------------
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss) $ (9,970) $ (58,421) $ (20,210)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization 32,838 33,762 32,588
Impairment of oil and gas properties -- 50,800 28,514
Provision for litigation -- 2,800 --
Changes in operating assets and liabilities:
Receivables (8,119) 2,578 (5,014)
Other current assets 2,343 (3,606) (3,210)
Other assets 265 379 (483)
Accounts payable and accrued liabilities 7,027 11,253 20,693
--------- --------- ---------
Net cash provided by operating activities 24,384 39,545 52,878
--------- --------- ---------

INVESTING ACTIVITIES:
Additions to oil and gas properties (80,823) (140,777) (68,317)
Additions to other property and equipment (682) (1,078) (551)
Proceeds from sale of oil and gas properties 19,758 -- --
--------- --------- ---------
Net cash used in investing activities (61,747) (141,855) (68,868)
--------- --------- ---------
FINANCING ACTIVITIES:
Payments of debt issue costs -- -- (29)
Proceeds from revolving credit facility, net (10,800) 39,400 14,000
Proceeds from ENA credit facility -- 25,000 --
Proceeds from senior credit facility 25,000 -- --
Additional capital contributed by Parent 23,284 -- --
Proceeds from sale of common stock of Parent -- 28,781 331
--------- --------- ---------
Net cash provided by financing activities 37,484 93,181 14,302
--------- --------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 121 (9,129) (1,688)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 2 9,131 10,819
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 123 $ 2 $ 9,131
========= ========= =========
</TABLE>

The accompanying notes are an integral part of these financial statements

31
<PAGE> 32

MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION -- Through 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. as of September 1, 1999 known as Enron North America Corp. ("ENA"),
together with members of management of the Predecessor Company, formed Mariner
Holdings, Inc. ("Mariner Holdings"), which then purchased from Hardy Holdings
Inc. all of the issued and outstanding stock of the Predecessor Company for a
purchase price of approximately $185.5 million effective April 1, 1996 for
financial accounting purposes (the "Acquisition"). As a result of the sale of
Hardy Oil & Gas USA Inc.'s common stock, the name was changed to Mariner Energy,
Inc. (the "Company"). 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.

EXCHANGE OFFERING -- In October 1998, JEDI and other shareholders
exchanged all of their common shares of Mariner Holdings, the Company's parent,
for an equivalent ownership percentage in common shares of Mariner Energy LLC.
As of December 31, 1999 Mariner Energy LLC owns 100% of Mariner Holdings.

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.

RECEIVABLES -- Substantially all of the Company's receivables 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, permanent impairments of oil and gas properties of
approximately $50,800,000 and $28,514,000 were recorded during 1998 and 1997,
respectively. No writedown was necessary in 1999.

The costs of unproved properties are excluded from amortization using
the full-cost method of accounting. These costs are assessed quarterly for
possible impairments or reduction in value based on geological and geophysical
data. If a reduction in value has occurred, costs being amortized are increased.
The majority of the costs will be evaluated over the next three years.

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 Company's taxable income is included in a
consolidated United States income tax return with Mariner Holdings Inc. 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 using an asset and liability approach which
results in the recognition of deferred tax assets and liabilities for the
expected future tax consequences of temporary differences between the book
carrying amounts and the tax bases of assets and liabilities. Valuation
allowances are established when necessary to reduce deferred tax assets to the
amount more likely than not to be recovered.

32
<PAGE> 33

MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

CAPITALIZED INTEREST COSTS -- The Company capitalizes interest based on
the cost of major development projects which are excluded from current
depreciation, depletion, and amortization calculations. Capitalized interest
costs were approximately $3,028,000, $1,702,000 and $729,000 for the years ended
December 31, 1999, 1998 and 1997, respectively.

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

HEDGING PROGRAM -- The Company utilizes derivative instruments in the
form of natural gas and crude oil price swap and price collar agreements in
order to manage price risk associated with future crude oil and natural gas
production and fixed-price crude oil and natural gas purchase and sale
commitments. Such agreements are accounted for as hedges using the deferral
method of accounting. Gains and losses resulting from these transactions are
deferred, as appropriate, until recognized as operating income in the Company"s
Statement of Operations as the physical production required by the contracts is
delivered.

The net cash flows related to any recognized gains or losses associated
with these hedges are reported as cash flows from operations. If the hedge is
terminated prior to expected maturity, gains or losses are deferred and included
in income in the same period as the physical production required by the
contracts is delivered.

The conditions to be met for a derivative instrument to qualify as a
hedge are the following: (i) the item to be hedged exposes the Company to price
risk; (ii) the derivative reduces the risk exposure and is designated as a hedge
at the time the derivative contract is entered into; and (iii) at the inception
of the hedge and throughout the hedge period there is a high correlation of
changes in the market value of the derivative instrument and the fair value of
the underlying item being hedged.

When the designated item associated with a derivative instrument
matures, is sold, extinguished or terminated, derivative gains or losses are
recognized as part of the gain or loss on sale or settlement of the underlying
item. When a derivative instrument is associated with an anticipated transaction
that is no longer expected to occur or if correlation no longer exists, the gain
or loss on the derivative is recognized in income to the extent the future
results have not been offset by the effects of price or interest rate changes on
the hedged item since the inception of the hedge.

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, 1999
and 1998, the estimated fair value of the Company's Senior Subordinated Notes
was approximately $92,000,000 and $100,000,000, respectively. The estimated fair
value was determined based on borrowing rates available at December 31, 1999 and
1998, respectively, for debt with similar terms and maturities. The carrying
amount of the Company's other financial instruments approximates fair value.

USE OF ESTIMATES IN THE PREPARATION OF FINANCIAL STATEMENTS -- The
preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amount of revenues and expenses during the reporting period. Actual
results could differ from these estimates.

33
<PAGE> 34

MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

MAJOR CUSTOMERS -- During the year ended December 31, 1999, sales of oil
and gas to three purchasers, including an affiliate, accounted for 26%, 21% and
13% of total revenues. During the year ended December 31, 1998, sales of oil and
gas to four purchasers, including an affiliate, accounted for 29%, 16%, 15% and
10% of total revenues. During the year ended December 31, 1997, sales of oil and
gas to four purchasers accounted for 19%, 19%, 18% and 14% of total revenues.
Management believes that the loss of any of these purchasers would not have a
material impact on the Company's financial condition or results of operations.

RECLASSIFICATIONS - Certain reclassifications were made to the prior
years financial statements to conform to the current year presentation.

RECENT ACCOUNTING PRONOUNCEMENT -- In June 1998, the Financial
Accounting Standards Board ("FASB") issued Statement of Financial Accounting
Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging
Activities" which was amended in June 1999 by SFAS No. 137, "Accounting for
Derivative Instruments and Hedging Activities -- Deferral of the Effective Date
of FASB Statement No. 133 -- an amendment of FASB Statement No. 133." SFAS No.
133, as amended, is effective for fiscal years beginning after June 15, 2000 and
establishes accounting and reporting standards for derivative instruments and
for hedging activities. The Company is currently evaluating what effect, if any,
SFAS No. 133 will have on the Company's financial statements. The Company will
adopt this statement no later than January 1, 2001.

2. RELATED-PARTY TRANSACTIONS

SALES TO AFFILIATES -- For the years ending December 31, 1999, 1998 and
1997, sales to affiliates were approximately $16.2 million, $8.9 million and
$13.0 million, respectively.

RECEIVABLES FROM AFFILIATES - At December 31, 1999 and 1998, receivables
from affiliates were $76,100 and $379,323, respectively.

AFFILIATE TRANSACTIONS SUBSEQUENT TO THE ACQUISITION -- Enron
Corp.("Enron") is the parent of ENA, and an affiliate of Enron and ENA is the
general partner of JEDI. Accordingly, Enron may be deemed to control JEDI,
Mariner Energy LLC, Mariner Holdings and the Company. In addition, eight 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, ENA and JEDI have provided, and may in the future
provide, and ENA Securities Limited Partnership 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, ENA, the Company, JEDI and the
members of the Company's management who are also shareholders of Mariner Energy
LLC 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.

TRANSPORTATION CONTRACT - In 1999 the Company constructed a 29 mile
flowline from a third party platform to the Mississippi Canyon 718 subsea well.
After commissioning, MEGS LLC, an Enron affiliate, purchased the flowline from
the Company and its joint interest partners. The Company received $8.8 million
in cash proceeds which were offset against the cost of constructing the
flowline. No gain or loss was recognized. In addition the Company entered into a
firm transportation contract at a rate of $0.26 per MMbtu with MEGS LLC to
transport its share of 86 Bcf of natural gas from the commencement of production
through March 2009. The Company's working interest at December 31, 1999 was 37%
and will increase to 51% after the project reaches payout.

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, 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
transactions with its affiliates, but those restrictions are subject to
significant exceptions. 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.

34
<PAGE> 35

MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

3. LONG-TERM DEBT

REVOLVING CREDIT FACILITY -- In 1996, the Company entered into an
unsecured revolving credit facility (the "Revolving Credit Facility") with Bank
of America as agent for a group of lenders (the "Lenders").

The Revolving Credit Facility provides for a maximum $150 million
revolving credit loan. The available borrowing base under the Revolving Credit
Facility is currently $60 million and is subject to periodic redetermination.
The Revolving Credit Facility has an outstanding balance of $42.6 million at
December 31, 1999. On June 28, 1999, the Revolving Credit Facility was amended
to extend the maturity date from October 1, 1999 to October 1, 2002 and to
pledge certain Mariner interests to secure the Revolving Credit Facility.

Borrowings under the Revolving Credit Facility bear interest, at the
option of the Company, at either (i) LIBOR plus 0.75% to 1.25% (depending upon
the level of utilization of the Borrowing Base) or (ii) the higher of (a) the
agent's prime rate or (b) the federal funds rate plus 0.5%. The effective
interest rate at December 31, 1999 was 8.50%. 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, as amended, 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 specified
relationships between cash flow and fixed charges and cash flow and interest on
indebtedness. As of December 31, 1999, the Company was in compliance with all
such requirements.

ENA CREDIT FACILITY " The Company"s parent entered into an agreement
with ENA to provide a $50 million unsecured, subordinated credit facility (the
"Facility"), the funds from which were contributed to the Company. This facility
was assigned to Mariner Energy LLC in 1999. The Facility accrues interest at an
annual rate of LIBOR plus 4.5% and required a structuring fee of 4% of the
borrowed amount. The effective interest rate was 10.96% as of December 31, 1999.
The Facility requires that a portion of the proceeds of any private or public
equity or debt offering by the Company"s parent be applied to repay amounts
outstanding under the Facility. The Facility matures on April 30, 2000 and
provides for an optional conversion to equity of Mariner Energy LLC by ENA. As
of December 31, 1998 the Company had applied push down accounting treatment and
reported the Mariner Energy LLC debt as a liability of the Company. Subsequent
to December 31, 1998, the Board of Directors of LLC resolved not to require the
use of cash flow from the Company's operations or sales of the Company's stock
or assets to repay the amounts outstanding under the Facility. Restrictions
under the Revolving Credit Facility and the 10-1/2% Senior Subordinated Notes
restricts the use of the Company's assets or cash flow to satisfy interest or
principal payments on the Facility. Consequently, the Company has reclassified
the ENA Credit Facility balance as of January 1, 1999, net of capitalized fees,
to equity. This reclassification was not included in the cash flow statement as
it represented a non-cash transaction.

SENIOR CREDIT FACILITY WITH ENA -- In April 1999, the Company
established a $25 million short-term credit facility with ENA to obtain funds
needed to execute the Company"s 1999 capital expenditure program and for
short-term working capital needs. The borrowing base under the short-term credit
facility is currently $25 million and is subject to periodic redetermination.
The facility accrues interest at an annual rate of LIBOR plus 2.5% and required
a structuring fee of 1% of the committed amount. The effective interest rate at
December 31, 1999 was 8.69%. The facility will mature on April 30, 2000 and is
expected to be repaid from a capital contribution from the Company's parent.
Accordingly, the facility has been classified as long-term debt as of December
31, 1999.

10 1/2% SENIOR SUBORDINATED NOTES -- On August 14, 1996 the Company
completed the sale of $100 million principal amount of 10"% 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 a bridge loan from JEDI incurred in the Acquisition, and (ii) repay
the Revolving Credit Facility. The Notes bear interest at 10"% 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.

35
<PAGE> 36

MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

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, 1999, 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 may 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.

Cash paid for interest for the years ending December 31, 1999, 1998 and
1997 was $15.1 million, $15.7 million and $10.9 million, respectively.

4. STOCKHOLDER'S EQUITY

STOCK OPTION PLAN -- During June 1996, Mariner Holdings established the
Mariner Holdings, Inc. 1996 Stock Option Plan (the "Plan") providing for the
granting of stock options to key employees and consultants. Options granted
under the Plan will not be less than the fair market value of the shares at the
date of grant. The maximum number of shares of Mariner Holdings common shares
that may be issued under the Plan was 142,800. In June 1998, the Plan was
amended to increase the number of eligible shares to be issued to 202,800. In
September 1998, concurrent with the exchange of each common share of Mariner
Holdings for twelve common shares of Mariner Energy LLC, the Plan was amended to
make Mariner Energy LLC the Plan sponsor. The maximum number of shares of common
shares that can be issued under the Plan was 2,433,600.

During the years ended December 31, 1999, 1998 and 1997, the Mariner
Energy LLC granted stock options ("Options") of 215,748, 329,172 and 73,080,
respectively. No options have been exercised or canceled during the three year
period. At December 31, 1999, options to purchase 2,228,304 shares had been
issued at an exercise price ranging from $8.33 to $14.58 per share. These
Options generally become exercisable as to one-fifth to one-third on each of the
first three or five anniversaries of the date of grant. The Options expire from
seven years to ten 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 Plan been determined based on the
fair value at the grant date for awards under the Plan consistent with the
method of SFAS No. 123, the Company"s net loss for the years ended December 31,
1999, 1998 and 1997 would have increased $1,172,000, $912,000 and $777,000,
respectively to $11,142,000, $59,333,000 and $20,987,000, respectively. The
effects of applying SFAS No. 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 6.46%, no
dividends and expected life of five years. Stock options available for future
grant amounted to 205,296 shares at December 31, 1999. Exercisable stock options
amounted to 1,211,882 shares at December 31, 1999.

CAPITAL CONTRIBUTION -- In March 2000, the Company received from
Mariner Energy LLC a cash contribution of approximately $30 million, which was
used to reduce accounts payable. This contribution was made from the proceeds
from Mariner Energy LLC's three year $112 million term loan with ENA. Due to
certain restrictions with the Company's Notes and Revolving Credit Agreement,
neither cash flow from operations or from assets sales would be available to
repay any portion of this term loan.

EQUITY INVESTMENT -- In June 1998, Mariner Holdings reached an agreement
with management shareholders and an affiliate of Enron to purchase common shares
of approximately $28.8 million of net equity capital, which was used to
supplement funding of the Company"s 1998 capital expenditure plan.

36
<PAGE> 37

MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

5. 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 1999, 1998 and
1997, the Company contributed $180,000, $182,000 and $200,000, respectively, to
the Plan. This plan is a continuation of a plan provided by the Predecessor
Company.

