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As filed with the Securities and Exchange Commission on July 26, 2005
Registration No. 333-124858
 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Amendment No. 1
to
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
 
Mariner Energy, Inc.
(Exact name of registrant as specified in its charter)
         
Delaware   1311   86-0460233
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification Number)
2101 CityWest Blvd., Bldg. 4, Suite 900
Houston, Texas 77042
(713) 954-5500
(Address, including zip code, and telephone number,
including area code, of registrant’s principal executive offices)
Teresa Bushman
Vice President and General Counsel
Mariner Energy, Inc.
2101 CityWest Blvd., Bldg. 4, Suite 900
Houston, Texas 77042
(713) 954-5505
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
 
Copies to:
     
Kelly B. Rose
Baker Botts L.L.P.
One Shell Plaza
910 Louisiana
Houston, Texas 77002
(713) 229-1796
  Brian J. Lynch, Esq.
Robert A. Welp, Esq.
Hogan & Hartson L.L.P.
8300 Greensboro Drive, Suite 1100
McLean, Virginia 22102
(703) 610-6100
 
     Approximate date of commencement of proposed sale to the public: From time to time after the effective date of this registration statement.
     If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act, check the following box.    þ
     If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o
     If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o
     If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o
     If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box.    o
     The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.
 
 


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The information in this prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.
Subject to Completion dated July 26, 2005
PROSPECTUS
(MARINER ENERGY, INC. LOGO)
33,348,130 Shares
Common Stock
 
         This prospectus relates to up to 33,348,130 shares of the common stock of Mariner Energy, Inc., which may be offered for sale by the selling stockholders named in this prospectus. The selling stockholders acquired the shares of common stock offered by this prospectus in private equity placements. We are registering the offer and sale of the shares of common stock to satisfy registration rights we have granted.
      We are not selling any shares of common stock under this prospectus and will not receive any proceeds from the sale of common stock by the selling stockholders. The shares of common stock to which this prospectus relates may be offered and sold from time to time directly from the selling stockholders or alternatively through underwriters or broker-dealers or agents. The shares of common stock may be sold in one or more transactions, at fixed prices, at prevailing market prices at the time of sale or at negotiated prices. Please read “Plan of Distribution.”
      Prior to this offering, there has been no public market for our common stock. We have applied to list our common stock on The Nasdaq Stock Market under the symbol MRNR.
 
      Investing in our common stock involves risks. You should read the section entitled “Risk Factors” beginning on page 8 for a discussion of certain risk factors that you should consider before investing in our common stock.
 
      You should rely only on the information contained in this prospectus or any prospectus supplement or amendment. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted.
      Neither the Securities and Exchange Commission (the “SEC”) nor any state securities commission has approved or disapproved of these securities or determined whether this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
The date of this prospectus is                     , 2005.


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 Consent of Deloitte & Touche LLP
 Consent of Ryder Scott Company, L.P.
WHERE YOU CAN FIND INFORMATION
      We have filed with the SEC, under the Securities Act of 1933, as amended (the “Securities Act”), a registration statement on Form S-1 with respect to the common stock offered by this prospectus. This prospectus, which constitutes part of the registration statement, does not contain all the information set forth in the registration statement or the exhibits and schedules which are part of the registration statement, portions of which are omitted as permitted by the rules and regulations of the SEC. Statements made in this prospectus regarding the contents of any contract or other documents are summaries of the material terms of the contract or document. With respect to each contract or document filed as an exhibit to the registration statement, reference is made to the corresponding exhibit. For further information pertaining to us and to the common stock offered by this prospectus, reference is made to the registration statement, including the exhibits and schedules thereto, copies of which may be inspected without charge at the public reference facilities of the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549. Copies of all or any portion of the registration statement may be obtained from the SEC at prescribed rates. Information on the public reference facilities may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a web site that contains reports, proxy and information statements and other information that is filed electronically with the SEC. The web site can be accessed at www.sec.gov.
      Upon completion of this offering, we will be required to comply with the informational requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and, accordingly, will file current reports on Form 8-K, quarterly reports on Form 10-Q, annual reports on Form 10-K, proxy statements and other information with the SEC. Those reports, proxy statements and other information will be available for inspection and copying at the public reference facilities and internet site of the SEC referred to above.

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SUMMARY
      This summary highlights selected information from this prospectus, but does not contain all information that you should consider before investing in the shares. You should read this entire prospectus carefully, including the “Risk Factors” beginning on page 8 of this prospectus and the financial statements included elsewhere in this prospectus. References to “Mariner,” “the Company,” “we,” “us,” and “our” refer to Mariner Energy, Inc. The estimates of our proved reserves as of December 31, 2002, 2003 and 2004 included in this prospectus are based on reserve reports prepared by Ryder Scott Company, L.P., independent petroleum engineers (“Ryder Scott”). A summary of their report on our proved reserves as of December 31, 2004 is attached to this prospectus as Annex A. We have provided definitions for some of the industry terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” beginning on page 89 of this prospectus.
About Mariner Energy, Inc.
      We are an independent oil and gas exploration, development and production company with principal operations in the Gulf of Mexico, both shelf and deepwater, and the Permian Basin in West Texas. As of December 31, 2004, we had 237.5 Bcfe of proved reserves, of which approximately 64% were natural gas and 36% were oil and condensate. As of December 31, 2004, the present value, discounted at 10% per annum, of estimated future net revenues from our proved reserves, before income tax, (“PV10”) was approximately $668 million, and our standardized measure of discounted future net cash flows attributable to our proved reserves was approximately $494 million. As of December 31, 2004, approximately 46% of our proved reserves were classified as proved developed. For the year ended December 31, 2004, our total net production was 37.6 Bcfe. We believe our proved reserve base is balanced, with 48% of the reserves located in the Permian Basin in West Texas, 37% in the Gulf of Mexico deepwater and 15% on the Gulf of Mexico shelf as of December 31, 2004. In the three-year period ended December 31, 2004, we deployed approximately $337.3 million of capital on acquisitions, exploration and development while adding approximately 190.8 Bcfe of proved reserves and producing approximately 110.7 Bcfe.
Summary of Geographic Areas of Activities
      The following table sets forth the estimated quantities of proved reserves attributable to our principal operating regions as of December 31, 2004.
                                   
    Estimated Proved Reserves(1)
     
    Oil   Natural   Total   Percent of
    (MMbbls)   Gas (Bcf)   (Bcfe)   Reserves
                 
West Texas Permian Basin
    8.7       62.8       114.8       48%  
Gulf of Mexico Deepwater(2)
    4.5       59.8       86.7       37%  
Gulf of Mexico Shelf(3)
    1.1       29.3       36.0       15%  
                         
 
Total
    14.3       151.9       237.5       100%  
                         
 
(1)  These estimates are based upon a reserve report prepared by Ryder Scott using criteria in compliance with SEC guidelines. A summary of their report is attached as Annex A to this prospectus.
(2)  Deepwater refers to water depths greater than 1,300 feet (the approximate depth of deepwater designation for royalty purposes by the U.S. Minerals Management Service (the “MMS”)).
(3)  Shelf refers to water depths less than 1,300 feet and includes an insignificant amount of Gulf Coast onshore properties.
      The distribution of our proved reserves reflects our efforts over the last three years to diversify our asset base, which in prior years had been focused primarily in the Gulf of Mexico deepwater. We have shifted some of our focus on deepwater activities to increased exploration and development on the Gulf of Mexico shelf and exploitation of our West Texas Permian Basin properties. By allocating our resources among these three areas, we expect to balance the risks associated with the exploration and development

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of our asset base. We intend to continue to pursue moderate-risk exploratory and development drilling projects in the Gulf of Mexico deepwater and on the Gulf of Mexico shelf, and also target low-risk infill drilling projects in West Texas. It is our practice to generate most of our prospects internally, but from time to time we also acquire third-party generated prospects. We then drill to find oil and natural gas reserves, a process that we refer to as “growth through the drill bit.”
West Texas Permian Basin
      We operate and own working interests in individual wells ranging from 33% to 84% (with an average working interest of approximately 66.5%) in the 18,500-acre Aldwell Unit, which has produced oil and gas since 1949. As of December 31, 2004, the Aldwell Unit and nearby North Stiles Unit accounted for 48%, or 114.8 Bcfe, of our proved reserves. The Aldwell and North Stiles Units are located in the heart of the Spraberry geologic trend southeast of Midland, Texas. We began our recent redevelopment of the Aldwell Unit by drilling eight wells in the fourth quarter of 2002, 43 wells in 2003, and 54 wells in 2004. We have accelerated our development program and anticipate drilling an additional 60-70 wells in the Aldwell Unit during 2005. During the five months ended May 31, 2005, we drilled 36 wells at our Aldwell and North Stiles Units. All of our drilling in the Aldwell and North Stiles Units has resulted in commercially successful wells that are expected to produce in quantities sufficient to exceed costs of drilling and completion. As of December 31, 2004, there were a total of 185 wells producing or capable of producing in the field. Our aggregate net capital expenditures for the 2004 drilling program were approximately $20.3 million.
Gulf of Mexico Deepwater
      We have interests in nine fields in the Gulf of Mexico deepwater, three of which we operate. The Gulf of Mexico deepwater accounts for 37%, or 86.7 Bcfe, of our December 31, 2004 proved reserves. Our net production from deepwater wells for December 2004 averaged approximately 44 MMcfe per day. As of March 31, 2005, we held interests in 53 Gulf of Mexico blocks with water depths of over 1,300 feet and had approximately 125,000 net undeveloped acres under lease. In 2004, we spent approximately $63.5 million net on drilling and completion activities in the deepwater. We drilled five exploratory wells, four of which were successful, and one development well, which was also successful.
      In 2004, four subsea tiebacks were in the development phase in the deepwater: Mississippi Canyon 718 (Pluto), Viosca Knoll 917 (Swordfish), Green Canyon 178 (Baccarat) and Mississippi Canyon 296 (Rigel). These four subsea tieback projects contain approximately 49 Bcfe of proved reserves as of December 31, 2004. Currently, production is expected to commence from all four projects in the second half of 2005. Swordfish, Baccarat and Rigel are the results of Mariner-generated prospects. The Swordfish and Pluto projects are operated by Mariner, and the Baccarat and Rigel projects are operated by other working interest owners.
Gulf of Mexico Shelf
      In the past two years, we have increased our drilling activities on the Gulf of Mexico shelf. As of March 31, 2005, we held interests in 22 fields on the Gulf of Mexico shelf, seven of which we operate. Gulf of Mexico shelf properties comprise 15%, or 36 Bcfe, of our proved reserves as of December 31, 2004. Our net production from these wells for December 2004 averaged approximately 35 MMcfe per day. As of March 31, 2005, we held interests in 59 Gulf of Mexico shelf blocks and had approximately 90,000 net undeveloped acres under lease. During 2004, we spent approximately $38.3 million to drill nine exploratory wells, three of which were successful, and two development wells, one of which was successful, on the Gulf of Mexico shelf.
      First production from our Ewing Bank 977 (Dice) project, a subsea tieback, and High Island 46 (Green Pepper) commenced in January 2005. First production from our two West Cameron 333 wells (Royal Flush) commenced during February 2005.

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Recent Developments
      Recent Tropical Storm Cindy and Hurricanes Dennis and Emily did not cause any significant damage to any of our projects in the Gulf of Mexico. However, as a precaution prior to Hurricane Dennis, workers and equipment were evacuated from several of our producing platforms and our Pluto and Baccarat development projects. The storm interruptions resulted in temporary shut-in of production at Ewing Bank 966 (Black Widow), Green Canyon 472/473 (King Kong) and Mississippi Canyon 357 and minor delays of our development activities at our Pluto and Baccarat projects. Production was restored to full capacity after the storm passed.
      Operations. During the first five months of 2005, we drilled 36 wells in the Aldwell and North Stiles Units, all of which were commercially successful and are expected to produce in quantities sufficient to exceed costs of drilling and completion. We recently completed construction of our own oil and gas gathering lines and compression facilities in the Aldwell Unit. We began flowing production through the new facilities on June 1, 2005. We have also entered into new contracts with third parties to provide processing of our natural gas and transportation of our oil in the unit. The new gas arrangement also provides us with the option to sell our gas to one of four firm or five interruptible sales pipelines versus a single outlet under the former arrangement. We expect these arrangements to improve the economics of production from the Aldwell Unit.
      In the March 2005 Central Gulf of Mexico federal lease sale, we were awarded the West Cameron 386 block located in water depth of approximately 85 feet.
      Production. Final reported production for the month of December 2004 averaged approximately 92 MMcfe per day. During the first quarter of 2005, we added new production from three shelf projects — High Island 46 (Green Pepper), Ewing Bank 977 (Dice) and West Cameron 333 (Royal Flush), as well as additional wells at our onshore Aldwell Unit. The production from the new wells was sufficient to maintain our total production rate at approximately 92 MMcfe per day for the first quarter of 2005. Production at the three projects has been stabilized at combined rates of approximately 9 MMcfe per day net to the Company. However, the Dice project is producing at a lower rate than expected from a zone that appears to be compartmentalized. We expect the Dice well to be sidetracked in the second half of 2005 to access a better location in the producing horizon.
      New production from our Swordfish and Pluto deepwater development projects and our Ochre shelf field was initially anticipated to be on line in the second quarter of 2005. Due to factors beyond our control, production from Swordfish and Pluto is now expected to commence in the third quarter of 2005 and production from Ochre is expected to commence in the fourth quarter of 2005.
      Development Projects. In late 2004, we participated in a successful exploratory well in our North Black Widow prospect in Ewing Banks 921, which is located approximately 125 miles south of New Orleans in approximately 1700 feet of water. We have a 35% working interest in this project. We are in the process of development planning for the North Black Widow discovery and the operator currently anticipates production to begin in the fourth quarter of 2005. We have booked no proved reserves to this project as of December 31, 2004.
      We also expect development work to be completed and production to commence at four other development projects in the second half of 2005. Viosca Knoll 917 (Swordfish), Mississippi Canyon 718 (Pluto) and Green Canyon 178 (Baccarat) are anticipated to commence production in the third quarter of 2005. Mississippi Canyon 296 (Rigel) is anticipated to commence production in the fourth quarter of 2005. Installation of facilities and equipment at Baccarat and North Black Widow are progressing as originally anticipated. However, initial production at Swordfish and Rigel has been delayed beyond our earlier forecasts due to factors outside our control.
      Production at Swordfish was delayed due to production facilities installation setbacks experienced by the operator of the host platform as a result of damage incurred from Hurricane Ivan. Initial production is currently expected to commence in the third quarter of 2005.

