|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
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|UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549FORM 10-KFor the fiscal year ended December 31, 2001
Commission file number 333-12707Mariner Energy, Inc.(Exact name of registrant as specified in its charter)Internal Revenue Service - Employer Identification No. 86-0460233
State of other jurisdiction of incorporation or organization - Delaware580 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 requirement for the past 90
days. Yes [X]    No [ ]

Note: The Company is not subject to the filing requirements of the Securities Exchange Act of 1934. This
quarterly 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 not established public trading
market for the registrant's common stock.

As of March 4, 2002, there were 1,380 shares of the registrant's common stock outstanding.
See Part III, Item 13.  "Certain Relationships and Related Party Transactions" related to common stock ownership and other entities related to registrant.
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|TABLE OF CONTENTS                                                                               
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|PART I                                                                                          
|ITEMS 1. AND 2.    BUSINESS AND PROPERTIES                                                      
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|ITEM 3.    LEGAL PROCEEDINGS                                                                    
|ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS                                  
|PART II                                                                                         
|ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS                
|ITEM 6.    SELECTED FINANCIAL DATA                                                              
|ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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|ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK                             
|ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA                                          
|PART III                                                                                        
|ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT                                  
|ITEM 11.    EXECUTIVE COMPENSATION                                                              
|ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT                      
|ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS                                
|PART IV                                                                                         
|ITEM 14.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K                     
|GLOSSARY                                                                                        
|SIGNATURES                                                                                      



# PART I

Mariner Energy, Inc. ("Mariner" or the "Company") has provided definitions for some of the natural gas and oil industry
terms used in this report in the "Glossary " on page 82.

Cautionary Statement About Forward-Looking Statements

Some of the information in this Form 10-K contains forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The forward-looking statements speak only as of the
date made, and we undertake no obligation to update such forward-looking statements. These forward-looking statements may be
identified by the use of the words "believe," "expect," "anticipate," "will," "contemplate," "would" and similar expressions that
contemplate future events and subject to uncertainties. Actual results and trends in the future may differ materially depending on a
variety of factors including, but not limited to the following matters:

- Impact of bankruptcy proceedings related to our ultimate parent, Enron Corp. and affiliates;
- cash flow and liquidity;
- financial position;
- business strategy;
- budgets;
- amount, nature and timing of capital expenditures, including future development costs;
- drilling of wells;
- natural gas and oil reserves;
- timing and amount of future production of natural gas and oil;
- operating costs and other expenses;
- prospect development and property acquisitions; and
- marketing of natural gas and oil.

Numerous important factors, risks and uncertainties may affect our operating results, including:

- The risks associated with exploration;
- the ability to find, acquire, market, develop and produce new properties;
- natural gas and oil price volatility;
- uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of
development expenditures;
- operating hazards attendant to the natural gas and oil business;
- downhole drilling and completion risks that are generally not recoverable from third parties or insurance;
- potential mechanical failure or under-performance of significant wells;
- climatic conditions;
- availability and cost of material and equipment;
- delays in anticipated start-up dates;
- actions or inactions of third-party operators of our properties;
- the ability to find and retain skilled personnel;
- availability of capital;
- the strength and financial resources of competitors;
- regulatory developments;
- environmental risks; and
- general economic conditions.

Any of the factors listed above and other factors contained in this annual report could cause our actual results to differ
materially from the results implied by these or any other forward-looking statements made by us or on our behalf. We cannot provide
assurance that future results will meet our expectations. You should pay particular attention to the risk factors and cautionary
statements described under "Risk Factors" in "Item 7. Management's Discussion and Analysis of Financial Conditions and Results of
Operations."

## Items 1. and
2. Business and Properties

(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. 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." In
1996, Joint Energy Development Investments Limited Partnership ("JEDI"), an affiliate of Enron Corp. ("Enron") and Enron North
America Corp. ("ENA") (also see further description under "Enron" in "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations"), along with management led a buyout from Hardy Oil & Gas, Plc. JEDI currently owns
approximately 96%, while employees and former employees own the remaining 4% of Mariner Energy LLC, which owns 100% of Mariner
Holdings, Inc. Mariner Holdings, Inc. owns all of the common stock of Mariner.

     Since 1996, we significantly increased our focus in the Gulf of Mexico. Originally our focus included mainly Gulf of Mexico
shelf (less than 600 feet water depth) drilling and some Gulf of Mexico deepwater (greater than 600 feet water depth) exploitation
projects. These deepwater projects were subsea field developments that were tiebacks to near existing infrastructures (offshore
platforms). In 1998, our strategy was modified to seek larger exploration and lower risk exploitation projects in deepwater further
from infrastructure, however, we would continue to use subsea field development technology that we had developed. These larger
deepwater projects provided opportunities for oil and gas reserve growth. During this time, we were successful in discovering
deepwater wells, peaking in 2001, our most successful year in which we drilled seven successful exploratory wells and added
approximately 113.1 Bcfe in reserves.

     These deepwater projects have higher reserve potential, however, they are also typified by substantially higher development
costs and a less uniformed reserve and production growth pattern. In 2001, coinciding with several key management changes, we
shifted our focus to a more balanced portfolio approach. We expect to continue to exploit our expertise in deepwater opportunities
while also drilling opportunities in the Gulf of Mexico shelf. In addition, it is our current objective to reduce or eliminate our
need for capital infusions and reliance on our Revolving Credit Facility.

     During 2001, we drilled eleven exploratory wells with seven successes. Ryder Scott Company estimated that we had proved
reserves of 237.1 Bcfe as of December 31, 2001, the highest level in our history, of which 74% were natural gas and 26% were oil and
condensate. Proved reserves included net reserve additions of 113.1 Bcfe, representing 311% of 2001's company record production of
36.7 Bcfe. Year 2001, additions included first proved reserve bookings from the Yosemite, Falcon, Crater Lake, Swordfish, Roaring
Fork and Shasta projects. One successful well, Bass Lite, is still under development evaluation.

     We expect our production for 2002 to be slightly higher than 2001's average rate of 100 MMcfe per day, with production from
the King Kong / Yosemite project expected to offset anticipated production declines in our other fields. Our 2002 production rate is
expected to average 108 Mcfe per day. As of March 4, 2002, our daily production was 117 Mcfe.

     In 2002, we expect to drill six to eight exploratory wells. We have also increased our 3-D seismic database and leasehold
position in 2002 by committing to a $13 million seismic acquisition payable over 36 months and were apparent high bidder, at $10.9
million, net to us, on 12 central Gulf of Mexico leases at the Central Gulf of Mexico Lease Sale. Development activities in 2002
include the completion of our King Kong / Yosemite and Crater Lake projects, development of the Falcon, Swordfish and Roaring Fork
discoveries and several development wells in currently producing fields.

     We anticipate capital expenditures for 2002, net of proceeds from property conveyances of $48.8 million, to be approximately
$65.4 million for leasehold acquisition, exploration drilling and development projects, compared to our 2001 capital expenditures of
approximately $74.0 million, net of proceeds from property conveyances of $90.5 million. We expect to fund our capital expenditures
by a combination of internally generated cash flow, proceeds from property conveyances, including the recently-announced sale of half
of our remaining interest in the Falcon development project, 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, 2001. 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, held constant throughout the projected
reserve life. The year-end oil and gas prices utilized 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".

|                                                                          | YEAR ENDING DECEMBER 31,
(dollars in millions unless otherwise indicated)
|------------------------------------------------------------------------- | -------------------------------------------------------------------------
|                                                                          |                                                                          
|                                                                          | 2001                                                                     
|                                                                          |                                                                          
|PROVED RESERVES:                                                          |                                                                          
|Oil (MMbbls)                                                              | 10.1                                                                     
|Natural gas (Bcf)                                                         | 176.5                                                                    
|Natural gas equivalent (Bcfe)                                             | 237.1                                                                    
|PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES(1)                         | $232.0                                                                   
|ANNUAL RESERVE REPLACEMENT RATIO(2)                                       | 3.2                                                                      
|CAPITAL EXPENDITURES AND DISPOSAL DATA:                                   |                                                                          
|Capital costs incurred                                                    | $164.5                                                                   
|Proceeds from property conveyances                                        | (90.5)                                                                   
|                                                                          |                                                                          
|Capital costs net of proceeds from property conveyances                   | 74.0                                                                     
|                                                                          |                                                                          
|PERCENTAGE OF NET CAPITAL COSTS ATTRIBUTABLE TO:                          |                                                                          
|Lease acquisition                                                         | 5.4%                                                                     
|Exploratory drilling, geological and geophysical                          | 35.0%                                                                    
|Development and other                                                     | 59.6%                                                                    
|PRODUCTION:                                                               |                                                                          
|Oil (MMbls)                                                               | 3.0                                                                      
|Natural gas (Bcf)                                                         | 18.8                                                                     
|Natural gas equivalent (Bcfe)                                             | 36.7                                                                     
|AVERAGE REALIZED SALES PRICE PER UNIT
(excluding the effects of hedging): |                                                                          
|Oil ($/Bbl)                                                               | $22.41                                                                   
|Natural gas ($/Mcf)                                                       | 4.86                                                                     
|Gas equivalent ($/Mcfe)                                                   | 4.31                                                                     
|AVERAGE REALIZED SALES PRICE PER UNIT
(including the effects of hedging): |                                                                          
|Oil ($/Bbl)                                                               | $23.22                                                                   
|Natural gas ($/Mcf)                                                       | 4.57                                                                     
|Gas equivalent ($/Mcfe)                                                   | 4.22                                                                     
|EXPENSES ($/MCFE):                                                        |                                                                          
|Lease operating                                                           | $0.55                                                                    
|Transportation                                                            | 0.33                                                                     
|General and administrative, net                                           | 0.25                                                                     

1. Discounted at an annual rate of 10%. See "Glossary" included elsewhere in this annual 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 a Mcfe basis for the year by actual production on an Mcfe basis for such year.

(b) Recent Events

On March 20, 2002, with bids totaling $10.9 million net to us, we were the apparent high bidder solely or with industry
partners, on 12 out of 16 blocks on which we and our partners submitted bids in the Central Gulf of Mexico Oil and Gas Lease Sale 182
held on that date. Each of the blocks is in water depths ranging from approximately 20 feet to 2,400 feet. Mariner has a 100%
working interest in four of the blocks, 50% working interest in seven blocks and 20% working interest in one block.

     In April 2002, we sold 50% of our working interest in our Falcon discovery and surrounding blocks, located in East Breaks
Block 579 in the western Gulf of Mexico, for $48.8 million. Subsequent to the sale we have a 25% working interest in the discovery
and surrounding blocks. The project is currently expected to begin production in the first quarter of 2003. At December 31, 2001,
the Falcon project had 66.8 Bcfe assigned as proven oil and gas reserves to our interest.

     The net carrying value of our 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, based on year-end prices of $2.65 per Mcf of natural gas and $19.43 per Bbl of
crude oil, an impairment of oil and gas properties of approximately $37.8 million would be required as of December 31, 2001.
However, as allowed by the Securities and Exchange Commission guidelines, since both natural gas and crude oil prices have
significantly increased since year-end, no writedown was required as of December 31, 2001.

(c)Business Strategy

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

- Bulk Seismic Purchases. In 2001 and the first quarter of 2002, we acquired three bulk seismic databases covering blocks in
both the shelf and deepwater Gulf of Mexico. We believe maintaining a large 3-D seismic database allows us to identify high
quality exploratory prospects. This seismic data allows us to better understand the geology before selecting prospects and
increases the probability of accurately identifying the hydrocarbon-bearing zones.
- Diversify Our Portfolio.Currently, we maintain several large lease positions in the deepwater Gulf of Mexico. The most
significant, our Falcon discovery, we will control with our partners nearby infrastructure, which we believe gives us a
competitive advantage in this deepwater area (see "Recent Events" above). In addition, in an effort to balance our portfolio,
we recently bid $10.9 million, apparently successfully, for 12 shelf blocks in the 182 Central OCS Gulf of Mexico Lease Sale.
We plan on drilling four to five shelf prospects from these leases. Shelf wells are less expensive, lower risk, and can be connected to market relatively quickly compared
to Deepwater wells; however, the reserve targets are typically smaller than in the Deepwater.
- Reduce Dependence on Capital Infusions and Borrowings.Historically, we have been required to obtain significant capital
infusions from ENA (also see further description under "Enron" in "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations") and to sell various properties in order to manage our cash flow. In 2001, we sold two
projects for approximately $90.5 million, which allowed us to maintain a high level of exploratory activity in addition to
repaying our Revolving Credit Facility. Subsequent to year-end, we sold 50% of our working interest in our Falcon project for
$48.8 million. The proceeds of the sale will be used to maintain an active exploration program and minimize the use of our
Revolving Credit Facility. We will continue to monetize non-core assets to redeploy capital into high quality projects.
- 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. Our
geoscientists average more than 20 years of experience in the exploration and production business, including extensive
experience in the Gulf and with major oil companies. Through our technical staff's understanding of the geology and geophysics
of the Gulf, we intend to continue to generate the majority of our prospects internally.
- Control Administrative Costs. In order for us to be competitive, we understand we must control administrative costs. In
September 2001, we reduced our workforce by approximately 20%. We believe these reductions will allow us to control costs
while maintaining necessary technical expertise. In addition, we will continue to generate reimbursements of costs through
joint ventures with partners.

(d) Reserves

The following table sets forth certain information with respect to our proved reserves by geographic area as of December 31,
2001. Reserve volumes and values were determined under the method prescribed by the Securities and Exchange Commission which requires
the application of year-end prices held constant throughout the projected reserve life. The reserve information as of December 31,
2001 is based upon a reserve report prepared by the independent petroleum consulting firm of Ryder Scott Company, independent reserve
engineers. 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 11 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.

|                                          | AS OF DECEMBER 31, 2001  
|----------------------------------------- | -------------------------
|                                          | PROVED RESERVE QUANTITIES
|                                          |                          
|                                          |                          
|Geographic Area                           | Oil     (MMBbls)         
|Deepwater Gulf                            | 4.3                      
|Gulf Shallow Water and Gulf Coast Onshore | 1.6                      
|Permian Basin                             | 4.2                      
|                                          |                          
|Total                                     | 10.0                     
|                                          |                          
|Proved Developed Reserves                 | 4.7                      
|                                          |                          

1. Discounted (at 10%) present value as of December 31, 2001 (year-end prices held constant).

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

(e) Oil and
Gas Properties

(i) Significant Properties with Proved Reserves as of December 31, 2001

We own oil and gas properties, both producing and not producing, onshore in Texas and offshore in the Gulf, primarily in
federal waters. Our 10 largest producing properties, as shown in the following table, accounted for approximately 95% of the
Company's proved reserves as of December 31, 2001.

|                                           | OPERATOR   | MARINERWORKINGINTEREST | APPROXIMATEWATERDEPTH (FEET) | PRODUCINGWELLS(3) | DATEPRODUCTIONCOMMENCED/EXPECTED | NETPROVEDRESERVES(BCFE)
|------------------------------------------ | ---------- | ---------------------- | ---------------------------- | ----------------- | -------------------------------- | -----------------------
|                                           |            |                        |                              |                   |                                  |                        
|DEEPWATER GULF:                            |            |                        |                              |                   |                                  |                        
|East Breaks 579 (Falcon)(1)                | Mariner    | 50%                    | 3,400                        | -                 | 1stquarter 2003                  | 66.8                   
|Green Canyon 472 (King Kong)               | Mariner    | 50%                    | 3,900                        | -                 | 1stquarter 2002                  | 31.1                   
|Mississippi Canyon 718 (Pluto)             | Mariner    | 51%                    | 2,710                        | 1                 | December 1999                    | 16.3                   
|Ewing Bank 966 (Black Widow)               | Mariner    | 69%                    | 1,850                        | 1                 | October 2000                     | 15.9                   
|Green Canyon 516 (Yosemite)                | Mariner    | 44%                    | 3,850                        | -                 | 1stquarter 2002                  | 14.9                   
|Viosca Knoll 917 (Swordfish)               | Mariner    | 15%                    | 4,200                        | -                 | 4thquarter 2003                  | 10.1                   
|Mississippi Canyon 322 (Crater Lake)       | Walter O&G | 40%                    | 700                          | -                 | 1stquarter 2002                  | 5.5                    
|GULF SHALLOW WATER AND GULF COAST ONSHORE: |            |                        |                              |                   |                                  |                        
|South Timbalier 316 (Roaring Fork)         | Westport   | 20%                    | 450                          | -                 | 3rdquarter 2003                  | 12.9                   
|Brazos A-105                               | Spirit     | 12.5%                  | 192                          | 5                 | January 1993                     | 5.1                    
|PERMIAN BASIN OF WEST TEXAS:               |            |                        |                              |                   |                                  |                        
|Spraberry Aldwell Unit(2)                  | Mariner    | 70.3%                  | Onshore                      | 81                | 1949                             | 46.9                   
|OTHER PROPERTIES:                          | --         | --                     | --                           | 49                | --                               | 11.6                   
|                                           |            |                        |                              |                   |                                  |                        
|TOTAL PROVED RESERVES:                     |            |                        |                              |                   |                                  | 237.1                  
|                                           |            |                        |                              |                   |                                  |                        

1. In April 2002, 50% of our working interest was sold for $48.8 million.
2. We operate the unit and own working interests in individual wells ranging from approximately 33% to 84%.
3. King Kong and Crater Lake projects began production in February 2002 and our Yosemite project began production in April 2002.