OVERRIDING ROYALTY INTERESTS -- Pursuant to agreements, certain key
employees and consultants are entitled to receive, as incentive compensation,
overriding royalty interests ("Overriding Royalty Interests") in certain oil and
gas prospects acquired by the Company. Such Overriding Royalty Interests entitle
the holder to receive a specified percentage of the gross proceeds from the
future sale of oil and gas (less production taxes), if any, applicable to the
prospects. Cash payments made by the Company under these agreements for the
three years ended December 31, 1999, 1998 and 1997 were $1.0 million, $1.0
million and $1.3 million, respectively.

6. 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, 1999 are as follows (in thousands):

<TABLE>
<S> <C>
2000 ............... $1,207
2001 ............... 1,110
2002 ............... 1,090
2003 ............... 1,077
2004 ............... 1,065
------
Total ........ $5,549
======
</TABLE>

Rental expense, before capitalization, was approximately $1,170,000,
$1,000,000 and $544,000 for the years ended December 31, 1999, 1998 and 1997,
respectively.

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

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

<TABLE>
<CAPTION>
Year Ended December 31,
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Natural gas quantity hedged (Mmbtu) ........................ 18,818 9,800 13,573
Increase (decrease) in natural gas sales (thousands) ....... $ (6,741) $ 2,337 $ (3,931)
Crude oil quantity hedged (MBbls) .......................... 389 0 118
Increase (decrease) in crude oil sales (thousands) ......... $ (2,152) $ 0 $ (614)
</TABLE>

37
<PAGE> 38

MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

The following tables set forth the Company"s position as of December 31,
1999.

<TABLE>
<CAPTION>
PRICE
NOTIONAL ---------------------------------------
TIME PERIOD QUANTITIES FLOOR CEILING FIXED FAIR VALUE
----------- ---------- ----- ------- ----- ----------
(in millions)
<S> <C> <C> <C> <C> <C>
NATURAL GAS (MMBTU)
January 1 - March 31, 2000
Collar purchased 5,460 $2.00 $ 2.70 --
Fixed price swap purchased 3,550 $ 2.18 (0.6)
Market sensitive swap sold (1,820) 2.60 (0.5)

April 1 - December 31, 2000
Collar purchased 2,263 2.25 $ 2.49 --
Fixed price swap purchased 7,445 2.18 (1.7)

January 1 - December 31, 2001
Fixed price swap purchased 4,501 2.18 (1.3)

January 1 - December 31, 2002
Fixed price swap purchased 1,831 2.18 (0.5)

CRUDE OIL (MBBLS)
January 1 - December 31, 2000
Fixed price swap purchased 1,482 18.66 (5.6)
</TABLE>

DEEPWATER RIG -- In the fourth quarter of 1999, Noble Drilling
Corporation filed suit against the Company alleging breech of contract regarding
a letter of intent for a five year Deepwater rig contract. In February 2000,
both the Company and Noble Drilling Corporation entered into a settlement
agreement whereby the Company committed to using this Deepwater rig for a
minimum of 660 days over a five-year period at market-based day rates for
comparable drilling rigs in comparable water depths subject to a floor day rate
ranging from $65,000 to $125,000. In exchange for market-based day rates, Noble
Drilling was assigned working interests in seven of the Company's deepwater
exploration prospects. The Company will pay Noble Drilling's share of the costs
of drilling the initial test well on each of these prospects.

LITIGATION -- In December, 1996, ETOCO, Inc., which owns a 20% interest
in one producing well operated by the Company, filed a lawsuit against the
Company in the district court of Hardin County, Texas, alleging damage due to
the Company"s refusal to drill an additional well. In April 1998, after a trial
on the merits, a jury awarded ETOCO $2.38 million in damages. In August 1998,
the court awarded ETOCO $0.5 million in attorneys" fees. On February 8, 1999,
the case was settled.

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

7. INCOME TAXES

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

<TABLE>
<CAPTION>
1999 1998 1997
---------------------- ---------------------- ----------------------

<S> <C> <C> <C> <C> <C> <C>
$ % $ % $ %
------- ------- ------- ------- ------- -------

Income (loss) before income taxes ........ (9,970) -- (58,421) -- (20,210) --

Income tax expense (benefit) computed
at statutory rates ....................... (3,490) (35) (20,447) (35) (7,074) (35)

Change in valuation allowance ............ 3,428 34 18,804 32 6,871 34

Other .................................... 62 1 1,643 3 203 1
------- ------- ------- ------- ------- -------

Tax Expense .............................. -- -- -- -- -- --
======= ======= ======= ======= ======= =======
</TABLE>

38
<PAGE> 39

MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

No federal income taxes were paid by the Company during the years ended
December 31, 1999, 1998 or 1997.

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.
Significant components of the deferred tax assets and liabilities are as follows
(in thousands):

<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------

<S> <C> <C> <C>
Deferred tax assets:

Net operating loss carry forwards ....................... $ 43,401 $ 34,771 $ 10,410

Differences between book and tax bases of properties .... -- -- 4,586
-------- -------- --------

43,401 34,771 14,996
-------- -------- --------

Valuation allowance .......................................... (36,130) (33,800) (14,996)

Total net deferred tax assets ................................ 7,271 971 --

Deferred tax liabilities --
Differences between book and tax bases of properties .... (7,271) (971) --
-------- -------- --------

Total net deferred taxes ........................... $ -- $ -- $ --
======== ======== ========
</TABLE>

As of December 31, 1999, the Company has a cumulative net operating loss
carryforward ("NOL") for federal income tax purposes of approximately $124
million, which begins to expire in the year 2012. A valuation allowance is
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.

39
<PAGE> 40

MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

8. OIL AND GAS PRODUCING ACTIVITIES AND CAPITALIZED COSTS

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

<TABLE>
<CAPTION>
Year ended Year ended Year ended
December 31, December 31, December 31,
1999 1998 1997
--------------- --------------- ---------------

<S> <C> <C> <C>
Oil and gas sales ................................... $ 52,468 $ 56,690 $ 62,771

Production costs .................................... (11,453) (9,858) (9,376)

Depreciation, depletion and amortization ............ (32,121) (33,833) (31,719)

Impairment of oil and gas properties ................ -- (50,800) (28,514)

Income tax expense .................................. -- -- --
--------------- --------------- ---------------

Results of operations ........................... $ 8,894 $ (37,801) $ (6,838)
=============== =============== ===============
</TABLE>

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

<TABLE>
<CAPTION>
Year ended Year ended Year ended
December 31, December 31, December 31,
1999 1998 1997
---------- ---------- ----------

<S> <C> <C> <C>
Property acquisition costs

Unproved properties ......................... $ 10,449 $ 43,143 $ 21,569

Proved properties ........................... -- -- 3,250

Exploration costs ................................ 13,522 35,674 27,364

Development costs ................................ 56,852 61,960 16,134
---------- ---------- ----------

Total costs .................................. $ 80,823 $ 140,777 $ 68,317
========== ========== ==========
Depreciation, depletion and amortization
rate per equivalent Mcf before impairment ........ $ 1.29 $ 1.40 $ 1.33
</TABLE>

The Company capitalizes internal costs associated with exploration
activities. These capitalized costs were approximately $9,440,000, $6,386,000
and $4,418,000 for the years ended December 31, 1999, 1998 and 1997,
respectively.

The following table summarizes costs related to unevaluated properties
which have been excluded from amounts subject to amortization at December 31,
1999. The Company regularly evaluates these costs to determine whether
impairment has occurred. The majority of these costs are expected to be
evaluated and included in the amortization base within three years.

40
<PAGE> 41

MARINER ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)

<TABLE>
<CAPTION>
Year ended Year ended Year ended Total at
December 31, December 31, December 31, December 31,
1999 1998 1997 1999
---------- ---------- ---------- ----------

<S> <C> <C> <C> <C>
Property
Acquisition costs ........ $ 10,993 $ 44,203 $ 20,827 $ 76,023

Exploration costs ......... 5,749 115 10 5,874
---------- ---------- ---------- ----------

Total ................. $ 16,742 $ 44,318 $ 20,837 $ 81,897
========== ========== ========== ==========
</TABLE>

Approximately 97% of excluded costs at December 31, 1999 relate to
activities in the Deepwater Gulf of Mexico and the remaining 3% relates to
activities in the Gulf of Mexico shallow waters and onshore areas near the Gulf.

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

Estimated proved net recoverable reserves as shown below include only
those quantities that are expected to be commercially recoverable at prices and
costs in effect at the balance sheet dates under existing regulatory practices
and with conventional equipment and operating methods. Proved developed reserves
represent only those reserves expected to be recovered through existing wells.
Proved undeveloped reserves include those reserves expected to be recovered from
new wells on undrilled acreage or from existing wells on which a relatively
major expenditure is required for recompletion. Also included in the Company"s
proved undeveloped reserves as of December 31, 1999 were reserves expected to be
recovered from wells for which certain drilling and completion operations had
occurred as of that date, but for which significant future capital expenditures
were required to bring the wells into commercial production.

Reserve estimates are inherently imprecise and may 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 in 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 are based. Actual results will differ, and are
likely to differ materially, from the results estimated.

41
<PAGE> 42

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

December 31, 1997 6,630 121,366
Revisions of previous estimates (836) (410)
Extensions, discoveries and other additions 4,351 27,416
Production (786) (19,477)
----------- ----------

December 31, 1998 9,359 128,895
---------- ---------
Revisions of previous estimates 715 (5,098)
Extensions, discoveries and other additions 1,225 24,972
Sale of reserves in place (742) (8,856)
Production (630) (21,123)
----------- ----------

December 31, 1999 9,927 118,790
========== =========
</TABLE>

Estimated Quantities of Proved Developed Reserves
(in thousands)

<TABLE>
<CAPTION>
Oil (Bbl) Gas (Mcf)
--------- ---------

<S> <C> <C>
December 31, 1997 3,486 76,343
December 31, 1998 2,886 86,024
December 31, 1999 3,799 82,760
</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.

42
<PAGE> 43

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

<TABLE>
<CAPTION>
Year ended December 31,
-------------------------------------------------
1999 1998 1997
--------- --------- ---------

<S> <C> <C> <C>
Future cash inflows ................................... $ 490,239 $ 383,490 $ 447,681

Future production costs ............................... (122,681) (103,400) (109,405)

Future development costs .............................. (70,774) (81,090) (73,568)

Future income taxes ................................... -- -- (35,346)
--------- --------- ---------

Future net cash flows ................................. 296,784 199,000 229,362

Discount of future net cash flows at 10% per annum .... (85,558) (51,371) (52,903)
--------- --------- ---------

Standardized measure of discounted future net cash
flows ................................................. $ 211,226 $ 147,629 $ 176,459
========= ========= =========
</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, 1999, 1998 and 1997, used
in the above table, were $23.85, $10.36 and $16.43 per Bbl, respectively, and
$2.23, $2.22 and $2.79 per Mcf, respectively, and do not include the effect of
hedging contracts in place at period end.

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,
-------------------------------------------------
1999 1998 1997
--------- --------- ---------

<S> <C> <C> <C>
Sales and transfers of oil and gas produced,
net of production costs ..................... $ (41,015) $ (46,832) $ (53,395)

Net changes in prices and production costs ....... 77,532 (67,815) (132,658)

Extensions and discoveries, net of
future development and
production costs ................................. 33,357 23,730 42,717

Development costs during period and net
change in development costs ...................... (3,661) 30,799 4,188

Revision of previous quantity estimates .......... (984) (6,846) (730)

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

Sales of reserves in place ....................... (15,535) -- --

Net change in income taxes ....................... -- 27,193 29,619

Accretion of discount before income taxes ........ 19,900 20,365 30,336

Changes in production rates (timing)
and other ........................................ (5,997) (9,424) (4,065)
--------- --------- ---------

Net change ....................................... $ 63,597 $ (28,830) $ (77,917)
========= ========= =========
</TABLE>

43
<PAGE> 44

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

None

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Set forth below are the names, ages and positions of our
executive officers and directors and a key consultant as of March 1, 2000. 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 47 Chairman of the Board, President and Chief Executive Officer
Richard R. Clark 44 Executive Vice President and Director
L. V. "Bud" McGuire 57 Senior Vice President of Operations
Michael W. Strickler 44 Senior Vice President of Exploration and Director
Frank A. Pici 44 Vice President of Finance and Chief Financial Officer
Gregory K. Harless 50 Vice President of Oil and Gas Marketing
W. Hunt Hodge 44 Vice President of Administration
Tom E. Young 41 Vice President of Land
David S. Huber 49 Consultant and Director of Deepwater Development
Raymond M. Bowen 44 Director
Richard B. Buy 47 Director
D. Brad Dunn 36 Director
Mark E. Haedicke 44 Director
Stephen R. Horn 41 Director
Jere C. Overdyke, Jr. 47 Director
Jeffrey B. Sherrick 45 Director
Frank Stabler 46 Director
</TABLE>

Mr. Henderson has been our Chairman of the Board since May 1996,
President and Chief Executive Officer since 1987 and a director since 1985. Mr.
Henderson served as a director of London-based Hardy Plc, our former parent
company, between 1989 and 1996. From 1984 to 1987, he served us or predecessors
as Vice President of Finance and Chief Financial Officer. From 1976 to 1984, he
held various positions with ENSTAR Corporation, including Treasurer of ENSTAR
Petroleum, which operated in the U.S. and Indonesia.

Mr. Clark has served us in various engineering and operations
activities since 1984 and has been Executive Vice President since May 1998. He
served as Senior Vice President of Production from 1991 until May 1998 and has
served as a director since 1988. Prior to joining us he worked as a Production
Engineer in the Offshore Production Group of Shell Oil Company.

Mr. McGuire joined us in June 1998 as Senior Vice President-Operations.
Prior to joining us, Mr. McGuire was Vice President-Operations for Enron Oil &
Gas International, Inc. Before joining EOGI, he served five years with
Kerr-McGee Corporation as Senior Vice President over worldwide production
operations. His experience prior to Kerr-McGee included Hamilton Oil Corporation
from 1981 to 1991, where he served as Deepwater Operations Manager then as Vice
President of Operations for Hamilton in the North Sea. He began his career in
1966 with Conoco.

Mr. Strickler joined us in 1984 and has served since such time in our
geological and exploration activities. He has served as Senior Vice President of
Exploration since 1991 and a director since 1989. Prior to joining us, Mr.
Strickler worked for several independent oil companies as an exploration
geologist, generating and evaluating exploration plays in the Gulf Coast, Mid
Continent, Rocky Mountains, West Texas and several overseas basins.

44
<PAGE> 45

Mr. Pici became Vice President of Finance and Chief Financial Officer
in December 1996. Prior to joining us, Mr. Pici was employed by Cabot Oil & Gas
Corporation holding several positions since 1989, including Corporate
Controller. Prior to joining Cabot Oil & Gas, he was Controller of an
independent oil & gas company, and he began his career with Coopers & Lybrand.
He is a Certified Public Accountant.

Mr. Harless has served as Vice President of Oil and Gas Marketing since
1990. Prior to joining us in 1988, he was Vice President of Marketing and
Regulatory Affairs of Enron Oil and Gas Company and District Operating Manager
with Coastal States Oil & Gas.

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

Mr. Young has served as Vice President of Land since November 1998.
Prior to his current position, Mr. Young served as Manager of Land for the
Central Gulf for approximately 10 years. Prior to joining us in 1985, Mr. Young
served as a landman for TXO Production Corp.