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      At Pluto, we proceeded as scheduled to lay an extension to the existing umbilical and flowline to finalize the development operation. Once on location, adverse current conditions in the eastern Gulf of Mexico (“loop currents” associated with the Gulf Stream current) delayed the safe unloading and installation of subsea facilities at the Pluto site until June 2005. Installation of the undersea facilities is now complete and we anticipate production to recommence in the third quarter of 2005.
      Installation of facilities and equipment at Rigel has progressed as expected, except for the umbilical line, which has experienced manufacturing delays. The contractor was unable to deliver the umbilical in usable condition from its U.S. plant and has moved final fabrication to a plant in the United Kingdom. Earliest production is now anticipated in the fourth quarter of 2005.
      Production at our Mississippi Canyon 66(Ochre) field has been shut-in since September 2004 due to destruction of the host facility during Hurricane Ivan. We recently executed an agreement to tie in production to a nearby replacement host facility and anticipate production to recommence in the fourth quarter of 2005. The field was producing at approximately 6.5 MMcfe per day net to our interest immediately prior to being shut-in by the hurricane.
      We believe the delays we have incurred on these projects should have no adverse impact on our volumes of estimated proved reserves or estimated daily production rates when production commences.
      Capital Budget Changes and Future Development Plans. In June 2005, the board of directors approved an increase in our capital expenditure budget from approximately $152 million to approximately $271 million. The increase in anticipated capital expenditures from the prior estimate is primarily related to the following new or accelerated projects.
  •   High Island A341 (Capricorn)— In May 2005 we drilled the Capricorn discovery well, which encountered approximately 104 net feet of pay in four zones. The Capricorn project is located approximately 115 miles south southwest of Cameron, Louisiana in approximately 240 feet of water. We anticipate drilling an appraisal well and installing the necessary platform and facilities in the fourth quarter of 2005, with first production anticipated in 2006. We are the operator and own a 60% working interest in the project.
 
  •   Atwater Valley 380, 381, 382, 425 and 426 (Bass Lite)— We acquired an additional 18.75% interest in the Bass/ Bass Lite project effective April 25, 2005, increasing our total working interest in this project to 38.75%. Mariner paid $5 million, and the seller retained a .94% net overriding royalty interest before project payout changing to a 2.3% net overriding royalty interest after project payout. The Bass Lite project is located approximately 200 miles southeast of New Orleans in approximately 6,500 feet of water. The blocks contain an undeveloped discovery and exploration potential. Mariner has been elected operator of the project, subject to MMS approval, and has budgeted the drilling of an appraisal well in the fourth quarter of 2005 subject to drill ship availability.
 
  •   LaSalle/ NW Nansen Project Development— In June 2005 we increased our working interest in the LaSalle project (East Breaks 558, 513 and 514) to 100% by acquiring the remaining working interest owned by a third party for $1.5 million. The seller retained a 2.5% net overriding royalty interest in the project. The blocks contain an undeveloped discovery and exploration potential. We have also executed a participation agreement with Kerr McGee to jointly develop the LaSalle project and Kerr McGee’s nearby NW Nansen exploitation project (East Breaks 602). Under the agreement, Mariner owns a 33% working interest in the NW Nansen project and a 50% working interest in the LaSalle project. The LaSalle and NW Nansen projects are located approximately 150 miles south of Galveston, Texas in water depths of approximately 3,100 and 3,300 feet, respectively. The development of these projects may require the drilling of up to four wells in 2005 and related completion and facility capital in 2006.
 
  •   Green Canyon 516, 472 and 473 (King Kong/ Yosemite Project Development)— In conjunction with the operator, we have planned a two well drilling program at the King Kong/ Yosemite field

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  to exploit potential new reserve additions. We anticipate drilling one exploration well and one development well— the first on block 472 in 2005 and the second on block 473 in 2006. We own a 50% working interest in blocks GC 472 and 473 and a 44% working interest in block 516.
      We also allocated a portion of the increase in our capital budget for the potential acquisition of additional onshore properties. We are currently negotiating with a private party to acquire and jointly develop working interests located in the Spraberry geologic trend in West Texas. Once a binding agreement is executed, details about the proposed transaction will be made available.
      The increased capital expenditures will be funded from cash flows and our existing bank facility. We recently requested an increase in our bank borrowing base from $135 million in anticipation of the projected increased capital requirements. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.” Our current capital budget for 2005 may be subject to further change as a result of a number of factors, including new drilling and acquisition opportunities that may arise, costs of drilling and completion, availability of drilling rigs, equipment and labor, availability of capital, drilling results and oil and natural gas prices.
      Commodity Price Risk Management. During the first quarter of 2005, we placed additional natural gas hedges of 4,400,000 MMBtus, 3,832,500 MMBtus, and 3,504,000 MMBtus for 2005, 2006, and 2007, respectively. Costless collars were utilized with a weighted average floor of $6.02 per MMBtu and a weighted average ceiling of $8.06 per MMBtu.
      Seismic Data. In April 2005, we entered into an agreement that provides us with access to a third party’s recent vintage 3-D seismic database covering over 1,500 blocks on the Gulf of Mexico shelf. Over the next two years we will select and license seismic data from this database covering up to 1,000 shelf blocks. This will increase significantly the amount of seismic data for the Gulf of Mexico that Mariner has under license, which currently covers more than 5,000 blocks of the Gulf of Mexico shelf and deepwater.
Summary of Capital Expenditures
      The following tables summarize information regarding our 2004 and current budgeted 2005 capital expenditures. The current budgeted 2005 capital expenditures are subject to change depending upon a number of factors, including new drilling and acquisition opportunities that may arise, costs of drilling and completion, availability of drilling rigs, equipment and labor, availability of capital, drilling results and oil and natural gas prices.
                   
    2004   2005 Budgeted
    Capital Expenditures   Capital Expenditures
         
Development Expenditures
               
Gulf of Mexico Deepwater
  $ 43.6     $ 76.8  
Gulf of Mexico Shelf
    24.7       25.7  
West Texas Permian Basin
    20.3       40.0  
             
 
Total Development Capital Expenditures
  $ 88.6     $ 142.5  
             
Exploration Expenditures
               
Exploratory Drilling
               
 
Gulf of Mexico Deepwater
  $ 19.9     $ 47.1  
 
Gulf of Mexico Shelf
    13.6       21.0  
Leasehold Acquisition
    3.5       6.1  
Delay Rentals
    1.3       1.5  
Geological & Geophysical
    9.6       8.7  
             
 
Total Exploration Capital Expenditures
  $ 47.9     $ 84.4  
             
Total Development and Exploration Capital Expenditures
  $ 136.5     $ 226.9  
             
 
Property Acquisitions
    4.9       36.1  
 
Capitalized Overhead and Interest
    7.3       7.4  
             
Total Capital Expenditures(1)
  $ 148.7     $ 270.4  
             

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(1)  See “Business—Strategy” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures and Capital Resources.” Total Capital Expenditures of $148.7 million for 2004 exclude approximately $0.2 million of additions to other property and equipment, primarily related to leasehold improvements and office equipment, and 2005 Budgeted Capital Expenditures of $270.4 million exclude $0.3 million budgeted for other property and equipment.
Corporate Information
      We were incorporated in August 1983 as a Delaware corporation. We have two subsidiaries, Mariner LP LLC, a Delaware limited liability company, and Mariner Energy Texas LP, a Delaware limited partnership.
      On March 2, 2004, Mariner was acquired by MEI Acquisitions Holdings, LLC, an affiliate of the private equity funds, Carlyle/ Riverstone Global Energy and Power Fund II, L.P. and ACON Investments LLC, through a merger of Mariner’s former indirect parent with MEI. Prior to the merger, we were owned indirectly by Joint Energy Development Investments Limited Partnership (“JEDI”), which was an indirect wholly owned subsidiary of Enron Corp. As a result of the merger, we are no longer affiliated with Enron Corp. See “Business—Enron Related Matters.”
      In March 2005, we completed a private placement of 16,350,000 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors. Our former sole stockholder, MEI Acquisitions Holdings, LLC, also sold 15,102,500 shares of our common stock in the private placement. We used the net proceeds from the sale of 12,750,000 shares of our common stock to purchase and retire an equal number of shares of our common stock from our former sole stockholder. As a result, an affiliate of our former sole stockholder now beneficially owns 5.3% of our outstanding common stock. See “Security Ownership of Certain Beneficial Owners and Management.”
      Our principal executive office is located at 2101 CityWest Blvd., Bldg. 4, Suite 900, Houston, Texas 77042-2831, and our telephone number is (713) 954-5500.

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The Offering
Common stock offered by selling stockholders 33,348,130 shares.
 
Use of proceeds We will not receive any proceeds from the sale of the shares of common stock by the selling stockholders.
 
Listing We have applied to list our common stock on The Nasdaq Stock Market under the symbol MRNR.
 
Common stock split Unless specifically indicated or the context requires otherwise, the share and per share information of this offering gives effect to a 21,556.61594 to 1 stock split, which was effected on March 3, 2005.
 
Dividend Policy We do not expect to pay dividends in the near future.
Risk Factors
      You should carefully consider all of the information contained in this prospectus prior to investing in the common stock. In particular, we urge you to carefully consider the information under “Risk Factors,” beginning on page 8 of this prospectus so that you understand the risks associated with an investment in our company and the common stock. These risks include the following:
  Oil and natural gas prices are volatile, and a decline in oil and natural gas prices would affect significantly our financial results and impede our growth.
 
  Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will affect materially the quantities and present value of our reserves.
 
  Unless we replace our oil and natural gas reserves, our reserves and production will decline.
 
  Relatively short production periods or reserve life for Gulf of Mexico properties subject us to higher reserve replacement needs and may impair our ability to replace production during periods of low oil and natural gas prices.

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RISK FACTORS
      You should consider carefully each of the risks described below, together with all of the other information contained in this prospectus, before deciding to invest in our common stock.
Risks Related to Our Business
  Oil and natural gas prices are volatile, and a decline in oil and natural gas prices would reduce our revenues, profitability and cash flow and impede our growth.
      Our revenues, profitability and cash flow depend substantially upon the prices and demand for oil and natural gas. The markets for these commodities are volatile and even relatively modest drops in prices can affect significantly our financial results and impede our growth. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:
  domestic and foreign supply of oil and natural gas;
 
  price and quantity of foreign imports;
 
  actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;
 
  level of consumer product demand;
 
  domestic and foreign governmental regulations;
 
  political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;
 
  weather conditions;
 
  technological advances affecting oil and natural gas consumption;
 
  overall U.S. and global economic conditions; and
 
  price and availability of alternative fuels.
      Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 64% of our estimated proved reserves as of December 31, 2004 were natural gas reserves, our financial results are more sensitive to movements in natural gas prices. Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations.
  Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will affect materially the quantities and present value of our reserves, which may lower our bank borrowing base and reduce our access to capital.
      Estimating oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing our estimates we project production rates and timing of development expenditures. We also analyze the available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. If the interpretations or assumptions we use in arriving at our estimates prove to be inaccurate, the amount of oil and natural gas that we ultimately recover may

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differ materially from the estimated quantities and net present value of reserves shown in this prospectus. See “Business—Proved Reserves” for information about our oil and gas reserves.
      Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates, perhaps significantly. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. At December 31, 2004, 54% of our proved reserves were proved undeveloped.
      The present value of future net revenues from our proved reserves referred to in this prospectus is not necessarily the actual current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on fixed prices and costs as of the date of the estimate. Actual future prices and costs fluctuate over time and may differ materially from those used in the present value estimate. In addition, discounted future net cash flows are estimated assuming that royalties to the MMS with respect to our affected offshore Gulf of Mexico properties will be paid or suspended for the life of the properties based upon oil and natural gas prices as of the date of the estimate. See “Business—Royalty Relief.” Since actual future prices fluctuate over time, royalties may be required to be paid for various portions of the life of the properties and suspended for other portions of the life of the properties.
      The timing of both the production and expenses from the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In addition, the 10% discount factor that we use to calculate the net present value of future net cash flows for reporting purposes in accordance with the SEC’s rules may not necessarily be the most appropriate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor in arriving at an accurate net present value of future net cash flows.
Unless we replace our oil and natural gas reserves, our reserves and production will decline.
      Our future oil and natural gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our level of production and cash flows will be affected adversely. In general, production from oil and natural gas 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 oil and natural gas 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.
Relatively short production periods or reserve life for Gulf of Mexico properties subjects us to higher reserve replacement needs and may impair our ability to replace production during periods of low oil and natural gas prices.
      Due to high production rates, production of reserves from reservoirs in the Gulf of Mexico generally declines more rapidly than from reservoirs in other producing regions. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies. Also, our revenues and return on capital will depend significantly on prices prevailing during these relatively short production periods. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut in production from producing wells during periods of low prices for oil and natural gas.