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

Gulf of Mexico

East Breaks 579 (Falcon)Mariner generated and acquired the Falcon prospect at a federal lease sale in August 1997. We
operate and have a 50% working interest (prior to the April 2002 sale of 50%) in this project, which is located in the deepwater Gulf
of Mexico 95 miles southeast of Corpus Christi, Texas in a water depth of 3,400 feet. In April 2001, the Mariner EB 579 #1 well was
drilled and yielded a significant discovery that was sanctioned for development in October of the same year. Estimated net proved
reserves from Falcon are 66.8 Bcfe. First production is anticipated to commence in first quarter of 2003 (also see "Recent Events").

     Green Canyon 472 / Green Canyon 516 (King Kong / Yosemite)In July 2000, we entered into an agreement to acquire Shell
Exploration and Production Company's 50% working interest in the "King Kong" Gulf of Mexico development project. The project is
located in approximately 3,900 feet of water in Green Canyon Blocks 472 and 473, approximately 150 miles southeast of New Orleans. We
purchased Shell's interest for an undisclosed amount of cash and overriding royalty interest in the field, and have been named
operator for development of the project. Agip Petroleum Co. Inc., as a successor to British Borneo, owns the remaining 50% working
interest. This project began production in February 2002 and it ties back 16 miles to the Allegheny mini-TLP operated by Agip. In
2001 we drilled our "Yosemite" exploration prospect located adjacent to King Kong in Green Canyon Block 516. Yosemite is jointly
developed with King Kong. The combined projects have estimated net proved reserves of 46.0 Bcfe as of December 31, 2001 and as of
April 15, 2002 were producing at a gross rate of 165 Mmcfe per day.

     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. Due to high natural gas commodity prices, however, royalty relief did not apply to natural gas
production in 2000 or 2001. 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, which occurred in the third quarter of 2000, our working interest increased to 51% and
Burlington's working interest decreased to 49%. We developed the field with a single subsea well which is located in the Gulf
approximately 150 miles southeast of New Orleans, Louisiana at a water depth of 2,710 feet and a flow line tied back approximately 29
miles to a production platform on the shelf. Production began on December 29, 1999 and through December 31, 2001 the field produced
net 21.5 Bcfe. As of December 31, 2001, the field had estimated remaining net proved reserves of 16.3 Bcfe, 75% of which was natural
gas.

     Ewing Bank 966 (Black Widow)We acquired the Black Widow prospect 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 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
commenced production in the fourth quarter of 2000 via subsea tieback to an existing platform, and the field has produced through
December 31, 2001 net 14.85 Bcfe. Estimated remaining net proved reserves from Black Widow are approximately 15.9 Bcfe, 87.6% of
which is oil.

     Viosca Knoll 917 (Swordfish)Mariner entered into a farmout agreement with BP (Amoco) in September 2001 to drill the
Swordfish prospect. We operate and have a 15% working interest in this project, which is located in the deepwater Gulf of Mexico 105
miles southeast of New Orleans, Louisiana in water depths that range from 4,200 feet. In November and December of 2001, Mariner
drilled two successful exploration wells on the prospect. Estimated net proved reserves for the Swordfish prospect are 10.1 Bcfe.
First production is anticipated to commence in the fourth quarter of 2003.

     Mississippi Canyon 322 (Crater Lake)Mariner generated and acquired the Crater Lake prospect at a federal sale in March of
1998. Mariner has a 40% working interest in this Walter Oil & Gas operated project, which is located in the deepwater Gulf of Mexico
75 miles southeast of New Orleans, Louisiana in a water depth of 700 feet. In May of 2001, Walter Oil and Gas drilled a successful
exploration well and a successful appraisal that were later completed. First production from the initial discovery well began
February 2002, and the current rate is 10 mmcfd. Production from the second well will begin upon depletion of the initial well. The
estimated net proved reserves from Crater Lake are 5.5 Bcfe.

     South Timbalier 316 (Roaring Fork)Mariner entered into a farmout agreement with Westport and Samedan in October 2001 to
participate in the drilling of the Roaring Fork prospect. Mariner has a 20% working interest in this Westport operated project,
which is located in the Gulf of Mexico 135 miles south of New Orleans, Louisiana in a water depth of 450 feet. Westport drilled a
successful exploration well on the prospect followed by two successful appraisal wells. The estimated net proved reserves for the
Roaring Fork prospect are 12.9 Bcfe. First production is anticipated to commence in the fourth quarter of 2003.

     Brazos A-105We generated the Brazos A-105 prospect and own a 12.5% 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 26.6 Bcfe net to us from its inception through December 31, 2001. The field had estimated
remaining net proved reserves of 5.1 Bcfe as of December 31, 2001, 99% of which was natural gas.Permian Basin of West Texas

     Spraberry Aldwell UnitWe 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 81 producing wells in the unit. Depending
upon, 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, 2001 were 46.9 Bcfe. We believe that the field's
potential for continued economic oil production exceeds 40 years.

     (ii) 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. We also consider the sale of discoveries that are not yet producing when we
believe we can obtain acceptable returns on our investment without holding the investment through depletion. Such sales enable us to
maintain financial flexibility, reduce overhead and redeploy the proceeds to activities that we believe have a higher potential
financial return. No property dispositions of producing properties were made during the three years ending December 31, 2001.
However, in 2001, 2000 and 1999 we sold a 63% gross pre-payout interest in our Pluto project for approximately $19 million (our
post-payout interest is a 51% working interest), a 20% gross interest in our Devils Tower project for $25 million and a 30% gross
interest in our Devils Tower project and 50% interest in our Aconcagua project for $39.5 million and $51 million respectively. In
April 2002, we sold 50% of our working interest in the Falcon project for $48.8 million. See "Recent Events" above.

     (iii) 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.

     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.(f)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.

|Year Ending December 31,                                            
|--------------------------------------------------------------------
|                                                                    
|                                                                    
|                                                                    
|PRODUCTION:                                                         
|Oil (MMbbls)                                                        
|Natural gas (Bcf)                                                   
|Natural Gas equivalent ((Bcfe)                                      
|AVERAGE REALIZED SALES PRICE PER UNIT(EXCLUDING EFFECTS OF HEDGING):
|Oil ($/Bbl)                                                         
|Natural gas ($/Mcf)                                                 
|Natural Gas equivalent ($/Mcfe)                                     
|AVERAGE REALIZED SALES PRICE PER UNIT(INCLUDING EFFECTS OF HEDGING):
|Oil ($/Bbl)                                                         
|Natural gas ($/Mcf)                                                 
|Natural Gas equivalent ($/Mcfe)                                     
|EXPENSES ($/MCFE):                                                  
|Lease operating                                                     
|Transportation                                                      
|General and administrative, net(1)                                  
|Depreciation, depletion and amortization                            
|CASH MARGIN ($/MCFE)(2)                                             

1. Net of overhead reimbursements received from other working interest
owners and amounts capitalized under the full cost accounting method.
2. Average equivalent gas sales price (including the effects of hedging
prior to de-designation as a hedge), minus lease operating and gross general and
administrative expenses.

(g) 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, 2001:

|      | TOTALPRODUCTIVEWELLS
|----- | --------------------
|
|      |                     
|Oil   | 88                  
|Gas   | 49                  
|      |                     
|TOTAL | 137                 
|      |                     

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.(h)Acreage

     The following table sets forth certain information with respect to the developed and undeveloped acreage as of December 31,
2001.

|                       | DEVELOPEDACRES(1) | UNDEVELOPEDACRES(2)
|---------------------- | ----------------- | -------------------
|
|
|Texas (Onshore)        | 18,337            | 12,300             
|Other states (Onshore) | 671               | 212                
|                       |                   |                    
|Offshore               | 317,244           | 100,571            
|                       |                   |                    
|Total                  | 336,252           | 113,083            
|                       |                   |                    

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.

(i) Drilling Activity

     Certain information with regard to our drilling activity during the years ended December 31, 2001, 2000 and 1999 is set
forth below.

|                   | YEAR ENDING DECEMBER 31,
|------------------ | ------------------------
|
|
|
|
|
|EXPLORATORY WELLS:
|Producing          | 7                       
|Dry                | 4                       
|                   |                         
|Total              | 11                      
|                   |                         
|DEVELOPMENT WELLS:
|Producing          | 7                       
|Dry                | 1                       
|                   |                         
|Total              | 8                       
|                   |                         
|TOTAL WELLS:      
|Producing          | 14                      
|Dry                | 5                       
|                   |                         
|Total              | 19                      
|                   |                         

(j) Marketing, Customers and Hedging Activities

     We market substantially all oil and gas production from properties we operate and properties operated by others where our
interest is significant. The majority of 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 for the sale and processing of such gas on terms that we believe to be competitive. The following table lists
customers accounting for more than 10% of our total revenues for the year indicated.

|                                                                  | PERCENTAGE OF TOTAL REVENUESFOR THE YEAR ENDINGDECEMBER 31,
|----------------------------------------------------------------- | -----------------------------------------------------------
|
|
|Enron North America and affiliates  (An affiliate of the Company) | 32%                                                        
|Genesis Crude Oil LP                                              | 24%                                                        
|Duke Energy                                                       | 14%                                                        

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. Effective December 2001, we no longer sold
our production to ENA. The loss of ENA as a purchaser has not had a material effect on the commodity prices we have received (also
see further description under "Enron" in "Item 7. Management's Discussion and Analysis of Financial Conditions and Results of
Operations").

     The following table sets forth the results of hedging transactions during the periods indicated. For the year ended December
31, 2001, the amounts are reflective of the results up to the point of de-designation (also see further description under "Enron" in
"Item 7. Management's Discussion and Analysis of Financial Conditions and Results of Operations") (December 2, 2001), which include
all settled contract months through December of 2001:

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

|                                                     | YEAR ENDING DECEMBER 31,
|---------------------------------------------------- | ------------------------
|
|
|
|Natural gas quantity hedged (Mmbtu)                  | 17,733                  
|Increase (decrease) in natural gas sales (thousands) | $(5,523)                
|Crude oil quantity hedged (MBbls)                    | 752                     
|Increase (decrease) in crude oil sales (thousands)   | $2,393                  

The following table sets forth our open positions as of December 31, 2001.

|TIME PERIOD                   | NOTIONALQUANTITIES | FIXED PRICE | FAIR VALUE(in millions)
|----------------------------- | ------------------ | ----------- | -----------------------
|NATURAL GAS (MMBTU)          
|January 1 - October 31, 2002 
|Fixed price swap purchased    | 1,831              | $2.18       | $(0.9)                 
|January 1 - December 31, 2002
|Fixed price swap purchased    | 12,134             | 4.43        | 20.4                   
|April 1 - December 31, 2002  
|Fixed price swap purchased    | 4,125              | 3.03        | 0.9                    
|January 1 - December 31, 2003
|Fixed price swap purchased    | 3,650              | 3.74        | 2.0                    
|CRUDE OIL (MBBL)             
|January 1 - June 30, 2002    
|Fixed price swap purchased    | 181                | 25.15       | 0.9                    
|January 1 - December 31, 2002
|Fixed price swap purchased    | 365                | 25.48       | 1.9                    
|Sub-Total                     |                    |             | $25.2(1)               
|                              |                    |             |                        
|Allowance for impairment      |                    |             | $(22.7)                
|                              |                    |             |                        
|Total                         |                    |             | $2.5                   
|                              |                    |             |                        

1. Subsequent to the date of default by Enron and ENA, and as of December 31, 2001,
the contracts decreased in gross market value by $523,000, which is reflected in
the impairment of related party receivables at the net valuation of 10% or
$52,000, after consideration for allowance.

(k)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.(l)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:

|WATER DEPTH          | ROYALTY RELIEF                                   
|-------------------- | -------------------------------------------------
|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

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 ("MMS") 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. In the event that prices exceed certain prescribed thresholds royalty relief is suspended. In
2000 and 2001, our Pluto, Black Widow, Garden Banks 179 and King Kong projects qualified for royalty relief however natural gas
prices exceeded the thresholds. Consequently, we have been required to pay royalties on natural gas for both 2000 and 2001. As of
December 31, 2001, we have accrued $4.7 million related to this obligation.(m)Regulation

     Our operations are subject to extensive and continually changing regulation affecting the oil and natural gas industry. 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. We do not believe that we are affected in a significantly different manner by these
regulations than are our competitors.(i) Transportation and Sale of Natural Gas

     The FERC (Federal Energy Regulatory Commission) 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 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 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, 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 is 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.(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.

     Resources Conservation Recovery Act. The Resource Conservation Recovery Act ("RCRA") is the principal 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.(n)Employees

     As of December 31, 2001, we had 55 full-time employees. Our employees are not represented by any labor unions. We consider
relations with our employees to be satisfactory. We have never experienced a work stoppage or strike.Item 3. Legal Proceedings

     In the ordinary course of business, we are a claimant and/or a defendant in various 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.

     Also see further description under "Enron" in "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations" regarding matters that could impact the Company operations.Item 4. Submission of Matters to a Vote of Security Holders

     None.



# PART II

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.

     See Part III, Item 13. "Certain Relationships and Related Party Transactions" related to common stock ownership and other
entities related to registrant.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.

|(All amounts in millions)                                                     
|------------------------------------------------------------------------------
|
|
|
|
|Total revenues                                                                
|Lease operating expenses                                                      
|Transportation                                                                
|Depreciation, depletion and amortization                                      
|Impairment of oil and gas properties                                          
|Impairment of Enron related receivables                                       
|Provision for Litigation                                                      
|General and administrative expenses                                           
|                                                                              
|Operating income (loss)                                                       
|Interest income                                                               
|Interest expense                                                              
|Income (loss) before income taxes                                             
|Provision for income taxes                                                    
|                                                                              
|Net income (loss)                                                             
|                                                                              
|CAPITAL EXPENDITURE AND
DISPOSAL DATA:                                        
|Exploration, including leasehold/seismic                                      
|Development and other                                                         
|Proceeds from property conveyances                                            
|                                                                              
|Total capital
expenditures net of
          proceeds from property
conveyances
|                                                                              
|BALANCE SHEET DATA (AT END OF
PERIOD):                                        
|Oil and gas properties, net,
at full cost                                     
|Total assets                                                                  
|Long-term debt, less current maturities                                       
|Stockholder's equity                                                          

1. Historically we have recorded all derivative transactions utilizing hedge
accounting treatment. On January 1, 2001 we
adopted Financial Accounting Standard No. 133 Accounting for Derivative
Instruments and Hedging Activities.  In addition, beginning on December 2, 2001, due to the Enron
bankruptcy, we ceased hedging accounting treatment.

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, 1999 and ended December 31, 2001. 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, we 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 profitably increase reserves, production and cash flow primarily through the
drillbit.

     During 2001 we:

- drilled eleven (11) exploratory wells, with seven (7) successes, in the Gulf of Mexico;
- drilled successful appraisal wells on our Aconcagua, King Kong, Crater Lake, Shasta, Swordfish and Roaring Fork prospects;
- completed a full year of production from our Black Widow project, which, when
combined with production from other projects, resulted in the highest level of
production in our history;
- sold our interest in Devils Tower and Aconcagua discoveries, with proceeds from
these sales being used to pay off our Revolving Credit Facility;
- added proved reserves of 113.1 Bcfe, which were approximately 311% of our 2001
production of 36.7 Bcfe, excluding 47.2 Bcfe in dispositions of our Aconcagua
and Devils Tower projects.

We anticipate capital expenditures for 2002, net of proceeds from property conveyances of $48.8 million, to be approximately
$65.4 million for leasehold acquisition, exploration drilling and development projects, compared to our 2001 capital expenditures of
approximately $74.0 million, net of proceeds from property conveyances of $90.5 million. We expect to fund our capital expenditures
by a combination of internally generated cash flow, proceeds from property conveyances, including the recently announced sale of half
of our remaining interest in the Falcon development project, and borrowings under our Revolving Credit Facility.

     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.(c) Enron-Control Relationships and Related Party Transactions

     Enron Bankruptcy- On December 2, 2001, Enron Corp. ("Enron") and one of its affiliates,Enron
North America Corp. ("ENA"), among other affiliates filed voluntary petitions for bankruptcy protection. The Company has been informed that of the various
affiliates of Enron to Mariner, only Enron and ENA are included in the bankruptcy. We do not know at this time if any other
affiliates of Enron will seek bankruptcy protection or what effect, if any, this may have on Joint Energy Development Investments Limited
Partnership ("JEDI") or the ownership of Mariner Energy LLC which owns 100% of our direct parent. Enron is the parent of ENA, and
an affiliate of ENA is the general partner of JEDI. JEDI is 100% owned by several different Enron and ENA affiliates. Accordingly,
Enron may be deemed to control JEDI, Mariner Energy LLC, Mariner Holdings and the Company. Additionally, seven of the Company's
directors are officers of Enron or affiliates of Enron. Because of these various potentially 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.