Mr. Huber, a consultant, began his association with us in 1991 as a
deepwater project management consultant and is presently our Director of
Deepwater Developments. Prior to joining us, Mr. Huber was employed by Hamilton
Oil Corporation in the North Sea from 1981 to 1991, holding 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. Bowen has served as a director since January 2000. He is currently
Managing Director of ENA and Co-Head of the Commercial Transactions Group and
has held various management positions with ENA since 1996. Prior to joining ENA,
Mr. Bowen was a Vice President and Senior Banker in Citicorp's Petroleum, Metals
and Mining Department in Houston.

Mr. Buy has served as a director since January 1998. Since 1994 he has
been an employee of ENA or its affiliates, currently serving as Senior Vice
President and Chief Risk Officer of Enron Corp. Prior to joining ENA Mr. Buy was
a Vice President at Bankers Trust in the Energy Group.

Mr. Dunn has served as a director since May 1999. He is a Vice
President of ENA and has held various positions with ENA since September 1994.
Before 1994, Mr. Dunn worked as a Petroleum Engineer with Delhi Gas Pipeline
Corporation and Mobil Oil Corporation.

Mr. Haedicke has served as a director since October 1998. He is
currently Managing Director, Legal, of ENA. Mr. Haedicke also serves on the
board of directors of the International Swaps and Derivatives Association, Inc.
and he holds a seat on the New York Mercantile Exchange. He has been associated
with ENA since its inception in 1990.

Mr. Horn has served as a director since November 1998. Since 1996, he
has been an employee and Vice President, Equity Investments, of ENA. Prior to
joining ENA, Mr. Horn was a principal in Yellowstone Energy Partners, a private
equity investing firm in Houston, Texas.

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

Mr. Sherrick has served as a director since January 2000. He is
currently the President and Chief Executive Officer of Enron Global Exploration
& Production Inc. and has held various management positions with Enron Oil & Gas
Company, or one of its affiliates, since 1993.

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

45
<PAGE> 46

The Shareholders' Agreement requires that the Board of Directors
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 -- The Acquisition, the Shareholders' Agreement and Related
Matters" on page 51.

ITEM 11. EXECUTIVE COMPENSATION

SUMMARY COMPENSATION TABLE

The following table sets forth the annual compensation for Mariner's
Chief Executive Officer and the four other most highly compensated executive
officers for the three fiscal years ended December 31, 1999. These individuals
are sometimes referred to as the "named executive officers".

Current Year
Annual Compensation Compensation
----------------------------------- Under our
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 1999 $285,000 $6,400 $5,438 $ 396
President and 1998 285,000 4,800 1,292 522
Chief Executive Officer 1997 255,000 6,000 1,904 315

Richard R. Clark 1999 225,000 6,400 3,508 243
Executive Vice President 1998 225,000 4,800 821 306
of Production 1997 185,000 6,000 1,205 306

Michael W. Strickler 1999 190,000 6,400 3,508 243
Senior Vice President 1998 182,000 4,800 821 306
of Exploration 1997 165,000 6,000 1,205 306

L. V. "Bud" McGuire (4) 1999 190,000 4,433 0 44,573
Senior Vice President 1998 110,834 0 0 788
of Operations 1997 0 0 0 0

Frank A. Pici 1999 160,000 6,400 2,043 243
Vice President of Finance and 1998 160,000 4,380 356 306
Chief Financial Officer 1997 146,000 2,747 152 306
</TABLE>

(1) Amounts shown reflect our 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) These amounts include the value conveyed during the applicable year
attributable to overriding royalty interests assigned to the named executive
officer during the applicable year and distributions received, if any, during
the applicable year attributable to overriding royalty interests assigned to the
named executive officers during the applicable year. For information on
overriding royalty payments received during the applicable year attributable to
overriding royalty interests assigned to the named executive officer during past
years, see the table below under "--Overriding Royalty Program." These amounts
also do not include amounts received during the applicable year as a result of
sales of overriding royalty interests by individuals, normally in connection
with sales of properties by us. No such sales were made in 1999, 1998 or 1997.

(3) Amounts shown reflect insurance premiums paid by us with respect to
term life insurance for the benefit of the named executive officers and any
performance bonuses paid during the year.

(4) Mr. McGuire joined us in June 1998 and is eligible for guideline
bonuses and incentive stock option awards under our incentive compensation plan.
He does not participate in the Overriding Royalty Program.

OPTIONS

Mariner Energy LLC granted 48,624 options to purchase common shares to
Mr. McGuire in 1999. None of the named executive officers exercised stock
options in 1999. The following table shows the number and value of options
owned by our named executive officers at December 31, 1999. All of the options
described in the table below have

46
<PAGE> 47

been issued under the Mariner Energy LLC 1996 Stock Option Plan.

<TABLE>
<CAPTION>
NUMBER OF
COMMON SHARES UNDERLYING
UNEXERCISED OPTIONS AT
DECEMBER 31, 1999
-----------------------------
EXERCISABLE UNEXERCISABLE
----------- -------------
<S> <C> <C>
Robert E. Henderson................ 143,172 95,448
Richard R. Clark................... 100,757 67,171
L. V. "Bud" McGuire................ 36,480 121,584
Michael W. Strickler............... 100,757 67,171
Frank A. Pici...................... 29,232 43,848
</TABLE>

SHARE OPTION PLAN

Under the Mariner Energy LLC 1996 Stock Option Plan, a committee of the
board of directors is authorized to grant options to purchase common shares,
including options qualifying as "incentive stock options" under Section 422 of
the Internal Revenue Code and options that do not so qualify, to employees and
consultants as additional compensation for their services to us. The 1996 plan
is intended to promote our long term financial interests by providing a means by
which designated employees and consultants may develop a sense of proprietorship
and personal involvement in our development and financial success. We believe
that this encourages them to remain with and devote their best efforts to our
business and to advance the mutual interests of us and our shareholders. A total
of 2,433,600 common shares may be issued under options granted under the 1996
plan, subject to adjustment for any share split, share dividend or other change
in the common shares or our capital structure. Options to purchase 2,228,304
common shares are outstanding under the 1996 plan, 1,211,882 of which are
currently exercisable. The exercise price for outstanding options to purchase an
aggregate of 1,683,386 shares under the 1996 plan is $8.33 per share, and the
exercise price for options to purchase the remaining outstanding aggregate of
544,920 shares under the 1996 plan is $14.58 per share. Subject to the
provisions of the 1996 plan, the compensation committee is authorized to
determine who may participate in the 1996 plan, the number of shares that may be
issued under each option granted under the 1996 plan, and the terms, conditions
and limitations applicable to each grant. Subject to some limitations, the board
of directors of Mariner Energy LLC is authorized to amend, alter or terminate
the 1996 plan.

EMPLOYMENT AGREEMENTS

We and each of the named executive officers are parties to employment
agreements that expire on September 30, 2002. Following the expiration date of
an employment agreement or the expiration of any extended term, the employment
agreements extend for six months, unless notice of termination is given by
either us or the named executive officer at least six months before the end of
the initial term or extended term, as applicable.

Under the employment agreements, the current annual salaries are
$285,000 for Mr. Henderson, $225,000 for Mr. Clark, $190,000 for Mr. Strickler,
$190,000 for Mr. McGuire and $160,000 for Mr. Pici. Our board of directors may
in its discretion increase their salaries.

The named executive officers are entitled to participate in any
medical, dental, life and accidental death and dismemberment insurance programs
and retirement, pension, deferred compensation and other benefit programs
instituted by us from time to time. The employees are also entitled to vacation,
reimbursement of specified expenses and, depending on the employment agreement,
an automobile allowance and reimbursement for expenses related to the use of
that vehicle. As incentive compensation, the named executive officers, except
for Mr. McGuire, are entitled to receive overriding royalty interests in some
oil and gas prospects that we have acquired under our overriding royalty
program. Mr. McGuire is entitled to receive annual cash bonuses and incentive
stock option awards under an incentive compensation plan separate from other
named executive officers.

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<PAGE> 48

If we terminate a named executive officer's employment agreement
without cause, if the named executive officer terminates his employment contract
for good reason, or if we give notice of termination on the expiration of his
term of employment, then the named executive officer will be entitled to, among
other things:

o the value of his salary and other benefits through the end of
the initial term or any extended term of the employment
agreement;

o a lump sum cash payment equal to 12 months salary in the case
of Mr. Henderson, nine months salary in the case of Messrs.
Clark, Strickler and McGuire and six months salary in the case
of Mr. Pici plus, in the case of Mr. McGuire, an amount equal
to 40% of nine months salary;

o a lump sum cash payment equal to all earned and unused
vacation time for the previous year and the then current year;

o an assignment of his vested interests under our overriding
royalty program, if eligible; and

o in the case of Mr. McGuire, a lump sum payment equal to any
unpaid bonus from prior years under our incentive compensation
plan, plus, in lieu of any bonus for subsequent years, an
amount equal to 40% of his base salary through the end of the
remaining term of his employment agreement.

If a named executive officer's employment agreement is terminated by
the named executive officer without good reason, the named executive officer
gives notice of termination on the expiration of his term of employment or if we
consent to a request by the named executive officer to terminate his employment
agreement before the expiration of his term, he will be entitled to:

o the value of his salary and benefits through the date that his
employment agreement is terminated;

o a lump sum cash payment equal to all earned and unused
vacation time for the previous year and the then current year;

o an assignment of his vested interests in our overriding
royalty program through the date of termination, if eligible;
and

If a named executive officer's employment agreement is terminated by us
for cause, we will have no obligation to that employee other than to:

o pay his salary through the day of termination;

o pay him the value of his benefits under the employment
agreement through the month of termination; and

o assign to him his vested interests in our overriding royalty
program through the date of termination, if eligible.

To the extent any amounts paid under an employment agreement are
subject to the "golden parachutes" excise tax, those amounts are grossed-up to
cover the excise tax and any applicable taxes on the gross-up amount.

Each named executive officer has agreed that during the term of his
employment agreement, and, if the named executive officer's employment agreement
is terminated by us for cause or terminated by the named executive officer other
than for good reason, for 12 months after the term expires in the case of
Messrs. Henderson, Clark, Strickler and McGuire and six months after the term
expires in the case of Mr. Pici, he will not compete with us for business or
hire away our employees.

For purposes of the employment agreements with the named executive
officers, "good reason" means:

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<PAGE> 49

o The assignment to the employee of any duties materially
inconsistent with the employee's position, authority, duties
or responsibilities with us or any other action that results
in a material diminution in, or interference with, such
position, authority, duties or responsibilities, if the
assignment or action is not cured within 30 days after the
employee has provided us with written notice;

o The failure to continue to provide the employee with office
space, related facilities and support personnel (a) that are
commensurate with the employee's responsibilities to, and
position with, us and not materially dissimilar to the office
space, related facilities and support personnel provided to
our other employees having comparable responsibilities or (b)
that are physically located at our principal executive
offices, if that failure is not cured within 30 days after the
employee has provided us with written notice;

o Any (a) reduction in the employee's monthly salary, (b)
reduction in, discontinuance of, or failure to allow or
continue to allow the employee's participation in, our
incentive compensation program, or (c) reduction in, or
failure to allow or continue the employee's participation in,
any employee benefit plan in which the employee is
participating or is eligible to participate before the
reduction or failure, and that reduction, discontinuance or
failure is not cured within 30 days after the employee has
provided us with written notice;

o The relocation of the employee's or our principal office and
principal place of the employee's performance of his duties
and responsibilities to a location more than 50 miles outside
of the central business district of Houston, Texas; or

o A breach of any material provision of the employment agreement
that is not cured within 30 days after the employee has
provided us with written notice.

CHANGE OF CONTROL AGREEMENTS

We are in the process of completing each of the named executive
officers' change of control agreements. Under these agreements, if a change of
control occurs and the named executive officer's employment is terminated
without cause or for good reason within 18 months of the change of control,
Messrs. Henderson, Clark, McGuire, Pici and Strickler are entitled to receive,
if the change in control is due to an acquisition of us by another company,
three and one-half times their base salary and targeted annual incentive bonus,
if applicable. The severance payment will be calculated assuming we satisfy the
applicable base target for a particular year for the targeted annual incentive
bonus. The ultimate payment due under the change of control agreements will be
the greater of the payment calculated under the change of control agreements or
the compensation due for the remaining balance under the employment agreements.
To the extent any amounts paid under the change in control agreemens are subject
to the "golden parachutes" excise tax, those amounts are grossed-up to cover the
excise tax and any applicable taxes on the gross-up amount. We expect these
agreements to be finalized in April 2000.

OVERRIDING ROYALTY PROGRAM

Employees participating in our overriding royalty program receive
incentive compensation in the form of overriding royalty interests in some of
the oil and natural gas prospects we acquired. The aggregate overriding royalty
interests do not exceed 1.5% of our working interest in these prospects before
well payout or 6% of our working interest in these prospects after payout. An
employee receives overriding royalty interests equal to specified undivided
percentages of our working interest percentage in prospects we acquired within
the United States and U.S. coastal waters during the term of the employee's
employment.

The overriding royalty interest percentage of our working interest to
which each named executive officer is entitled for the period before well payout
is one-fourth of the overriding royalty interest percentage for the period after
well payout. These percentages currently range from 0.09375% to 0.23250% before
payout and from 0.37500% to 0.93000% after payout for the named executive
officers.

If all or a portion of our working interest in a prospect is sold or
farmed out to unaffiliated third parties and we determine in good faith that our
interest will not be marketable on satisfactory terms if marketed subject to the
named executive officer's overriding royalty interest affecting the prospect, we
may adjust the named executive officer's overriding royalty interest in the
prospect. These adjustments are determined by a committee designated by our
board of directors, at least half of the members of which are individuals who
have been granted an overriding royalty interest by us. Some

49
<PAGE> 50

committee decisions require the approval of our board of directors. These
adjustments apply only to the portion of our working interest sold or farmed out
to a third party and do not affect the named executive officer's overriding
royalty interest in the portion of a prospect retained by us.

We may also elect, within 60 days after the end of our fiscal year, to
reduce a named executive officer's overriding royalty interest in prospects that
we acquired during the fiscal year. We must base these reductions on the levels
of exploration and development costs related to these prospects actually
incurred during the fiscal year. With respect to certain deepwater prospects, we
also may elect, in our sole discretion, to make other reductions and adjustments
to the employee's overriding royalty interest based on estimated exploration
levels and development costs to be incurred in connection with these deepwater
prospects. We retain a right of first refusal to purchase any overriding royalty
interest assigned to a named executive officer. This right applies to any
third-party offer received by the named executive officer during or within one
year after the named executive officer's employment is terminated.

The following table shows distributions received during the applicable year
by the named executive officers who are participants in the plan, some of which
were paid by third parties, from overriding royalty interests we granted to the
officers during the last 15 years.

<TABLE>
<CAPTION>
AGGREGATE CASH AMOUNTS RECEIVED
FROM PREVIOUSLY ASSIGNED OVERRIDING
ROYALTY INTERESTS(1)
-------------------------------------------
NAME 1999 1998 1997
------------------- ---- ---- ----
<S> <C> <C> <C>
Robert E. Henderson............. $227,054 $354,857 $ 394,136
Richard R. Clark................ 137,774 218,077 237,982
Michael W. Strickler............ 131,103 212,803 234,603
Frank A. Pici................... 1,093 0 0
</TABLE>

- ----------

(1) For information on the value conveyed and distributions received, if any,
during the applicable year attributable to overriding royalty interests
assigned to the named executive officer during the applicable year, see the
table under " -- Summary Compensation Table."