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  Because a significant part of the value of our production and reserves is concentrated in a small number of offshore properties, any production problems or inaccuracies in reserve estimates related to those properties could reduce our revenue, profitability and cash flow materially.
      During December 2004, approximately 78% of our daily production came from five offshore fields. If mechanical problems, storms or other events curtail a substantial portion of this production in the future, our cash flow would be affected adversely. At December 31, 2004, approximately 37% of our proved reserves were located on seven offshore properties. If the actual reserves associated with any one of these properties are less than our estimated reserves, our results of operations and financial condition could be adversely affected. During the three years ended December 31, 2002, 2003 and 2004, weather and mechanical problems affecting our offshore producing properties resulted in aggregate downtime for our offshore producing properties of 7.3%, 7.1% and 7.3%, respectively.
      A substantial portion of our exploration and production activities are located in the Gulf of Mexico. This concentration of activity makes us more vulnerable than some other industry participants to the risks associated with the Gulf of Mexico, including delays and increased costs relating to adverse weather conditions such as hurricanes, which are common in the Gulf of Mexico during certain times of the year, drilling rig and other oilfield services and compliance with environmental and other laws and regulations.
Our exploration and development activities may not be commercially successful.
      Exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
  unexpected drilling conditions;
 
  pressure or irregularities in formations;
 
  equipment failures or accidents;
 
  adverse weather conditions, including hurricanes, which are common in the Gulf of Mexico during certain times of the year;
 
  compliance with governmental regulations;
 
  unavailability or high cost of drilling rigs, equipment or labor;
 
  reductions in oil and natural gas prices; and
 
  limitations in the market for oil and natural gas.
      Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain. 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 producible economically. In addition, the use of 3-D seismic and other advanced technologies require greater predrilling expenditures than traditional drilling strategies. Because of these factors, we could incur losses as a result of exploratory drilling expenditures. Poor results from exploration activities could have a material adverse effect on our future cash flows and results of operations.
  Oil and gas drilling and production involve many business and operating risks, any one of which could reduce our levels of production, cause substantial losses or prevent us from realizing profits.
      Our business is subject to all of the operating risks associated with drilling for and producing oil and natural gas, including:
  fires;
 
  explosions;

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  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.
  Our offshore operations involve special risks that could increase our cost of operations and adversely affect our ability to produce oil and gas.
      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.
      Exploration for oil or natural gas in the deepwater of the Gulf of Mexico generally involves greater operational and financial risks than exploration on the shelf. As of December 31, 2004, approximately 37% of our estimated proved reserves, representing 47% of our PV10, are located in the deepwater of the Gulf of Mexico. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. Our deepwater wells use subsea completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics. These operations may encounter mechanical difficulties and equipment failures that could result in significant cost overruns. Furthermore, the deepwater operations generally lack the physical and oilfield service infrastructure present on the shelf. As a result, a significant amount of time may elapse between a deepwater discovery and our marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the deepwater may never be produced economically.
Our hedging transactions may not protect us adequately from fluctuations in oil and natural gas prices and may limit future 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 oil and natural gas prices and to achieve more predictable cash flow. These financial arrangements typically take the form of price swap contracts and costless collars. Hedging arrangements expose us to the risk of financial loss in some circumstances, including situations when the other party to the hedging contract defaults on its contract or production is less than expected. During periods of high commodity prices, hedging arrangements may limit significantly the extent to which we can realize financial gains from such higher prices. For example, in calendar year 2004, our hedging arrangements reduced the benefit we received from increases in the prices for oil and natural gas by approximately $27.6 million. Although we

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currently maintain an active hedging program, we may choose not to engage in hedging transactions in the future. As a result, we may be affected adversely during periods of declining oil and natural gas prices.
We will require additional capital to fund our future activities. If we fail to obtain additional capital, we may not be able to implement fully our business plan, which could lead to a decline in reserves.
      We depend on our ability to obtain financing beyond our cash flow from operations. Historically, we have financed our business plan and operations primarily with internally generated cash flow, bank borrowings, proceeds from the sale of oil and natural gas properties, entering into exploration arrangements with other parties, the issuance of debt, privately raised equity and, prior to the bankruptcy of Enron Corp. (our indirect parent company until March 2, 2004), borrowings from Enron affiliates. In the future, we will require substantial capital to fund our business plan and operations. We expect to be required to meet our needs from our excess cash flow, debt financings and additional equity offerings. Sufficient capital may not be available on acceptable terms or at all. If we cannot obtain additional capital resources, we may curtail our drilling, development and other activities or be forced to sell some of our assets on unfavorable terms.
      The issuance of additional debt would require that a portion of our cash flow from operations be used for the payment of interest on our debt, thereby reducing our ability to use our cash flow to fund working capital, capital expenditures, acquisitions and general corporate requirements, which could place us at a competitive disadvantage relative to other competitors. Additionally, if revenues decrease as a result of lower oil or natural gas prices, operating difficulties or declines in reserves, our ability to obtain the capital necessary to undertake or complete future exploration and development programs and to pursue other opportunities may be limited, which could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could result in a decline in our oil and natural gas reserves.
Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.
      Properties we acquire may not produce as expected, may be in an unexpected condition and may subject us to increased costs and liabilities, including environmental liabilities. The reviews we conduct of acquired properties prior to acquisition are not capable of identifying all potential adverse conditions. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties or properties with known adverse conditions and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems or permit a buyer to become sufficiently familiar with the properties to assess fully their condition, any deficiencies, and development potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.
Market conditions or transportation impediments may hinder our access to oil and natural gas markets or delay our production.
      Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines or trucking and terminal facilities. In deepwater operations, the availability of a ready market depends on the proximity of and our ability to tie into existing production platforms owned or operated by others and the ability to negotiate commercially satisfactory arrangements with the owners or operators. We may be required to shut in natural gas wells or delay initial production for lack of a market or because of inadequacy or unavailability of natural gas pipeline or gathering system capacity. When that occurs, we are unable to realize revenue from those wells until the production can be tied to a gathering system. This

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can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.
  The unavailability or high cost of drilling rigs, equipment, supplies or personnel could affect adversely our ability to execute on a timely basis our exploration and development plans within budget, which could have a material adverse effect on our financial condition and results of operations.
      Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or affect adversely our exploration and development operations, which could have a material adverse effect on our financial condition and results of operations. An increase in drilling activity in the U.S. or the Gulf of Mexico could increase the cost and decrease the availability of necessary drilling rigs, equipment, supplies and personnel.
  Competition in the oil and natural gas industry is intense, and many of our competitors have resources that are greater than ours giving them an advantage in evaluating and obtaining properties and prospects.
      We operate in a highly competitive environment for acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel. Many of our competitors, major and large independent oil and natural gas companies, possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional prospects and discover reserves in the future will depend on our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.
Financial difficulties encountered by our farm-out partners or third-party operators could affect the exploration and development of our prospects adversely.
      From time to time, we enter into farm-out agreements to fund a portion of the exploration and development costs of our prospects. Moreover, other companies operate some of the other properties in which we have an ownership interest. Liquidity and cash flow problems encountered by our partners and co-owners of our properties may lead to a delay in the pace of drilling or project development that may be detrimental to a project.
      In addition, our farm-out partners and working interest owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farm-out partner, we may have to obtain alternative funding in order to complete the exploration and development of the prospects subject to the farm-out agreement. In the case of a working interest owner, we may be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary in order to fund either of these contingencies.
  We cannot control the drilling and development activities on properties we do not operate, and therefore we may not be in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves.
      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

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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.
Compliance with environmental and other government regulations could be costly and could affect production negatively.
      Exploration for and development, production and sale of oil and natural gas in the U.S. and the Gulf of Mexico are subject to extensive federal, state and local laws and regulations, including environmental and health and safety laws and regulations. We may be required to make large expenditures to comply with these environmental and other requirements. Matters subject to regulation include, among others, environmental assessment prior to development, discharge and emission permits for drilling and production operations, drilling bonds, and reports concerning operations and taxation.
      Under these laws and regulations, and also common law causes of action, we could be liable for personal injuries, property damage, oil spills, discharge of pollutants and hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations or to obtain or comply with required permits may result in the suspension or termination of our operations and subject us to remedial obligations as well as administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs. We cannot predict how agencies or courts will interpret existing laws and regulations, whether additional or more stringent laws and regulations will be adopted or the effect these interpretations and adoptions may have on our business or financial condition. For example, the Oil Pollution Act of 1990 (the “OPA”) imposes a variety of regulations on “responsible parties” related to the prevention of oil spills. The implementation of new, or the modification of existing, environmental laws or regulations promulgated pursuant to the OPA could have a material adverse impact on us. Further, 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 have a material adverse effect on our financial condition and results of operations. See “Business— Regulation” for more information on our regulatory and environmental matters.
Our insurance may not protect us against our business and operating risks.
      We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations.
We may be affected adversely if we are unable to retain or attract key personnel and executives.
      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. In addition, the use of 3-D seismic and other advanced technologies requires experienced technical personnel whom we may be unable to retain or attract.

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      We believe that our operations are dependent to a significant extent on the efforts of key employees, most of whom have more than 20 years of experience in the oil and gas business. The loss of the services of any of these key individuals could have a material adverse effect on us. We do not maintain any insurance against the loss of any of these individuals.
      Our bank credit agreement includes a change of control provision that provides in part that an event of default will occur if Scott Josey ceases to be the Chief Executive Officer or President of Mariner or to be actively engaged in the executive management of Mariner and is not replaced with an individual of comparable qualifications within six months. Therefore, if Mr. Josey were to leave our employment and we were unable to obtain the services of another senior executive with comparable experience to replace him, our banks would have the right to declare our bank loans due and we would have to seek alternative financing.
Risks Related to our Common Stock
An active market for our common stock may not develop and the market price for shares of our common stock may be highly volatile and could be subject to wide fluctuations after this offering.
      Prior to the effectiveness of the registration statement of which this prospectus forms a part, we were a private company and there was no public market for our common stock. An active market for our common stock may not develop or may not be sustained after this offering. In addition, we cannot assure you as to the liquidity of any such market that may develop or the price that our stockholders may obtain for their shares of our common stock.
      Even if an active trading market develops, the market price for shares of our common stock may be highly volatile and could be subject to wide fluctuations. Some of the factors that could negatively affect our share price include:
  actual or anticipated variations in our reserve estimates and quarterly operating results;
 
  changes in oil and gas prices;
 
  changes in our funds from operations or earnings estimates;
 
  publication of research reports about us or the exploration and production industry;
 
  increases in market interest rates which may increase our cost of capital;
 
  changes in applicable laws or regulations, court rulings and enforcement and legal actions;
 
  changes in market valuations of similar companies;
 
  adverse market reaction to any increased indebtedness we incur in the future;
 
  departures of key management personnel;
 
  actions by our stockholders;
 
  speculation in the press or investment community; and
 
  general market and economic conditions.
We do not anticipate paying any dividends on our common stock in the foreseeable future.
      We do not expect to declare or pay any cash or other dividends in the foreseeable future on our common stock. Our existing revolving credit facility restricts our ability to pay cash dividends on our common stock, and we may also enter into other credit agreements or other borrowing arrangements in the future that restrict our ability to declare or pay cash dividends on our common stock.

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You may experience dilution of your ownership interests due to the future issuance of additional shares of our common stock, which could have an adverse effect on our stock price.
      We may in the future issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present stockholders and purchasers of common stock offered hereby. We are currently authorized to issue 70 million shares of common stock and 20 million shares of preferred stock with such designations, preferences and rights as determined by our board of directors. As of the date of this prospectus, 35,615,400 shares of common stock were outstanding. This includes 2,267,270 shares of common stock that have been granted to certain employees as restricted stock pursuant to our Equity Participation Plan. In addition, we have reserved an additional 2,000,000 shares for future issuance to employees as restricted stock or stock option awards pursuant to our Stock Incentive Plan, of which options to purchase 798,960 shares have already been granted. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of our common stock or other securities that are convertible into or exercisable for common stock in connection with the hiring of personnel, future acquisitions, future private placements of our securities for capital raising purposes, or for other business purposes. Future sales of substantial amounts of our common stock, or the perception that sales could occur, could have a material adverse effect on the price of our common stock.
Provisions in our organizational documents and under Delaware law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock.
      The existence of some provisions in our organizational documents and under Delaware law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock. The provisions in our certificate of incorporation and bylaws that could delay or prevent an unsolicited change in control of our company include a staggered board of directors, board authority to issue preferred stock, and advance notice provisions for director nominations or business to be considered at a stockholder meeting. In addition, Delaware law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. See “Description of Capital Stock.”

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
      Various statements this prospectus contains, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. The forward-looking statements in this prospectus speak only as of the date of this prospectus; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this prospectus. These risks, contingencies and uncertainties relate to, among other matters, the following:
  the volatility of oil and natural gas prices;
 
  discovery, estimation, development and replacement of oil and natural gas reserves;
 
  cash flow and liquidity;
 
  financial position;
 
  business strategy;
 
  amount, nature and timing of capital expenditures, including future development costs;
 
  availability and terms of capital;
 
  timing and amount of future production of oil and natural gas;
 
  availability of drilling and production equipment;
 
  operating costs and other expenses;
 
  prospect development and property acquisitions;
 
  marketing of oil and natural gas;
 
  competition in the oil and natural gas industry;
 
  governmental regulation of the oil and natural gas industry; and
 
  developments in oil-producing and natural gas-producing countries.

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USE OF PROCEEDS
      We will not receive any of the proceeds from the sale of the shares of common stock offered by this prospectus. Any proceeds from the sale of the shares offered by this prospectus will be received by the selling stockholders.
CAPITALIZATION
      The following table shows our capitalization as of March 31, 2005. You should refer to “Selected Historical Consolidated Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements included elsewhere in this prospectus in evaluating the material presented below.
             
    March 31,
    2005
     
    (in millions)
Long-term debt:
       
 
Credit facility— revolving note due March 2007
  $ 55.0  
 
Promissory note to former indirect stockholder(1)
    4.0  
       
   
Total long-term debt
    59.0  
Stockholders’ equity(2)
    178.2  
       
   
Total capitalization
  $ 237.2  
       
 
(1)  For a description of the promissory note to our former indirect stockholder, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations— JEDI Term Promissory Note.”
 
(2)  Reflects the receipt of net proceeds from the sale of 3.6 million shares reduced by approximately $1.9 million of offering costs.