     Mariner Energy LLC's only asset is 100% of the common stock of Mariner Holdings, Inc., our direct parent. The only asset
of Mariner Holdings is 100% of the common shares of Mariner. Covenants in Mariner's Revolving Credit Facility and Senior
Subordinated Notes restrict the funds of Mariner that can be distributed to Mariner Energy LLC to repay its term loan to an ENA
affiliate - see below "ENA Affiliate Term Loan". Mariner Energy LLC is currently attempting to obtain an extension of the ENA
Affiliate Term Loan, but there can be no assurance that an extension will be obtained. In the event Mariner Energy LLC is unable to
obtain an extension or restructure its obligations, it would either default or be forced to sell its interest in Mariner or cause
Mariner to sell a substantial portion of its assets to repay its Revolving Credit Facility, if any amounts are outstanding, and
outstanding Senior Subordinated Notes so that it could distribute any remaining cash proceeds to Mariner Energy LLC to be used to
repay the ENA Affiliate Term Loan.

     As a result of the Enron and ENA bankruptcies, among other implications, as part of our normal operations we may not be able
to obtain credit from banks or trade vendors or enter into hedging arrangements on acceptable terms. This may also hinder our
ability to enter into certain transactions including purchase or sale arrangements and conduct significant capital programs.

     Organization and Ownership of the Company - 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 company
incorporated in the United Kingdom. Pursuant to a stock purchase agreement dated April 1, 1996, JEDI and ENA, together with members
of management of the Predecessor Company, formed Mariner Holdings, Inc. ("Mariner Holdings"). Mariner Holdings 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 (the "Acquisition"). After the Acquisition, the name of the Predecessor Company was changed to Mariner Energy, Inc. In
October 1998, JEDI and other shareholders exchanged all of their common shares of Mariner Holdings, the Company's direct parent, for
an equivalent ownership percentage in common shares of Mariner Energy LLC. Mariner Energy LLC owns 100% of Mariner Holdings.

     The following chart represents our current ownership structure and affiliation with Enron entities.



Subsequent to the Acquisition, Mariner Energy LLC, Mariner Holdings and Mariner have each entered into various
financing and operating transactions with affiliates. In addition the Company may have from time to time engaged 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 and entering into other oil and
gas related or financial transactions. Certain of the Company's third-party debt instruments and arrangements 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 obtained in an agreement with a third party. Below is a
summary of key transactions between the Company and affiliate entities.Mariner Energy LLC

     ENA Credit Facility - In September 1998 Mariner Holdings established a credit facility to obtain additional capital. The
credit facility, as subsequently amended and assigned to Mariner Energy LLC, provided for unsecured, subordinated loans of up to $50
million, bearing interest at LIBOR plus 4.5%, payable at April 30, 2000. The full amount borrowed under this credit facility was
repaid on March 21, 2000 with proceeds from the ENA Affiliate Term Loan described below. The net proceeds from this facility were
contributed to Mariner.

     ENA Affiliate Term Loan - In March 2000, Mariner Energy LLC established an unsecured term loan with ENA to repay amounts
outstanding under the ENA Credit Facility with Mariner Energy LLC ($50 million plus accrued interest) described above and Mariner's
Senior Credit Facility with ENA ($25 million plus accrued interest), described below, and to provide additional working capital. The
additional working capital of $55 million was contributed to Mariner in 2000. The loan bears interest at 15%, which interest accrues
and is added to the loan principal. Repayment of the balance of loan principal and accrued interest, which was approximately $143
million as of December 31, 2001, is due March 20, 2003. As part of the loan agreement, two five-year warrants were issued to ENA
providing the right to purchase up to 900,000 of common shares of Mariner Energy LLC for $0.01 per share.

     We have been informed that the Term Loan was transferred from ENA to an ENA affiliate.Mariner Holdings, Inc.

     1998 Equity Investment - In June 1998, Mariner Holdings issued additional equity to its existing shareholders, including
JEDI, for approximately $14.58 per share, for a net investment of $28.8 million, all of which was contributed to Mariner. Mariner
Holdings paid approximately $1.2 million as a structuring fee, on a pro rata basis, to existing shareholders participating in this
transaction. Approximately $1 million of this fee was paid to ECT Securities Limited Partnership.Mariner Energy, Inc.

     Senior Credit Facility with ENA - In April 1999 Mariner established a senior credit facility with ENA primarily to obtain
additional working capital. The facility provided for senior unsecured revolving loans of up to $25 million, bearing interest at
LIBOR plus 2.5%, payable quarterly. The full amount borrowed under the senior credit facility was repaid on March 21, 2000, with
proceeds from the ENA Affiliate Term Loan described above.Other Transactions

     Oil and Gas Production Sales to ENA or Affiliates - During the three years ending December 31, 2001, 2000 and 1999, sales of
oil and gas production to ENA or affiliates were $50.2 million, $73.4 million and $16.2 million, respectively. These sales were generally made on 1 to 3
month contracts. At the time ENA filed its petition for bankruptcy protection, the Company immediately ceased selling its physical
production to ENA. As of December 31, 2001, we had an outstanding receivable for $3.0 million from ENA. This amount was not paid as
scheduled and is still outstanding. The Company has estimated 90% of this balance is uncollectible and has recorded an allowance and
related expense for $2.7 million.

     Accounting for Price Risk Management Activities- Mariner engages in price risk management activities from time to time.
These activities are intended to manage Mariner's exposure to fluctuations in commodity prices for natural gas and crude oil. The
Company primarily utilizes price swaps and costless collars as a means to manage such risk. During 2001 and as of December 31, 2001,
all of our hedging contracts were with ENA. As a result of ENA's bankruptcy, the contracts are currently in default. The November
and December settlements for oil and gas have not been collected, and there is significant uncertainty that the $4.0 million owed to
the Company for the November and December settlements or any future settlements will be collected. As a result of the default, the
Company has recorded an allowance representing 90% of the recorded hedge settlements receivable of $4.0 million, fair market value of
the derivative assets of $25.8 (as of December 2, 2001), and accounts receivable for oil and gas sales of $3.0 million. Reflected in
the earnings of the Company for the period ended December 31, 2001 is a loss for impairment of Enron related receivables of $29.5
million. In accordance with Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and
Hedging Activities," as amended by SFAS No. 137 and No. 138, we have de designated our contracts effective December 2, 2001 and are
recognizing all market value changes subsequent to such de-designation in earnings of the Company. The value recorded up to the time
of de-designation and included in Accumulated Other Comprehensive Income ("AOCI"), will reverse out of AOCI and into earnings as the
original corresponding production, as hedged by the contracts, is produced. As of December 31, 2001, $25.8 million remained in AOCI
to be reversed out during the contract periods covering January 1, 2002 through December 31, 2003. Due to the uncertainty of future
settlements, the overall effect of the ENA bankruptcy has been to eliminate our commodity price hedge protection.

     The following table sets forth the results of hedging transactions during the periods indicated. For the year ended December
31, 2001, the amounts are reflective of the results up to the point of de-designation (December 2, 2001), which include all settled
contract months through December of 2001:

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

|                                                     | YEAR ENDING DECEMBER 31,
|---------------------------------------------------- | ------------------------
|
|
|
|Natural gas quantity hedged (Mmbtu)                  | 17,733                  
|Increase (decrease) in natural gas sales (thousands) | $(5,523)                
|Crude oil quantity hedged (MBbls)                    | 752                     
|Increase (decrease) in crude oil sales (thousands)   | $2,393                  

The following table sets forth our open positions as of December 31, 2001.

|TIME PERIOD                   | NOTIONALQUANTITIES | FIXED PRICE | FAIR VALUE(in millions)
|----------------------------- | ------------------ | ----------- | -----------------------
|NATURAL GAS (MMBTU)          
|January 1 - October 31, 2002 
|Fixed price swap purchased    | 1,831              | $2.18       | $(0.9)                 
|January 1 - December 31, 2002
|Fixed price swap purchased    | 12,134             | 4.43        | 20.4                   
|April 1 - December 31, 2002  
|Fixed price swap purchased    | 4,125              | 3.03        | 0.9                    
|January 1 - December 31, 2003
|Fixed price swap purchased    | 3,650              | 3.74        | 2.0                    
|CRUDE OIL (MBBL)             
|January 1 - June 30, 2002    
|Fixed price swap purchased    | 181                | 25.15       | 0.9                    
|January 1 - December 31, 2002
|Fixed price swap purchased    | 365                | 25.48       | 1.9                    
|Sub-Total                     |                    |             | $25.2(1)               
|                              |                    |             |                        
|Allowance for impairment      |                    |             | $(22.7)                
|                              |                    |             |                        
|Total                         |                    |             | $2.5                   
|                              |                    |             |                        

1. Subsequent to the date of default by Enron and ENA, and as of December 31, 2001, the contracts decreased in gross market
value by $523,000, which is reflected in the impairment of related party receivables at the net valuation of 10% or
$52,000, after consideration for allowance.

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 that is not in bankruptcy, purchased the flowline from the
Company and its joint interest partners. The Company received $8.8 million in cash proceeds that 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
with MEGS LLC at a rate of $0.26 per Mmbtu to transport the Company's share of 86 Bcf of natural gas from the commencement of
production through March 2009. The Company's working interest in the well at December 31, 2001 was 51%. For the year ending
December 31, 2001, the Company paid $4.2 million on this contract. The remaining volume commitment is 30.8 Bbtu or $7.9 million net
to the Company. Pursuant to the contract, the Company must deliver minimum quantities through the flowline or be subject to minimum
monthly payment requirements. Throughout 2001 the Company failed to meet these minimum requirements and paid $1.5 million relating to
the shortfall. The Company estimates that future production will also fail to meet minimum delivery requirements and has accrued
$972,000 for future shortfalls.

     Services Agreement- In conjunction with the change of certain key management positions, the Company entered into a services
agreement for ENA to provide certain administrative services. The Company is obligated to pay $45,000 per month under this agreement.

     Supplemental Affiliate Data- Provided below is supplemental balance sheet and income statement amounts for affiliate
entities:

|                                        | YEAR ENDED DECEMBER 31,
|--------------------------------------- | -----------------------
|
|
|RELATED PARTY RECEIVABLE:               |                        
|Derivative Asset                        | $2.5                   
|Settled Hedge Receivable                | 0.4                    
|Oil and Gas Receivable                  | 0.3                    
|ACCURED LIABILITIES:                    |                        
|Transportation Contract                 | $0.9                   
|Service Agreement                       | $0.3                   
|STOCKHOLDERS' EQUITY:                  
|Common Stock                            | $0.001                 
|Additional Paid-in Capital              | $227.3                 
|INCOME STATEMENT DATA                  
|Oil and Gas Sales                       | $50.2                  
|General and Administrative Expenses     | 0.2                    
|Transportation Expenses                 | 4.2                    
|Impairment of Enron Related Receivables | 29.5                   

(d) Risk Factors

     Exploration Risks- In addition to the other information set forth elsewhere in this annual report, including the potential
impact of the Enron bankruptcy matters, the following factors should be carefully considered when evaluating Mariner. Exploration is
a high-risk activity, and the 3-D seismic data and other advanced technologies we use cannot eliminate exploration risk. In
addition, use of these technologies requires experienced technical personnel who we may be unable to attract or retain.

     Our future success will depend on the success of our exploratory drilling program. Exploration activities involve numerous
risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. In addition, we are often
uncertain as to the future cost or timing of drilling, completing and producing wells. Furthermore, drilling operations may be
curtailed, delayed or canceled as a result of the additional exploration time and expense associated with a variety of factors,
including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, adverse weather
conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rigs or equipment.

     Even when used and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists and
geologists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if
hydrocarbons are present or economically producible. We could incur losses as a result of exploratory drilling expenditures. Poor
results from exploration activities could affect future cash flows and results of operations materially and adversely.

     Our exploratory drilling success will depend, in part, on our ability to attract and retain experienced explorationists and
other professional personnel. Competition for explorationists and engineers with experience in the Gulf of Mexico is intense. If we
cannot retain our current personnel or attract additional experienced personnel, our ability to compete in the Gulf of Mexico could
be adversely affected.

     Exploration for natural gas and oil at deeper drilling depths and in the deep waters of the Gulf of Mexico involves greater
operational and financial risks than exploration at shallower depths and in shallower waters. These risks could result in substantial
losses.

     Prospect Development Risks- Our 2001 discoveries on East Breaks 579 ("Falcon"), Viosca Knoll 917 ("Swordfish") and South
Timbalier ("Roaring Fork") have required and over the next two years will continue to require significant financial resources. We do
not expect production from these discoveries to commence prior to 2003, but we must commit substantial resources in advance of the
expected production date and cannot predict the price of oil if and when production commences.

     Operative Risks- The natural gas and oil business involves a variety of operating risks, including fires, explosions,
blow-outs and surface cratering, uncontrollable flows of underground natural gas, oil and formation water, natural disasters, pipe or
cement failures, casing collapses, embedded oilfield drilling and service tools, abnormally pressured formations and environmental
hazards such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases. If any of these events occur, we
could incur substantial losses as a result of injury or loss of life, severe damage to and destruction of property, natural resources
and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties,
suspension of our operations and repairs to resume operations. If we experience any of these problems, well bores, platforms,
gathering systems and processing facilities could be adversely affected, which in turn could adversely affect our ability to conduct
operations.

     Offshore operations are also subject to a variety of operating risks specific to the marine environment, such as capsizing,
collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to
facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds
available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties.

     Production of reserves from reservoirs in the Gulf of Mexico generally declines more rapidly than from reservoirs in many
other producing regions of the world. This results in recovery of a relatively higher percentage of reserves from properties in the
Gulf of Mexico during the initial few years of production. As a result, reserve replacement needs from new prospects are greater and
require us to incur significant capital expenditures to replace production.

     Financial Position Risks- For some risks, we may not obtain insurance if we believe the cost of available insurance is
excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a
significant accident or other event occurs and is not fully covered by insurance, it could adversely affect our operations.

     As part of our strategy, we explore for natural gas and oil at deeper drilling depths and in the deep waters of the Gulf of
Mexico, where operations are more difficult and costly than at shallower depths. Deep depth and deep water drilling and operations
require the application of recently developed technologies that involve a higher risk of mechanical failure. We have experienced and
will continue to experience significantly higher drilling costs for our deep depth and deepwater prospects. Furthermore, the deep
waters of the Gulf of Mexico lack the physical and oilfield service infrastructure present in the shallower waters. As a result, a
significant amount of time may elapse between a deep water discovery and our marketing of the associated natural gas or oil,
increasing both the financial and operational risk involved with these operations.

     Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil. Prices also
affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount
we can borrow under the Credit Facility is subject to periodic re-determination based in part on changing expectations of future
prices. Lower prices may also reduce the amount of natural gas and oil that we can economically produce.

     Conversely, our potential need to generate revenues to fund ongoing capital commitments or reduce indebtedness may limit our
ability to slow or shut-in production from producing wells during periods of low prices for natural gas and oil.

     Prices for natural gas and oil fluctuate widely. For example, natural gas prices declined significantly in 2001 from levels
reached in the second half of 2000 and early 2001. Prices for natural gas and oil also declined significantly in 1998 and, for an
extended period of time, remained substantially below prices obtained in previous years. Among the factors that can cause this
fluctuation are the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price
and availability of alternative fuels, political conditions in natural gas and oil producing regions, the domestic and foreign supply
of natural gas and oil, the price of foreign imports and overall economic conditions. If natural gas and oil prices decline, even if
for only a short period of time, it is possible that write-downs of natural gas and oil properties could occur. While we attempt to
partially minimize this risk through our hedging arrangements, hedging production has limited and may continue to limit potential
gains from increases in commodity prices or result in losses.

     We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in natural gas and oil prices
and to achieve more predictable cash flow. These financial arrangements take the form of swap contracts or costless collars and are
placed. The Company had in place both financial hedge and physical contracts with ENA at the time ENA filed for bankruptcy in
December 2001. We did not receive payment as required under these contracts. We cannot provide assurance that other trading
counterparties will not become credit risks in the future. Hedging arrangements expose us to risks in some circumstances, including
situations when the other party to the hedging contract defaults on its contract obligations or there is a change in the expected
differential between the underlying price in the hedging agreement and actual prices received. These hedging arrangements have
limited and may continue to limit the benefit we could receive from increases in the prices for natural gas and oil. We cannot
provide assurance that our hedging transactions will adequately protect us from fluctuations in natural gas and oil prices. We may
choose not to engage in hedging transactions in the future. As a result, we may be adversely affected during periods of declining
natural gas and oil prices.

     We have experienced and expect to continue to experience substantial capital expenditure and working capital needs,
particularly as a result of our drilling program. In the future, we expect we will require additional financing, in addition to cash
generated from our operations, to fund our planned growth. We cannot be certain that additional financing will be available on
acceptable terms or at all. In the event additional capital resources are unavailable, we may curtail our drilling, development and
other activities or be forced to sell some of our assets on an untimely or unfavorable basis.

     We incurred net losses of $10.0 million, $58.4 million, and $20.2 million in 1999, 1998, and 1997, respectively. Our
development of and participation in a larger number of prospects has required and will continue to require substantial capital
expenditures. We cannot provide assurance that it will sustain profitability or positive cash flows from operating activities in the
future. Our failure to sustain profitability in the future could adversely affect our company.