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Mariner is an indirect wholly owned subsidiary of Mariner Energy LLC.
The following table sets forth the name and address of the only shareholder of
Mariner Energy LLC that is known by the Company to beneficially own more than 5%
of the outstanding common shares of Mariner Energy LLC, the number of shares
beneficially owned by such shareholder, and the percentage of outstanding shares
of common shares of Mariner Energy LLC so owned, as of March 1, 1999. As of
March 1, 2000, there were 13,928,304 common shares of Mariner Energy LLC
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 13,334,184 95.7%
Mariner Energy LLC 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
ENA, which is a wholly-owned subsidiary of Enron Corp. The general partner of
JEDI exercises sole voting and investment power with respect to such shares.

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<PAGE> 51

The table appearing below sets forth information as of March 1, 2000,
with respect common shares of Mariner Energy LLC beneficially owned by each of
our directors, our named officers listed in the compensation table, a key
consultant and all directors and executive officers and such key consultant as a
group, and the percentage of outstanding common shares of Mariner Energy LLC 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...................... 84,840 *

Richard R. Clark......................... 61,440 *

L. V. "Bud" McGuire...................... 6,000 *

Michael W. Strickler..................... 61,440 *

Frank A. Pici............................ 20,472 *

David S. Huber........................... 61,440 *

Raymond M. Bowen......................... 0 *

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

D. Brad Dunn............................. 0 *

Mark E. Haedicke......................... 0 *

Stephen R. Horn.......................... 0 *

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

Jeffrey B. Sherrick...................... 0 *

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

All directors and executive officers and
key consultant as a group (17 persons).... 347,388 2.49%
</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.

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<PAGE> 52

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

THE ACQUISITION, THE SHAREHOLDERS" AGREEMENT AND RELATED MATTERS

Mariner Energy LLC, JEDI and each other shareholder of Mariner are
parties to the Amended and Restated Shareholders" Agreement (as amended, the
"Shareholders" Agreement").

Mariner Energy LLC has agreed to reimburse each Management Shareholder
who paid for equity in Mariner"s predecessor by assignment of overriding royalty
interests for any additional taxes and related costs incurred by such Management
Shareholder 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.

ENRON AND AFFILIATES

Enron is the parent of ENA, and an affiliate of Enron and ENA is the
general partner of JEDI. Accordingly, Enron may be deemed to control JEDI and
us. See "Ownership of Securities". In addition, eight of the Company"s directors
are officers of Enron or of affiliates of Enron: Mr. Buy is Senior Vice
President and Chief Risk Officer of Enron Corp., Mr. Haedicke is a Managing
Director of ENA, Mr. Dunn is a Vice President of ENA, Mr. Bowen is a Managing
Director of ENA and Co-Head of the Commercial Transactions Group, Mr. Sherrick
is President and Chief Executive Officer of Enron Global Exploration and
Production, Inc., Mr. Horn is a Vice President of ENA, Mr. Overdyke is Managing
Director of ENA, and Mr. Stabler is the President and Chief Operating Officer of
Enron Caribbean Basin.

Enron and certain of its subsidiaries and other affiliates collectively
participate in nearly all phases of the oil and natural gas industry and,
therefore, compete with Mariner. In addition, ENA, JEDI and other affiliates of
ENA have provided, and may in the future provide, and ECT Securities Limited
Partnership, another affiliate of Enron, 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 Mariner. Because of
these various possible conflicting interests, the Shareholders' Agreement
includes provisions designed to clarify that generally Enron and its affiliates
have no duty to make business opportunities available to Mariner and no duty to
refrain from conducting activities that may be competitive with us.

Under the terms of the Shareholders' Agreement, Enron and its
affiliates (which include, without limitation, ENA and JEDI) are specifically
permitted to compete with Mariner, and neither Enron nor any of its affiliates
has any obligation to bring any business opportunity to Mariner.

Under the Revolving Credit Facility, Mariner has covenanted that it
will not engage in any transaction with any of its affiliates (including Enron,
ENA, JEDI and affiliates of such entities) providing for the rendering of
services or sale of property unless such transaction is as favorable to such
party as could be obtained in an arm"s-length transaction with an unaffiliated
party in accordance with prevailing industry customs and practices. The
Revolving Credit Facility excludes from this covenant (i) any transaction
permitted by the Shareholders" Agreement, (ii) the grant of options to purchase
or sales of equity securities to directors, officers, employees and consultants
of Mariner and (iii) the assignment of any overriding royalty interest pursuant
to an employee incentive compensation plan.

The Indenture, dated as of August 1, 1996, between Mariner and United
States Trust Company of New York (the "Indenture"), under which the Senior
Subordinated Notes were issued, contains similar restrictions. Under the
Indenture, Mariner Energy, Inc. has covenanted not to engage in any transaction
with an affiliate unless the terms of that transaction are no less favorable to
Mariner than could be obtained in an arm"s-length transaction with a
nonaffiliate. Further, if such transaction involves more than $1 million, it
must be approved in writing by a majority of Mariner"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 Mariner. 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
Mariner"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) certain prior transactions.

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<PAGE> 53

Mariner 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, Mariner has entered into
several agreements with Enron or affiliates of Enron for the purpose of hedging
oil and natural gas prices on Mariner"s future production. Mariner 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 Mariner than would be
contained in an agreement with a third party.

1998 EQUITY INVESTMENT

In June 1998, Mariner Holdings issued additional equity to its existing
shareholders, including JEDI, for approximately $14.58 per share, for an
aggregate investment of $30.0 million (the "1998 Equity Investment"). We paid
approximately $1.2 million as a structuring fee, on a pro rata basis, to
existing shareholders participating in this transaction. Approximately $1.0
million of this fee was paid to ECT Securities Corp., an affiliate of JEDI.

MARINER ENERGY LLC CREDIT FACILITY WITH ENA

Our parent established the ENA Credit Facility to provide us with
additional capital. The ENA Credit Facility provides for unsecured, subordinated
loans to our parent up to $50 million, bearing interest at LIBOR plus 4.5%,
at maturity. The full amount available under this credit facility had been
drawn as of December 31, 1999. Our parent paid a structuring fee equal to 4% of
the principal amount of the borrowing. This agreement is expected to be repaid
in full at maturity on April 30, 2000 with proceeds from a new three year term
loan between Mariner Energy LLC and ENA.

SENIOR CREDIT FACILITY WITH ENA

In April 1999, we established a $25 million borrowing-based, short-term
credit facility with ENA to obtain funds needed to execute our 1999 capital
expenditure program and for short-term working capital needs. This facility's
maturity was extended from December 31, 1999 to April 30, 2000 and is expected
to be repaid through a capital contribution from Mariner Energy LLC. We paid ENA
a structuring fee equal to 1% of the principle amount.

CAPITAL CONTRIBUTION

In March 2000, we received from Mariner Energy LLC a cash contribution
of approximately $30 million, which was used to reduce accounts payable. This
contribution was made from the proceeds from Mariner Energy LLC's three year
$112 million term loan with ENA. Due to certain restrictions with the Company's
Indenture and Revolving Credit Agreement, neither cash flow from operations or
from assets sales would be available to repay any portion of this term loan.

FIRM TRANSPORTATION CONTRACT

In 1999 we constructed a 29 mile flowline from a third party platform
to the Mississippi Canyon 718 subsea well. After commissioning the flowline,
MEGS LLC, an Enron affiliate, purchased the flowline from us and our joint
interest partners. We received $8.8 million in cash proceeds which were offset
against the cost of constructing the flowline. No gain or loss was recognized.
In addition, we entered into a firm transportation contract with MEGS LLC at a
rate of $0.26 per Mcf to transport our share of 86 Bcf of natural gas from the
commencement of production through March 2009. Our working interest at December
31, 1999 was 37% and will increase to 51% after the project reaches payout.

53
<PAGE> 54

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 * have been previously filed on last
years Form 10-K. All exhibits not so designated are incorporated by
reference to a prior filing as indicated.

Exhibits designed by the symbol ** are filed with this Annual Report on
Form 10-K.

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* Amended and Restated Certificate of Incorporation of the
Registrant, as amended.

3.2* Bylaws of Registrant, as amended.

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

4.2(d) First Amendment to Indenture, dated as of January 31, 1998,
between the Registrant and United States Trust Company of New
York, as Trustee.

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

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 Toronto
Dominion (Texas), Inc.

4.5(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.

4.6(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.

4.7(a) Form of the Registrant's 10"% Senior Subordinated Note Due
2006, Series B.

4.8* Credit and Subordination Agreement dated as of September 2,
1998 between Mariner Holdings, Inc. and Enron Capital & Trade
Resources Corp.

4.9(f) Amended and Restated Credit Agreement, dated June 28, 1999,
among Mariner Energy, Inc., NationsBank of Texas, N.A., as
Agent, Toronto Dominion (Texas), Inc., as Co-agent, and the
financial institutions listed on schedule 1 thereto.

4.10(f) Second Amended and Restated Credit Agreement, dated as of
April 15, 1999, between Mariner Energy LLC and Enron North
America Corp. (formerly Enron Capital & Trade Resources
Corp.).

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<PAGE> 55

4.11(f) Revolving Credit Agreement dated as of April 15, 1999, between
Mariner Energy, Inc. and Enron North America Corp. (formerly
Enron Capital & Trade Resources Corp.).

10.1* Amended and Restated Shareholders" Agreement, dated October
12, 1998, among Mariner Energy LLC, Enron Capital & Trade
Resources Corp., Mariner Holdings, Inc., Joint Energy
Development Investments Limited Partnership and the other
shareholders of Mariner Energy LLC.

10.3(f) Amended and Restated Credit Agreement, dated June 28, 1999,
between Mariner Energy and Bank of America, N.A.

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*" Amended and Restated Employment Agreement, dated January 1,
1997, between the Registrant and Tom E. Young.

10.8*" Amended and Restated Employment Agreement, dated December 27,
1998, between the Registrant and Gregory K. Harless.

10.9*" Amended and Restated Employment Agreement, dated December 27,
1998, between the Registrant and W. Hunt Hodge.

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

10.11(a)" Mariner Holdings, Inc. 1996 Stock Option Plan (assumed by
Mariner Energy LLC).

10.12(a)" Form of Incentive Stock Option Agreement (pursuant to the
Mariner Holdings, Inc. 1996 Stock Option Plan, assumed by
Mariner Energy LLC).

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

10.14(a)" Form of Nonstatutory Stock Option Agreement (pursuant to the
Mariner Holdings, Inc. 1996 Stock Option Plan, assumed by
Mariner Energy LLC).

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

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

10.17*" Amended and Restated Employment Agreement, dated as of
December 1, 1998, between the Registrant and Frank A. Pici.

10.18*" Amended and Restated Employment Agreement, dated as of June 1,
1998, between the Registrant and L.V. Bud McGuire.

10.19(e) Third Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and Richard R. Clark.

10.20(e) Fourth Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and Gregory K. Harless.

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<PAGE> 56

10.21(e) Third Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and Robert E. Henderson.

10.22(e) Fourth Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and William Hunt Hodge.

10.23(e) First Amendment to Amended and Restated Consulting Services
Agreement, effective as of October 1, 1999, between Mariner
Energy, Inc. and David S. Huber.

10.24(e) First Amendment to Employment Agreement, effective as of
October 1, 1999, between Mariner Energy, Inc. and L.V.
McGuire.

10.25(e) Third Amendment to Employment Agreement, effective as of
October 1, 1999, between Mariner Energy, Inc. and Frank A.
Pici.

10.26(e) Fourth Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and Michael W. Strickler.

10.27(e) First Amendment to Amended and Restated Employment Agreement,
effective as of October 1, 1999, between Mariner Energy, Inc.
and Thomas E. Young.

10.28** Gas Gathering Agreement, dated December 29, 1999 between MEGS,
LLC and Mariner Energy, Inc. and Burlington Resources, Inc.

10.29** First Amendment to Amended and Restated Credit Agreement,
dated December 31, 1999 by and among Mariner Energy, Inc.,
Bank of America, N.A., Toronto Dominion (Texas), Inc., Bank of
Nova Scotia, and ABN-AMRO Bank, N.V.

23.1** Consent of Ryder Scott Company.

23.2** Ryder Scott Company Letter of Estimated Proved Reserves dated
March 07, 2000

27.1** Financial Data Schedule.

- --------------------------
(a) Incorporated by reference to the Company"s Registration Statement on
Form S-4 (Registration No. 333-12707), filed September 25, 1996.

(b) Incorporated by reference to Amendment No. 1 to the Company"s
Registration Statement on Form S-4 (Registration No. 333-12707), filed
December 6, 1996.

(c) Incorporated by reference to Amendment No. 2 to the Company"s
Registration Statement on Form S-4 (Registration No. 333-12707), filed
December 19, 1996.

(d) Incorporated by reference to the Company"s Annual Report on Form 10-K
for the year ended December 31, 1996 (Registration No. 333-12707) filed
March 31, 1997.

(e) Incorporated by reference to the Mariner Energy LLC November 4, 1999
filing on Forms S-1 (Registration No. 333-87287).

(f) Incorporated by reference to the Mariner Energy, Inc. March 31, 1999,
June 30, 1999 or September 30, 1999 quarterly filings on Form 10-Q.

(b) REPORTS ON FORM 8-K:

The Company filed no reports on Form 8-K during the quarter ended
December 31, 1999.

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<PAGE> 57

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.

"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".

57
<PAGE> 58

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

Mcf. One thousand cubic feet of natural gas.

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

MMBTU. One million British thermal units.

Mmcf. One million cubic feet of natural gas.

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

NYMEX. New York Mercantile Exchange.

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

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

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

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

"proved reserves" The estimated quantities of crude oil, natural gas
and other hydrocarbon liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.

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

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

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

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<PAGE> 59

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

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

59
<PAGE> 60

SIGNATURES

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

March 30, 2000

MARINER ENERGY, INC.

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

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

<TABLE>
<CAPTION>
Signature Title Date
- --------- ----- ----

<S> <C> <C>
/s/ Robert E. Henderson Chairman of the Board, President and March 29, 2000
- -------------------------------------- Chief Executive Officer
Robert E. Henderson (Principal Executive Officer)

/s/ Frank A. Pici Vice President of Finance and March 29, 2000
- -------------------------------------- Chief Financial Officer
Frank A. Pici (Principal Financial Officer and Principal
Accounting Officer)

/s/ Richard R. Clark Director and Executive Vice President March 29, 2000
- --------------------------------------
Richard R. Clark

/s/ L. V. "Bud" McGuire Director and Senior Vice President
- -------------------------------------- of Operations March 29, 2000
L. V. "Bud" McGuire

/s/ Michael W. Strickler Director and Senior Vice President
- -------------------------------------- of Exploration March 29, 2000
Michael W. Strickler

/s/ Richard B. Buy Director March 29, 2000
- --------------------------------------
Richard B. Buy

/s/ Mark E. Haedicke Director March 29, 2000
- --------------------------------------
Mark E. Haedicke

/s/ Stephen R. Horn Director March 29, 2000
- --------------------------------------
Stephen R. Horn

/s/ Raymond M. Bowen Director March 29, 2000
- --------------------------------------
Raymond M. Bowen

/s/ D. Brad Dunn Director March 29, 2000
- --------------------------------------
D. Brad Dunn

/s/ Jere C. Overdyke, Jr. Director March 29, 2000
- --------------------------------------
Jere C. Overdyke, Jr.