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DILUTION
      Our net tangible book value as of March 31, 2005 was $5.00 per share of common stock. Net tangible book value per share is determined by dividing our tangible net worth (tangible assets less total liabilities) by the 35,615,400 shares of our common stock that were outstanding on March 31, 2005. Investors who purchase our common stock in this offering may pay a price per share that exceeds the net tangible book value per share of our common stock. If you purchase our common stock from the selling stockholders identified in this prospectus, you will experience immediate dilution of $9.00 in the net tangible book value per share of our common stock assuming a sale price of $14.00 per share. The following table illustrates the per share dilution to new investors purchasing shares from the selling stockholders identified in this prospectus:
                   
Assumed offering price per share   $ 14.00  
 
Net tangible book value per share at March 31, 2005
  $ 5.00          
 
Increase per share attributable to new investors
    -0-          
Net tangible book value per share after this offering     5.00  
       
Dilution per share to new investors   $ 9.00  
       
      The foregoing discussion and table are based upon the number of shares actually issued and outstanding as of March 31, 2005. As of March 31, 2005, we had 787,360 stock options outstanding at an exercise price of $14.00 per share, none of which were vested as of March 31, 2005. To the extent the market value of our shares is greater than $14.00 per share and any of these outstanding options are exercised, there may be further dilution to new investors.
DIVIDEND POLICY
      We do not expect to pay dividends in the near future. Our credit facility contains restrictions on the payment of dividends to stockholders. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Credit Facility.”

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA
      The following table shows our historical consolidated financial data as of and for each of the five years ended December 31, 2004 and the three-month periods ended March 31, 2004 and 2005. In addition, the table includes combined historical financial data for the three-month period ended March 31, 2004 and the year ended December 31, 2004, which combines our results of operations for the periods prior to and after the March 2, 2004 merger in which we were acquired by MEI Acquisitions Holdings, LLC. The merger resulted in the application of “push-down accounting,” whereby our financial statements after the transaction reflect the fair value of our assets and liabilities at the transaction date. The combined data does not reflect the adjustments to our statement of operations that would be reflected in pro forma financial statements. However, because we believe that such adjustments are not material, we believe that the combined data presents a fair presentation and facilitates an understanding of our results of operations for 2004. You should read the following data in connection with “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements included elsewhere in this prospectus, where there is additional disclosure regarding the information in the following table, including pro forma information regarding the merger. Our historical results are not necessarily indicative of results to be expected in future periods.
                                                                                             
    Post-Merger       Post-Merger   Pre-Merger       Post-Merger   Pre-Merger   Pre-Merger
                                 
            Period from   Period from       Period from   Period from    
        Combined(1)   March 3,   January 1,       March 3,   January 1,    
    Three Months   Three Months   2004   2004   Combined(2)   2004   2004    
    Ended   Ended   through   through   Year Ended   through   through   Year Ended December 31,
    March 31,   March 31,   March 31,   March 2,   December 31,   December 31,   March 2,    
    2005   2004   2004   2004   2004   2004   2004   2003   2002   2001   2000
                                             
    (unaudited)   (unaudited)   (unaudited)       (unaudited)                        
    (in millions, except per share data)
Statement of Operations Data:
                                                                                       
 
Total revenues
  $ 55.8     $ 61.0     $ 21.2     $ 39.8     $ 214.2     $ 174.4     $ 39.8     $ 142.5     $ 158.2     $ 155.0     $ 121.1  
 
Lease operating expenses
    6.2       7.2       3.1       4.1       25.5       21.4       4.1       24.7       26.1       20.1       17.2  
 
Transportation expenses
    1.0       1.7       0.7       1.1       3.0       1.9       1.1       6.3       10.5       12.0       7.8  
 
Depreciation, depletion and amortization
    15.1       16.9       6.2       10.6       64.9       54.3       10.6       48.3       70.8       63.5       56.8  
 
Impairment of production equipment held for use
                            1.0       1.0                                
 
Derivative settlement
                                              3.2                    
 
Impairment of Enron related receivables
                                                    3.2       29.5        
 
General and administrative expenses
    5.2       2.7       1.5       1.1       8.8       7.6       1.1       8.1       7.7       9.3       6.5  
                                                                   
 
Operating income
    28.3       32.5       9.7       22.9       111.0       88.2       22.9       51.9       39.9       20.6       32.8  
 
Interest income
    0.5       0.1             0.1       0.3       0.2       0.1       0.8       0.4       0.7       0.1  
 
Interest expense
    (1.8 )     (0.7 )     (0.7 )           (6.0 )     (6.0 )           (7.0 )     (10.3 )     (8.9 )     (11.0 )
                                                                   
 
Income before income taxes
    27.0       31.9       9.0       23.0       105.3       82.4       23.0       45.7       30.0       12.4       21.9  
 
Provision for income taxes
    (9.2 )     (11.1 )     (3.1 )     (8.1 )     (36.9 )     (28.8 )     (8.1 )     (9.4 )                  
                                                                   
 
Income before cumulative effect of change in accounting method net of tax effects
    17.8       20.8       5.9       14.9       68.4       53.6       14.9       36.3       30.0       12.4       21.9  
 
Income before cumulative effect per common share
                                                                                       
   
Basic
    0.58       0.70       0.20       .50       2.30       1.80       .50       1.22       1.01       .42       .74  
   
Diluted
    0.58       0.70       0.20       .50       2.30       1.80       .50       1.22       1.01       .42       .74  
 
Cumulative effect of changes in accounting method
                                              1.9                    
                                                                   
 
Net income
  $ 17.8     $ 20.8     $ 5.9     $ 14.9     $ 68.4     $ 53.6     $ 14.9     $ 38.2     $ 30.0     $ 12.4     $ 21.9  
                                                                   
 
Net income per common share
                                                                                       
   
Basic
    0.58       0.70       0.20       .50       2.30       1.80       .50       1.29       1.01       .42       .74  
   
Diluted
    0.58       0.70       0.20       .50       2.30       1.80       .50       1.29       1.01       .42       .74  
Capital Expenditure and Disposal Data:
                                                                                       
 
Exploration, including leasehold/seismic
  $ 1.2     $ 9.9     $ 2.4     $ 7.5     $ 47.9     $ 40.4     $ 7.5     $ 31.6     $ 40.4     $ 66.3     $ 46.7  
 
Development and other
    40.9       10.2       2.4       7.8       101.0       93.2       7.8       51.7       65.7       98.2       61.4  
 
Proceeds from property conveyances
                                              (121.6 )     (52.3 )     (90.5 )     (29.0 )
                                                                   
 
Total capital expenditures net of proceeds from property conveyances
  $ 42.1     $ 20.1     $ 4.8     $ 15.3     $ 148.9     $ 133.6     $ 15.3     $ (38.3 )   $ 53.8     $ 74.0     $ 79.1  
                                                                   

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    Post-Merger   Pre-Merger
         
        December 31,
    March 31,   December 31,    
    2005   2004   2003   2002   2001   2000
                         
    (unaudited)                    
    (in millions)
Balance Sheet Data:(3)
                                               
 
Property and equipment, net, full cost method
  $ 328.3     $ 303.8     $ 207.9     $ 287.6     $ 290.6     $ 287.8  
 
Total assets
    418.8       376.0       312.1       360.2       363.9       335.4  
 
Long-term debt, less current maturities
    59.0       115.0             99.8       99.8       129.7  
 
Stockholder’s equity
    178.2       133.9       218.2       170.1       180.1       141.9  
 
Working capital (deficit)(4)
    (27.5 )     (18.7 )     38.3       (24.4 )     (19.6 )     (15.4 )
 
(1)  The combined information for the three months ended March 31, 2004 includes the pre-merger information for the period from January 1, 2004 through March 2, 2004 and the post-merger information for the period from March 3, 2004 through March 31, 2004.
(2)  The combined information for the year ended December 31, 2004 includes the pre-merger information for the period from January 1, 2004 through March 2, 2004 and the post-merger information for the period from March 3, 2004 through December 31, 2004.
(3)  Balance sheet data as of December 31, 2004 reflects purchase accounting adjustments to oil and gas properties, total assets and stockholder’s equity resulting from the acquisition of our former indirect parent on March 2, 2004.
(4)  Working capital (deficit) excludes current derivative assets and liabilities, deferred tax assets and restricted cash.
                                                                                         
    Post-Merger       Post-Merger   Pre-Merger       Post-Merger   Pre-Merger   Pre-Merger
                                 
                Period       Period        
        Combined(1)       from       from   Period from    
    Three   Three   Period from   January 1,       March 3,   January 1,    
    Months   Months   March 3,   2004   Combined(2)   2004   2004    
    Ended   Ended   2004 through   through   Year Ended   through   through   Year Ended December 31,
    March 31,   March 31,   March 31,   March 2,   December 31,   December 31,   March 2,    
    2005   2004   2004   2004   2004   2004   2004   2003   2002   2001   2000
                                             
    (unaudited)   (unaudited)   (unaudited)       (unaudited)                        
    (all amounts in millions)
Other Financial Data:
                                                                                       
EBITDA(3)
  $ 43.5     $ 49.4     $ 15.9     $ 33.4     $ 176.9     $ 143.5     $ 33.4     $ 100.3     $ 113.9     $ 113.6     $ 89.6  
Net cash provided by operating activities
    49.0       25.5       5.2       20.3       156.2       135.9       20.3       103.5       60.3       113.5       63.9  
Net cash (used) provided by investing activities
    (42.1 )     (20.1 )     (4.8 )     (15.3 )             (133.6 )     (15.3 )     38.3       (53.8 )     (74.0 )     (79.1 )
Net cash (used) provided by financing activities
    (8.0 )     (31.2 )     (31.2 )                   64.9             (100.0 )           (30.0 )     17.4  
Reconciliation of Non- GAAP Measures:
                                                                                       
EBITDA
  $ 43.5     $ 49.4     $ 15.9     $ 33.4     $ 176.9     $ 143.5     $ 33.4     $ 100.3     $ 113.9     $ 113.6     $ 89.6  
Changes in working capital
    4.8       (23.3 )     (10.0 )     (13.2 )     (6.3 )     6.9       (13.2 )     21.8       (20.4 )     7.5       (15.5 )
Non-cash hedge gain(4)
    (1.4 )                       (7.9 )     (7.9 )           (2.0 )     (23.2 )            
Amortization/other
    0.3                         0.8       0.8                   (0.1 )     0.6       0.7  
Stock compensation expense
    1.3                                                              
Net interest expense
    (1.3 )     (0.6 )     (0.7 )     0.1       (5.7 )     (5.8 )     0.1       (6.2 )     (9.9 )     (8.2 )     (10.9 )
Income tax expense
    1.8                         (1.6 )     (1.6 )           (10.4 )                  
                                                                   
Net cash provided by operating activities
  $ 49.0     $ 25.5     $ 5.2     $ 20.3     $ 156.2     $ 135.9     $ 20.3     $ 103.5     $ 60.3     $ 113.5     $ 63.9  
                                                                   
 
(1)  The combined information for the three months ended March 31, 2004 includes the pre-merger information for the period from January 1, 2004 through March 2, 2004 and the post-merger information for the period March 3, 2004 through March 31, 2004.
(2)  The combined information for the year ended December 31, 2004 includes the pre-merger information for the period from January 1, 2004 through March 2, 2004 and the post-merger information for the period from March 3, 2004 through December 31, 2004.
(3)  EBITDA means earnings before interest, income taxes, depreciation, depletion and amortization. For the three months ended March 31, 2005, EBITDA includes $1.3 million in non-cash stock compensation expense related to restricted stock granted in the first quarter of 2005. We believe that EBITDA is a widely accepted financial indicator that provides additional information about our ability to meet our future requirements for debt service, capital expenditures and working capital, but EBITDA should not be considered in isolation or as a substitute for net income, operating income, net cash provided by operating activities or any other measure of financial

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performance presented in accordance with generally accepted accounting principles or as a measure of a company’s profitability or liquidity. Our definition of EBITDA may not be comparable to similarly titled measures of other companies.
(4)  In accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137 and No. 138, we de-designated our contracts effective December 2, 2001 after the counterparty (an affiliate of Enron Corp.) filed for bankruptcy and recognized all market value changes subsequent to such de-designation in our earnings. The value recorded up to the time of de-designation and included in Accumulated Other Comprehensive Income (“AOCI”), has reversed out of AOCI and into earnings as the original corresponding production, as hedged by the contracts, is produced. We have designated subsequent hedge contracts as cash flow hedges with gains and losses resulting from the transactions recorded at market value in AOCI, as appropriate, until recognized as operating income in our Statement of Operations as the physical production hedged by the contracts is delivered.