     Concentration Risks- We are subject to risks associated with the Gulf of Mexico, where substantially all of our exploration
activities and production are located. This concentration of activity makes us more vulnerable than many of our competitors to the
risks associated with the Gulf of Mexico, including delays and increased costs relating to adverse weather conditions, drilling rig
and other oilfield services and compliance with environmental and other laws and regulations.

     A significant part of the value of our production and reserves is concentrated in a small number of offshore properties.
Because of this concentration, any production problems or inaccuracies in reserve estimates related to those properties are more
likely to adversely impact in our business. During 2001, over 62 percent of our production came from four properties in the Gulf of
Mexico. If mechanical problems, storms or other events curtailed a substantial portion of this production, our cash flow would be
adversely affected. In addition, at December 31, 2001 approximately 75 percent of the proved reserves was attributable to 9
properties. If the actual reserves associated with any one of these 9 properties are substantially less than the estimated reserves,
our results of operations and financial condition could be adversely affected.

     Industry Risks - Our industry is subject to rapid and significant advancements in technology, including the introduction of
new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive
disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors
may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future
allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a
timely basis or at a cost that is acceptable to us. One or more of the technologies that we currently use or that we may implement in
the future may become obsolete, and we may be adversely affected. For example, marine seismic acquisition technology has been
characterized by rapid technological advancements in recent years and further significant technological developments could
substantially impair the 3-D seismic data's value.

     We compete with major and independent natural gas and oil companies for property acquisitions. We also compete for the
equipment and labor required to operate and develop properties. Most of our competitors have substantially greater financial and
other resources than we do. As a result, in the deep water where exploration is more expensive, competitors may be better able to
withstand sustained periods of unsuccessful drilling. In addition, larger competitors may be able to absorb the burden of any changes
in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.
These competitors may be able to pay more for exploratory prospects and productive natural gas and oil properties and may be able to
define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for natural
gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to
evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most of
our competitors have been operating in the Gulf of Mexico for a much longer time than we have and have demonstrated the ability to
operate through industry cycles.

     Other companies operate some of the properties in which we have an interest. As a result, we have a limited ability to
exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working
interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely
affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of drilling
and development activities on properties operated by others therefore depend upon a number of factors that are outside of our
control, including timing and amount of capital expenditures, the operator's expertise and financial resources, approval of other
participants in drilling wells and selection of technology.

     Reserve Risks- The process of estimating natural gas and oil reserves is complex. It requires interpretations of available
technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these
interpretations or assumptions could materially affect the estimated quantities and net present value of reserves.

     In order to prepare these estimates, we must project production rates and timing of development expenditures. We must also
analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can
vary. The process also requires economic assumptions such as natural gas and oil prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. Therefore, estimates of natural gas and oil reserves are inherently imprecise.

     Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and
quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could
materially affect the estimated quantities and net present value of reserves. In addition, we may adjust estimates of proved reserves
to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many
of which are beyond our control. At December 31, 2001, approximately 74 percent of our proved reserves were either proved undeveloped
or proved non-producing. Moreover, some of the producing wells included in our reserve report had produced for a relatively short
period of time as of December 31, 2001. Because most of the reserve estimates are not based on a lengthy production history and are
calculated using volumetric analysis, these estimates are less reliable than estimates based on a lengthy production history.

     It should not be assumed that the present value of future net cash flows from our proved reserves is the current market
value of its estimated natural gas and oil reserves. In accordance with Securities and Exchange Commission requirements, we base the
estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future
prices and costs may differ materially from those used in the net present value estimate.

     Our future natural gas and oil production depends on our success in finding or acquiring additional reserves. If we fail to
replace reserves, our level of production and cash flows could be adversely impacted. In general, production from natural gas and oil
properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved
reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire
properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset
base of natural gas and oil reserves would be impaired to the extent cash flow from operations is reduced and external sources of
capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. If we
are not successful, our future production and revenues will be adversely affected.

     Regulation Risks- We are subject to complex laws and regulations, including environmental regulations which can adversely
affect the cost, manner or feasibility of doing business.

     Exploration for and development, production and sale of natural gas and oil in the U.S. and especially in the Gulf of Mexico
are subject to extensive federal, state and local laws and regulations, including environmental laws and regulations. We may be
required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation
include discharge permits for drilling operations, drilling bonds, reports concerning operations and taxation.

     Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of
hazardous materials, remediation and clean-up costs and other environmental damages. We do not believe that full insurance coverage
for all potential environmental damages is available at a reasonable cost. Failure to comply with these laws and regulations also may
result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover,
these laws and regulations could change in ways that substantially increase costs. For example, Congress or the MMS could decide to
limit exploratory drilling or natural gas production in additional areas of the Gulf of Mexico. Accordingly, any of these
liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our financial condition
and results of operations.(e) Critical Accounting Policies and Estimates

     Our discussion and analysis of Mariner's financial condition and results of operation are based upon financial
statements that have been prepared in accordance with accounting principles generally accepted in the United States of America. The
preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets,
liabilities, revenues and expenses. Our significant accounting policies are described in Note 1 to our financial statements. In
response to SEC Release No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting Policies," we have identified
certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and
which require the application of significant judgment by our management. We analyze our estimates, including those related to oil and
gas revenues, oil and gas properties, fair value of derivative instruments, income taxes and contingencies and litigation, and base
our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual
results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting
policies affect our more significant judgments and estimates used in the preparation of our financial statements:

     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, based on year-end prices of $2.65
per Mcf of natural gas and $19.43 per Bbl of crude oil, a permanent impairment of oil and gas properties of approximately $37.8
million would be required as of December 31, 2001. However as allowed by the Securities and Exchange Commission guidelines since both
natural gas and crude oil prices have significantly increased since year-end, no writedown was required as of December 31, 2001.

     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.

     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
$2,836,000, $3,885,000, and $3,028,000 for the years ended December 31, 2001, 2000 and 1999, 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, recorded at market value are deferred, and recorded in Accumulated Other
Comprehensive Income ("AOCI") as appropriate, until recognized as operating income in the Company's Statement of Operations as the
physical production hedged by the contracts is delivered.

     The net cash flows related to any recognized gains or losses associated with these hedges are reported as oil and gas
revenues and presented in 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 hedged by the contracts is delivered.

     The conditions to be met for a derivative instrument to qualify as a cash 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.

     Financial Instruments- The Company's financial instruments consist of cash and cash equivalents, receivables, payables,
and debt. At December 31, 2001 and 2000, the estimated fair value of the Company's $100,000,000 Senior Subordinated Notes was
approximately $95,000,000 and $91,000,000, respectively. The estimated fair value was determined based on borrowing rates available
at December 31, 2001 and 2000, respectively, for debt with similar terms and maturities. The carrying amount of the Company's other
instruments noted above approximate fair value.

     Major Customers- During the year ended December 31, 2001, sales of oil and gas to three purchasers, including an Enron
affiliate, accounted for 32%, 24% and 14% of total revenues. During the year ended December 31, 2000, sales of oil and gas to two
purchasers, including an affiliate, accounted for 49% and 16% of total revenues. During the year ended December 31, 1999, sales of
oil and gas to three purchasers accounted for 26%, 21% and 13% 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.(f) Results of Operations

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

|Year Ending December 31,                                            
|--------------------------------------------------------------------
|                                                                    
|                                                                    
|                                                                    
|PRODUCTION:                                                         
|Oil (MMbbls)                                                        
|Natural gas (Bcf)                                                   
|Natural Gas equivalent ((Bcfe)                                      
|AVERAGE REALIZED SALES PRICE(EXCLUDING EFFECTS OF HEDGING):         
|Oil ($/Bbl)                                                         
|Natural gas ($/Mcf)                                                 
|Natural Gas equivalent ($/Mcfe)                                     
|AVERAGE REALIZED SALES PRICE(INCLUDING EFFECTS OF HEDGING):         
|Oil ($/Bbl)                                                         
|Natural gas ($/Mcf)                                                 
|Natural Gas equivalent ($/Mcfe)                                     
|EXPENSES ($/MCFE):                                                  
|Lease operating                                                     
|Transportation                                                      
|General and administrative, net                                     
|Depreciation, depletion and amortization     (excluding impairments)

(i) 2001 compared to 2000

     Net productionincreased during 2001 to 36.7 billion cubic feet of natural gas equivalent (Bcfe) from 36.3 Bcfe in 2000, a
1% improvement. Production from a full year of our Black Widow project more than offset production declines in our other fields,
primarily the Sandy Lake field, located onshore, and the Dulcimer and Apia fields, located offshore.

     Hedging activities in 2001 (before de-designation due to the impact of the ENA bankruptcy) decreased our average realized
natural gas price received by $0.29 per Mcf and revenues by $5.5 million, compared with a decrease of $0.83 per Mcf and revenues of
$21.4 million in 2000. Our hedging activities with respect to crude oil during 2001 increased the average sales price received by
$0.81 per Bbl and revenues by $2.4 million compared with a decrease of $7.99 per Bbl and revenues of $14.3 million.

     Oil and gas revenuesincreased 28% to $155.0 million for 2001 from $121.1 million for 2000, due to a 26% increase in
realized prices to $4.22 per Mcfe in 2001 from $3.34 per Mcfe in 2000.

     Lease operating expensesincreased 17% to $20.1 million for 2001 from $17.2 million for 2000 due to the higher production
costs associated with our Black Widow project.

     Transportation expensesincreased 54% to $12.0 million for 2001 from $7.8 million for 2000. The increase was attributable
to a full year's transportation expenses on Black Widow as well as mandatory minimum transportation charges on our Pluto project.

     Depreciation, depletion, and amortizationexpense increased 12% to $63.5 million for 2001 from $56.8 million for 2000 as a
result of the increase in the unit-of-production depreciation, depletion and amortization rate to $1.73 per Mcfe from $1.57 per Mcfe.

     Impairment of Enron related receivablesof $29.5 million was taken as a result of ENA filing a petition for bankruptcy
protection (also see "Enron"). The allowance represents an 90% allowance on $7.0 million of settled physical and hedge contracts
through December 31, 2001 and an 90% allowance on $25.3 million of hedge contracts marked to market value.

     General and administrative expenses, which are net of overhead reimbursements we received from other working interest
owners, increased 42% to $9.3 million for 2001 from $6.5 million for 2000 due to severance payments made as part of the change in key
management as well as administrative reductions.

     Net interest expensefor 2001 decreased 25% to $8.2 million from $10.9 million for 2000, primarily due to reduced debt
levels allowed by our sale of certain oil and gas properties.

     Income (loss) before income taxesdecreased to a net income of $12.4 million for 2001 from $21.9 million in 2000, primarily
as a result of increased revenue offset in part by increased expenses discussed above.

     (ii) 2000 compared to 1999

     Net productionincreased 46% to 36.3 Bcfe for 2000 from 24.9 Bcfe for 1999. 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 activitiesin 2000 decreased our average realized natural gas price received by $0.83 per Mcf and revenues by $21.4
million, compared with a decrease of $0.32 per Mcf and revenues of $6.7 million in 1999. Our hedging activities with respect to crude
oil during 2000 reduced the average sales price received by $7.97 per Bbl and revenues by $14.1 million compared with a decrease of
$3.42 per Bbl and revenues by $2.2 million in 1999.

     Oil and gas revenuesincreased 122% to $121.1 million for 2000 from $54.5 million for 1999, due to a 34% increase in
realized prices to $3.34 per Mcfe in 2000 from $2.19 per Mcfe in 1999.

     Lease operating expensesincreased 50% to $17.2 million for 2000 from $11.5 million for 1999 due to the higher offshore
production discussed above and well workovers on three offshore wells and two wells in our Sandy Lake field.

     Transportation expensesincreased 290% to $7.8 million for 2000 from $2.0 million for 1999. The increase was attributable
to the addition of additional production on offshore properties that are subject to transportation tarriffs.

     Depreciation, depletion, and amortizationexpense increased 77% to $56.8 million for 2000 from $32.1 million for 1999 as a
result of the increase in the unit-of-production depreciation, depletion and amortization rate to $1.57 per Mcfe from $1.29 per Mcfe.

     General and administrative expenses, which are net of overhead reimbursements we received from other working interest
owners, increased 22% to $6.6 million for 2000 from $5.4 million for 1999 due to increased personnel-related costs in 1999 required
for us to pursue our deepwater Gulf exploration and development plan.

     Net interest expensefor 2000 decreased 19% to $11.0 million from $13.5 million for 1999.

     Income (loss) before income taxesincreased 119% to $21.9 million for 2000 from a loss of $10.0 million in 1999 as a result
of the items discussed above.(g) Liquidity and Capital Resources(i) Cash Flows and Liquidity

     As of December 31, 2001, we had a working capital deficit of approximately $19.6 million, compared to a working capital
deficit of $15.4 million at December 31, 2000. The increase in the working capital deficit was primarily a result of higher accounts
payable attributable to work being performed on our King Kong / Yosemite and Crater Lake projects in progress at year end. We expect
our 2002 capital expenditures, excluding capitalized general and administrative, interest costs and proceeds from property
conveyances, to be approximately $65.5 million, which is lower than budgeted cash flow from operations. There can be no assurance
that actual cash flow from operations will exceed capital expenditures or that our access to capital will be sufficient to meet our
needs for capital. Accordingly, we may be required to reduce our planned capital expenditures and forego planned exploratory
drilling (see "Recent Events" regarding the April 2002 sale with proceeds of $48.8 million).

     Our Revolving Credit Facility matures in October 2002. We expect to begin renegotiation of our agreement with existing
banks that provide the facility during the first half of 2002. We plan to minimize the use of the facility until such time as this
agreement can be renegotiated or replaced with a similar agreement. There is no assurance that this agreement can be renegotiated or
replaced. In addition our parent, Mariner Energy LLC, is currently obligated under a three-year unsecured term loan with an ENA
affiliate, which matures in March 2003. Currently we expect to attempt to obtain an extension on this agreement. In the event Mariner
Energy, LLC is unable to obtain an extension or restructure its obligation, Mariner Energy LLC would either default or be forced to sell its interest in Mariner
Energy, Inc., or cause Mariner to sell a substantial portion of its assets to repay its Revolving Credit Facility and outstanding
Senior Subordinated Notes to that it could distribute cash to Mariner Energy LLC to be used to repay the term loan. In the event
either a change of control occurs of our company or a sale of a substantial portion of our assets, both the balances outstanding
under the Senior Subordinated Notes and Revolving Credit Facility would have to be repaid prior to payment of the term loan.
Although we believe we will be successful in extending the term loan, there can be no assurance that an extension will be obtained.

     We had a net cash inflow of $9.5 million in 2001, compared to a net cash inflow of $2.3 million in 2000 and a net cash
outflow of $0.1 million in 1999. A discussion of the major components of cash flows for these years follows.

|                                                          | 2001   | 2000  | 1999 
|--------------------------------------------------------- | ------ | ----- | -----
|Cash flows provided by operating activities (in millions) | $113.6 | $63.9 | $24.4

Cash flows provided by operating activities in 2001 increased by $49.6 million compared to 2000 due to increased oil and gas
prices, offset in part by higher production lease operating and general and administrative expenses. Cash flows from operating
activities in 2000 increased by $39.5 million from 1999 primarily due to increased oil and gas prices, production lease operating and
general and administrative expenses.

|                                                      | 2001  | 2000  | 1999 
|----------------------------------------------------- | ----- | ----- | -----
|Cash flows used in investing activities (in millions) | $74.0 | $79.1 | $61.8

Cash flows used in investing activities in 2001 decreased by $5.1 million compared to 2000 due to increased capital
expenditures offset by $90.5 million in proceeds from property conveyances. Cash flows used in investing activities in 2000 increased
by $17.3 million compared to 1999 increased capital expenditures offset by $29.0 million in proceeds from property conveyances.

|                                                          | 2001    | 2000  | 1999 
|--------------------------------------------------------- | ------- | ----- | -----
|Cash flows provided by financing activities (in millions) | $(30.0) | $17.4 | $37.5

Cash flows provided by financing activities in 2001 decreased by $47.4 million compared to 2000 due to a $30 million net
reduction in borrowings against our Revolving Credit Facility. This reduction in our Revolving Credit Facility was attributable to
repayments using proceeds from property conveyances mentioned above. Cash flows provided by financing activities in 2000 decreased by
$20.1 million as compared to 1999 due to a $37.6 million net reduction in borrowings against our Revolving Credit Facility and our
Affiliate Credit Facility as compared to a $14.2 million increase in borrowings against that facility for the previous year. In
addition, capital contributions resulting from the sale of stock to Mariner Energy LLC increased by $31.7 million.
(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 primarily through the use
of commodity swap and costless collar agreements. While the use of these hedging arrangements limits the downside risk of adverse
price movements, it also limits future gains from favorable movements. All hedge activities historically have been conducted with
Enron. As a result of the Enron bankruptcy we have de-designated all hedge positions (see "Enron").