/s/ Frank Stabler Director March 29, 2000
- --------------------------------------
Frank Stabler

/s/ Jeffrey B. Sherrick Director March 29, 2000
- --------------------------------------
Jeffrey B. Sherrick
</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

<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------ -----------

<S> <C>
10.13** List of executive officers who are parties to an Incentive
Stock Option Agreement.

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

10.28** Gas Gathering Agreement, dated December 29, 1999 between MEGS,
LLC and Mariner Energy, Inc. and Burlington Resources, Inc.

23.1** Consent of Ryder Scott Company.

23.2** Ryder Scott Company Letter of Estimated Proved Reserves dated
March 07, 2000

27.1** Financial Data Schedule.
</TABLE>

<PAGE> 1
EXHIBIT 10.13

Executive Officers who are Parties
to an Incentive Stock Option Agreement

<TABLE>
<CAPTION>
Number of Shares of Mariner
Energy LLC, Common Stock
Executive Officer Subject to Stock Option Agreement
----------------- ---------------------------------

<S> <C>
Robert E. Henderson 60,000
Richard R. Clark 60,000
Michael W. Strickler 60,000
L. V. McGuire 34,282
Frank A. Pici 60,000
Thomas A. Young 30,840
Gregory K. Harless 30,840
W. Hunt Hodge 60,000
------

Totals 395,962
=======
</TABLE>

<PAGE> 1
EXHIBIT 10.15

Executive Officers who are Parties
to an Nonstatutory Stock Option Agreement

<TABLE>
<CAPTION>
Number of Shares of Mariner
Energy LLC, Common Stock
Executive Officer Subject to Stock Option Agreement
----------------- ---------------------------------

<S> <C>
Robert E. Henderson 178,620
Richard R. Clark 107,928
Michael W. Strickler 107,928
L. V. McGuire 123,782
Frank A. Pici 13,080
W. Hunt Hodge 13,080
David S. Huber 162,576
-------

Totals 706,994
=======
</TABLE>

<PAGE> 1
EXHIBIT 10.28

GAS GATHERING AGREEMENT

THIS GAS GATHERING AGREEMENT (this "Agreement"), dated December 29,
1999 (the "Effective Date"), is by and between MEGS, L.L.C., a Delaware limited
liability company ("Gatherer"), and MARINER ENERGY, INC., a Delaware corporation
("Mariner") and BURLINGTON RESOURCES OFFSHORE INC., a Delaware corporation
("BROI"), and BURLINGTON RESOURCES TRADING INC., a Delaware corporation
("BRTI"). BROI and BRTI are referred to herein collectively as "Burlington."
Burlington and Mariner are referred to herein individually as a "Shipper" and
collectively as the "Shippers." Gatherer and both Shippers together are
sometimes referred to herein individually as a "Party" and collectively as the
"Parties."

R E C I T A L S :

A. Shippers have certain quantities of Gas and Condensate available
from Mississippi Canyon Blocks 673, 674, 717, and 718, offshore Louisiana.

B. Shippers have requested Gatherer to receive such quantities of Gas
and Condensate on a firm basis at Shippers' subsea production facilities in
Mississippi Canyon Block 674 and redeliver such quantities of Gas and Condensate
to Marathon Oil Company's production platform in South Pass Block 89.

C. Gatherer desires to receive, gather, and deliver, or cause the
delivery of, such Gas and Condensate, for the consideration and on the other
terms and conditions hereinafter set forth.

NOW, THEREFORE, Gatherer and Shippers do hereby agrees as follows:

1
<PAGE> 2

ARTICLE 1
DEFINITIONS

1. Defined Terms. As used herein, including the exhibits hereto, the
following terms shall have the meanings defined below:

"Affiliate" means any person that directly Controls, is Controlled by,
or is under common Control with the person or Party in question.

"Aggregate Dollar Commitment" means $33,602,055 less the aggregate
amount of Third Party Gathering Net Proceeds received by Gatherer.

"Annual Excess Payments" means, for each Shipper in any Contract Year,
the amount, if any, by which the aggregate Monthly Payments paid by that Shipper
for each Month in that Contract Year (as reduced by amounts credited against
Monthly Payments by that Shipper under Section 2 of Article 9) exceed the
aggregate Minimum Dollar Commitments for that Shipper for each Month in that
Contract Year. An example calculation of Annual Excess Payments is attached
hereto as Exhibit D.

"British Thermal Unit" or "Btu" means the amount of heat required to
raise the temperature of one (1) pound of water one degree (1 Degrees)
Fahrenheit at sixty degrees (60 Degrees) Fahrenheit.

"Condensate" means the liquid hydrocarbons having an API gravity not
less than twenty degrees (20 Degrees) and not more than sixty degrees
(60 Degrees).

"Contract Year" means each period of 365 consecutive days beginning on
the Effective Date, but any such period which contains a date of February 29
shall consist of 366 days.

"Control" means the ownership, directly or indirectly, of fifty percent
(50%) or more of the outstanding voting securities of an entity or the power or
authority, through the ownership of voting securities, by contract or otherwise,
to direct the management, activities, or policies of the entity.

"Crediting Account" means the account established by Gatherer for each
Shipper as of the date of this Agreement to track, record, and account for
certain amounts under this

2
<PAGE> 3

Agreement. The Crediting Account for each Shipper shall be deemed to have a zero
balance as of the Effective Date. The balance in the Crediting Account shall be
(i) increased, as of the last day of each Contract Year, by the amount, if any,
by which aggregate Monthly Payments paid by that Shipper in that Contract Year
exceed the aggregate Monthly Gathering Fees for that Shipper in that Contract
Year and (ii) decreased, as of the last day of each Month, for the portion of
the Monthly Payment for that Shipper satisfied from the Crediting Account that
Month under Section 2 of Article 9.

"Day" means a period of twenty-four (24) consecutive hours, beginning
and ending at 7:00 a.m. Central Prevailing Time ("CPT").

"Dedicated Reserves" means all hydrocarbon reserves owned or controlled
by each Shipper, or their respective permitted successors or assigns, in
Mississippi Canyon Blocks 673, 674, 717, and 718, offshore Louisiana.

"Gas" means methane and other gaseous hydrocarbons including gaseous
combustible, noncombustible, and inert elements, compounds, components or
mixtures thereof and liquefiable hydrocarbons in the vapor stream produced at
the wellhead.

"Gathering Rate" means (i) until the date on which the aggregate amount
of the Monthly Payments that Shippers have paid to Gatherer under Article 9,
Section 1 of this Agreement equals or exceeds the Aggregate Dollar Commitment,
$0.2575 per MMBtu and (ii) thereafter, $0.05 per MMBtu.

"Gathering System" means Gatherer's 85/8-inch pipeline approximately 29
miles long extending from the outlet of subsea production facilities of Shippers
located in Mississippi Canyon Block 674 to the inlet of the meter station
located on Marathon Oil Company's production platform in South Pass Block 89 and
all related and appurtenant facilities all as more particularly described on
Exhibit E attached hereto

"Insurable Event" means any event (a) for which insurance is generally
available, (b) that results in physical damage to the Gathering System to such
an extent that the Gathering System is not capable of receiving, transporting
and delivering Gas from the Point of Receipt to the Point

3
<PAGE> 4

of Delivery, and (c) that is not caused by a breach by Operator of its duties
and obligations under the Operating Agreement.

"Minimum Dollar Commitment" means, for each Shipper in each Month, that
Shipper's percentage share of the dollar amount shown in the column "Minimum
Dollar Commitment" in Exhibit A for that Month; except that for each Month after
the Month in which the aggregate of all Monthly Payments that Shippers have paid
to Gatherer reaches the Aggregate Dollar Commitment, the Minimum Dollar
Commitment shall equal zero, regardless of any amount that is otherwise set
forth in Exhibit A.

"Minimum Monthly Payment" means, for each Shipper in each Month, (i)
the Minimum Dollar Commitment for that Shipper in that Month less (ii) the
Annual Excess Payments for that Shipper in the prior Contract Year, if any,
divided by 12.

"Month" means a period beginning at 7:00 a.m. CPT on the first day of
the calendar month and ending at 7:00 a.m. CPT on the first day of the next
succeeding calendar month.

"Monthly Gathering Fee" means, for each Shipper in each Month, the
product of (i) the Gathering Rate for that Month multiplied by (ii) the total
quantity (in MMBtu's) of Gas and Condensate gathered and redelivered for that
Shipper in that Month in the Gathering System.

"Monthly Payment" is defined in Section 1 of Article 9.

"Operating Agreement" means that certain Operations and Maintenance
Agreement, of even date herewith, between MEGS, L.L.C., as Owner, and Operator.

"Operator" means Mariner Energy, Inc. as operator of the Gathering
System and any permitted successor operator of the Gathering System.

"Point of Delivery" means the interconnection between the upstream
flange connecting the Gathering System to Marathon Oil Company's processing and
handling facilities in South Pass Block 89.

"Point of Receipt" means the point of interconnection between the
Gathering System and Shippers' subsea production facilities in Mississippi
Canyon Block 674.

"Project Payout" has the meaning assigned to that term in Section VI of
that certain

4
<PAGE> 5

Participation Agreement between Mariner and BROI, dated May 1, 1999.

"Psia" means pounds per square inch absolute.

"Psig" means pounds per square inch gauge.

"Shipper's percentage share" means, for Mariner, 37% before Project
Payout and 51% after Project Payout, and for Burlington, 63% before Project
Payout and 49% after Project Payout.

"Third Party Gathering Net Proceeds" means cash proceeds received by
Gatherer to gather Third Party Gas on the Gathering System, less any costs and
expenses incurred by Gatherer in connection with gathering such Third Party Gas.

2. Rules of Construction. In construing and interpreting this
Agreement, the following rules of construction shall be followed:

(a) words imparting the singular shall include the plural and
vice versa;

(b) a reference in this Agreement to any Article, Section,
clause, or paragraph is, except where it is expressly stated to the
contrary or the context otherwise requires, a reference to such
Article, Section, clause, or paragraph herein;

(c) headings are for convenience of reference only and shall
not be used for purposes of construction or interpretation of this
Agreement;

(d) each reference to any applicable law shall be construed as
a reference to such applicable law as it may have been, or may from
time to time be, amended, replaced, or re-enacted and shall include any
subordinate legislation, rule, or regulation promulgated under any such
applicable law;

(e) the terms "hereof," "herein," "hereto," "hereunder," and
words of similar or like import refer to this entire Agreement and not
any one particular Article, Section, Schedule, or other subdivision of
this Agreement;

(f) any accounting terms used but not expressly defined herein
shall have the meanings given to them under generally accepted
accounting principles of the United States of America as consistently
applied by the person to which they relate;

5
<PAGE> 6

(g) the word "including" and its syntactical variants means
"including, but not limited to" and corresponding syntactical variant
expressions;

(h) in computing any period of time prescribed or allowed
under this Agreement, the day of the act, event, or default from which
the designated period of time begins to run shall be included and if
the last day of the period so computed is not a working day in the
place where performance is due, then the period shall run until the
close of business on the immediately succeeding working day; and

(i) this Agreement shall be deemed to be the product of each
Party hereto, and there shall be no presumption that an ambiguity
should be construed in favor of or against Gatherer solely as a result
of such Party's actual or alleged role in the drafting of this
Agreement.

ARTICLE 2
TERM

This Agreement shall become effective on the Effective Date of its
execution and shall remain in force as to each Shipper (i) until the date that
it is no longer economic for that Shipper to produce the Dedicated Reserves of
that Shipper or (ii) until the date on which the aggregate amount of the Monthly
Payments that Shippers have paid to Gatherer under Article 9, Section 1 of this
Agreement equals or exceeds the Aggregate Dollar Commitment, whichever occurs
later.

ARTICLE 3
REGULATION

The operation of the provisions of this Agreement shall be subject to
all applicable statutes and all applicable and lawful orders, rules, and
regulations of regulatory bodies having jurisdiction.

ARTICLE 4
DEDICATION AND GATHERING

1. Dedication. Each Shipper hereby commits and dedicates to the
performance of this Agreement, and covenants to deliver or cause to be
delivered, subject to the terms of this

6
<PAGE> 7

Agreement, its Dedicated Reserves for the term of this Agreement.

2. Quantity. Subject to the provisions of this Agreement, Gatherer
shall receive on a firm basis from the Shippers at the Point of Receipt
quantities of Gas from the Dedicated Reserves up to a maximum daily quantity
equal to the lesser of (i) the capacity of the Gathering System on that Day or
(ii) the capacity of the facilities and pipelines receiving and transporting Gas
from and after the Point of Delivery, or such additional quantities as the
Parties may agree to from time to time, and deliver or cause the delivery of
such Gas to or for the account of the Shippers at the Point of Delivery.

3. Allocation of Capacity. Subject to all applicable statues and all
applicable orders, rules and regulations, including the Outer Continental Shelf
Lands Act and any interpretations by a regulatory agency or judicial body having
jurisdiction thereof, capacity on the Gathering System shall be allocated, if
necessary, first to Shippers, and the Dedicated Reserves, and thereafter, in a
manner that Gatherer determines appropriate from time to time on the Gathering
System. If the Gatherer desires from time to time to gather Gas and/or
Condensate, other than the Dedicated Reserves on the Gathering System
(collectively, "Third Party Gas"), Gatherer must either (i) obtain each
Shippers' prior written consent, which shall not be unreasonably withheld, to
gather such Third Party Gas on the Gathering System or (ii) agree to indemnify
each Shipper in writing for all expenses and losses (including lost profits)
incurred by that Shipper as a direct result of Gatherer gathering such Third
Party Gas. Shippers understand and agree that Gatherer shall have no obligation
under this Agreement to gather Third Party Gas.

4. Nominations. Monthly nominations and daily scheduling and balancing
of gas to be gathered hereunder shall be pursuant to Exhibit B attached hereto
and hereby incorporated by reference into and made a part of this Agreement.

ARTICLE 5
CONDENSATE AND LIQUEFIABLE HYDROCARBONS

1. Receipt and Delivery. Subject to the terms of this Agreement,
Gatherer shall

7
<PAGE> 8

gather on firm basis the Condensate and liquefiable hydrocarbons associated with
Shipper's Gas gathered hereunder. Gatherer shall receive such Condensate and
liquefiable hydrocarbons at the Point of Receipt and deliver such Condensate and
liquefiable hydrocarbons to or for the account of Shippers at the Point of
Delivery.

2. Metering. Condensate metering shall be provided at the Point of
Delivery by Shippers at no cost to Gatherer.

ARTICLE 6
DELIVERY PRESSURE

1. Point of Receipt. Deliveries of Gas to Gatherer for gathering
hereunder at the Point of Receipt shall be at such pressures as Gatherer may
from time to time require to flow the Gas and Condensate through the Gathering
System generally at the volumes set forth on Exhibit A hereto. In no event shall
Shippers cause Gas to be delivered at the Point of Receipt at a pressure in
excess of the maximum allowable operating pressure of the Gathering System.
Shippers understand and agree that Gatherer shall be under no obligation to
provide compression services under this Agreement.

2. Point of Delivery. Deliveries of Gas by Gatherer for Shipper
hereunder at the Point of Delivery shall be at such pressures as may be
available from time to time in the facilities at the Point of Delivery.

ARTICLE 7
QUALITY

1. All Gas and Condensate delivered at the Point of Receipt by Shippers
under the terms of this Agreement shall conform to the specifications of the
operator of the platform at the Point of Delivery.