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MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
      On March 2, 2004, Mariner’s former indirect parent, Mariner Energy LLC, merged with MEI Acquisitions Holdings, LLC, an affiliate of the private equity funds, Carlyle/ Riverstone Global Energy and Power Fund II, L.P. and ACON Investments LLC. Prior to the merger, we were owned indirectly by JEDI, which was an indirect wholly-owned subsidiary of Enron Corp. The gross merger consideration was $271.1 million (which excludes $7.0 million of acquisition costs and other expenses paid directly by the Company), $100 million of which was provided as equity by our new owners. As a result of the merger, we are no longer affiliated with Enron Corp. See “Business— Enron Related Matters.” The merger did not result in a change in our strategic direction or operations. The financial information contained herein is presented in the style of Pre-Merger activity (for all periods prior to March 2, 2004) and Post-Merger activity (for the March 3, 2004 through December 31, 2004 period) to reflect the impact of the restatement of assets and liabilities to fair value as required by “push-down” purchase accounting at the March 2, 2004 merger date. The application of push-down accounting had no effect on our 2004 results of operations other than immaterial increases in depreciation, depletion and amortization expense and interest expense and a related decrease in our provision for income taxes. To facilitate management’s discussion and analysis of financial condition and results of operations, we have presented 2004 financial information as Pre-Merger (for the January 1 through March 2, 2004 period), Post-Merger (for the March 3, 2004 through December 31, 2004 period), Combined (for the full period from January 1 through December 31, 2004), Post-Merger (for the March 3, 2004 through March 31, 2004 period) and Combined (for the full period from January 1, 2004 through March 31, 2004). The combined presentation does not reflect the adjustments to our statement of operations that would be reflected in a pro forma presentation. However, because such adjustments are not material, we believe that our combined presentation presents a fair presentation and facilitates an understanding of our results of operations.
      In March 2005 we completed a private placement of 16,350,000 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors, which generated approximately $229 million of gross proceeds, or approximately $211 million net of initial purchaser’s discount, placement fee and offering expenses. Our former sole stockholder, MEI Acquisitions Holdings, LLC, also sold 15,102,500 shares of our common stock in the private placement. We used $166 million of the net proceeds from the sale of 12,750,000 shares of common stock to purchase and retire an equal number of shares of our common stock from our former sole stockholder. We used $39 million of the remaining net proceeds of approximately $45 million to repay borrowings drawn on our credit facility, and the balance to pay down $6 million of a $10 million promissory note payable to JEDI. See “Business— Enron Related Matters.” As a result of the private placement transaction, an affiliate of MEI Acquisitions Holdings, LLC now beneficially owns approximately 5.3% of our outstanding common stock.
      We are an independent oil and natural gas exploration, development and production company with principal operations in the Gulf of Mexico and the Permian Basin in West Texas. In the Gulf of Mexico, our areas of operation include the deepwater and the shelf area. We have been active in the Gulf of Mexico and West Texas since the mid-1980s. During the last three years, as a result of increased drilling of shelf prospects and development drilling in our Aldwell Unit, we have evolved from a company with primarily a deepwater focus to one with a balance of exploitation and exploration of the Gulf of Mexico deepwater and shelf, and longer-lived Permian Basin properties.
      Our revenues, profitability and future growth depend substantially on prevailing prices for oil and gas and our ability to find, develop and acquire oil and gas reserves that are economically recoverable while controlling and reducing costs. The energy markets have historically been very volatile. Commodity prices have been at or near historical highs during 2004 and may fluctuate and decline significantly in the future. Although we attempt to mitigate the impact of price declines through our hedging strategy, a substantial or extended decline in oil and natural gas prices or poor drilling results could have a material adverse

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effect on our financial position, results of operations, cash flows, quantities of natural gas and oil reserves that we can economically produce and our access to capital.
First Quarter 2005 Highlights
      During the first quarter of 2005, we recognized net income of $17.8 million on total revenues of $55.8 million compared to net income of $20.8 million on total revenues of $61.0 million in the first quarter of 2004. Net income decreased 14% compared to the first quarter of 2004, primarily the result of a 20% decrease in oil and gas production, partially offset by a 21% improvement in net realized commodity prices by us (before the effects of hedging). Our hedging results also contributed to the decrease in net income as we recorded a $3.9 million loss for the three months ended March 31, 2005 compared to a gain of $1.9 million for the same period in 2004.
      Our first quarter 2005 results reflect the private placement of an additional 3.6 million shares of stock in March. The net proceeds of approximately $45 million generated by the private placement were used to repay existing debt. We also granted 2,267,270 shares of restricted stock and options to purchase 787,350 shares of stock in March and recorded compensation expense of $1.3 million in the first quarter of 2005 related to the restricted stock.
2004 Highlights
      We recognized net income of $68.4 million in 2004 compared to net income of $38.2 million in 2003. The increase in net income was primarily the result of improvements in operating results, including a 13% increase in production volumes, a 21% improvement in the net commodity prices realized by us (before the effects of hedging) and an 8% decrease in lease operating expenses and transportation expenses on a per unit basis. These improvements were partially offset by an 8% increase in general and administrative expenses and a 34% increase in depreciation, depletion, and amortization expenses. Our hedging results also improved by $9.7 million to a $19.8 million loss, from a $29.5 million loss in the prior year. In addition, we recorded income tax expenses of $36.9 million in 2004 compared to $9.4 million in 2003.
      We have incurred and expect to continue to incur substantial capital expenditures. However, for the three years ended December 31, 2004, our capital expenditures of $337.3 million have been below our combined cash flow from operations and proceeds from property sales.
      During 2004, we increased our proved reserves by approximately 69 Bcfe, bringing estimated proved reserves as of December 31, 2004 to approximately 237.5 Bcfe after 2004 production of 37.6 Bcfe.
      We had $2.5 million and $60.2 million in cash and cash equivalents as of December 31, 2004 and December 31, 2003, respectively.
Production
      Three of our shelf properties, Ewing Bank 977 (Dice), West Cameron 333 (Royal Flush) and High Island 46 (Green Pepper) began producing in the first quarter of 2005. Our first quarter 2005 production averaged approximately 59 MMcf of natural gas per day and approximately 5,500 barrels of oil per day or a total of approximately 92 MMcfe per day.
      Our December 2004 total production averaged approximately 58 MMcf of natural gas per day and approximately 5,700 barrels of oil per day or total equivalents of approximately 92 MMcfe per day. Natural gas production comprised approximately 63% of total production. In September 2004, the Company incurred damage from Hurricane Ivan that affected our Mississippi Canyon 66 (Ochre) and Mississippi Canyon 357 fields. Production from Mississippi Canyon 357 was shut-in until March 2005, when necessary repairs were completed and production recommenced. As of March 31, 2005, production from Mississippi Canyon 66 (Ochre) remained shut-in. This field was producing at a net rate of approximately 6.5 MMcfe per day immediately prior to the hurricane.

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      Historically, a majority of our total production has been comprised of natural gas. We anticipate that our concentration in natural gas production will continue. As a result, Mariner’s revenues, profitability and cash flows will be more sensitive to natural gas prices than to oil and condensate prices.
      Generally, our producing properties in the Gulf of Mexico will have high initial production rates followed by steep declines. As a result, we must continually drill for and develop new oil and gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find and develop these reserves. Our challenge is to find and develop reserves at economic rates and commence production of these reserves as quickly and efficiently as possible.
      Deepwater discoveries typically require a longer lead time to bring to productive status. Since 2001, we have made several deepwater discoveries that are in various stages of development. We currently anticipate commencing production in the second half of 2005 from Viosca Knoll 917 (Swordfish), Mississippi Canyon 718 (Pluto), Mississippi Canyon 296 (Rigel), Green Canyon 178 (Baccarat), and Ewing Banks 921 (North Black Widow). However, myriad uncertainties, including scheduling, weather, and construction lead times, could cause a delay in the start up of any one or all of the projects.
Oil and Gas Property Costs
      In the three months ended March 31, 2005, we incurred approximately $42.1 million in capital expenditures with 92% related to development activities primarily at our Aldwell Unit and for our Viosca Knoll 917 (Swordfish) and Mississippi Canyon 718 (Pluto) offshore projects. First quarter 2005 development expenditures also included $3.5 million for oil and gas property interests acquired in the West Texas Permian Basin area. We incurred approximately $1.2 million of exploration capital expenditures in the first quarter of 2005.
      During 2004, we incurred approximately $148.9 million in capital expenditures with 60% related to development activities, 32% related to exploration activities, including the acquisition of leasehold and seismic, and the remainder related to acquisitions and other items (primarily capitalized overhead and interest).
      We spent approximately $88.6 million in development capital expenditures in 2004 primarily on Aldwell Unit development and for Viosca Knoll 917 (Swordfish), Mississippi Canyon 718 (Pluto), and West Cameron 333 (Royal Flush) offshore projects.
      All capital for exploration activities relate to offshore projects, with approximately 30% of exploration capital expended for leasehold, seismic, and geological and geophysical costs. During 2004 we participated in fourteen exploration wells, with seven being successful. We incurred approximately $47.9 million of exploration capital expenditures in 2004.
      We anticipate that, based on our current budget, capital expenditures in 2005 will approximate $271 million with approximately 53% allocated to development projects, 31% to exploration activities, 13% to acquisitions and the remainder to other items (primarily capitalized overhead and interest).
Oil and Gas Reserves
      We have maintained our reserve base through exploration and exploitation activities despite selling 79.7 Bcfe of our reserves since the fourth quarter of 2001. Historically, we have not acquired significant reserves through acquisition activities. As of December 31, 2004, Ryder Scott estimated our net proved reserves at approximately 237.5 Bcfe, with a PV10 of approximately $668 million. See “Business— Proved Reserves” for more information concerning our reserve estimates.
      The development drilling at our West Texas Aldwell Unit and Gulf of Mexico deepwater divestitures have significantly changed our reserve profile since 2001. Proved reserves as of December 31, 2004 were comprised of 48% West Texas Permian Basin, 15% Gulf of Mexico shelf and 37% Gulf of Mexico deepwater compared to 20% West Texas Permian Basin, 15% Gulf of Mexico shelf and 65% Gulf of

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Mexico deepwater as of December 31, 2001. The change has resulted in a more balanced reserve base, increased average reserve life and a more predictable cost and production profile. Proved undeveloped reserves were approximately 54% of total proved reserves as of December 31, 2004. Approximately 39% of proved undeveloped reserves were related to our West Texas Aldwell Unit, where we had 100% development drilling success on 105 wells from 2002 through 2004.
      Since December 31, 1997, we have added proved undeveloped reserves attributable to 11 deepwater projects. Of those projects, seven have either been converted to proved developed reserves or sold as indicated in the following table.
                     
    Net Proved        
    Undeveloped        
    Reserves       Year converted to
Property   (Bcfe)(1)   Year added   proved developed or sold
             
Mississippi Canyon 718 (Pluto)(2)
    25.1       1998     2000 (100% converted to proved developed)
Ewing Bank 966 (Black Widow)
    14.0       1999     2000 (100% converted to proved developed)
Mississippi Canyon 773 (Devils Tower)
    28.0       2000     2001 (100% of Mariner’s interest sold)
Mississippi Canyon 305 (Aconcagua)
    19.2       2000     2001 (100% of Mariner’s interest sold)
Green Canyon 472/473 (King Kong)
    25.5       2000     2002 (100% converted to proved developed)
Green Canyon 516 (Yosemite)
    14.9       2001     2002 (100% converted to proved developed)
East Breaks 79 (Falcon)
    66.8       2001     2002 (50% of Mariner’s interest sold)
2003 (all of Mariner’s remaining interest sold)
 
(1)  Net proved undeveloped reserves attributable to the project in the year it was first added to our proved reserves.
 
(2)  This field was shut-in in April 2004 pending the drilling of a new well and installation of an extension to the existing infield flowline and umbilical. As a result, as of December 31, 2004, 9.0 Bcfe of our net proved reserves attributable to this project were classified as proved undeveloped reserves. We expect production from Pluto to recommence in the third quarter of 2005, which should result in the reserves associated with this project being reclassified as proved developed before the end of 2005.
      The proved undeveloped reserves attributable to the remaining four deepwater projects were added as follows:
                     
            Year expected to
    Net Proved Undeveloped       convert to proved
Property   Reserves (Bcfe)(1)   Year added   developed status
             
Viosca Knoll 917 (Swordfish)
    13.4       2001     2005
Mississippi Canyon 296/252 (Rigel)
    22.4       2003     2005
Green Canyon 646 (Daniel Boone)
    16.4       2003     2007
Green Canyon 178 (Baccarat)
    4.0       2004     2005
 
(1)  Net proved undeveloped reserves attributable to the project as of December 31, 2004.

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Oil and Natural Gas Prices and Hedging Activities
      Prices for oil and natural gas can fluctuate widely, thereby affecting the amount of cash flow available for capital expenditures, our ability to borrow and raise additional capital and the amount of oil and natural gas that we can economically produce. Recently, oil and natural gas prices have been at or near historical highs and very volatile as a result of various factors, including weather, industrial demand, war and political instability and uncertainty related to the ability of the energy industry to provide supply to meet future demand.
      Our revenues, profitability and future growth depend substantially on prevailing prices for oil and gas and our ability to find, develop and acquire oil and gas reserves that are economically recoverable while controlling and reducing costs. A substantial or extended decline in oil and natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that we can economically produce and access to capital.
      We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices. Typically, our hedging strategy involves entering into commodity price swap arrangements and costless collars with third parties. Price swap arrangements establish a fixed price and an index-related price for the covered commodity. When the index-related price exceeds the fixed price, we pay the third party the difference, and when the fixed price exceeds the index-related prices, the third party pays us the difference. Costless collars establish fixed cap (maximum) and floor (minimum) prices as well as an index-related price for the covered commodity. When the index-related price exceeds the fixed cap price, we pay the third party the difference, and when the index-related price is less than the fixed floor price, the third party pays us the difference. While our hedging arrangements enable us to achieve a more predictable cash flow, these arrangements also limit the benefits of increased prices. As a result of increased oil and natural gas prices, we incurred cash hedging losses of $27.7 million in 2004, of which $7.9 million relates to the hedge liability recorded at the March 2, 2004 merger date. Major challenges related to our hedging activities include a determination of the proper production volumes to hedge and acceptable commodity price levels for each hedge transaction. Our hedging activities may also require that we post cash collateral with our counterparties from time to time to cover credit risk. We had no collateral requirements as of December 31, 2004 or March 31, 2005.
      In accordance with purchase price accounting implemented at the time of the merger of our former indirect parent company on March 2, 2004, we recorded the mark-to-market liability of our hedge contracts at such date totaling $12.4 million as a liability on our balance sheet. As of December 31, 2004, the amount of our mark-to-market hedge liabilities totaled $22.4 million. See “—Liquidity and Capital Resources— Commodity Prices and Related Hedging Activities.”
Operating Costs
      Lease operating expenses were $25.5 million in 2004, compared with $24.7 million in 2003. These costs fluctuated primarily due to levels of production and workover activities. In order to measure our operating performance, we also monitor lease operating and transportation expenses on a per unit of production basis. Lease operating expenses per Mcfe were $0.68 in 2004, compared to $0.74 in 2003. Transportation expenses were $3.0 million or $0.08 per Mcfe in 2004 as compared to $6.3 million or $0.19 per Mcfe in 2003. In the fourth quarter of 2004, we filed new transportation allowances with the MMS for purposes of royalty calculation. This resulted in a $3.2 million decrease in transportation expenses in 2004 compared to 2003.
      Lease operating expenses were $6.2 million for the three months ended March 31, 2005, or $0.74 per Mcfe and transportation expenses were $1.0 million or $0.12 per Mcfe for the first quarter of 2005.
      General and administrative expenses were $8.8 million, or $0.23 per Mcfe, in 2004 and $8.1 million, or $0.24 per Mcfe in 2003. Our general and administrative expenses are reported net of overhead recoveries from our working interest partners, and for 2003 and 2004, we have capitalized approximately 45% of our general and administrative expenses. For the year ended December 31, 2004, approximately

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44% of our general and administrative expenses (before capitalization) were comprised of salaries and wages (excluding bonus compensation) that are subject to market-related increases.
      General and administrative expenses were $5.2 million for the three months ended March 31, 2005, or $0.62 per Mcfe, including $1.3 million, or $0.16 per Mcfe in compensation expense related to restricted stock granted in March 2005 and $2.3 million or $0.27 per Mcfe related to payments to terminate financial advisory agreements with former stockholders.
Critical Accounting Policies and Estimates
      Our discussion and analysis of Mariner’s financial condition and results of operations are based upon financial statements that have been prepared in accordance with GAAP in the U.S. 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. 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, which would have a significant impact on depreciation, depletion and amortization. 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.
      The costs of unproved properties are excluded from amortization using the full-cost method of accounting. These costs are assessed quarterly for possible inclusion in the full-cost property pool based on geological and geophysical data. If a reduction in value has occurred, costs being amortized are increased. The majority of the costs relating to our unproved properties will be evaluated over the next three years.
Proved Reserves
      Our most significant financial estimates are based on estimates of proved natural gas and oil reserves. Estimates of proved reserves are key components of our unevaluated properties, our rate for recording depreciation, depletion and amortization and our full cost ceiling limitation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond our control. The estimation process relies on assumptions and interpretations of available geologic, geophysical, engineering and production data, and the accuracy of reserve estimates is a function of the quality and quantity of available data. Our reserves are fully engineered on an annual basis by Ryder Scott, our independent petroleum engineers.
Compensation Expense
      As a result of the adoption of SFAS Statement No. 123(R), we will record compensation expense for the fair value of restricted stock that was granted on March 11, 2005 pursuant to our Equity Participation Plan and for the fair value of subsequent grants of stock options or restricted stock made pursuant to our Stock Incentive Plan. In general, compensation expense will be determined at the date of grant based on the fair value of the stock or options granted.