Our Senior Subordinated Notes bear interest at 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 2001 interest expense by $0.1 million. The carrying value of our Revolving Credit Facility approximates market since
these instruments have floating interest rates. The market value of the Senior Subordinated Notes was approximately $95.0 million
based on borrowing rates available at December 31, 2001.(iii) Capital Expenditures and Capital ResourcesCapital 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, 2001.

|                                                                      | YEAR ENDINGDECEMBER 31,
|--------------------------------------------------------------------- | -----------------------
|
|
|
|Capital expenditures (in millions):                                  
|Leasehold acquisition                                                 | $8.8                   
|Oil and natural gas exploration                                       | 57.5                   
|Oil and natural gas development and other                             | 98.2                   
|Proceeds from property conveyances                                    | (90.5)                 
|                                                                      |                        
|Total capital expenditures, net of proceeds from property conveyances | $74.0                  
|                                                                      |                        

Our capital expenditures for 2001 were $74.0 million, including the $90.5 million of proceeds from property conveyances,
which was $5.1 million less than 2000. The decrease was primarily a result of higher property conveyance proceeds offset in part by
higher leasehold acquisition, geological and geophysical, and development expenditures.

     Our capital expenditures for 2000 were $79.1 million, excluding the $29.0 million of proceeds from property conveyances,
which was $17.4 million more than 1999. The increase was primarily a result of higher exploratory expenditures and development costs
as we operated with increased access to capital.

     Our approved capital expenditure budget for 2002 is approximately $65.4 million after estimated proceeds from property
conveyances. Our budget includes approximately $50 million for exploration activities, $64.2 million for development activities and
$48.8 million in proceeds from property conveyances. An active Gulf exploration program is underway, with funds budgeted to drill
seven to ten wells. The exploration budget also anticipates additions to our 3-D seismic database and our leasehold position. The
development budget includes funds for completion of our King Kong / Yosemite, Crater Lake, Falcon, Roaring Fork and Swordfish
projects and several development wells in currently-producing fields.

     Our long-term debt outstanding as of December 31, 2001 was approximately $99.8 million, comprised entirely of Senior
Subordinated Notes. Following our semi-annual borrowing base redetermination which is expected to be completed in April 2002, our
borrowing base under the Revolving Credit Facility is expected to be $45 million. This Revolving Credit Facility is due to mature in
October 2002.

     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.

     We expect to fund our activities for 2002 through a combination of cash flow from operations, borrowings under our Revolving
Credit Facility, and proceeds from property conveyances. 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. 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 be certain that we will be able to obtain
financing on acceptable terms to complete a refinancing.(h) Recent Events

     On March 20, 2002, with bids totaling $10.9 million net to us, we were the apparent high bidder solely or with industry
partners, on 12 out of 16 blocks on which we and our partners submitted bids in the Central Gulf of Mexico Oil and Gas Lease Sale 182
held on that date. Each of the blocks is in water depths ranging from approximately 20 feet to 2,400 feet. Mariner has a 100%
working interest in four of the blocks, 50% working interest in seven blocks and 20% working interest in one block.

     In April 2002, we sold 50% of our working interest in our Falcon discovery and surrounding blocks, located in East Breaks
Block 579 in the western Gulf of Mexico, for $48.8 million. Subsequent to the sale we have a 25% working interest in the discovery
and surrounding blocks. The project is currently expected to begin production in the first quarter of 2003. At December 31, 2001,
the Falcon project had 66.8 Bcfe assigned as proven reserves.

     The net carrying value of our 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, based on year-end prices of $2.65 per Mcf of natural gas and $19.43 per Bbl of
crude oil, an impairment of oil and gas properties of approximately $37.8 million would be required as of December 31, 2001.
However, as allowed by the Securities and Exchange Commission guidelines, since both natural gas and crude oil prices have
significantly increased since year-end, no writedown was required as of December 31, 2001.(i)Contractual Commitments

     We have numerous contractual commitments in the ordinary course of business, debt
service requirements and operating lease commitments . The following table summarizes these commitments at
December 31, 2001 (in millions):

|                                   | 2002  | 2003 | 2004 | 2005 | 2006   | BEYOND2006
|---------------------------------- | ----- | ---- | ---- | ---- | ------ | ----------
|
|DEBT AND OTHER OBLIGATIONS         | $--   | $--  | $--  | $--  | $100   | $--       
|OPERATING LEASES                   | 1.5   | 0.7  | 0.1  | --   | --     | --        
|TRANSPORTATION EXPENSES            | 2.5   | 1.7  | 1.2  | 0.9  | 0.7    | 0.9       
|OTHER COMMITMENTS                  | 6.8   | 6.3  | 0.7  | 3.4  | 3.0    | 31.1      
|TOTAL CONTRACTUAL CASH COMMITMENTS | $10.8 | $8.7 | $2.0 | $4.3 | $103.7 | $40.0     

Other Commitments- In the ordinary course of business we enter into long-term commitments to purchase seismic
data. The minimum annual payments under these contracts are $6.8 million in 2002, $6.3 million in 2003 and $2.7 million in 2004.(j)Recent Accounting Pronouncements

     In July 2001, the Financial Accounting Standards Board issued SFAS No. 141, "Business Combinations" (effective July 1, 2001)
and SFAS No. 142, "Goodwill and Other Intangible Assets" (effective on January 1, 2002). SFAS No. 141 prohibits pooling-of-interests
accounting for acquisitions. SFAS No. 142 specifies that goodwill and some intangible assets will no longer be amortized but instead
will be subject to periodic impairment testing. We do not believe the adoption of these standards will have an impact on our
financial statements.

     In August and October 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" and SFAS No. 144,
"Accounting for Impairment or Disposal of Long-Lived Assets". SFAS 143 requires entities to record the fair value of a liability for
an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the
related long-lived asset. Subsequently, the asset retirement costs should be allocated to expense using a systematic and rational
method. SFAS 143 is effective for fiscal years beginning after June 15, 2002. SFAS 144 addresses financial accounting and reporting
for the impairment of long-lived assets and for long-lived assets to be disposed of. It supersedes, with exceptions, SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of", and is effective for fiscal years
beginning after December 15, 2001. The company is currently assessing the impact of SFAS No. 143 and No. 144 and therefore cannot
reasonably estimate the impact, if any, these statements will have on its financial statements upon adoption.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.



|Item 8.  Financial Statements and Supplmentary Data                                    
|---------------------------------------------------------------------------------------
|
|
|Independent Auditors' Report                                                           
|Balance Sheets at December 31, 2001 and 2000                                           
|Statements of Operations for the years ended December 31, 2001, 2000 and 1999          
|Statements of Stockholder's Equity for the years ended December 31, 2001, 2000 and 1999
|Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999          
|Notes to Financial Statements                                                          



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, 2001 and 2000 and the related statements of operations,
stockholders equity and cash flows for each of the three years in the
period ended December 31, 2001. 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 auditing standards generally accepted in the United States of
America. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the
financial statements referred to above present fairly, in all material respects,
the financial position of Mariner Energy, Inc. as of December 31, 2001 and 2000,
and the results of its operations and cash flows for each of the three years in
the period ended December 31, 2001, in conformity with accounting principles
general accepted in the United States of America.

As described in Note 1, the
Company changed its method of accounting for derivative instruments and hedging
activities in accordance with Statement of Financial Accounting Standards No.
133 Accounting for Derivative Instruments and Hedging Activities.

As described in Note 2, the
Company has various related-party transactions and certain control relationships
with Enron Corp.

/s/ DELOITTE & TOUCHE LLPDELOITTE & TOUCHE LLP

Houston, Texas
April 10, 2002

|MARINER ENERGY, INC.BALANCE SHEETS(in thousands, except share data)                                                                                   
|------------------------------------------------------------------------------------------------------------------------------------------------------
|
|
|
|
|
|Current Assets:                                                                                                                                       
|Cash and cash equivalents                                                                                                                             
|Receivables                                                                                                                                           
|Prepaid expenses and other                                                                                                                            
|                                                                                                                                                      
|Total current assets                                                                                                                                  
|                                                                                                                                                      
|Property and Equipment:                                                                                                                               
|Oil and gas properties, at full cost:                                                                                                                 
|Proved                                                                                                                                                
|Unproved, not subject to amortization                                                                                                                 
|                                                                                                                                                      
|Total                                                                                                                                                 
|Other property and equipment                                                                                                                          
|Accumulated depreciation, depletion and amortization                                                                                                  
|                                                                                                                                                      
|Total property and equipment, net                                                                                                                     
|                                                                                                                                                      
|Other Assets, Net of Amortization                                                                                                                     
|Long-Term Related Party Receivable                                                                                                                    
|                                                                                                                                                      
|TOTAL ASSETS                                                                                                                                          
|                                                                                                                                                      
|LIABILITIES AND STOCKHOLDER'S EQUITY                                                                                                                  
|Current Liabilities:                                                                                                                                  
|Accounts payable                                                                                                                                      
|Accrued liabilities                                                                                                                                   
|Accrued interest                                                                                                                                      
|                                                                                                                                                      
|Total current liabilities                                                                                                                             
|                                                                                                                                                      
|Other Liabilities                                                                                                                                     
|Long-Term Debt:                                                                                                                                       
|Senior Subordinated Notes                                                                                                                             
|Revolving Credit Facility                                                                                                                             
|                                                                                                                                                      
|Total long-term debt                                                                                                                                  
|                                                                                                                                                      
|Stockholder's Equity:                                                                                                                                 
|Common stock, $1 par value; 2,000 and 1,000 shares         authorized, 1,380 issued
and outstanding,
        at December 31 2001 and December 31, 2000
|Additional paid-in-capital                                                                                                                            
|Accumulated other comprehensive income                                                                                                                
|Accumulated deficit                                                                                                                                   
|                                                                                                                                                      
|Total stockholder's equity                                                                                                                            
|                                                                                                                                                      
|TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY                                                                                                            
|                                                                                                                                                      
|The accompanying notes are an integral part of these financial statements                                                                             



|MARINER ENERGY, INC.STATEMENTS OF OPERATIONS(in thousands)               
|-------------------------------------------------------------------------
|
|
|
|
|REVENUES:                                                                
|Oil sales                                                                
|Gas sales                                                                
|
|Total revenues                                                           
|
|COSTS AND EXPENSES:                                                      
|Lease operating expense                                                  
|Transportation expense                                                   
|General and administrative expense                                       
|Depreciation, depletion and amortization                                 
|Impairment of Enron related receivables                                  
|
|Total costs and expenses                                                 
|
|OPERATING INCOME                                                         
|INTEREST:                                                                
|Income                                                                   
|Expense                                                                  
|
|INCOME (LOSS) BEFORE TAXES                                               
|PROVISION FOR INCOME TAXES                                               
|
|NET INCOME (LOSS)                                                        
|
|The accompanying notes are an integral part of these financial statements



|MARINER ENERGY, INC.STATEMENTS OF STOCKHOLDER'S EQUITY(in thousands, except number of shares)
|---------------------------------------------------------------------------------------------
|
|
|
|BALANCE AT DECEMBER 31, 1998                                                                 
|Capital contribution                                                                         
|Net loss                                                                                     
|
|BALANCE AT DECEMBER 31, 1999                                                                 
|
|Capital contribution                                                                         
|Net income                                                                                   
|
|BALANCE AT DECEMBER 31, 2000                                                                 
|
|Net income                                                                                   
|Cumulative effect of change         in accounting principal                                  
|Change in fair value of        derivative hedging         investments                        
|Hedge settlements         reclassified to income                                             
|
|Total comprehensive income                                                                   
|
|BALANCE AT DECEMBER 31, 2001                                                                 
|
|The accompanying notes are an integral part of these financial statements                    



|MARINER ENERGY, INC.STATEMENTS OF CASH FLOWS(in thousands)                          
|------------------------------------------------------------------------------------
|
|
|
|
|OPERATING ACTIVITIES:                                                               
|Net income (loss)                                                                   
|Adjustments to reconcile net loss to net cash      provided by operating activities:
|Depreciation, depletion and amortization                                            
|Impairment of Enron related receivables                                             
|Changes in operating assets and liabilities:                                        
|Receivables                                                                         
|Other current assets                                                                
|Other assets                                                                        
|Accounts payable and accrued liabilities                                            
|
|Net cash provided by operating activities                                           
|
|INVESTING ACTIVITIES:                                                               
|Additions to oil and gas properties                                                 
|Proceeds from property conveyances                                                  
|Additions to other property and equipment                                           
|
|Net cash used in investing activities                                               
|
|FINANCING ACTIVITIES:                                                               
|Repayment of revolving credit facility                                              
|Capital contributed by sale of stock to parent                                      
|Proceeds from (payments to) the affiliate credit facility                           
|
|Net cash (used in) provided by financing activities                                 
|
|INCREASE IN CASH AND CASH EQUIVALENTS                                               
|CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD                                    
|
|CASH AND CASH EQUIVALENTS AT END OF PERIOD                                          
|
|The accompanying notes are an integral part of these financial statements           



# MARINER
ENERGY, INC.NOTES TO FINANCIAL STATEMENTS

For the Years
Ended December 31, 2001, 2000 and 1999

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 company incorporated in the United
Kingdom. Pursuant to a stock purchase agreement dated April 1, 1996, Joint Energy Development Investments Limited Partnership
("JEDI"), Enron North America Corp. ("ENA") (see "Note 2. Related-Party Transactions"), 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"). After the acquisition, the name of the predecessor company 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 owned 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, based on year-end prices of $2.65
per Mcf of natural gas and $19.43 per Bbl of crude oil, a permanent impairment of oil and gas properties of approximately $37.8
million would be required as of December 31, 2001. However as allowed by the Securities and Exchange Commission guidelines since both
natural gas and crude oil prices have significantly increased since year-end, no writedown was required as of December 31, 2001.

     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 three to seven years.

     Other Assets- Other assets are primarily deferred loans stated at cost subject to amortization over the life of the related debt.  Accumulated
amortization as of December 31, 2001 and 2000 was $5.6 million and $4.8 million, respectively.

     Income Taxes- The Company's taxable income is included in a consolidated United States income tax return with Mariner
Energy, LLC. 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.

     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
$2,836,000, $3,885,000, and $3,028,000 for the years ended December 31, 2001, 2000 and 1999, 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, recorded at market value are deferred, and recorded in Accumulated Other
Comprehensive Income ("AOCI") as appropriate, until recognized as operating income in the Company's Statement of Operations as the
physical production hedged by the contracts is delivered.

     The net cash flows related to any recognized gains or losses associated with these hedges are reported as oil and gas
revenues and presented in 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 hedged by the contracts is delivered.

     The conditions to be met for a derivative instrument to qualify as a cash 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, 2001 and 2000, the estimated fair value of the Company's $100,000,000 Senior Subordinated Notes was
approximately $95,000,000 and $91,000,000, respectively. The estimated fair value was determined based on borrowing rates available
at December 31, 2001 and 2000, respectively, for debt with similar terms and maturities. The carrying amount of the Company's other
instruments noted above approximate fair value.

     Use of Estimates in the Preparation of Financial Statements - The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of America 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.

     Major Customers- During the year ended December 31, 2001, sales of oil and gas to three purchasers, including an Enron
affiliate, accounted for 31%, 24% and 14% of total revenues. During the year ended December 31, 2000, sales of oil and gas to two
purchasers, including an affiliate, accounted for 49% and 16% of total revenues. During the year ended December 31, 1999, sales of
oil and gas to three purchasers accounted for 26%, 21% and 13% 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 Pronouncements- In July 2001, the Financial Accounting Standards Board issued SFAS No. 141,
"Business Combinations" (effective July 1, 2001) and SFAS No. 142, "Goodwill and Other Intangible Assets" (effective on January 1,
2002). SFAS No. 141 prohibits pooling-of-interests accounting for acquisitions. SFAS No. 142 specifies that goodwill and some
intangible assets will no longer be amortized but instead will be subject to periodic impairment testing. The Company does not
believe the adoption of these statements will have an impact on its financial statements.

     In August and October 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" and SFAS No.
144, "Accounting for Impairment or Disposal of Long-Lived Assets". SFAS 143 requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying
amount of the related long-lived asset. Subsequently, the asset retirement costs should be allocated to expense using a systematic
and rational method. SFAS 143 is effective for fiscal years beginning after June 15, 2002. SFAS 144 addresses financial accounting
and reporting for the impairment of long-lived assets and for long-lived assets to be disposed of. It supersedes, with exceptions,
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of", and is effective for
fiscal years beginning after December 15, 2001. The Company is currently assessing the impact of SFAS No. 143 and No. 144 and
therefore cannot reasonably estimate the impact, if any, these statements will have on its financial statements upon adoption.2.      RELATED-PARTY TRANSACTIONS

     Enron Bankruptcy- On December 2, 2001, Enron Corp. ("Enron") and one of its affiliates,Enron
North America Corp. ("ENA"), among other affiliates filed voluntary petitions for bankruptcy protection. The Company has been informed that of the various
affiliates of Enron to Mariner, only Enron and ENA are included in the bankruptcy. We do not know at this time if any other
affiliates of Enron will seek bankruptcy protection or what effect, if any, this may have on Joint Energy Development Investments Limited
Partnership ("JEDI") or the ownership of Mariner Energy LLC which owns 100% of our direct parent. Enron is the parent of ENA, and
an affiliate of ENA is the general partner of JEDI. JEDI is 100% owned by several different Enron and ENA affiliates. Accordingly,
Enron may be deemed to control JEDI, Mariner Energy LLC, Mariner Holdings and the Company. Additionally, seven of the Company's
directors are officers of Enron or affiliates of Enron. Because of these various potentially 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.