2. Refuse Delivery. If any Gas or Condensate offered for delivery
hereunder shall fail at any time to conform to such quality specifications at
the Point of Delivery, then Gatherer shall immediately have the right to refuse
to accept delivery of such Gas and Condensate and

8
<PAGE> 9

shall immediately notify Shippers of the specifications violation. Shippers
understand and agree that Gatherer shall be under no obligation to provide any
form of separation, dehydration, or other type of treating service with respect
to the Gas and Condensate being gathered under this Agreement.

ARTICLE 8
MEASUREMENT

1. Meter. Gas received by Gatherer at the Point of Receipt for Shippers
shall be measured at the meter station at the Point of Delivery on Marathon Oil
Company's platform in South Pass Block 89. The delivery of equivalent thermal
quantities of Gas and Condensate by Gatherer at the Point of Delivery for
Shipper shall be based upon the measurement made at such meter station.

2. Procedures. The Gas shall be measured in accordance with the
provisions of Exhibit C attached hereto and hereby incorporated by reference
into and made a part of this Agreement.

ARTICLE 9
GATHERING FEES

1. Monthly Amount. Each Shipper agrees to pay to Gatherer an amount
each Month (the "Monthly Payment") equal to the greater of (i) such Shipper's
Monthly Gathering Fee for that Month or (ii) such Shipper's Minimum Monthly
Payment for that Month.

2. Payment From Crediting Account. Each Shipper shall have the right in
each Month when (i) a positive balance exists in the Crediting Account for that
Shipper as of the first day of that Month and (ii) the Monthly Gathering Fee
exceeds the Minimum Dollar Commitment for that Shipper in that Month, to satisfy
the portion of its Monthly Payment due for that Month that exceeds the Minimum
Dollar Commitment from its Crediting Account by written notice to Gatherer. Such
written notice must be received by Gatherer no later than 10 Days after such

9
<PAGE> 10

Shipper's receipt of Gatherer's statement described in Article 10, Section 1.

3. Temporary Suspension Period. During any period when none of
Shippers' Gas can be received and transported on the Gathering System as a
result of an Insurable Event (a "Temporary Suspension Period"), Shippers'
obligations to make Monthly Payments shall be temporarily suspended beginning
with the Month (the "Suspension Commencement Month") following the Month in
which the Temporary Suspension Period began and ending with the Month in which
the Temporary Suspension Period ended. When the Temporary Suspension Period has
ended, Shippers' obligations to make Monthly Payments shall resume in the Month
immediately following the end of the Temporary Suspension Period (the "Payment
Resumption Month"); provided, however, that the Minimum Dollar Commitment for
each Shipper in the Payment Resumption Month shall equal that Shipper's
percentage share of the Minimum Dollar Commitment for the Suspension
Commencement Month and the Minimum Dollar Commitment for each Shipper for each
Month following the Payment Resumption Month shall equal that Shipper's
percentage share of the Minimum Dollar Commitment for the corresponding Month
following the Suspension Commencement Month. By way of example, if the Temporary
Suspension Period begins in July 2000 and ends in March 2001, then the Minimum
Dollar Commitment for each Shipper in April 2001 shall equal that Shipper's
percentage share of the Minimum Dollar Commitment set forth in Exhibit A for
August 2000 and the Minimum Dollar Commitment for each Shipper in May 2001 shall
equal that Shipper's percentage share of the Minimum Dollar Commitment set forth
in Exhibit A for September 2000 and so forth. In all events each Shipper shall
remain obligated to pay such Shipper's percentage share of the Aggregate Dollar
Commitment.

4. No Responsibility. Gatherer shall not be liable by reason of this
Agreement, or the gathering of Gas or Condensate hereunder, for any Gas
gathering, occupation, production, severance, sales, or first use tax or taxes
of similar nature or equivalent in effect which are now or hereafter imposed by
any authority on the Gas gathered pursuant to this Agreement or on the
production thereof.

10
<PAGE> 11

5. Tax Reimbursement. Each Shipper shall reimburse Gatherer for that
Shipper's percentage share of any tax (including first use tax) charge,
assessment, or other governmental exaction, including any tax under existing
statutes validly assessed on and paid by Gatherer for, in respect of, or on
account of the taking, gathering, or delivery by Gatherer of the Gas and
Condensate under this Agreement. Such obligation to reimburse shall specifically
not include income, excess profits, capital stock, or franchise taxes.

ARTICLE 10
BILLING

1. Monthly Statement. Gatherer shall deliver to each Shipper its
statement as soon as practicable after the end of each Month for service
rendered hereunder during such Month. If actual quantities are not available to
Gatherer, Gatherer may use estimated quantities for the calculation of all
amounts due by such Shipper hereunder. As soon as actual quantities become
available for a Month, the estimated quantities shall be corrected for that
Month, the amounts due shall be recalculated, and any amounts due by one Party
to another Party shall be shown in the next statement of Gatherer.

2. Payment. Each Shipper shall pay Gatherer for the amounts due each
month by wire transfer, or any other mutually agreed upon method, to Gatherer's
account (account name and number to be specified on the statement) on or before
15 days from the date the statement for such amounts is received by such
Shipper. Each Shipper must tender a timely payment even if the statement
presented by Gatherer includes estimated receipt or delivery quantities. If a
Shipper fails to pay any statement in whole or in part when due, in addition to
any other rights or remedies available to Gatherer, interest shall accrue on
unpaid amounts at a rate equal to the lesser of (i) the prime rate published
from time to time in The Wall Street Journal plus 2% or (ii) the maximum rate
permitted from time to time by applicable law. Such interest shall accrue
beginning on the payment due date of Gatherer's statement and ending when such
statement is paid. Notwithstanding the foregoing, if a legitimate good faith
dispute arises between Gatherer

11
<PAGE> 12

and a Shipper concerning a statement, such Shipper shall pay that portion of the
statement not in dispute on or before such due date, and, upon the ultimate
determination of the disputed portion of the statement, such Shipper shall pay
Gatherer the remaining amount owed plus the interest accrued thereon at the rate
shown above.

ARTICLE 11
POSSESSION OF GAS AND CONDENSATE

1. Risk of Loss. As between the Parties, (i) Shipper shall be deemed to
be in control and possession of the Gas and Condensate hereunder prior to
delivery thereof to Gatherer at the Point of Receipt and after redelivery
thereof by Gatherer at the Point of Delivery, and (ii) Gatherer shall be deemed
to be in control and possession of the Gas and Condensate hereunder after
receipt thereof by Gatherer at the Point of Receipt and until redelivery thereof
by Gatherer for Shipper at the Point of Delivery.

2. Indemnity. With respect to the Gas gathered hereunder, the Party in
control and possession of the Gas shall be responsible for and shall indemnify
the other party in respect to any losses, injuries, claims, liabilities or
damages caused thereby and occurring while the Gas is in the possession of the
Party in control. With respect to the Condensate gathered hereunder, each
Shipper shall indemnify and hold harmless Gatherer against any losses, injuries,
claims, liabilities or damages whatsoever occurring in connection with or
relating to the Condensate gathered hereunder. As between MEGS, L.L.C. as Owner
and Mariner as Operator under the Operating Agreement, the foregoing indemnity
obligations of Gatherer under this Section are subject to Mariner's indemnity
obligations as Operator under Section 7.1 of the Operating Agreement.

ARTICLE 12
TITLE AND WARRANTY

Each Shipper hereby warrants that it has good title to all the Gas
delivered by it to

12
<PAGE> 13

Gatherer or the right to deliver such Gas to Gatherer hereunder, and that such
Gas shall be free and clear of all liens, encumbrances, and claims whatsoever
(other than liens related to any financing transaction) and agrees to indemnify
Gatherer against all losses, costs, suits, actions, damages, and expenses
incurred by it on account of any such liens, encumbrances, and claims
whatsoever. In no event shall title to the Gas gathered hereunder vest in
Gatherer as a result of the gathering services performed hereunder.

ARTICLE 13
FORCE MAJEURE

1. Excused Performance. No failure or delay in performance, whether in
whole or in part, by either Gatherer or Shippers shall be deemed to be a breach
hereof when such failure or delay is due to a Force Majeure Event.
Notwithstanding the foregoing, the occurrence of a Force Majeure Event shall not
relieve Shippers from their obligations to make Monthly Payments under this
Agreement, except to the extent such Force Majeure Event also constitutes an
Insurable Event and then such payment obligations shall be suspended only during
the Temporary Suspension Period provided for in Section 3 of Article 9.

2. Force Majeure Event Defined. "Force Majeure Event" means any event
not within the control of the affected Party and which, by the exercise of due
diligence, such Party is unable to prevent or overcome, including any act of
God, strike, lockout, or other industrial disturbance, act of the public enemy,
sabotage, war (whether or not an actual declaration is made thereof), blockade,
insurrection, riot, epidemic, landslide, lightning, earthquake, flood, storm,
fire, washout, arrest and restraint of rulers and peoples, civil disturbance,
explosion, the act of any court or governmental authority, or any other such
cause.

3. Remedy of Force Majeure Event. Force Majeure Events shall be
remedied by the affected Party with all reasonable efforts. The settlement of
strike or lockout shall be entirely within the discretion of the affected Party.

4. Notice of Force Majeure Event. A Party affected by a Force Majeure
Event shall

13
<PAGE> 14

give notice in writing to the other Parties as soon as possible after the
occurrence of the Force Majeure Event. Such notice shall describe the Force
Majeure Event and give the affected Party's estimate as to its expected duration
and what steps are being taken to overcome the effects thereof.

ARTICLE 14
NOTICES

1. Notice. Any notice, request, demand or statement provided for in
this Agreement, or any notice which a Party may desire to give to the other
Party, shall be in writing and shall be delivered by first class United States
mail, postage prepaid, overnight courier, personal delivery, or facsimile
transfer at the following address:

(a) if to Gatherer:
MEGS, L.L.C.
1400 Smith Street
Houston, Texas 77002
Attention: Vice President - Gas Network Services
Facsimile No.: 713-345-7040

(b) if to Mariner:
Mariner Energy, Inc.
580 WestLake Park Blvd., Suite 1300
Houston, Texas 77079
Attention: Vice President of Marketing
Facsimile No.: 281-584-5678

(c) if to Burlington:
Burlington Resources Trading Inc.
5051 Westheimer, Suite 1400
Houston, Texas 77056
Attention: Manager, Gulf Coast Marketing & Supply
Facsimile No.: 713-624-9606

2. Change of Address. Such notices shall be effective when received by
the Party being notified; provided that with respect to any notice sent by
facsimile, such notice shall be effective when received by the Party being
notified if sent during normal business hours and such notice shall be effective
the first business day after receipt by the Party being notified if sent at any
other time. Either Party may change its address or facsimile number for notice
by giving written notice to the other Party.

3. Routine Notices. Routine dispatching contracts and communications
may be

14
<PAGE> 15

handled orally or in writing between the respective designated representatives
of Gatherer and Shipper.

ARTICLE 15
DISPUTE RESOLUTION

Any claim, counterclaim, demand, cause of action, dispute, and
controversy arising out of or relating to this Agreement or the relationship
established by this Agreement, any provision hereof, the alleged breach hereof,
or in any way relating to the subject matter of this Agreement, involving the
Parties and/or their respective representatives (collectively "Claims"), even if
such Claims allegedly are extra-contractual in nature, sound in contract, tort,
or otherwise, or arise under state or federal law, shall be resolved by binding
arbitration. Arbitration shall be conducted in accordance with the rules of
arbitration of the Federal Arbitration Act and, to the extent an issue is not
addressed by the federal law on arbitration, by the commercial arbitration rules
of the American Arbitration Association. The validity, construction, and
interpretation of this Agreement to arbitrate, and all procedural aspects of the
arbitration conducted pursuant hereto shall be decided by the arbitrators. In
deciding the substance of the Parties' Claims, the arbitrators shall refer to
the governing law. The arbitrators shall have no authority to award treble,
exemplary, or punitive damages of any type under any circumstances whether or
not such damages may be available under state or federal law, or under the
Federal Arbitration Act, or under the commercial arbitration rules of the
American Arbitration Association, the Parties hereby waiving their right, if
any, to recover any such damages. The arbitration proceeding shall be conducted
in Houston, Texas. Within thirty days of the notice of initiation of the
arbitration procedure, Gatherer shall select one arbitrator and Shippers shall,
collectively, select one arbitrator. If after a good faith effort to
collectively select one arbitrator the Shippers cannot agree on one arbitrator,
then Burlington shall have the right to select the arbitrator for the Shippers.
The two arbitrators shall select a third arbitrator. The third arbitrator shall
be a person who has over eight years professional experience in the natural Gas
industry and who has not previously been employed by either Party and does not
have a direct or indirect interest in either

15
<PAGE> 16

Party or the subject matter of the arbitration. While the third arbitrator shall
be neutral, the two Party-appointed arbitrators are not required to be neutral,
and it shall not be grounds for removal of either of the two party-appointed
arbitrators or for vacating the arbitrators' award that either of such
arbitrators has past or present minimal relationships with the party that
appointed such arbitrator. To the fullest extent permitted by law, any
arbitration proceeding and the arbitrators award shall be maintained in
confidence by the Parties.

ARTICLE 16
OTHER PROVISIONS

1. Modifications. No modifications of the terms and provisions of this
Agreement shall be or become effective except by the execution by both Parties
of a supplementary written agreement.

2. No Waiver. No waiver by either Party of any one or more defaults by
the other Party in performance of any provisions of this Agreement shall operate
or be construed as a waiver of any other then existing default or future
default, whether of a like or different character.

3. Assignment. This Agreement shall not be assigned by Gatherer or
either Shipper without the prior written consent of the other Party, which
consent can be withheld by the nonassigning Party in its sole discretion.
Notwithstanding the foregoing, Gatherer and either Shipper may, without the need
for consent from the other Party (but upon prior written notice to the other
Party), (a) transfer, sell, pledge, encumber, or assign this Agreement or the
accounts, revenues, or proceeds hereof in connection with any financing,
securitization, monetization, receivables sale, factoring or other financial
arrangements, (b) transfer or assign this Agreement to an Affiliate, or (c)
transfer or assign this Agreement to any person or entity succeeding to all or
substantially all of the assets of such Party. In the case of clauses (b) and
(c) any such assignee shall agree in writing to be bound by the terms and
conditions hereof.

16
<PAGE> 17

4. Binding Effect. Subject to Section 3 above, this Agreement shall
inure to the benefit of and be binding upon the Parties and their respective
successors and permitted assigns. No assignment or transfer permitted hereunder
shall relieve Shippers or Gatherer of any of their respective obligations under
this Agreement unless agreed to in writing by all of the Parties.

5. Choice of Law. This Agreement shall be governed by the laws of the
State of Texas without giving effect to any principles of conflicts of laws.

6. Entire Agreement. This Agreement constitutes the entire agreement
between the Parties pertaining to the subject matter hereof and supersedes all
prior agreements and understandings, oral or written, which the Parties may have
in connection therewith.

7. No Joint Obligations. The obligations of each Shipper under this
Agreement shall be several and not joint.

[The next page is the signature page]

17
<PAGE> 18

IN WITNESS WHEREOF, the Parties have executed this Agreement to be
effective as of the day and year first above written.

Shippers:

MARINER ENERGY, INC.

BY: /s/ Greg K. Harless
-------------------------------------
NAME: Greg K. Harless
-----------------------------------
TITLE: Vice President - Marketing
----------------------------------

BURLINGTON RESOURCES
OFFSHORE INC.