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      We will record compensation expense of $31.7 million for the fair value of restricted stock that we granted following the closing of the private equity placement pursuant to our Equity Participation Plan. The compensation expense will be amortized over the applicable vesting periods. Future grants of stock options and restricted stock under our Stock Incentive Plan will also result in recognition of compensation expense in accordance with FASB No. 123(R). For more information concerning our Equity Participation Plan, see “Management—Equity Participation Plan.”
Revenue Recognition
      We recognize oil and gas revenue from our interests in producing wells as oil and gas from those wells is produced and sold under the entitlements method. Oil and gas volumes sold are not significantly different from our share of production.
Income Taxes
      Our taxable income through 2004 has been included in a consolidated U.S. income tax return with our former indirect parent company, 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. We record 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. In February 2005, Mariner Energy LLC was merged into us, and we will file our own income tax return following the effective date of that merger.
Capitalized Interest Costs
      We capitalize interest based on the cost of major development projects which are excluded from current depreciation, depletion, and amortization calculations.
Accrual for Future Abandonment Costs
      SFAS No. 143, “Accounting for Asset Retirement Obligations,” addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
Hedging Program
      In June 1998 the FASB issued SFAS No. 133, “Accounting for Derivative Instruments and Certain Hedging Activities.” In June 2000 the FASB issued SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activity, an Amendment of SFAS No. 133.” SFAS No. 133 and SFAS No. 138 require that all derivative instruments be recorded on the balance sheet at their respective fair values.
      The Company utilizes derivative instruments, typically in the form of natural gas and crude oil price swap agreements and costless collar arrangements, in order to manage price risk associated with future crude oil and natural gas production. These agreements are accounted for as cash flow hedges. Gains and losses resulting from these transactions are recorded at fair market value and deferred to the extent such amounts are effective. Such gains or losses are recorded in AOCI as appropriate, until recognized as operating income as the physical production hedged by the contracts is delivered.

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      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 flow 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.
Use of Estimates in the Preparation of Financial Statements
      The preparation of financial statements in conformity with GAAP 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.
Results of Operations
      For certain information with respect to our oil and natural gas production, average sales price received and expenses per unit of production for the three years ended December 31, 2004, see “Business—Production.”
Three Months Ended March 31, 2005 compared to Three Months Ended March 31, 2004
      Net production during the three months ended March 31, 2005 decreased approximately 20% to 8.3 Bcfe from 10.3 Bcfe in the same period of 2004 primarily due to decreased Gulf of Mexico production, partially offset by increased onshore production. Increased development drilling at our Aldwell unit in West Texas contributed to a 63% increase in onshore production to an average of approximately 14.9 Mmcfe per day in the first quarter of 2005 from an average of approximately 9.1 Mmcfe per day in the first quarter of 2004.
      In the deepwater Gulf of Mexico, production decreased approximately 31% to an average of approximately 40 Mmcfe per day in the first quarter of 2005 compared to an average of approximately 58 Mmcfe per day in the first quarter of 2004. The decrease was largely due to reduced production at our Black Widow and Pluto fields. Pluto was shut-in in April 2004 pending drilling of the new Mississippi Canyon 674 #3 well and installation of an extension to the existing subsea facilities. Production at Black Widow is undergoing expected declines.
      In the Gulf of Mexico shelf, production decreased by approximately 21% to an average of approximately 37 Mmcfe per day in the first quarter of 2005 from an average of approximately 48 Mmcfe per day in the first quarter of 2004. About 6.2 Mmcfe per day of the decrease is attributable to our Ochre field which remains shut-in due to the effects of Hurricane Ivan in September 2004. Production from three new shelf discoveries (Green Pepper, Royal Flush, and Dice) offset normal declines at our other Gulf of Mexico shelf fields.
      Hedging activities in the first quarter of 2005 increased our average realized natural gas price received by $0.02 per Mcf and revenues by $0.1 million, compared with an increase of $0.50 per Mcf and revenues of $3.3 million for the same period in 2004. Our hedging activities with respect to crude oil during the first

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quarter of 2005 decreased the average sales price received by $7.96 per barrel and revenues by $3.9 million compared with a decrease of $2.17 per barrel and revenues of $1.4 million for the same period in 2004.
      Oil and gas revenues decreased 12% to $54.0 million in the first quarter of 2005 when compared to first quarter 2004 oil and gas revenues of $61.0 million, due to the aforementioned 20% decrease in production, partially offset by a 10% increase in realized prices (including the effects of hedging) to $6.50 per Mcfe in the first quarter of 2005 from $5.91 per Mcfe in the same period in 2004.
      Other revenues of $1.9 million in the first quarter of 2005 represent an indemnity payment received from our former stockholder related to the Merger.
      Lease operating expenses decreased 15% to $6.2 million in the first quarter of 2005 from $7.2 million in the first quarter of 2004. The reduced costs were primarily attributable to our deep water fields, including Pluto, which was temporarily shut-in in April 2004, partially offset by the addition of new producing wells at our Aldwell unit. On a per unit basis, lease operating expenses were $0.74 per Mcfe in the first quarter of 2005 compared to $0.70 per Mcfe in the first quarter of 2004.
      Transportation expenses were $1.0 million or $0.12 per Mcfe in the first quarter of 2005, compared to $1.7 million or $0.17 per Mcfe in the first quarter of 2004. The reduction is primarily attributable to our deep water fields and includes reductions caused by the filing of new and higher transportation allowances with the MMS on two of our deep water fields for purpose of royalty calculation.
      Depreciation, depletion, and amortization expense decreased 10% to $15.1 million during the first quarter of 2005 from $16.9 million for the first quarter of 2004 as a result of decreased production of 2.0 Bcfe in the first quarter of 2005 compared to the first quarter 2004, partially offset by an increase in the unit-of-production depreciation, depletion and amortization rate to $1.82 per Mcfe for the first quarter of 2005 from $1.63 per Mcfe for the same period in 2004. The per unit increase was primarily the result of push-down accounting to restate our oil and gas assets to fair value as of March 2, 2004.
      General and administrative expenses (“G&A”), which are net of $1.0 million and $0.7 million of overhead reimbursements received from other working interest owners in the first quarter of 2005 and 2004, respectively, increased 93% to $5.2 million during the first quarter of 2005 compared to $2.7 million in the first quarter of 2004. The increase was primarily due to recognizing $1.3 million in stock compensation expense related to restricted stock granted in the first quarter of 2005 and $2.3 million paid to our former stockholders to terminate a services agreement. In addition, G&A expenses increased by $0.9 million due to a reduction in the amount of G&A capitalized in the first quarter of 2005 compared to the first quarter of 2004. These increases were partially offset by reduced compensation expense of $1.7 million in the first quarter of 2005 compared to the first quarter of 2004 which included merger-related payments under the Company’s Long-Term Incentive Plan.
      Net interest expense for the first quarter of 2005 increased 138% to $1.3 million from $0.6 million in the first quarter of 2004, primarily due to lower average debt levels in the first quarter of 2004 compared to the first quarter of 2005. In connection with the Merger on March 2, 2004, the Company incurred $135 million in new bank debt and issued a $10 million promissory note to JEDI. For comparison purposes, approximately one month of interest related to such borrowings is reflected in the first quarter of 2004 compared to three months of interest in 2005.
      Income before income taxes and change in accounting method decreased to $27.0 million for the first quarter of 2005 compared to $31.9 million for the same period in 2004, attributable primarily to the decrease in oil and gas revenues resulting from the decreased production and increased G&A expenses, both as noted above. Offsetting these factors were the receipt of other income related to the indemnity payment and lower DD&A, lease operating and transportation expenses.
      Provision for income taxes decreased to $9.3 million for the first quarter of 2005 from $11.2 million for the first quarter of 2004 as a result of decreased operating income for the three months ended March 31, 2005 compared to the prior period.

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Year Ended December 31, 2004 compared to Year Ended December 31, 2003
      Net production during 2004 increased to 37.6 Bcfe from 33.4 Bcfe during 2003 primarily due to the commencement of production on our Roaring Fork and Ochre projects, offset by normal production declines on existing fields.
      Hedging activities in 2004 decreased our average realized natural gas price received by $0.32 per Mcf and revenues by $7.5 million, compared with a decrease of $1.03 per Mcf and revenues of $24.5 million for 2003. Our hedging activities with respect to crude oil during 2004 decreased the average sales price received by $5.35 per bbl and revenues by $12.3 million compared with a decrease of $3.11 per bbl and revenues of $5.0 million for 2003.
      Oil and gas revenues increased 50% to $214.2 million during 2004 when compared to 2003 oil and gas revenues of $142.5 million, due to a 13% increase in production and a 33% increase in realized prices (including the effects of hedging) to $5.70 per Mcfe in 2004 from $4.27 per Mcfe in 2003.
      Lease operating expenses increased 3% to $25.5 million in 2004 from $24.7 million in 2003 due to increased activity in our West Texas Aldwell project, partially offset by lower compression costs on our King Kong and Yosemite projects and the shut-in of our Pluto project for a large portion of 2004 pending the drilling and completion of the Mississippi Canyon 674 No. 3 well, which has been drilled and awaits installation of flowlines and related facilities.
      Transportation expenses were $3.0 million for 2004, compared to $6.3 million for 2003. In the fourth quarter of 2004, we filed new transportation allowances with the MMS for purpose of royalty calculation. This resulted in a $3.2 million decrease in transportation expense in 2004 compared to 2003. In addition, transportation expense from our new Roaring Fork field was offset by declines from our existing fields.
      Depreciation, depletion, and amortization expense increased 34% to $64.9 million during 2004 from $48.3 million for 2003 as a result of an increase in the unit-of-production depreciation, depletion and amortization rate to $1.73 per Mcfe from $1.45 per Mcfe for the comparable period and a production increase of 4.2 Bcfe in 2004 compared to 2003. The per unit increase is primarily attributable to non-cash purchase accounting adjustments resulting from the merger.
      General and administrative expenses (“G&A”), which is net of $4.4 million of overhead reimbursements received from other working interest owners, increased 8% to $8.8 million during 2004 compared to $8.1 million in 2003 primarily due to increased compensation costs paid in connection with the merger and payments made pursuant to services contracts with affiliates of our sole stockholder, offset by increased overhead recoveries from our partners and amounts capitalized.
      Impairment of production equipment held for use reflects the reduction of the carrying cost of our inventory as of December 31, 2004 by $1.0 million to account for a reduction in estimated value primarily related to subsea trees held in inventory.
      Net interest expense for 2004 decreased 8% to $5.7 million from $6.2 million for 2003, primarily due to the repayment of our senior subordinated notes in August 2003, replaced by lower-cost bank debt in March 2004.
      Income before income taxes and change in accounting method increased to $105.3 million for 2004 compared to $45.7 million in 2003, attributable primarily to the increase in oil and gas revenues resulting from the increased production and realized prices noted above.
      Provision for income taxes increased to $36.9 million for 2004 from $9.4 million for 2003 as a result of increased current year operating income.
Year Ended December 31, 2003 Compared to Year Ended December 31, 2002
      Net production decreased during 2003 to 33.4 Bcfe from 39.8 Bcfe in 2002. Production from new drilling in our onshore Aldwell project and offshore Roaring Fork and Vermilion 143 projects was offset by