     Mariner Energy LLC's only asset is 100% of the common stock of Mariner Holdings, Inc., our direct parent. The only asset
of Mariner Holdings is 100% of the common shares of Mariner. Covenants in Mariner's Revolving Credit Facility and Senior
Subordinated Notes restrict the funds of Mariner that can be distributed to Mariner Energy LLC to repay its term loan to an ENA
affiliate - see below "ENA Affiliate Term Loan". Mariner Energy LLC is currently attempting to obtain an extension of the ENA
Affiliate Term Loan, but there can be no assurance that an extension will be obtained. In the event Mariner Energy LLC is unable to
obtain an extension or restructure its obligations, it would either default or be forced to sell its interest in Mariner or cause
Mariner to sell a substantial portion of its assets to repay its Revolving Credit Facility, if any amounts are outstanding, and
outstanding Senior Subordinated Notes so that it could distribute any remaining cash proceeds to Mariner Energy LLC to be used to
repay the ENA Affiliate Term Loan.

     As a result of the Enron and ENA bankruptcies, among other implications, as part of our normal operations we may not be able
to obtain credit from banks or trade vendors or enter into hedging arrangements on acceptable terms. This may also hinder our
ability to enter into certain transactions including purchase or sale arrangements and conduct significant capital programs.

     Organization and Ownership of the Company - 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 company
incorporated in the United Kingdom. Pursuant to a stock purchase agreement dated April 1, 1996, JEDI and ENA, together with members
of management of the Predecessor Company, formed Mariner Holdings, Inc. ("Mariner Holdings"). Mariner Holdings 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 (the "Acquisition"). After the Acquisition, the name of the Predecessor Company was changed to Mariner Energy, Inc. In
October 1998, JEDI and other shareholders exchanged all of their common shares of Mariner Holdings, the Company's direct parent, for
an equivalent ownership percentage in common shares of Mariner Energy LLC. Mariner Energy LLC owns 100% of Mariner Holdings.


     Subsequent to the Acquisition, Mariner Energy LLC, Mariner Holdings and Mariner have each entered into various
financing and operating transactions with affiliates. In addition the Company may have from time to time engaged 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 and entering into other oil and
gas related or financial transactions. Certain of the Company's third-party debt instruments and arrangements 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 obtained in an agreement with a third party. Below is a
summary of key transactions between the Company and affiliate entities.Mariner Energy LLC

     ENA Credit Facility - In September 1998 Mariner Holdings established a credit facility to obtain additional capital. The
credit facility, as subsequently amended and assigned to Mariner Energy LLC, provided for unsecured, subordinated loans of up to $50
million, bearing interest at LIBOR plus 4.5%, payable at April 30, 2000. The full amount borrowed under this credit facility was
repaid on March 21, 2000 with proceeds from the ENA Affiliate Term Loan described below. The net proceeds from this facility were
contributed to Mariner.

     ENA Affiliate Term Loan - In March 2000, Mariner Energy LLC established an unsecured term loan with ENA to repay amounts
outstanding under the ENA Credit Facility with Mariner Energy LLC ($50 million plus accrued interest) described above and Mariner's
Senior Credit Facility with ENA ($25 million plus accrued interest), described below, and to provide additional working capital. The
additional working capital of $55 million was contributed to Mariner in 2000. The loan bears interest at 15%, which interest accrues
and is added to the loan principal. Repayment of the balance of loan principal and accrued interest, which was approximately $143
million as of December 31, 2001, is due March 20, 2003. As part of the loan agreement, two five-year warrants were issued to ENA
providing the right to purchase up to 900,000 of common shares of Mariner Energy LLC for $0.01 per share.

     We have been informed that the Term Loan was transferred from ENA to an ENA affiliate.Mariner Holdings, Inc.

     1998 Equity Investment - In June 1998, Mariner Holdings issued additional equity to its existing shareholders, including
JEDI, for approximately $14.58 per share, for a net investment of $28.8 million, all of which was contributed to Mariner. Mariner
Holdings paid approximately $1.2 million as a structuring fee, on a pro rata basis, to existing shareholders participating in this
transaction. Approximately $1 million of this fee was paid to ECT Securities Limited Partnership.Mariner Energy, Inc.

     Senior Credit Facility with ENA - In April 1999 Mariner established a senior credit facility with ENA primarily to obtain
additional working capital. The facility provided for senior unsecured revolving loans of up to $25 million, bearing interest at
LIBOR plus 2.5%, payable quarterly. The full amount borrowed under the senior credit facility was repaid on March 21, 2000, with
proceeds from the ENA Affiliate Term Loan described above.Other Transactions

     Oil and Gas Production Sales to ENA or Affiliates - During the three years ending December 31, 2001, 2000 and 1999, sales of
oil and gas production to ENA or affiliates were $50.2 million, $73.4 million and $16.2 million, respectively. These sales were generally made on 1 to 3
month contracts. At the time ENA filed its petition for bankruptcy protection, the Company immediately ceased selling its physical
production to ENA. As of December 31, 2001, we had an outstanding receivable for $3.0 million from ENA. This amount was not paid as
scheduled and is still outstanding. The Company has estimated 90% of this balance is uncollectible and has recorded an allowance and
related expense for $2.7 million.

     Accounting for Price Risk Management Activities- Mariner engages in price risk management activities from time to time.
These activities are intended to manage Mariner's exposure to fluctuations in commodity prices for natural gas and crude oil. The
Company primarily utilizes price swaps and costless collars as a means to manage such risk. During 2001 and as of December 31, 2001,
all of our hedging contracts were with ENA. As a result of ENA's bankruptcy, the contracts are currently in default. The November
and December settlements for oil and gas have not been collected, and there is significant uncertainty that the $4.0 million owed to
the Company for the November and December settlements or any future settlements will be collected. As a result of the default, the
Company has recorded an allowance representing 90% of the recorded hedge settlements receivable of $4.0 million, fair market value of
the derivative assets of $25.8 (as of December 2, 2001), and accounts receivable for oil and gas sales of $3.0 million. Reflected in
the earnings of the Company for the period ended December 31, 2001 is a loss for impairment of Enron related receivables of $29.5
million. In accordance with Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and
Hedging Activities," as amended by SFAS No. 137 and No. 138, we have de designated our contracts effective December 2, 2001 and are
recognizing all market value changes subsequent to such de-designation in earnings of the Company. The value recorded up to the time
of de-designation and included in Accumulated Other Comprehensive Income ("AOCI"), will reverse out of AOCI and into earnings as the
original corresponding production, as hedged by the contracts, is produced. As of December 31, 2001, $25.8 million remained in AOCI
to be reversed out during the contract periods covering January 1, 2002 through December 31, 2003. Due to the uncertainty of future
settlements, the overall effect of the ENA bankruptcy has been to eliminate our commodity price hedge protection.

     The following table sets forth the results of hedging transactions during the periods indicated. For the year ended December
31, 2001, the amounts are reflective of the results up to the point of de-designation (December 2, 2001), which include all settled
contract months through December of 2001:

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

|                                                     | YEAR ENDING DECEMBER 31,
|---------------------------------------------------- | ------------------------
|
|
|
|Natural gas quantity hedged (Mmbtu)                  | 17,733                  
|Increase (decrease) in natural gas sales (thousands) | $(5,523)                
|Crude oil quantity hedged (MBbls)                    | 752                     
|Increase (decrease) in crude oil sales (thousands)   | $2,393                  

The following table sets forth our open positions as of December 31, 2001.

|TIME PERIOD                   | NOTIONALQUANTITIES | FIXED PRICE | FAIR VALUE(in millions)
|----------------------------- | ------------------ | ----------- | -----------------------
|NATURAL GAS (MMBTU)          
|January 1 - October 31, 2002 
|Fixed price swap purchased    | 1,831              | $2.18       | $(0.9)                 
|January 1 - December 31, 2002
|Fixed price swap purchased    | 12,134             | 4.43        | 20.4                   
|April 1 - December 31, 2002  
|Fixed price swap purchased    | 4,125              | 3.03        | 0.9                    
|January 1 - December 31, 2003
|Fixed price swap purchased    | 3,650              | 3.74        | 2.0                    
|CRUDE OIL (MBBL)             
|January 1 - June 30, 2002    
|Fixed price swap purchased    | 181                | 25.15       | 0.9                    
|January 1 - December 31, 2002
|Fixed price swap purchased    | 365                | 25.48       | 1.9                    
|Sub-Total                     |                    |             | $25.2(1)               
|                              |                    |             |                        
|Allowance for impairment      |                    |             | $(22.7)                
|                              |                    |             |                        
|Total                         |                    |             | $2.5                   
|                              |                    |             |                        

1. Subsequent to the date of default by Enron and ENA, and as of December 31, 2001, the contracts decreased in gross market
value by $523,000, which is reflected in the impairment of related party receivables at the net valuation of 10% or
$52,000, after consideration for allowance.

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 that is not in bankruptcy, purchased the flowline from the
Company and its joint interest partners. The Company received $8.8 million in cash proceeds that 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
with MEGS LLC at a rate of $0.26 per Mmbtu to transport the Company's share of 86 Bcf of natural gas from the commencement of
production through March 2009. The Company's working interest in the well at December 31, 2001 was 51%. For the year ending
December 31, 2001, the Company paid $4.2 million on this contract. The remaining volume commitment is 30.8 Bbtu or $7.9 million net
to the Company. Pursuant to the contract, the Company must deliver minimum quantities through the flowline or be subject to minimum
monthly payment requirements. Throughout 2001 the Company failed to meet these minimum requirements and paid $1.5 million relating to
the shortfall. The Company estimates that future production will also fail to meet minimum delivery requirements and has accrued
$972,000 for future shortfalls.

     Services Agreement- In conjunction with the change of certain key management positions, the Company entered into a services
agreement for ENA to provide certain administrative services. The Company is obligated to pay $45,000 per month under this agreement.

     Supplemental Affiliate Data- Provided below is supplemental balance sheet and income statement amounts for affiliate
entities:

|                                        | YEAR ENDED DECEMBER 31,
|--------------------------------------- | -----------------------
|
|
|RELATED PARTY RECEIVABLE:               |                        
|Derivative Asset                        | $2.5                   
|Settled Hedge Receivable                | 0.4                    
|Oil and Gas Receivable                  | 0.3                    
|ACCURED LIABILITIES:                    |                        
|Transportation Contract                 | $0.9                   
|Service Agreement                       | $0.3                   
|STOCKHOLDERS' EQUITY:                  
|Common Stock                            | $0.001                 
|Additional Paid-in Capital              | $227.3                 
|INCOME STATEMENT DATA                  
|Oil and Gas Sales                       | $50.2                  
|General and Administrative Expenses     | 0.2                    
|Transportation Expenses                 | 4.2                    
|Impairment of Enron Related Receivables | 29.5                   

3.     LIQUIDITY

As of December 31, 2001, we had a working capital deficit of approximately $19.6 million, compared to a working capital
deficit of $15.4 million at December 31, 2000. The increase in the working capital deficit was primarily a result of a higher
accounts payable, as a result of work being performed on our King Kong / Yosemite and Crater Lake projects in progress at year end.
We expect our 2002 capital expenditures, excluding capitalized general and administrative, interest costs and proceeds from property
conveyances (see "Note 4. Recent Events"), to be approximately $101.9 million, which would exceed cash flow from operations.
However, we believe there will be adequate cash flow due to increased commodity prices and proceeds from property conveyances in
order for us to fund our remaining planned activities in 2002. There can be no assurance that our access to capital will be
sufficient to meet our needs for capital. As such, we may be required to reduce our planned capital expenditures and forego planned
exploratory drilling.

     The Company's Revolving Credit Facility matures in October 2002. We expect to begin renegotiation of our agreement with existing
banks that provide the facility during the first half of 2002. We plan to minimize the use of the facility until such time as this
agreement can be renegotiated or replaced with a similar agreement. There is no assurance that this agreement can be renegotiated or
replaced. In addition our parent, Mariner Energy LLC, is currently obligated under a three-year unsecured term loan with an ENA
affiliate, which matures in March 2003. Currently we expect to attempt to obtain an extension on this agreement. In the event Mariner
Energy, LLC is unable to obtain an extension or restructure its obligation, Mariner Energy LLC would either default or be forced to sell its interest in Mariner
Energy, Inc., or cause Mariner to sell a substantial portion of its assets to repay its Revolving Credit Facility and outstanding
Senior Subordinated Notes to that it could distribute cash to Mariner Energy LLC to be used to repay the term loan. In the event
either a change of control occurs of the company or a sale of a substantial portion of the Company's assets, both the balances outstanding
under the Senior Subordinated Notes and Revolving Credit Facility would have to be repaid prior to payment of the term loan.
Although we believe we will be successful in extending the term loan, there can be no assurance that an extension will be obtained.4.     RECENT EVENTS

     On March 20, 2002, with bids totaling $10.9 million net to us, we were the apparent high bidder solely or with industry
partners, on 12 out of 16 blocks on which we and our partners submitted bids in the Central Gulf of Mexico Oil and Gas Lease Sale 182
held on that date. Each of the blocks is in water depths ranging from approximately 20 feet to 2,400 feet. Mariner has a 100%
working interest in four of the blocks, 50% working interest in seven blocks and 20% working interest in one block.

     In April 2002, we sold 50% of our working interest in our Falcon discovery and surrounding blocks, located in East Breaks
Block 579 in the western Gulf of Mexico, for $48.8 million. Subsequent to the sale we have a 25% working interest in the discovery
and surrounding blocks. The project is currently expected to begin production in the first quarter of 2003. At December 31, 2001,
the Falcon project had 66.8 Bcfe assigned as proven reserves.

     The net carrying value of our 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, based on year-end prices of $2.65 per Mcf of natural gas and $19.43 per Bbl of
crude oil, an impairment of oil and gas properties of approximately $37.8 million would be required as of December 31, 2001.
However, as allowed by the Securities and Exchange Commission guidelines, since both natural gas and crude oil prices have
significantly increased since year-end, no writedown was required as of December 31, 2001.5.     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. Subsequent to the semi annual
redetermination, the available borrowing base under the Revolving Credit Facility is expected to be $45 million and is subject to
periodic redetermination. The Revolving Credit Facility had an outstanding balance of $0 at December 31, 2001. 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 collateralize 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, 2001 was 8.49%. 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, 2001, the
Company was in compliance with all such requirements.

     10 1/2% Senior Subordinated Notes- On August 14, 1996, the Company completed the sale of $100 million principal amount of 10
1/2% Senior Subordinated Notes Due 2006, (the "Notes"). The proceeds of the Notes were used by the Company to (i) pay a dividend to
Mariner Holdings, which used the dividend to fully repay a bridge loan from JEDI incurred in the Acquisition, and (ii) repay a
previous revolving credit facility. The Notes bear interest at 101/2% payable semiannually in arrears on February 1 and August 1 of
each year. The Notes are unsecured obligations of the Company, and are subordinated in right of payment to all senior debt (as
defined in the indenture governing the Notes) of the Company, including indebtedness under the Revolving Credit Facility.

     The indenture pursuant to which the Notes are issued contains certain covenants that, among other things, limit the ability
of the Company to incur additional indebtedness, pay dividends, redeem capital stock, make investments, enter into transactions with
affiliates, sell assets and engage in mergers and consolidations. As of December 31, 2001, 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 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, 2001, 2000 and 1999 was $11.4 million, $15.3 million and $15.1
million, respectively.6.     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 must 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 correspondingly increased to 2,433,600.

     During the years ended December 31, 2001, 2000 and 1999, Mariner Energy LLC granted stock options ("Options") of 13,166,
39,144 and 215,748, respectively. No options have been exercised, but 141,264 options have been canceled during the three year
period. At December 31, 2001, options to purchase 2,200,620 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 to 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 income for the year ended December 31, 2001
would have been decreased by $325,000 to $12,068,000 and the net income for the year ending 2000 would have decreased $422,000 and
the net loss for 1999 $428,000, 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 4.54% for the year ending December 31, 2001 and 4.75% and 6.46% for the years ending December 31, 2000 and 1999,
respectively. Stock options available for future grant amounted to 294,250 shares at December 31, 2001. Exercisable stock options
amounted to 2,044,742 shares at December 31, 2001.7.     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, must be determined annually and
must 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 2001, 2000 and 1999, the Company contributed $369,677, $291,940 and $180,000,
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, 2001, 2000 and 1999 were $5.8, $2.9 million and $1.0 million, respectively.8.      COMMITMENTS AND CONTINGENCIES

     Enron Matters- See "Note 2. Related-Party Transactions", the Company has various related-party transactions and certain
control relationships with Enron Corp. and affiliates.

     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, 2001 are as follows (in
thousands):

|2002  | 1,542 
|----- | ------
|2003  | 728   
|2004  | 121   
|2005  | 41    
|2006  | 10    
|      |       
|Total | $2,442
|      |       

Rental expense, before capitalization, was approximately $1,492,000, $1,228,000 and $1,170,000 for the years ended December
31, 2001, 2000 and 1999, respectively.

     Other Commitments- In the ordinary course of business we enter into long-term commitments to purchase seismic
data. The minimum annual payments under these contracts are $6.8 million in 2002, $6.3 million in 2003 and $2.7 million in 2004.