BY: /s/ Hunter L. Malson
-------------------------------------
NAME: Hunter L. Malson
-----------------------------------
TITLE: Vice President
----------------------------------

BURLINGTON RESOURCES
TRADING INC.

BY: /s/ Hunter L. Malson
-------------------------------------
NAME: Hunter L. Malson
-----------------------------------
TITLE: Vice President
----------------------------------

Gatherer:

MEGS, L.L.C.

BY: /s/ Douglas B. Dunn
-------------------------------------
NAME: Douglas B. Dunn
-----------------------------------
TITLE: Vice President
----------------------------------

18
<PAGE> 19

EXHIBIT A
PRODUCTION AND GATHERING SCHEDULE

[attached behind this page]

<PAGE> 20

EXHIBIT B
NOMINATIONS, BALANCING, AND PENALTIES

1. Monthly Nomination Procedure. The Shippers shall cause the operator
of the Dedicated Reserves to submit in writing to Gatherer no later than the
first day of each Month Shippers' best estimate (referred to herein as
"Shippers' Daily Nominated Quality") of their daily requirements for such Month.
Shippers' Daily Nominated Quantity shall be stated in MMBtu's, shall designate
quantities at the Point of Receipt and Point of Delivery, and shall reflect any
imbalance (or Shippers' best estimate of any imbalance), make-up quantities,
scheduled daily variations, the Btu content per cubic foot of Gas, and, if
applicable, any Condensate or liquefiable hydrocarbons delivered to Gatherer.
Unless modified by Shippers as described below, Shippers' Daily Nominated
Quantity shall be effective for each day of the applicable Month. Nominations to
commence service on any day other than the first day of any Month or to modify
Shippers' Daily Nominated Quantity shall be submitted in writing by the operator
of the Dedicated Reserves on behalf of Shippers and received by Gatherer no
later than the business day immediately preceding the day that such service is
requested to commence or that such modification is to be effective.

2. Balancing. The intent of Gatherer and Shippers is that Gas be
received and delivered hereunder at the same rate, and Shippers shall not, in
any manner, use Gatherer's system for storage or peaking purposes. It is
recognized that an exact daily balancing of receipts and deliveries may not be
possible due to the inability of the Parties to control precisely such receipts
and deliveries. However, Gatherer, to the extent practicable, will deliver each
day an equivalent thermal quantity of Gas received by Gatherer that day.

3. Statement. Following the end of each Month Gatherer shall provide to
each Shipper a cumulative imbalance statement showing any imbalances on the
Gathering System. Imbalances shall be corrected insofar as practicable during
the month following the month in

<PAGE> 21

which they occur. If an imbalance exists upon termination of this Agreement, the
term hereof shall be extended for a period not to exceed an additional sixty
(60) days, during which time the party whose deliveries or redeliveries are in
arrears shall eliminate its deficit and thereby achieve zero balance, unless the
parties mutually agree upon an appropriate alternative method of balancing.

4. Constant Delivery. Gas delivered to Gatherer hereunder during any
day shall be delivered at as nearly a constant rate as operating conditions will
permit.

<PAGE> 22

EXHIBIT C
MEASUREMENT

1. Unit. The measurement unit of natural Gas received and delivered
hereunder shall be 1,000 cubic feet of Gas measured according to Boyle's Law for
the measurement of Gas under varying pressures with deviations therefrom as
provided below, on the measurement basis hereinafter specified.

2. Volume. The unit of volume for purposes of measurement of Gas
received and delivered hereunder and for the purposes of determination of
equivalent volumes hereunder shall be one (1) cubic foot of natural Gas at a
temperature of 60 degrees Fahrenheit and at a pressure of 14.73 psia.

3. Meters. Orifice meters and appurtenant facilities used in the
measurement of the Gas to be received or delivered shall be provided by Shippers
at Shippers' expense and shall be designed and fabricated in accordance with
specifications of ANSI/API 2530 "Orifice Metering of Natural Gas and Other
Related Hydrocarbon Fuels" and any modification and amendment thereof as agreed
upon by the Parties. Such facilities shall include the use of electronic
measurement and data acquisition equipment, straightening vanes and pulsation
dampening equipment where necessary. Operations of the orifice meters and
appurtenant facilities used in the measurement of Gas to be received or
delivered shall be in accordance with specifications of ANSI/API 2530 and any
modification and amendment thereof as agreed upon by the Parties.

4. Accuracy of Measurement Equipment.

(a) The accuracy of the measuring and testing equipment shall
be verified as frequently as permitted at the Point of Delivery. Tests for
quality of the Gas may be made at the time of testing equipment or at other
times as mutually agreed upon. Notice of the time and nature of each test shall
be given by Gatherer to Shippers sufficiently in advance to permit arrangement
for each Shipper's representative to be present. Tests and adjustments shall be
made in the presence of and observed by representatives of both Gatherer and
Shipper. All tests

<PAGE> 23
shall be made by Gatherer at Shippers' expense.

(b) If upon test, any measuring equipment, including recording
calorimeters, is found to be in error in the aggregate by not more than 1%,
previous recordings of such equipment shall be considered accurate in computing
deliveries of Gas, but such equipment shall be adjusted at once to record
accurately.

(c) If upon test, any measuring equipment shall be found in
the aggregate to be inaccurate by an amount exceeding 1% at a recording
corresponding to the average hourly rate of flow for the period since the last
preceding test, such equipment shall be adjusted at once to record accurately,
and any previous recordings of such equipment shall be corrected to zero error
for any period which is known definitely, but in case the period is not known or
agreed upon, such correction shall be for a period extending over one-half of
the time elapsed since the date of the last test.

5. Corrections. If a meter is out of service or registering
inaccurately, the quantities of Gas received or delivered during such period
shall be determined as follows:

(a) using the registration of any check meters or meters, if
installed and accurately registering; or in the absence of subsection a,

(b) correcting the error if the percentage of error is
ascertainable by calibration, tests or mathematical calculation or in the
absence of both subsections a and b, then,

(c) estimating the quantity received or delivered by receipts
or deliveries during periods under similar conditions when the meter was
registering accurately.

6. Review of Data. Each Party shall, upon request of the other Party,
mail or deliver for checking and calculation all volume and temperature meter
data in its possession and used in the measurement of Gas received or delivered
hereunder with 30 days after the last chart for each billing period is removed
from the meter. Such charts shall be returned within 30 days after the receipt
thereof.

7. Record Retention. Each Party shall preserve or cause to be preserved
for mutual use all test data, charts, or other similar records for a period of
at least three years unless a
<PAGE> 24
longer period is required by the applicable rules and regulations of regulatory
bodies having jurisdiction with respect to the retention of such records.

<PAGE> 25

EXHIBIT D
EXAMPLE CALCULATION
OF ANNUAL EXCESS PAYMENTS

<PAGE> 26

EXHIBIT E
DESCRIPTION OF GATHERING SYSTEM

[attached behind this page]

<PAGE> 1
EXHIBIT 10.29

FIRST AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT

THIS FIRST AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT (this
"First Amendment") is made and entered into as of the 31st day of December,
1999, by and among MARINER ENERGY, INC., a Delaware corporation ("Borrower"),
BANK OF AMERICA, N.A., as Administrative Agent ("Administrative Agent"), TORONTO
DOMINION (TEXAS), INC., as Co-Agent ("Co-Agent") and BANK OF AMERICA, N.A.,
TORONTO DOMINION (TEXAS), INC., THE BANK OF NOVA SCOTIA and ABN AMRO BANK N.V.
(individually a "Bank" and collectively the "Banks").

WHEREAS, Borrower, NationsBank, N.A. (which changed its name to Bank of
America, N.A., and then merged with and into Bank of America National Trust and
Savings Association, which surviving entity then changed its name to Bank of
America, N.A.), as Administrative Agent, Co-Agent and the Banks entered into
that certain Amended and Restated Credit Agreement dated June 28, 1999 (the
"Credit Agreement");

WHEREAS, Borrower, Administrative Agent, Co-Agent and the Banks desire
to amend certain terms and provisions of the Credit Agreement, as set forth
herein.

NOW, THEREFORE, FOR AND IN CONSIDERATION of the mutual covenants and
agreements contained herein, the parties hereto agree as follows:

1. Section 10.2 of the Credit Agreement is deleted in its entirety, and the
following is substituted in its place:

Section 10.2. Interest Coverage Ratio. Borrower will not
permit the consolidated Interest Coverage Ratio of Borrower and
Guarantor as of the end of the Fiscal Quarter ending December 31, 1999
to be less than 2.00 to 1.0. Borrower will not permit the consolidated
Interest Coverage Ratio of Borrower and Guarantor as of the end of any
other Fiscal Quarter to be less than 2.25 to 1.0.

1. The closing of the transactions contemplated by this First Amendment is
subject to the satisfaction of the following conditions:

(a) All legal matters incident to the transactions herein
contemplated shall be satisfactory to counsel to Administrative Agent;
and

(b) Administrative Agent shall have received a fully executed
copy of this First Amendment.

1. Except as amended hereby, the Credit Agreement shall remain unchanged,
and the terms, conditions and covenants of the Credit Agreement shall continue
and be binding upon the parties hereto.

1. Within thirty (30) days of the next action, whether by consent or at a
meeting, of the Board of Directors of Borrower and Guarantor, Borrower will
deliver an executed copy of resolutions

<PAGE> 2

of the Board of Directors of Borrower and Guarantor in form and substance
reasonably satisfactory to Administrative Agent ratifying the execution,
delivery and performance of this First Amendment and all documents, instruments
and certificates referred to herein.

1. Each of the terms defined in the Credit Agreement is used in this First
Amendment with the same meaning, except as otherwise indicated in this First
Amendment. Each of the terms defined in this First Amendment is used in the
Credit Agreement with the same meaning, except as otherwise indicated in the
Credit Agreement.

1. This First Amendment may be executed in any number of counterparts, each
of which shall constitute an original, but all of which, when taken together,
shall constitute but one agreement.

1. THIS FIRST AMENDMENT SHALL BE DEEMED TO BE A CONTRACT UNDER, SUBJECT TO,
AND SHALL BE CONSTRUED FOR ALL PURPOSES IN ACCORDANCE WITH THE LAWS OF THE STATE
OF TEXAS.

1. THE CREDIT AGREEMENT, AS AMENDED, REPRESENTS THE FINAL AGREEMENT BETWEEN
THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR
SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES.

THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

IN WITNESS WHEREOF, the parties have caused this First Amendment to be
executed by their duly authorized officers as of the day and year first above
written.

MARINER ENERGY, INC.

By: /s/ Frank Pici
Name: Frank Pici
Title: Vice President Finance

BANK OF AMERICA, N.A., as Administrative Agent

By: /s/ James Ducoto
Name: James Ducoto
Title: Vice President

TORONTO DOMINION (TEXAS), INC.,
as Co-Agent

By: /s/ Mark A. Bario
Name: Mark A. Bario
Title: Vice President

- -2-

<PAGE> 3

BANK OF AMERICA, N.A.

By: /s/ Mark Barid
Name: Mark Barid
Title: Vice President

TORONTO DOMINION (TEXAS), INC.

By: /s/ [ILLEGIBLE]
Name: [ILLEGIBLE]
Title: Vice President

THE BANK OF NOVA SCOTIA

By: /s/ [ILLEGIBLE]
Name: [ILLEGIBLE]
Title: Vice President

ABN AMRO BANK N.V.

By: /s/ Matt McCain
Name: Matt McCain
Title: Vice President

By: /s/ Deanna Breland
Name: Deanna Breland
Title: Vice President

The undersigned Guarantor, Mariner Holdings, Inc., executes this First
Amendment to evidence its acknowledgment of the terms and provisions hereof and
to evidence its agreements to the matters set forth herein.

MARINER HOLDINGS, INC.

By: /s/ Frank Pici
Name: Frank Pici
Title: Vice President - Finance

- -3-

<PAGE> 1
EXHIBIT 23.1

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We consent to the use of the name of this firm and of certain
information contained in our reserve report dated December 31, 1999, prepared
for Mariner Energy, Inc. ("Mariner"), in Mariner's Annual Report on Form 10-K
for the year ended December 31, 1999.

/s/ RYDER SCOTT COMPANY
PETROLEUM ENGINEERS

RYDER SCOTT COMPANY
PETROLEUM ENGINEERS

Houston, Texas
March 30, 2000

<PAGE> 1
EXHIBIT 23.2

[RYDER SCOTT LETTERHEAD]

March 7, 2000

Mariner Energy, Inc.
580 WestLake Park Blvd., Suite 1300
Houston, Texas 77079

Gentlemen:

At your request, we have prepared an estimate of the reserves,
future production, and income attributable to certain leasehold interests of
Mariner Energy, Inc. (Mariner) as of January 1, 2000. The subject properties are
located in the states of Louisiana, Mississippi, and Texas and in the federal
waters offshore Louisiana and Texas. The income data were estimated using the
Securities and Exchange Commission (SEC) guidelines for future price and cost
parameters.

The estimated reserves and future income amounts presented in
this report are related to hydrocarbon prices. December 1999 hydrocarbon prices
were used in the preparation of this report as required by SEC guidelines;
however, actual future prices may vary significantly from December 1999 prices.
Therefore, volumes of reserves actually recovered and amounts of income actually
received may differ significantly from the estimated quantities presented in
this report. The results of this study are summarized below.

SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold Interests of
MARINER ENERGY, INC.
As of January 1, 2000

<TABLE>
<CAPTION>
Proved
----------------------------------------------------------------------------------
Developed
------------------------------------- Total
Producing Non-Producing Undeveloped Proved
------------ ------------- ------------ ------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
Oil/Condensate - Barrels 3,630,055 158,931 6,125,830 9,914,816
Plant Products - Barrels 4,292 6,003 1,385 11,680
Gas - MMCF 73,308 9,452 36,030 118,790

INCOME DATA
Future Gross Revenue $246,981,784 $24,406,318 $218,853,706 $490,238,808
Deductions 70,401,284 8,177,354 114,876,803 193,455,441
------------ ----------- ------------ ------------
Future Net Income (FNI) $176,580,500 $16,228,964 $103,973,903 $296,783,367

Discounted FNI @ 10% $141,110,144 $12,552,032 $ 57,563,969 $211,226,145
</TABLE>

<PAGE> 2

Mariner Energy, Inc.
March 7, 2000
Page 2

<TABLE>
<CAPTION>
Probable
----------------------------------------------------------------------------------
Developed
------------------------------------- Total
Producing Non-Producing Undeveloped Probable
------------ ------------- ------------ ------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
Oil/Condensate - Barrels 1,414,543 12,346 1,763,383 3,190,272
Plant Products - Barrels 0 0 1,411 1,411
Gas - MMCF 28,550 1,869 8,813 39,232

INCOME DATA
Future Gross Revenue $ 94,434,319 $ 4,353,718 $ 57,172,991 $155,961,028
Deductions 12,826,818 581,351 10,837,567 24,245,736
------------ ----------- ------------ ------------
Future Net Income (FNI) $ 81,607,501 $ 3,772,367 $ 46,335,424 $131,715,292

Discounted FNI @ 10% $ 57,300,492 $ 2,623,352 $ 32,319,329 $ 92,243,173
</TABLE>

<TABLE>
<CAPTION>
Possible
----------------------------------------------------------------------------------
Developed
------------------------------------- Total
Producing Non-Producing Undeveloped Possible
------------ ------------- ------------ ------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
Oil/Condensate - Barrels 2,729 1,162 1,609,346 1,613,237
Plant Products - Barrels 0 0 0 0
Gas - MMCF 1,378 1,566 1,936 4,880

INCOME DATA
Future Gross Revenue $ 3,024,209 $ 3,306,100 $ 38,693,373 $ 45,023,682
Deductions 88,520 418,656 6,114,866 6,622,042
------------ ----------- ------------ ------------
Future Net Income (FNI) $ 2,935,689 $ 2,887,444 $ 32,578,507 $ 38,401,640

Discounted FNI @ 10% $ 1,975,923 $ 1,824,394 $ 19,766,637 $ 23,566,954
</TABLE>

Liquid hydrocarbons are expressed in standard 42 gallon
barrels. All gas volumes are sales gas expressed in millions of cubic feet
(MMCF) at the official temperature and pressure bases of the areas in which the
gas reserves are located.