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production declines in other fields and loss of production from our offshore Pluto project during the first seven months of 2003 as a result of a flowline mechanical problem that required extended maintenance.
      Hedging activities in 2003 decreased our average realized natural gas price received by $1.03 per Mcf and revenues by $24.5 million, compared with an increase of $0.68 per Mcf and revenues of $20.3 million in 2002. Our hedging activities with respect to crude oil during 2003 decreased the average sales price received by $3.11 per bbl and revenues by $5.0 million compared with an increase of $1.25 per bbl and revenues of $2.1 million in 2002.
      Oil and gas revenues decreased 10% to $142.5 million in 2003 from $158.2 million in 2002 (including the effects of hedge gains and losses), due to a 16% decrease in production offset by an 8% increase in average realized prices to $4.27 per Mcfe in 2003 from $3.97 per Mcfe in 2002 including the effects of hedging gains and losses.
      Lease operating expenses decreased 5% to $24.7 million in 2003 from $26.1 million in 2002 due to the reduced chemical requirements at our King Kong and Yosemite projects offset by higher chemical costs at our Pluto field.
      Transportation expenses decreased 40% to $6.3 million for 2003 from $10.5 million for 2002. The decrease was primarily attributable to lower minimum fees required under the transportation agreement for our Pluto project.
      Depreciation, depletion, and amortization expense decreased 32% to $48.3 million for 2003 from $70.8 million for 2002 as a result of the decrease in the unit-of-production depreciation, depletion and amortization rate to $1.45 per Mcfe from $1.78 per Mcfe and 6.4 Bcfe of less production in 2003 compared to 2002. The primary driver behind the reduced DD&A rate per Mcfe was the reduction of our full cost pool and concurrent reduction of proved reserves by the proceeds from the sale of an interest in the Falcon and Harrier properties in 2003.
      Early derivative settlements of non hedge designated instruments resulted in a loss of $3.2 million in 2003. There were no similar transactions in 2002.
      G&A, which is net of $1.8 million of overhead reimbursements received from other working interest owners, increased 5% to $8.1 million for 2003 from $7.7 million for 2002. The increase was comprised of an 11% reduction in gross G&A (before capitalized items and overhead recoveries) driven primarily by reduced professional service costs and office rent, offset by higher employee compensation costs, which included retention payments. The reduction in gross G&A was offset by reduced overhead recoveries and capitalized items compared to 2002.
      Net interest expense for 2003 decreased 37% to $6.2 million from $9.9 million for 2002, primarily due to mid-year retirement of our senior subordinated notes.
      Income before income taxes and change in accounting method increased to a net income of $45.7 million for 2003 from $30.0 million in 2002, primarily as a result of 30% higher operating income (primarily driven by lower DD&A partially offset by lower oil and gas revenues) all as described more fully above.
      Provision for income taxes increased to $9.4 million in 2003 as a result of the Company utilizing all of its net operating losses. The provision for income taxes in 2002 was $0.
Liquidity and Capital Resources
Cash Flows and Liquidity
      Working capital at March 31, 2005 was a negative $27.5 million, excluding restricted cash, current derivative liabilities and related tax effects. Accounts payable and accrued liabilities at March 31, 2005 increased by approximately 17% over levels at December 31, 2004 primarily due to increased current obligations for our Swordfish development project at quarter end. As of December 31, 2004, we had negative working capital of approximately $18.7 million compared to positive working capital of

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$38.3 million at December 31, 2003, in each case excluding current derivative liabilities and restricted cash. The reduction in working capital from the prior year is primarily the result of a change in the manner the Company utilizes excess cash. At year-end 2003, the Company operated with no debt and consequently accumulated cash (approximately $60 million at year-end 2003) generated by operations and asset sales in order to fund future obligations and business activities. In March 2004, the Company entered into a revolving credit facility, and since then has utilized excess cash to pay down outstanding advances to maintain debt levels as low as possible. In addition, our accounts payable and accrued liabilities at December 31, 2004 increased by about 32% over levels at December 31, 2003 primarily as a result of funding for development of our deepwater projects in progress at year end.
      Our 2004 capital expenditures were $148.9 million. Approximately 60% of our capital expenditures were incurred for development projects, 32% for exploration activities and the remainder for acquisitions and other items (primarily capitalized overhead and interest).
      We anticipate that our capital expenditures for 2005 will approximate $271 million with approximately 53% allocated to development projects, 31% to exploration activities, 13% to acquisitions and the remainder to other items (primarily capitalized overhead and interest). This is an increase of approximately $119 million over our original 2005 budget. The increase is primarily driven by new projects at our King Kong, Yosemite, LaSalle/NW Nansen, Bass Lite, and Capricorn projects. We have also added capital to our budget for anticipated acquisitions of interests in onshore properties in 2005.
      With the anticipated increase in capital expenditures, cash flows generated by operations for 2005 will not be sufficient to fund our 2005 capital expenditures. Any requirements for funding that exceed our cash flows will be funded through additional borrowings under our existing revolving credit facility. We currently have a borrowing base of $135 million with approximately $95 million drawn as of June 30, 2005. We have requested our bank group to increase our borrowing base from $135 million to a level sufficient to fund our currently projected capital expenditures.
      However, the timing of expenditures (especially regarding deepwater projects) is unpredictable. Also, our cash flows are heavily dependent on the oil and natural gas commodity markets and our ability to hedge oil and natural gas prices is limited by our revolving credit facility to no more than 80% of our expected production from proved developed producing reserves. If either oil or natural gas commodity prices decrease from their current levels, our ability to finance our planned capital expenditures could be affected negatively. Furthermore, amounts available for borrowing under our revolving credit facility are largely dependent on our level of proved reserves and current oil and natural gas prices. If either our proved reserves or commodity prices decrease, amounts available to us to borrow under our revolving credit facility could be negatively affected. If our cash flows are less than anticipated or amounts available for borrowing under our revolving credit facility are reduced, we may be forced to defer planned capital expenditures.
      In conjunction with the March 2004 merger, we established a new credit facility maturing on March 2, 2007. The new credit facility was fully drawn at inception for $135 million. See “—Credit Facility.” In addition, we issued a $10 million promissory note to JEDI as part of the merger consideration. See “Business—Enron Related Matters” and “—JEDI Term Promissory Note.” This note matures in March 2006. Net proceeds from a private equity placement were approximately $45 million, of which $6 million was used to pay down the JEDI promissory note with the remainder used to pay down the credit facility.

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      We had a net cash outflow of $57.6 million in 2004, compared to a net cash inflow of $41.8 million in 2003 and a net cash inflow of $6.5 million in 2002. A discussion of the major components of cash flows for these periods follows.
                                         
    Combined   Post-Merger   Pre-Merger
             
                Year Ended
        Period from   Period from   December 31,
    Year Ended   March 3, 2004 to   January 1, 2004 to    
    December 31, 2004   December 31, 2004   March 2, 2004   2003   2002
                     
    (unaudited)                
        (in millions)        
Cash flows provided by operating activities
  $ 156.2     $ 135.9     $ 20.3     $ 103.5     $ 60.3  
      Cash flows provided by operating activities in 2004 increased by $52.7 million compared to 2003 primarily due to improved operating results and net income driven by increased production volumes and higher net oil and natural gas prices realized by the Company.
                                         
    Combined   Post-Merger   Pre-Merger
             
                Year Ended
        Period from   Period from   December 31,
    Year Ended   March 3, 2004 to   January 1, 2004 to    
    December 31, 2004   December 31, 2004   March 2, 2004   2003   2002
                     
    (unaudited)                
        (in millions)        
Cash flows used in (provided by) investing activities
  $ 148.9     $ 133.6     $ 15.3     $ (38.3 )   $ 53.8  
      Cash flows used in investing activities in 2004 increased by $187.2 million compared to 2003 due to increased capital expenditures in 2004 and the sale of assets in prior years.
                                         
    Combined   Post-Merger   Pre-Merger
             
                Year Ended
        Period from   Period from   December 31,
    Year Ended   March 3, 2004 to   January 1, 2004 to    
    December 31, 2004   December 31, 2004   March 2, 2004   2003   2002
                     
    (unaudited)                
        (in millions)        
Cash flows used in financing activities
  $ (64.9 )   $ (64.9 )         $ (100.0 )      
      Cash flows used in financing activities in 2004 decreased by $35.1 million compared to 2003 as a result of a $166 million dividend to our former indirect parent used to help repay a term loan to an affiliate of Enron Corp. and the placement of our revolving credit facility.
Commodity Prices and Related 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 price swap agreements and costless collar arrangements. While the use of these hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements.

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      As of March 31, 2005, the Company had the following hedge contracts outstanding:
                           
            March 31, 2005
        Fixed   Fair Value
Fixed Price Swaps   Quantity   Price   Gain/(Loss)
             
            (in millions)
Crude Oil (Bbls)
                       
 
April 1 — December 31, 2005
    412,500     $ 25.34     $ (12.9)  
 
January 1 — December 31, 2006
    140,160       29.56       (3.6)  
Natural Gas (MMBtus)
                       
 
April 1 — December 31, 2005
    5,490,189       5.04       (15.4)  
 
January 1 — December 31, 2006
    1,827,547       5.53       (4.7)  
                   
Total   $ (36.6)  
       
                                   
                March 31, 2005
                Fair Value
Costless Collars   Quantity   Floor   Cap   Gain/(Loss)
                 
                (in millions)
Crude Oil (Bbls)
                               
 
April 1 — December 31, 2005
    173,250     $ 35.60     $ 44.77     $ (2.1)  
 
January 1 — December 31, 2006
    251,850       32.65       41.52       (3.5)  
 
January 1 — December 31, 2007
    202,575       31.27       39.83       (2.6)  
Natural Gas (MMBtus)
                               
 
April 1 — December 31, 2005
    6,545,000       6.01       8.02       (3.3)  
 
January 1 — December 31, 2006
    7,347,450       5.78       7.85       (5.0)  
 
January 1 — December 31, 2007
    5,310,750       5.49       7.22       (3.4)  
                         
Total   $ (19.9)  
       
      As of December 31, 2004, the Company had the following hedge contracts outstanding:
                           
            December 31, 2004
        Fixed   Fair Value
Fixed Price Swaps   Quantity   Price   Gain/(Loss)
             
            (in millions)
Crude Oil (Bbls)
                       
 
January 1 — December 31, 2005
    606,000     $ 26.15     $ (10.0)  
 
January 1 — December 31, 2006
    140,160       29.56       (1.5)  
Natural Gas (MMBtus)
                       
 
January 1 — December 31, 2005
    8,670,159       5.41       (7.0)  
 
January 1 — December 31, 2006
    1,827,547       5.53       (1.9)  
                   
Total   $ (20.4)  
       

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                December 31, 2004
                Fair Value
Costless Collars   Quantity   Floor   Cap   Gain/(Loss)
                 
                (in millions)
Crude Oil (Bbls)
                               
 
January 1 — December 31, 2005
    229,950     $ 35.60     $ 44.77     $ (0.4)  
 
January 1 — December 31, 2006
    251,850       32.65       41.52       (0.7)  
 
January 1 — December 31, 2007
    202,575       31.27       39.83       (0.6)  
Natural Gas (MMBtus)
                               
 
January 1 — December 31, 2005
    2,847,000       5.73       7.80       0.4   
 
January 1 — December 31, 2006
    3,514,950       5.37       7.35       (0.3)  
 
January 1 — December 31, 2007
    1,806,750       5.08       6.26       (0.4)  
                         
Total   $ (2.0)  
       
      We have reviewed the financial strength of our hedge counterparties and believe our credit risk to be minimal. Under the terms of some of these transactions, from time to time we may be required to provide security in the form of cash or letters of credit to our counterparties. As of December 31, 2004 and March 31, 2005, we had no deposits for collateral.
      The following table sets forth the results of third party hedging transactions during the periods indicated:
                           
    Year Ended December 31,
     
    2004   2003   2002
             
    (dollars in millions)
Natural Gas
                       
 
Quantity settled (MMBtus)
    18,823,063       25,520,000        
 
Increase (Decrease) in Natural Gas Sales
  $ (10.8 )   $ (27.1 )      
Crude Oil
                       
 
Quantity settled (Mbbls)
    1,554       730       353  
 
Increase (Decrease) in Crude Oil Sales
  $ (16.9 )   $ (5.0 )   $ (0.8 )
      In accordance with purchase price accounting implemented at the time of the merger of our former indirect parent on March 2, 2004, we recorded the mark-to-market liability of our hedge contracts at such date totaling $12.4 million as a liability on our balance sheet. See “—Critical Accounting Policies and Estimates—Hedging Program.” For the year ended December 31, 2004, $7.9 million of the $27.7 million of cash hedge losses relate to the liability recorded at the time of the merger.
Interest Rate Hedges
      Borrowings under our revolving credit the facility, discussed below, mature on March 2, 2007, and bear interest at either a LIBOR-based rate or a prime-based rate, at our option, plus a specified margin. Both options expose us to risk of earnings loss due to changes in market rates. We have not entered into interest rate hedges that would mitigate such risk.
Credit Facility
      We have a revolving credit facility which provides up to $150 million of revolving borrowing capacity, subject to a borrowing base limitation. The borrowing capacity is currently subject to a borrowing base of $135 million. The borrowing base is subject to redetermination by the lenders quarterly; provided however, if at least $10 million of unused availability exists, the borrowing base will be redetermined semi-annually. The borrowing base is based upon the evaluation by the lenders of our oil and gas reserves and other factors. Any increase in the borrowing base requires the consent of all lenders.
      We have requested our bank group to increase our borrowing base from $135 million to a level sufficient to fund our currently projected capital expenditures.