     Deepwater Rig- In the fourth quarter of 1999, Noble Drilling Corporation filed suit against the Company alleging breach 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. As of December 31, 2001, 208 days remained on this commitment and the Company has drilled six of
the seven prospects.

     Litigation- The Company, in the ordinary course of business, is a claimant and/or a defendant in various 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.9.     INCOME TAXES

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

|                                                         | YEAR ENDING DECEMBER 31,
|-------------------------------------------------------- | ------------------------
|
|
|
|
|
|Income (loss) before income taxes                        | 12,393                  
|Income tax expense (benefit) computed at statutory rates | 4,338                   
|Change in valuation allowance                            | (4,544)                 
|Other                                                    | 206                     
|Tax Expense                                              | --                      

No federal income taxes were paid by the Company during the years ended December 31, 2001, 2000 or 1999.

     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):

|                                                      | YEAR ENDING DECEMBER 31,
|----------------------------------------------------- | ------------------------
|
|
|
|DEFERRED TAX ASSETS:                                 
|Net operating loss carry forwards                     | $21,618                 
|Differences between book and tax basis of receivables | 10,335                  
|Valuation allowance                                   | (18,597)                
|Total net deferred tax assets                         | 13,356                  
|DEFERRED TAX LIABILITIES:                            
|Differences between book and tax bases of properties  | (13,356)                
|Total net deferred taxes                              | --                      

As of December 31, 2001, the Company had a cumulative net operating loss carryforward ("NOL") for federal income tax
purposes of approximately $61.8 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.10.      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):

|                                         | YEAR ENDING DECEMBER 31,
|---------------------------------------- | ------------------------
|
|
|
|Oil and gas sales                        | $155,000                
|Production costs                         | (20,063)                
|Transportation                           | (12,011)                
|Depreciation, depletion and amortization | (63,503)                
|
|Results of operations                    | $59,423                 
|

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

|                                                                                        | YEAR ENDING DECEMBER 31,
|--------------------------------------------------------------------------------------- | ------------------------
|
|
|
|Property acquisition costs     Unproved properties                                      | $ 8,721                 
|Exploration costs                                                                       | 57,665                  
|Development costs                                                                       | 96,999                  
|Proceeds from property conveyances                                                      | (90,500)                
|                                                                                        |                         
|Total costs, net of proceeds from     property conveyances                              | $72,885                 
|                                                                                        |                         
|Depreciation, depletion and amortization rate per      equivalent Mcf before impairment | $1.73                   

The Company capitalizes internal costs associated with exploration activities in progress. These capitalized costs were
approximately $10,508,000, $11,625,000 and $9,440,000 for the years ended December 31, 2001, 2000 and 1999, respectively.

     The following table summarizes costs related to unevaluated properties which have been excluded from amounts subject to
amortization at December 31, 2001. 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.

|                           | COST INCURRED DURING THE YEARENDED DECEMBER 31, |        | Total at
|-------------------------- | ----------------------------------------------- | ------ | --------
|
|
|Property acquisition costs | $3,340                                          | $1,714 | $130    
|Exploration costs          | 13,786                                          | 813    | 1,226   
|
|Total                      | $17,126                                         | $2,527 | $1,356  
|

All of the excluded costs at December 31, 2001 relate to activities in the Gulf of Mexico.11.      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, 2001 were reserves expected to be recovered from wells for which certain drilling and
completion operations had occurred as of that date, (See "Note 4. Recent Events" regarding sale of 50% of working interest in the
Falcon project subsequent to December 31, 2001) 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.

|ESTIMATED QUANTITIES OF PROVED RESERVES(in thousands)
|-----------------------------------------------------
|
|
|DECEMBER 31, 1998                                    
|
|Revisions of previous estimates                      
|Extensions, discoveries and other additions          
|Sale of reserves in place                            
|Production                                           
|
|DECEMBER 31, 1999                                    
|
|Revisions of previous estimates                      
|Extensions, discoveries and other additions          
|Sale of reserves in place                            
|Purchase of reserves in place                        
|Production                                           
|
|DECEMBER 31, 2000                                    
|
|Revisions of previous estimates                      
|Extensions, discoveries and other additions          
|Sale of reserves in place                            
|Production                                           
|
|DECEMBER 31, 2001                                    
|



|ESTIMATED QUANTITIES OF PROVED DEVELOPED RESERVES(in thousands)
|---------------------------------------------------------------
|
|
|December 31, 1999                                              
|December 31, 2000                                              
|December 31, 2001                                              

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.

|STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS(in thousands)
|----------------------------------------------------------------------
|
|
|
|
|Future cash inflows                                                   
|Future production costs                                               
|Future development costs                                              
|Future income taxes                                                   
|
|Future net cash flows                                                 
|
|Discount of future net cash flows at 10% per annum                    
|
|Standardized measure of discounted future net flows                   
|

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, 2001, 2000 and 1999, used in the above table, were $16.40, $26.36 and $23.85 per Bbl, respectively, and $2.60,
$11.32 and $2.23 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):

|                                                                             | YEAR ENDING DECEMBER 31,
|---------------------------------------------------------------------------- | ------------------------
|
|
|
|Sales and transfers of oil and gas produced,   net of production costs       | $(122,053)              
|Net changes in prices and production costs                                   | (661,871)               
|Extensions and discoveries, net of future   development and production costs | 130,512                 
|Development costs during period and net   change in development costs        | 40,674                  
|Revision of previous quantity estimates                                      | (106,813)               
|Purchases of reserves in place                                               | --                      
|Sales of reserves in place                                                   | (172,072)               
|Net change in income taxes                                                   | 270,509                 
|Accretion of discount before income taxes                                    | 104,321                 
|Changes in production rates (timing) and other                               | (23,884)                
|
|Net change                                                                   | $(540,677)              
|

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
4, 2002. 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.

|Name                  | Age | Position with the Company                       
|--------------------- | --- | ------------------------------------------------
|Scott Josey           | 44  | Chairman of the Board and Officer               
|Allan Keel            | 42  | President and Chief Executive Officer           
|Richard R. Clark      | 46  | Executive Vice President                        
|Michael A. Wichterich | 34  | Vice President of Finance & Administration      
|C. Ken Burgess        | 55  | Vice President of Drilling & Production         
|Mike van den Bold     | 39  | Vice President of Development                   
|Gregory K. Harless    | 52  | Vice President of Oil & Gas Marketing           
|Thomas E. Young       | 43  | Vice President of Business Development & Land   
|Kelly D. Zelikovitz   | 43  | General Counsel and Secretary                   
|David S. Huber        | 51  | Consultant and Director of Deepwater Development
|Robert E. Henderson   | 49  | Director                                        
|Michael W. Strickler  | 46  | Director                                        
|Craig A. Fox          | 46  | Director                                        
|Jesus G. Melendrez    | 42  | Director                                        
|Raymond M. Bowen, Jr. | 42  | Director                                        
|Jeffrey McMahon       | 41  | Director                                        
|Robert H. Walls, Jr.  | 41  | Director                                        

Mr. Josey is the Chairman of the Board of Mariner Energy, Inc. From 2000 to 2001, Mr. Josey served as Vice President and
Co-Manager of Enron Energy Capital Resources, which provided debt, mezzaine, and equity capital to energy companies. From 1995 to
2000, Mr. Josey was the managing partner of Sagestone Capital, which provided investment-banking services to the oil and gas industry
and portfolio management services to Commonfund Capital, a fund of funds for endowments and foundations. From 1993 to 1995, Mr.
Josey was a Director with Enron Capital & Trade Resources Corp. in its energy investment group. From 1982 to 1993, Mr. Josey was
with Texas Oil and Gas Corp., where he worked in all phases of its drilling, production, pipeline, corporate planning and commercial
activities. Mr. Josey is a member of the Society of Petroleum Engineers and the Independent Producers Association of America. Mr.
Josey received his BS in mechanical engineering from Texas A&M University, his MBA from the University of Texas, and his MS in
petroleum engineering from the University of Houston.

     Mr. Keel is President and Chief Executive Officer of Mariner Energy, Inc. He joined the company in August of 2001. Prior
to joining Mariner, Mr. Keel was employed as Vice President of Enron Energy Capital Resources where he originated and structured
volumetric production payments and private equity placements. From 1996 until mid-2000, Mr. Keel was employed by Westport Resources
Corporation as its Vice President and General Manager of the Gulf Coast region. In this capacity, Mr. Keel built Westport's Gulf of
Mexico business from a grassroots effort into a viable Gulf of Mexico entity. From 1984 to 1996, Mr. Keel was employed by Energen
Resources where he directed the company's exploration, joint venture, and acquisition activities. He received his BS and MS degrees
in geology from the University of Alabama and a MBA from Owen School of Management at Vanderbilt University. Mr. Keel is a member of
the American Association of Petroleum Geologists and the Independent Producers Association of America.

     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. Wichterich has been our Vice President of Finance and Administration since September 2001. Prior to obtaining this
position he was the Company's Corporate Controller from 1998 through August 2001. He was previously employed at
PricewaterhouseCoopers from 1989 through 1998 with ending title of Senior Manager.

     Mr. Burgess has serviced as Vice President of Drilling and Production since September 2001. Before obtaining this position
he was Manager of Drilling from 1998 until August 2001. Prior to this time he was employed by Conoco Inc., serving in various
drilling engineering and operations management positions, both domestically and international. Ken has 29 years industry experience,
including 15 years in GOM and international arenas.

     Mr. van den Bold has been our Vice President of Development since October 2001. Prior to obtaining his position, he was a
Senior Development Geologist. He was previously employed at British Borneo and British Petroleum from 1986 through 2000 in various
exploration and development positions. He received his BS and MS degrees in geology from the Louisiana State University.

     Mr. Harless has been our Vice President - Oil and Gas Marketing since 1990. His experience before joining us in 1988
included Vice President of marketing and regulatory affairs of Enron Oil and Gas Company and District Operations Manager with Coastal
States Oil & Gas Co.

     Mr. Young joined Mariner Energy, Inc., in 1985 and is currently serving as Vice President - Business Development and Land.
Tom has spent the majority of his career with Mariner Energy serving in various managerial positions, which include domestic and
international negotiations. During his tenure, Tom has been involved in acquisition, exploration, production and marketing of
properties in the Gulf of Mexico, with emphasis in Deepwater Gulf of Mexico. His last assignment as Vice President - Land, included,
among other things, supervision of lease acquisitions, contract negotiations, planning, forecasting, and strategy formation for the
Company.

     Ms. Zelikovitz has been our General Counsel and Secretary since August 2000. She is in private practice and has a
contractual relationship with us. Prior to May 1998, she held various legal and management positions with Mobil Oil Corporation,
Greenhill Petroleum Corporation, Union Texas Petroleum Corporation, and with a Houston-based law firm.

     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. Henderson has been a Director since 1985. From May 1996 to August 2001 he was President and Chief Executive Officer.
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. Strickler has been a Director since 1989. From May 1996 until August 2001 he served as Senior Vice President of
Exploration. 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.

     Mr. Fox is Vice President and Technical Manager for Enron Energy Capital Resources. Mr. Fox received his bachelor's of
science degree in mechanical engineering from Texas A&M University in 1977. He was employed with Houston Oil & Minerals, Tenneco Oil
Company, and Sandefer Oil & Gas as a reservoir and production engineer for 15 years before joining Enron Finance Corp. in 1992 as a
Senior Reservoir Engineer. He became a Vice President in the engineering group supporting producer finance in 1995.

     Mr. Melendrez is a Vice President of ENA and is responsible for the execution and structuring of upstream transactions.
Prior to joining ENA in 1999, Mr. Melendrez was Sr. Vice President of Enserch Energy Services, Inc. He has held financial positions
with several Enron affiliates since the early 1990's that involved loan restructuring and power marketing.

     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. McMahon became a director in March 2002. Since January 28, 2002, Mr. McMahon holds the position of President & Chief
Operating Officer of Enron Corp. Mr. McMahon is responsible for managing the reorganization process under Chapter 11 of the
bankruptcy code as well as the day to day operations of the company. Mr. McMahon was appointed to this position as part of a complete
change in the executive management of Enron in late 2001 and early 2002. For a short period prior to this, Mr. McMahon held the
position of Chief Financial Officer. Previously, Mr. McMahon held the position of President and Chief Executive Officer of Enron
Industrial Markets. In this operating position, Mr. McMahon was responsible for all aspects of Enron's forest products and steel
business worldwide.

     Mr. Walls is currently Executive Vice President and General Counsel for Enron Corp. He held the position
of Managing Director and Deputy General Counsel of Enron Corp. from August, 2000 to March, 2002. Prior to that he served as Managing
Director and General Counsel of Enron International Inc. where he was responsible for the legal activities of Enron's international
business. Rob began his legal career with Vinson & Elkins, L.L.P. in 1985, where he gained extensive experience in
the areas of energy, finance and international law. He left Vinson & Elkins in 1992 to serve as Vice President and General Counsel
of Enron Power Corp. and became Senior Vice President and General Counsel of Enron Development Corp. when Enron reorganized in late
1995.

     The Shareholders' Agreement requires that the Board of Directors include at least three nominees of the Management
Stockholders. The remaining board members are to include nominees of JEDI. See "Certain Relationships and Related Transactions on
page 72.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, 2001. These individuals are sometimes referred to as the
"named executive officers".

|NAME AND PRINCIPAL POSITION                                   | YEAR         | ANNUALSALARY          | OTHER ANNUALCOMPENSATION (1) | CURRENT YEARCOMPENSATION UNDEROUR OVERRIDINGROYALTY PROGRAM (2) | ALL OTHERCOMPENSATION (3)
|------------------------------------------------------------- | ------------ | --------------------- | ---------------------------- | --------------------------------------------------------------- | -------------------------
|
|Allan D. Keel(4)President and Chief Executive Officer         | 200120001999 | 000                   | 000                          | 000                                                             | 000                      
|Richard R. ClarkExecutive Vice President                      | 200120001999 | 250,000235,000225,000 | 6,8003,6806,400              | 7,0435,5963,508                                                 | 270210243                
|C. Ken BurgessVice President - Drilling and Production        | 200120001999 | 170,000141,500135,000 | 6,8003,3001,350              | 000                                                             | 53,48951,0409,140        
|Gregory K. HarlessVice President - Oil&Gas Marketing          | 200120001999 | 156,000149,000143,000 | 5,9603,2905,720              | 4,4003,5062,192                                                 | 414414497                
|Donald M. Clement, Jr.Exploration Manager, Gulf of Mexico     | 200120001999 | 154,000144,000137,000 | 6,8003,4801,718              | 2,2561,4611,075                                                 | 45,27051,64514,670       
|Thomas E. YoungVice President - Business Development and Land | 200120001999 | 150,000129,000120,000 | 5,1602,8174,200              | 2,8402,3561,418                                                 | 180180243                

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 2001, 2000 or 1999.
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. Keel performs his services under a Services Agreement with ENA at $20,000 per month.

Options

     None of the named executive officers exercised stock options in 2001. The following table shows the number and value of
options owned by our named executive officers at December 31, 2001. All of the options described in the table below have been issued
under the Mariner Energy LLC 1996 Stock Option Plan.

|                       | NUMBER OFCOMMON SHARESUNDERLYINGUNEXERCISED OPTIONS ATDECEMBER 31, 2001
|---------------------- | -----------------------------------------------------------------------
|
|
|
|C. Ken Burgess         | 31,973                                                                 
|Richard R. Clark       | 167,928                                                                
|Donald M. Clement, Jr. | 96,690                                                                 
|Gregory K. Harless     | 42,840                                                                 
|Thomas E. Young        | 42,840                                                                 

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 our shareholders and us. 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 2,139,350 common shares are
outstanding under the 1996 plan, 2,044,742 of which are currently exercisable. The exercise price for outstanding options to purchase
an aggregate of 1,608,516 shares under the 1996 plan is $8.33 per share, and the exercise price for options to purchase the remaining
outstanding aggregate of 530,834 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 except
for Mr. Keel who performs his services under a Service Agreement with ENA at $20,000 per month. Following the expiration date of an
employment agreement or the expiration of any extended term, the employment agreements extend for three to 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 $250,000 for Mr. Clark, $170,000 for Mr. Burgess, $156,000
for Mr. Harless, $154,000 for Clement and $150,000 for Mr. Young. 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, Mr. Clark, Mr.
Harless, and Mr. Young are entitled to receive overriding royalty interests in some oil and gas prospects that we have acquired under
our overriding royalty program. Mr. Burgess and Mr. Clement are entitled to receive annual cash bonuses and incentive stock option
awards under an incentive compensation plan separate from other named executive officers.

     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:

- the value of his salary and other benefits through the end of the initial term or any extended term of the employment
agreement;
- a lump sum cash payment equal to nine months salary in the case of Mr. Clark, six months salary in the case of Messrs.
Harless, Clement and Young and three months salary in the case of Mr. Burgess;
- a lump sum cash payment equal to all earned and unused vacation time for the previous year and the then current year;
- an assignment of his vested interests under our overriding royalty program, if eligible; and
- in the case of Messrs. Burgess and Clement, 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 25% 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:

- the value of his salary and benefits through the date that his employment agreement is terminated;
- a lump sum cash payment equal to all earned and unused vacation time for the previous year and the then current year;
- an assignment of his vested interests in our overriding royalty program through the date of termination, if eligible; and
- in the case of Messrs. Burgess and Clement, 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 25% 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 us for cause, we will have no obligation to that
employee other than to:

- pay his salary through the day of termination;
- pay him the value of his benefits under the employment agreement through the month of termination; and
- 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 Messr. Clark, and six months after the term expires in the case of Messrs.
Harless, Clement, Burgess, and Young, they will not compete with us for business or hire our employees.