The future gross revenue is after the deduction of production
taxes. The deductions are comprised of the normal direct costs of operating the
wells, ad valorem taxes, recompletion costs, development costs, and certain
abandonment costs net of salvage. The future net income is before the deduction
of state and federal income taxes and general administrative overhead, and has
not been adjusted for outstanding loans that may exist nor does it include any
adjustment for cash on hand or undistributed income. No attempt was made to
quantify or otherwise account for any accumulated gas production imbalances that
may exist. Gas reserves account for approximately 52.8 percent, liquid
hydrocarbon account for approximately 47.1 percent, and plant product reserves
account for the remaining .1 percent of total future gross revenue from proved
reserves.

The discounted future net income shown above was calculated
using a discount rate of 10 percent per annum compounded monthly. Future net
income was discounted at four other discount rates which were also compounded
monthly. These results are shown on each estimated projection of future
production and income presented in a later section of this report and in summary
form below.

<PAGE> 3

Mariner Energy, Inc.
March 7, 2000
Page 3

<TABLE>
<CAPTION>
Discounted Future Net Income
As of January 1, 2000
--------------------------------------------------------------------
Discount Rate Total Total Total
Percent Proved Probable Possible
--------------------- -------------------- ------------------- -----------------

The results shown above are presented for your information and should not be
construed as our estimate of fair market value.

RESERVES INCLUDED IN THIS REPORT

The proved reserves included herein conform to the definition
as set forth in the Securities and Exchange Commission's Regulation S-X Part
210.4-10 (a) as clarified by subsequent Commission Staff Accounting Bulletins.
The probable reserves and possible reserves included herein conform to
definitions of probable and possible reserves approved by the Society of
Petroleum Engineers and the Society of Petroleum Evaluation Engineers. The
definitions of proved, probable, and possible reserves are included under the
tab "Reserve Definitions and Pricing Assumptions" in this report.

We have included probable and possible reserves and income in
this report at the request of Mariner. These data are for Mariner's information
only and should not be included in reports to the SEC according to the SEC
guidelines. The probable reserves are less certain to be recovered than the
proved reserves and reserves classified as possible are less certain to be
recovered than those in the probable category. The reserves and income
quantities attributable to the different reserve classifications that are
included herein have not been adjusted to reflect the varying degrees of risk
associated with them and thus are not comparable.

The proved, probable and possible developed non-producing
reserves included herein are comprised of shut-in and behind pipe categories.
The various reserve status categories are defined under the tab "Reserve
Definitions and Pricing Assumptions" in this report.

ESTIMATES OF RESERVES

In general, the reserves included herein were estimated by
performance methods or the volumetric method; however, other methods were used
in certain cases where characteristics of the data indicated such other methods
were more appropriate in our opinion. The reserves estimated by the performance
method utilized extrapolations of various historical data in those cases where
such data were definitive. Reserves were estimated by the volumetric method in
those cases where there were inadequate historical performance data to establish
a definitive trend or where the use of production performance data as a basis
for the reserve estimates was considered to be inappropriate.

The reserves included in this report are estimates only and
should not be construed as being exact quantities. They may or may not be
actually recovered, and if recovered, the revenues therefrom and the actual
costs related thereto could be more or less than the estimated amounts.
Moreover, estimates of reserves may increase or decrease as a result of future
operations.

<PAGE> 4

Mariner Energy, Inc.
March 7, 2000
Page 4

FUTURE PRODUCTION RATES

Initial production rates are based on the current producing
rates for those wells now on production. Test data and other related information
were used to estimate the anticipated initial production rates for those wells
or locations which are not currently producing. If no production decline trend
has been established, future production rates were held constant, or adjusted
for the effects of curtailment where appropriate, until a decline in ability to
produce was anticipated. An estimated rate of decline was then applied to
depletion of the reserves. If a decline trend has been established, this trend
was used as the basis for estimating future production rates. For reserves not
yet on production, sales were estimated to commence at an anticipated date
furnished by Mariner.

In general, we estimate that future gas production rates
limited by allowables or marketing conditions will continue to be the same as
the average rate for the latest available 12 months of actual production until
such time that the well or wells are incapable of producing at this rate. The
well or wells were then projected to decline at their decreasing delivery
capacity rate. Our general policy on estimates of future gas production rates is
adjusted when necessary to reflect actual gas market conditions in specific
cases.

The future production rates from wells now on production may
be more or less than estimated because of changes in market demand or allowables
set by regulatory bodies. Wells or locations which are not currently producing
may start producing earlier or later than anticipated in our estimates of their
future production rates.

HYDROCARBON PRICES

Mariner furnished us with prices in effect at January 1, 2000
and these prices were held constant except for known and determinable
escalations. In accordance with Securities and Exchange Commission guidelines,
changes in liquid and gas prices subsequent to December 31, 1999, were not taken
into account in this report. Future prices used in this report are discussed in
more detail under the tab "Reserve Definitions and Pricing Assumptions" in this
report.

COSTS

Operating costs for the leases and wells in this report are
based on the operating expense reports of Mariner and include only those costs
directly applicable to the leases or wells. When applicable, the operating costs
include a portion of general and administrative costs allocated directly to the
leases and wells under terms of operating agreements. No deduction was made for
indirect costs such as general administration and overhead expenses, loan
repayments, interest expenses, and exploration and development prepayments that
are not charged directly to the leases or wells.

Development costs were furnished to us by Mariner and are
based on authorizations for expenditure for the proposed work or actual costs
for similar projects. The estimated net cost of abandonment after salvage was
included for properties where abandonment costs net of salvage are significant.
The estimates of the net abandonment costs furnished by Mariner were accepted
without independent verification.

Current costs were held constant throughout the life of the
properties.

<PAGE> 5

Mariner Energy, Inc.
March 7, 2000
Page 5

GENERAL

Table A presents a one line summary of proved reserve and
income data for each of the subject properties which are ranked according to
their future net income discounted at 10 percent per year. Table B presents a
one line summary of gross and net reserves and income data for each of the
subject properties. Table C presents a one line summary of initial basic data
for each of the subject properties. Tables 1 through 335 present our estimated
projection of production and income by years beginning January 1, 2000, by
state, field, and lease or well.

While it may reasonably be anticipated that the future prices
received for the sale of production and the operating costs and other costs
relating to such production may also increase or decrease from existing levels,
such changes were, in accordance with rules adopted by the SEC, omitted from
consideration in making this evaluation.

The estimates of reserves presented herein were based upon a
detailed study of the properties in which Mariner owns an interest; however, we
have not made any field examination of the properties. No consideration was
given in this report to potential environmental liabilities which may exist nor
were any costs included for potential liability to restore and clean up damages,
if any, caused by past operating practices. Mariner has informed us that they
have furnished us all of the accounts, records, geological and engineering data,
and reports and other data required for this investigation. The ownership
interests, prices, and other factual data furnished by Mariner were accepted
without independent verification. The estimates presented in this report are
based on data available through December 1999.

Neither we nor any of our employees have any interest in the
subject properties and neither the employment to make this study nor the
compensation is contingent on our estimates of reserves and future income for
the subject properties.

This report was prepared for the exclusive use and sole
benefit of Mariner Energy, Inc. The data, work papers, and maps used in this
report are available for examination by authorized parties in our offices.
Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

Timothy J. Torres, P.E.
Petroleum Engineer
JRW/sw

Approved:

- --------------------------------
John R. Warner, P.E.
Senior Vice President

<PAGE> 6

DEFINITIONS OF RESERVES

PROVED RESERVES (SEC DEFINITION)

Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing operating conditions, i.e., prices and costs as of the
date the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalation based on
future conditions.

Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation test. In certain instances,
proved reserves are assigned on the basis of a combination of core analysis and
electrical and other type logs which indicate the reservoirs are analogous to
reservoirs in the same field which are producing or have demonstrated the
ability to produce on a formation test. The area of a reservoir considered
proved includes (1) that portion delineated by drilling and defined by fluid
contacts, if any, and (2) the adjoining portions not yet drilled that can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts, the
lowest known structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir.

Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot project or the
operation of an installed program in the reservoir provides support for the
engineering analysis on which the project or program was based, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.

Proved natural gas reserves are comprised of non-associated, associated
and dissolved gas. An appropriate reduction in gas reserves has been made for
the expected removal of natural gas liquids, for lease and plant fuel, and for
the exclusion of non-hydrocarbon gases if they occur in significant quantities
and are removed prior to sale. Estimates of proved reserves do not include crude
oil, natural gas, or natural gas liquids being held in underground or surface
storage.

Proved reserves are estimates of hydrocarbons to be recovered from a
given date forward. They may be revised as hydrocarbons are produced and
additional data become available.

<PAGE> 7

Definitions of Reserves
Page 2

UNPROVED RESERVES (SPE/SPEE DEFINITIONS)

Unproved reserves are based on geologic and/or engineering data similar
to that used in estimates of proved reserves; but technical, contractual,
economic, or regulatory uncertainties preclude such reserves being classified as
proved. They may be estimated assuming future conditions different from those
prevailing at the time of the estimate.

Estimates of unproved reserves may be made for internal planning or
special evaluations, but are not routinely compiled.

Unproved reserves are not to be added to proved reserves because of
different levels of uncertainty.

Unproved reserves may be divided into two subclassifications: PROBABLE
and POSSIBLE.

PROBABLE RESERVES

Probable reserves are less certain than proved reserves and can be
estimated with a degree of certainty sufficient to indicate they are more likely
to be recovered than not.

In general, probable reserves may include (1) reserves anticipated to
be proved by normal stepout drilling when subsurface control is inadequate to
classify these reserves as proved; (2) reserves in formations that appear to be
productive based on log characteristics but that lack core data or definitive
tests and which are not analogous to producing or proved reservoirs in the area;
(3) incremental reserves attributable to infill drilling that otherwise could be
classified as proved but closer statutory spacing had not been approved at the
time of the estimate; (4) reserves attributable to an improved recovery method
that has been established by repeated commercially successful applications when
a project or pilot is planned but not in operation and rock, fluid, and
reservoir characteristics appear favorable for commercial application; (5)
reserves in an area of a formation that has been proved productive in other
areas of the field but subject area appears to be separated from the proved area
by faulting and the geologic interpretation indicates subject area is
structurally higher than the proved area; (6) reserves attributable to a
successful workover, treatment, retreatment, change of equipment, or other
mechanical procedure, where such procedure has not been proved successful in
wells exhibiting similar behavior in analogous reservoirs; and (7) incremental
reserves in a proved producing reservoir where an alternate interpretation of
performance or volumetric data indicates significantly more reserves than can be
classified as proved.

POSSIBLE RESERVES

Possible reserves are less certain than probable reserves and can be
estimated with a low degree of certainty, insufficient to indicate whether they
are more likely to be recovered than not.

In general, possible reserves may include (1) reserves suggested by
structural and/or stratigraphic extrapolation beyond areas classified as
probable, based on geologic and/or geophysical interpretation; (2) reserves in
formations that appears to be hydrocarbon bearing based on logs or cores but
that may not be productive at commercial rates; (3) incremental reserves
attributable to infill drilling that are subject to technical uncertainty; (4)
reserves attributable to an improved recovery method when a project or pilot is
planned but not in operation and rock, fluid, and reservoir characteristics are
such that a reasonable doubt exists that the project will be commercial; and (5)
reserves in an area of a formation that has been proved productive in other
areas of the field but subject area appears to be separated from the proved area
by faulting and geologic interpretation indicates subject area is structurally
lower than the proved area.

<PAGE> 8

RESERVE STATUS CATEGORIES

Reserve status categories define the development and producing status
of wells and/or reservoirs.

PROVED DEVELOPED (SEC DEFINITION)

Proved developed oil and gas reserves are reserves that can be expected
to be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.

Developed reserves may be subcategorized as producing or non-producing
using the SPE/SPEE Definitions:

Producing

Producing reserves are expected to be recovered from completion intervals
open at the time of the estimate and producing. Improved recovery reserves
are considered to be producing only after an improved recovery project is in
operation.

Non-Producing

Non-producing reserves include shut-in and behind pipe reserves. Shut-in
reserves are expected to be recovered from completion intervals open at the
time of the estimate, but which had not started producing, or were shut-in
for market conditions or pipeline connection, or were not capable of
production for mechanical reasons, and the time when sales will start is
uncertain. Behind pipe reserves are expected to be recovered from zones
behind casing in existing wells, which will require additional completion
work or a future recompletion prior to the start of production.

PROVED UNDEVELOPED (SEC DEFINITION)

Proved undeveloped oil and gas reserves are reserves that are expected
to be recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required for recompletion. Reserves on
undrilled acreage shall be limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Estimates for proved undeveloped reserves are attributable to any
acreage for which an application of fluid injection or other improved technique
is contemplated, only when such techniques have been proved effective by actual
tests in the area and in the same reservoir.

<PAGE> 9

HYDROCARBON PRICING PARAMETERS

SECURITIES AND EXCHANGE COMMISSION PARAMETERS

OIL AND CONDENSATE

Mariner furnished us with oil and condensate prices in effect
at December 31, 1999 and these prices were held constant to depletion of the
properties. In accordance with Securities and Exchange Commission guidelines,
changes in liquid prices subsequent to December 31, 1999 were not considered in
this report.

PLANT PRODUCTS

Mariner furnished us with plant product prices in effect at
December 31, 1999 and these prices were held constant to depletion of the
properties.

GAS

Mariner furnished us with gas prices in effect at December 31,
1999 and with its forecasts of future gas prices which take into account SEC
guidelines, current spot market prices, contract prices, and fixed and
determinable price escalations where applicable. In accordance with SEC
guidelines, the future gas prices used in this report make no allowances for
future gas price increases which may occur as a result of inflation nor do they
make any allowance for seasonal variations in gas prices which may cause future
yearly average gas prices to be somewhat lower than December 31, 1999 gas
prices. For gas sold under contract, the contract gas price including fixed and
determinable escalations, exclusive of inflation adjustments, was used until the
contract expires and then was adjusted to the current market price for the area
and held at this adjusted price to depletion of the reserves.

<ARTICLE> 5
<MULTIPLIER> 1,000

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<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 123
<SECURITIES> 0
<RECEIVABLES> 23,683
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 28,697
<PP&E> 465,180
<DEPRECIATION> 199,233
<TOTAL-ASSETS> 297,512
<CURRENT-LIABILITIES> 60,987
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 65,025
<TOTAL-LIABILITY-AND-EQUITY> 297,512
<SALES> 52,468
<TOTAL-REVENUES> 52,468
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<OTHER-EXPENSES> 0
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<INTEREST-EXPENSE> 13,468
<INCOME-PRETAX> (9,970)
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</TABLE>