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

- 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;
- 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;
- 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;
- 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
- 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.

In March of 2002, Mr. Clark, Mr. Harless, and Mr. Young terminated their employment agreements for "Good Reason" under terms
as defined in their contracts.
Change of Control Agreements

     We have issued 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, Messr. Clark is entitled to receive, if the change in control is due to an acquisition of us by another company,
three and one-half times his base salary and targeted annual incentive bonus, if applicable. Messrs. Harless, Clement, and Young are
entitled to receive, if the change in control is due to an acquisition of us by another company, two 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 agreements 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.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 we propose to sell or farm out all or a portion of our working interest in a prospect to an unaffiliated third party 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 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 from overriding royalty interests we granted to the officers during the last 15 years.

|                   | AGGREGATE CASH AMOUNTS RECEIVEDFROM PREVIOUSLY ASSIGNEDOVERRIDDINGROYALTY INTERESTS (1)
|------------------ | ---------------------------------------------------------------------------------------
|
|
|Richard R. Clark   | 544,237                                                                                
|Gregory K. Harless | 382,985                                                                                
|Thomas E. Young    | 189,059                                                                                

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". The above amounts only include payments made by the Company. Certain participants also
receive overrides from third parties.

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, 2001, there were 13,928,308 common
shares of Mariner Energy LLC outstanding.

|TITLE OF CLASS                    | NAME AND ADDRESSOF BENEFICIAL OWNER                                                                      | NATURE OFBENEFICIAL OWNERSHIP | AMOUNT ANDPERCENT OF CLASS
|--------------------------------- | -------------------------------------------------------------------------------------------------------- | ----------------------------- | --------------------------
|Common Stock ofMariner Energy LLC | Joint Energy Development    Investments Limited Partnership(1)1400 Smith Street    Houston, Texas  77002 | 13,334,186                    | 95.7%                     

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.

The table appearing below sets forth information as of March 4, 2002, with respect common shares of Mariner Energy LLC
beneficially owned by each of our directors, the 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.

|DIRECTORS, KEY CONSULTANT ANDNAMED EXECUTIVE OFFICERS                  | AMOUNT AND NATURE OFBENEFICIAL OWNERSHIP (1) | PERCENTOF CLASS
|---------------------------------------------------------------------- | -------------------------------------------- | ---------------
|Robert E. Henderson                                                    | 84,840                                       | *              
|C. Ken Burgess                                                         | 0                                            | --             
|Richard R. Clark                                                       | 61,440                                       | *              
|Donald M. Clement, Jr.                                                 | 12,000                                       | *              
|Gregory K. Harless                                                     | 13,200                                       | *              
|David S. Huber                                                         | 61,440                                       | *              
|Michael W. Strickler                                                   | 61,440                                       | *              
|Thomas E. Young                                                        | 15,600                                       | *              
|All directors and executive officersconsultant as a group (10 persons) | 309,960                                      | 2.23%          

* 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.

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 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.

     Enron Bankruptcy- On December 2, 2001, Enron Corp. ("Enron") and one of its affiliates,Enron
North America Corp. ("ENA"), among other affiliates filed voluntary petitions for bankruptcy protection. The Company has been informed that of the various
affiliates of Enron to Mariner, only Enron and ENA are included in the bankruptcy. We do not know at this time if any other
affiliates of Enron will seek bankruptcy protection or what effect, if any, this may have on Joint Energy Development Investments Limited
Partnership ("JEDI") or the ownership of Mariner Energy LLC which owns 100% of our direct parent. Enron is the parent of ENA, and
an affiliate of ENA is the general partner of JEDI. JEDI is 100% owned by several different Enron and ENA affiliates. Accordingly,
Enron may be deemed to control JEDI, Mariner Energy LLC, Mariner Holdings and the Company. Additionally, seven of the Company's
directors are officers of Enron or affiliates of Enron. Because of these various potentially 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.
     Mariner Energy LLC's only asset is 100% of the common stock of Mariner Holdings, Inc., our direct parent. The only asset
of Mariner Holdings is 100% of the common shares of Mariner. Covenants in Mariner's Revolving Credit Facility and Senior
Subordinated Notes restrict the funds of Mariner that can be distributed to Mariner Energy LLC to repay its term loan to an ENA
affiliate - see below "ENA Affiliate Term Loan". Mariner Energy LLC is currently attempting to obtain an extension of the ENA
Affiliate Term Loan, but there can be no assurance that an extension will be obtained. In the event Mariner Energy LLC is unable to
obtain an extension or restructure its obligations, it would either default or be forced to sell its interest in Mariner or cause
Mariner to sell a substantial portion of its assets to repay its Revolving Credit Facility, if any amounts are outstanding, and
outstanding Senior Subordinated Notes so that it could distribute any remaining cash proceeds to Mariner Energy LLC to be used to
repay the ENA Affiliate Term Loan.

     As a result of the Enron and ENA bankruptcies, among other implications, as part of our normal operations we may not be able
to obtain credit from banks or trade vendors or enter into hedging arrangements on acceptable terms. This may also hinder our
ability to enter into certain transactions including purchase or sale arrangements and conduct significant capital programs.

     Organization and Ownership of the Company - 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 company
incorporated in the United Kingdom. Pursuant to a stock purchase agreement dated April 1, 1996, JEDI and ENA, together with members
of management of the Predecessor Company, formed Mariner Holdings, Inc. ("Mariner Holdings"). Mariner Holdings 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 (the "Acquisition"). After the Acquisition, the name of the Predecessor Company was changed to Mariner Energy, Inc. In
October 1998, JEDI and other shareholders exchanged all of their common shares of Mariner Holdings, the Company's direct parent, for
an equivalent ownership percentage in common shares of Mariner Energy LLC. Mariner Energy LLC owns 100% of Mariner Holdings.

     The following chart represents our current ownership structure and affiliation with Enron entities.



Subsequent to the Acquisition, Mariner Energy LLC, Mariner Holdings and Mariner have each entered into various
financing and operating transactions with affiliates. In addition the Company may have from time to time engaged 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 and entering into other oil and
gas related or financial transactions. Certain of the Company's third-party debt instruments and arrangements 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 obtained in an agreement with a third party. Below is a
summary of key transactions between the Company and affiliate entities.Mariner Energy LLC

     ENA Credit Facility - In September 1998 Mariner Holdings established a credit facility to obtain additional capital. The
credit facility, as subsequently amended and assigned to Mariner Energy LLC, provided for unsecured, subordinated loans of up to $50
million, bearing interest at LIBOR plus 4.5%, payable at April 30, 2000. The full amount borrowed under this credit facility was
repaid on March 21, 2000 with proceeds from the ENA Affiliate Term Loan described below. The net proceeds from this facility were
contributed to Mariner.

     ENA Affiliate Term Loan - In March 2000, Mariner Energy LLC established an unsecured term loan with ENA to repay amounts
outstanding under the ENA Credit Facility with Mariner Energy LLC ($50 million plus accrued interest) described above and Mariner's
Senior Credit Facility with ENA ($25 million plus accrued interest), described below, and to provide additional working capital. The
additional working capital of $55 million was contributed to Mariner in 2000. The loan bears interest at 15%, which interest accrues
and is added to the loan principal. Repayment of the balance of loan principal and accrued interest, which was approximately $143
million as of December 31, 2001, is due March 20, 2003. As part of the loan agreement, two five-year warrants were issued to ENA
providing the right to purchase up to 900,000 of common shares of Mariner Energy LLC for $0.01 per share.

     We have been informed that the Term Loan was transferred from ENA to an ENA affiliate.Mariner Holdings, Inc.

     1998 Equity Investment - In June 1998, Mariner Holdings issued additional equity to its existing shareholders, including
JEDI, for approximately $14.58 per share, for a net investment of $28.8 million, all of which was contributed to Mariner. Mariner
Holdings paid approximately $1.2 million as a structuring fee, on a pro rata basis, to existing shareholders participating in this
transaction. Approximately $1 million of this fee was paid to ECT Securities Limited Partnership.Mariner Energy, Inc.

     Senior Credit Facility with ENA - In April 1999 Mariner established a senior credit facility with ENA primarily to obtain
additional working capital. The facility provided for senior unsecured revolving loans of up to $25 million, bearing interest at
LIBOR plus 2.5%, payable quarterly. The full amount borrowed under the senior credit facility was repaid on March 21, 2000, with
proceeds from the ENA Affiliate Term Loan described above.Other Transactions

     Oil and Gas Production Sales to ENA or Affiliates - During the three years ending December 31, 2001, 2000 and 1999, sales of
oil and gas production to ENA or affiliates were $50.2 million, $73.4 million and $16.2 million, respectively. These sales were generally made on 1 to 3
month contracts. At the time ENA filed its petition for bankruptcy protection, the Company immediately ceased selling its physical
production to ENA. As of December 31, 2001, we had an outstanding receivable for $3.0 million from ENA. This amount was not paid as
scheduled and is still outstanding. The Company has estimated 90% of this balance is uncollectible and has recorded an allowance and
related expense for $2.7 million.

     Accounting for Price Risk Management Activities- Mariner engages in price risk management activities from time to time.
These activities are intended to manage Mariner's exposure to fluctuations in commodity prices for natural gas and crude oil. The
Company primarily utilizes price swaps and costless collars as a means to manage such risk. During 2001 and as of December 31, 2001,
all of our hedging contracts were with ENA. As a result of ENA's bankruptcy, the contracts are currently in default. The November
and December settlements for oil and gas have not been collected, and there is significant uncertainty that the $4.0 million owed to
the Company for the November and December settlements or any future settlements will be collected. As a result of the default, the
Company has recorded an allowance representing 90% of the recorded hedge settlements receivable of $4.0 million, fair market value of
the derivative assets of $25.8 (as of December 2, 2001), and accounts receivable for oil and gas sales of $3.0 million. Reflected in
the earnings of the Company for the period ended December 31, 2001 is a loss for impairment of Enron related receivables of $29.5
million. In accordance with Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative Instruments and
Hedging Activities," as amended by SFAS No. 137 and No. 138, we have de designated our contracts effective December 2, 2001 and are
recognizing all market value changes subsequent to such de-designation in earnings of the Company. The value recorded up to the time
of de-designation and included in Accumulated Other Comprehensive Income ("AOCI"), will reverse out of AOCI and into earnings as the
original corresponding production, as hedged by the contracts, is produced. As of December 31, 2001, $25.8 million remained in AOCI
to be reversed out during the contract periods covering January 1, 2002 through December 31, 2003. Due to the uncertainty of future
settlements, the overall effect of the ENA bankruptcy has been to eliminate our commodity price hedge protection.

     The following table sets forth the results of hedging transactions during the periods indicated. For the year ended December
31, 2001, the amounts are reflective of the results up to the point of de-designation (December 2, 2001), which include all settled
contract months through December of 2001:

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

|                                                     | YEAR ENDING DECEMBER 31,
|---------------------------------------------------- | ------------------------
|
|
|
|Natural gas quantity hedged (Mmbtu)                  | 17,733                  
|Increase (decrease) in natural gas sales (thousands) | $(5,523)                
|Crude oil quantity hedged (MBbls)                    | 752                     
|Increase (decrease) in crude oil sales (thousands)   | $2,393                  

The following table sets forth our open positions as of December 31, 2001.

|TIME PERIOD                   | NOTIONALQUANTITIES | FIXED PRICE | FAIR VALUE(in millions)
|----------------------------- | ------------------ | ----------- | -----------------------
|NATURAL GAS (MMBTU)          
|January 1 - October 31, 2002 
|Fixed price swap purchased    | 1,831              | $2.18       | $(0.9)                 
|January 1 - December 31, 2002
|Fixed price swap purchased    | 12,134             | 4.43        | 20.4                   
|April 1 - December 31, 2002  
|Fixed price swap purchased    | 4,125              | 3.03        | 0.9                    
|January 1 - December 31, 2003
|Fixed price swap purchased    | 3,650              | 3.74        | 2.0                    
|CRUDE OIL (MBBL)             
|January 1 - June 30, 2002    
|Fixed price swap purchased    | 181                | 25.15       | 0.9                    
|January 1 - December 31, 2002
|Fixed price swap purchased    | 365                | 25.48       | 1.9                    
|Sub-Total                     |                    |             | $25.2(1)               
|                              |                    |             |                        
|Allowance for impairment      |                    |             | $(22.7)                
|                              |                    |             |                        
|Total                         |                    |             | $2.5                   
|                              |                    |             |                        

1. Subsequent to the date of default by Enron and ENA, and as of December 31, 2001, the contracts decreased in gross market
value by $523,000, which is reflected in the impairment of related party receivables at the net valuation of 10% or
$52,000, after consideration for allowance.

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 that is not in bankruptcy, purchased the flowline from the
Company and its joint interest partners. The Company received $8.8 million in cash proceeds that 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
with MEGS LLC at a rate of $0.26 per Mmbtu to transport the Company's share of 86 Bcf of natural gas from the commencement of
production through March 2009. The Company's working interest in the well at December 31, 2001 was 51%. For the year ending
December 31, 2001, the Company paid $4.2 million on this contract. The remaining volume commitment is 30.8 Bbtu or $7.9 million net
to the Company. Pursuant to the contract, the Company must deliver minimum quantities through the flowline or be subject to minimum
monthly payment requirements. Throughout 2001 the Company failed to meet these minimum requirements and paid $1.5 million relating to
the shortfall. The Company estimates that future production will also fail to meet minimum delivery requirements and has accrued
$972,000 for future shortfalls.

     Services Agreement- In conjunction with the change of certain key management positions, the Company entered into a services
agreement for ENA to provide certain administrative services. The Company is obligated to pay $45,000 per month under this agreement.

     Supplemental Affiliate Data- Provided below is supplemental balance sheet and income statement amounts for affiliate
entities:

|                                        | YEAR ENDED DECEMBER 31,
|--------------------------------------- | -----------------------
|
|
|RELATED PARTY RECEIVABLE:               |                        
|Derivative Asset                        | $2.5                   
|Settled Hedge Receivable                | 0.4                    
|Oil and Gas Receivable                  | 0.3                    
|ACCURED LIABILITIES:                    |                        
|Transportation Contract                 | $0.9                   
|Service Agreement                       | $0.3                   
|STOCKHOLDERS' EQUITY:                  
|Common Stock                            | $0.001                 
|Additional Paid-in Capital              | $227.3                 
|INCOME STATEMENT DATA                  
|Oil and Gas Sales                       | $50.2                  
|General and Administrative Expenses     | 0.2                    
|Transportation Expenses                 | 4.2                    
|Impairment of Enron Related Receivables | 29.5                   

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 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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# 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".

     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.

     "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.

|SIGNATURES                                                                                                                              
|----------------------------------------------------------------------------------------------------------------------------------------
|The registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.                     
|April 16, 2002                                                                                                                          
|MARINER ENERGY, INC.
     by: /s/   Allan Keel          Allan Keel,
          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.
|SIGNATURE                                                                                                                               
|/s/   Scott D. Josey                                                                                                                    
|                                                                                                                                        
|Scott D. Josey                                                                                                                          
|/s/   Allan D. Keel                                                                                                                     
|                                                                                                                                        
|Allan D. Keel                                                                                                                           
|/s/   Michael A. Wichterich                                                                                                             
|                                                                                                                                        
|Michael A. Wichterich                                                                                                                   
|/s/   C. Ken Burgess                                                                                                                    
|                                                                                                                                        
|C. Ken Burgess                                                                                                                          
|/s/   Mike van den Bold                                                                                                                 
|                                                                                                                                        
|Mike van den Bold                                                                                                                       
|/s/   Kelly D. Zelikovitz                                                                                                               
|                                                                                                                                        
|Kelly D. Zelikovitz                                                                                                                     
|/s/   David S. Huber                                                                                                                    
|                                                                                                                                        
|David S. Huber                                                                                                                          
|/s/   Robert E. Henderson                                                                                                               
|                                                                                                                                        
|Robert E. Henderson                                                                                                                     
|/s/   Michael W. Strickler                                                                                                              
|                                                                                                                                        
|Michael W. Strickler                                                                                                                    
|/s/   Craig A. Fox                                                                                                                      
|                                                                                                                                        
|Craig A. Fox                                                                                                                            
|/s/   Jesus G. Melendrez                                                                                                                
|                                                                                                                                        
|Jesus G. Melendrez                                                                                                                      
|/s/   Raymond M. Bowen, Jr.                                                                                                             
|                                                                                                                                        
|Raymond M. Bowen, Jr.                                                                                                                   
|/s/   Jeffrey McMahon                                                                                                                   
|                                                                                                                                        
|Jeffrey McMahon                                                                                                                         
|/s/   Robert H. Walls, Jr.                                                                                                              
|                                                                                                                                        
|Robert H. Walls, Jr.                                                                                                                    

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.