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      Borrowings under the facility bear interest, at our option, at a rate of (i) LIBOR plus 2.00% to 2.75% depending upon utilization, or (ii) the greater of (a) the Federal Funds Rate plus 0.50% or (b) the Reference Rate, plus 0.00% to 0.50% depending upon utilization.
      Substantially all of our assets, other than the assets securing the term promissory note issued to JEDI, are pledged to secure the credit facility and obligations under hedging arrangements with members of our bank group. In addition, both of our subsidiaries, Mariner Energy Texas LP and Mariner LP LLC, have guaranteed our obligations under the credit facility. We must pay a commitment fee of 0.25% to 0.50% per year on the unused availability under the credit facility, depending upon utilization.
      The credit facility contains various restrictive covenants and other usual and customary terms and conditions of a revolving credit facility, including limitations on the payment of cash dividends and other restricted payments, limitations on the incurrence of additional debt, prohibitions on the sale of assets, and requirements for hedging a portion of our oil and natural gas production. Financial covenants require us to, among other things:
  maintain a ratio, as of the last day of each fiscal quarter, of (a) current assets (excluding cash posted as collateral to secure hedging obligations) plus unused availability under the credit facility to (b) current liabilities (excluding the current portion of debt and current portion of hedge liabilities) of not less than 1.00 to 1.00;
 
  maintain a ratio, as of the last day of each fiscal quarter, of (a) EBITDA (earnings before interest, taxes, depreciation, amortization and depletion) to (b) the sum of interest expense and maintenance capital expenditures for such period and 20% (on an annualized basis) of outstanding advances, of not less than 1.20 to 1.00; and
 
  maintain a ratio, as of the last day of each fiscal quarter, of (a) total debt to (b) EBITDA of not greater than 1.75 to 1.00 prior to the issuance of bonds as described in the credit agreement and 3.00 to 1.00 thereafter.
      The credit facility also contains customary events of default, including the occurrence of a change of control or default by us in the payment or performance of any other indebtedness equal to or exceeding $2.0 million.
      As of March 31, 2005, $55.0 million was outstanding under the credit facility, and the weighted average interest rate was 4.93%. This debt matures on March 2, 2007.
JEDI Term Promissory Note
      As part of the merger consideration payable to JEDI, we issued a term promissory note to JEDI in the amount of $10 million. The note matures on March 2, 2006, and bears interest, payable in kind at our option, at a rate of 10% per annum until March 2, 2005, and 12% per annum thereafter unless paid in cash in which event the rate remains 10% per annum. We have chosen to pay the interest in cash rather than in kind. The JEDI note is secured by a lien on three of our properties with no proved reserves located in the Gulf of Mexico. We can offset against the note the amount of certain claims for indemnification that can be asserted against JEDI under the terms of the merger agreement. The JEDI term promissory note contains customary events of default, including an event of default triggered by the occurrence of an event of default under our credit facility. We used $6 million of the proceeds from the recent private equity placement to repay a portion of the JEDI note. As of June 30, 2005, $4 million was still outstanding under the JEDI note.

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Capital Expenditures and Capital Resources
      The following table presents major components of our capital expenditures for each of the three years in the period ended December 31, 2004.
                                           
    Combined   Post-Merger   Pre-Merger
             
                Year Ended
        Period from   Period from   December 31,
    Year Ended   March 3, 2004 to   January 1, 2004    
    December 31, 2004   December 31, 2004   to March 2, 2004   2003   2002
                     
    (unaudited)                
        (in millions)        
Capital expenditures:
                                       
 
Leasehold acquisition
  $ 4.8     $ 4.4     $ 0.4     $ 4.8     $ 14.9  
 
Oil and natural gas exploration
    43.0       35.9       7.1       26.8       25.5  
Oil and natural gas development
    88.6       82.0       6.6       44.3       55.3  
Proceeds from property conveyances
                      (121.6 )     (52.3 )
Acquisitions
    4.9       4.9                    
Other items (primarily capitalized overhead and interest)
    7.6       6.4       1.2       7.4       10.4  
                               
Total capital expenditures, net of proceeds from property conveyances
  $ 148.9     $ 133.6     $ 15.3     $ (38.3 )   $ 53.8  
                               
      Our net capital expenditures for 2004 increased by $187.2 million, as compared to 2003, as a result of increased exploration and development expenditures with no offsetting proceeds from property conveyances in 2004.
      Our net capital expenditures for 2003 decreased $92.1 million as compared to 2002 as a result of higher proceeds from property conveyances and overall lower capital expenditures as result of our shift to a more balanced portfolio among Gulf of Mexico deepwater and shelf and onshore properties.
      We had no long-term debt outstanding as of December 31, 2003. As of December 31, 2004, long-term debt was $115 million. See “—Credit Facility.”
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, 2004:
                                           
        Less            
        than one           More than
    Total   year   1-3 years   3-5 years   5 years
                     
    (in millions)
Long-term debt obligations
  $ 115.0     $     $ 115.0     $     $  
Operating leases
    1.1       0.6       0.5              
Abandonment liabilities
    24.0       4.7       7.2       7.7       4.4  
Derivative liability
    22.4       17.0       5.4              
Other long-term liabilities
    3.0       2.0       1.0              
                               
 
Total contractual cash commitments
  $ 165.5     $ 24.3     $ 129.1     $ 7.7     $ 4.4  
                               
 
(1)  As of December 31, 2004, we had incurred debt obligations under our credit facility and the JEDI promissory note that are due as follows: $10 million in 2006; and $105 million in 2007. However, we used a portion of the net proceeds of the private equity placement to repay a portion of amounts outstanding under our credit facility and $6 million under the JEDI promissory note.

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      MMS Appeal— Mariner operates numerous properties in the Gulf of Mexico. Two of such properties were leased from the MMS subject to the Outer Continental Shelf Deep Water Royalty Relief Act (the “RRA”). The RRA relieved the obligation to pay royalties on certain predetermined leases until a designated volume is produced. These two leases contained language that limited royalty relief if commodity prices exceeded predetermined levels. For the years 2000, 2001, 2003 and 2004, commodity prices exceeded the predetermined levels. Management believes the MMS did not have the authority to set pricing limits, and the Company filed an administrative appeal with the MMS and has withheld royalties regarding this matter. The MMS filed a motion to dismiss our appeal with the Department of the Interior’s Board of Land Appeals. On April 6, 2005, the Board of Land Appeals granted the MMS’ motion and dismissed our appeal. We are currently considering our alternative legal options. The Company has recorded a liability for 100% of the exposure on this matter which on December 31, 2004 was $10.9 million.
Off-Balance Sheet Arrangements
      Transportation Contract— In 1999, Mariner constructed a 29-mile flowline from a third party platform to the Mississippi Canyon 674 subsea well. After commissioning, MEGS LLC, an Enron affiliate, purchased the flowline from Mariner and its joint interest partner. In addition, Mariner entered into a firm transportation contract with MEGS LLC at a rate of $0.26 per MMBtu to transport Mariner’s share of approximately 130,000,000 MMbtus of natural gas from the commencement of production through March 2009. Mariner’s working interest in the well is 51%. For the year ended December 31, 2003, Mariner paid $1.9 million on this contract. The remaining volume commitment was 14,707,107 MMbtus or $3.8 million net to Mariner. Pursuant to the contract, the Company was required to deliver minimum quantities through the flowline or be subject to minimum monthly payment requirements.
      On May 10, 2004, Mariner and the other 49% working interest owner in the Mississippi Canyon 674 well purchased the flowline from MEGS LLC for an adjusted purchase price of approximately $3.8 million, of which approximately $1.9 million was paid by Mariner, and terminated the transportation contract and associated liability. Accordingly, we currently have no off-balance sheet arrangements.
Recent Accounting Pronouncements
      On December 16, 2004, the FASB issued FASB Statement No. 123 (revised 2004), “Share-Based Payment,” (FASB No. 123(R)) that addresses the accounting for share-based payment transactions (for example, stock options and awards of restricted stock) in which an employer receives employee-services in exchange for equity securities of the company or liabilities that are based on the fair value of the company’s equity securities. The new standard replaces FASB Statement No. 123, “Accounting for Stock-Based Compensation” (FASB No. 123) and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and generally requires such transactions be accounted for using a fair-value-based method that recognizes compensation expense rather than the optional pro forma disclosure allowed under FASB No. 123. The Company adopted the provisions of the new standard on January 1, 2005.
      On September 2, 2004, the FASB issued FASB Staff Position No. FAS 142-2, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Producing Entities,” addressing whether the scope exception within SFAS No. 142, “Goodwill and Other Intangible Assets” includes the balance sheet classification and disclosures for drilling and mineral rights of oil and gas producing properties. The FASB staff concluded that the accounting framework for oil and gas entities is based on the level of established reserves, not whether an asset is tangible or intangible, and thus the scope exception extended to the balance sheet classification and disclosure provisions for such assets.
      On September 28, 2004, the SEC released Staff Accounting Bulletin (“SAB”) 106 regarding the application of SFAS 143, “Accounting for Asset Retirement Obligations (“AROs”),” by oil and gas producing companies following the full cost accounting method. Pursuant to SAB 106, oil and gas producing companies that have adopted SFAS 143 should exclude the future cash outflows associated with settling AROs (ARO liabilities) from the computation of the present value of estimated future net

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revenues for the purposes of the full cost ceiling calculation. In addition, estimated dismantlement and abandonment costs, net of estimated salvage values, that have been capitalized (ARO assets) should be included in the amortization base for computing depreciation, depletion and amortization expense. Disclosures are required to include discussion of how a company’s ceiling test and depreciation, depletion and amortization calculations are impacted by the adoption of SFAS 143. SAB 106 is effective prospectively as of the beginning of the first fiscal quarter beginning after October 4, 2004. Since our adoption of SFAS 143 on January 1, 2003, we have calculated the ceiling test and our depreciation, depletion and amortization expense in accordance with the interpretations set forth in SAB 106; therefore, the adoption SAB 106 had no effect on our financial statements.
      On December 16, 2004, the FASB issued Statement 153, “Exchanges of Nonmonetary Assets,” an amendment of APB Opinion No. 29, to clarify the accounting for nonmonetary exchanges of similar productive assets. SFAS 153 eliminates the exception from the fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. The statement will be applied prospectively and is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. We do not have any nonmonetary transactions for any period presented to which this statement would apply. We do not expect the adoption of SFAS 153 to have a material impact on our financial statements.
Quantitative and Qualitative Disclosures About Market Risk.
      For a discussion of our market risk, See “—Liquidity and Capital Resources— Commodity Prices and Related Hedging Activities.”

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BUSINESS
About Mariner
      We are an independent oil and gas exploration, development and production company with principal operations in the Gulf of Mexico and the Permian Basin in West Texas. As of December 31, 2004, we had 237.5 Bcfe of proved reserves, of which approximately 64% were natural gas and 36% were oil and condensate. The estimated pre-tax PV10 value of our proved reserves as of December 31, 2004 was approximately $668 million. As of December 31, 2004, approximately 46% of our proved reserves were classified as proved developed. For the year ended December 31, 2004, our total net production was 37.6 Bcfe. Our proved reserve base is balanced, with 48% of the reserves located in the Permian Basin of West Texas, 37% in the Gulf of Mexico deepwater and 15% on the Gulf of Mexico shelf as of December 31, 2004.
      The distribution of our proved reserves reflects our efforts over the last three years to diversify our asset base, which in prior years had been focused primarily in the Gulf of Mexico deepwater. We have shifted some of our focus on deepwater activities to increased exploration and development on the Gulf of Mexico shelf and exploitation of our West Texas Permian Basin properties. By allocating our resources among these three areas, we expect to balance the risks associated with the exploration and development of our asset base. We intend to continue to pursue moderate-risk exploratory and development drilling projects in the Gulf of Mexico deepwater and on the Gulf of Mexico shelf, and also target low-risk infill drilling projects in West Texas. It is our practice to generate most of our prospects internally, but from time to time we also acquire third-party generated prospects. We then drill to find oil and natural gas reserves, a process that we refer to as “growth through the drill bit.”
Our Strategy
      Our goal is to create stockholder value by increasing reserves, production and cash flow through the following key strategies:
      Maintain a Balanced Portfolio Approach. We believe the combination of lower-risk drilling for long-lived onshore reserves and moderate-risk exploration, exploitation and development of the Gulf of Mexico shelf and deepwater can generate attractive cash flow and rates of return at an acceptable level of risk.
      Exploit Our Existing Reserve Base. Approximately 60% of our capital expenditures in 2004 were incurred for development activities. We plan to allocate approximately 53% of our estimated capital expenditures in 2005 for the same purpose. We drilled three development wells in the Gulf of Mexico during 2004 and expect to drill several development wells in 2005. We will also continue to pursue development of the necessary third-party production and processing infrastructure to allow us to begin production from previous Gulf of Mexico discoveries that are not currently included in our proved reserves.
      Our proved undeveloped reserves as of December 31, 2004 include 148 locations and 50 Bcfe at our Aldwell Unit in the West Texas Permian Basin. During 2004, we drilled 54 wells at Aldwell, all of which were successful and are expected to produce in quantities sufficient to exceed the costs of drilling and completion. We intend to expand our West Texas holdings by selectively acquiring additional assets to provide growth opportunities.
      We believe that conversion of proved undeveloped reserves and probable reserves to proved developed reserves is a low-risk, cost-effective strategy to increase stockholder value.
      Manage Exploration and Development Exposure. To better manage the risk of developing our asset base, we intend to limit our net exploration and development exposure on offshore projects. Our goal is to limit our exposure on any single project and participate in a greater number of projects, thereby employing a portfolio approach to manage our risk exposure. Generally, we prefer to limit our ownership of these projects to a working interest not exceeding 50% and to limit our estimated net exploration dry hole costs to $4 million per well in order to better diversify our project capital expenditures. In addition, with our internally generated prospects, we seek arrangements with industry partners in which they agree to pay a

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disproportionate share of risked dry hole costs and compensate us for expenses incurred in prospect generation. We intend to continue our practice of sharing costs of offshore exploration and development activities by selling interests in projects to industry partners. From time to time, we may also sell entire interests in offshore prospects in order to better diversify our portfolio, and we may enter into trades or farm-in transactions whereby we acquire interests in third-party generated prospects. We believe all of these measures allow us to participate in more projects with significant upside and limit the risks associated with these activities and to achieve better than average risk-adjusted returns.
      Approximately 32% of our capital expenditures in 2004 were allocated to shelf and deepwater exploration activities in the Gulf of Mexico with a moderate risk profile. We plan to allocate approximately 31% of our estimated capital expenditures in 2005 to similar types of opportunities. Shelf wells are generally less expensive to drill and complete and can be brought on production more quickly than deepwater wells. Reserve targets for deepwater wells are typically larger. We will continue to pursue select deepwater projects that we believe have sufficient gross reserve potential to provide acceptable risk/reward ratios. To better manage the typically higher costs of deepwater projects, we generally focus on projects that can be brought online for production utilizing subsea tieback technology. This technology is a relatively low-cost and time-efficient method for connecting deepwater wells to existing production facilities. We believe we have developed considerable expertise in the application of subsea tieback technology.
      Achieve Efficiency Through Operatorship. Mariner’s operations professionals are experienced in all aspects of oil and gas exploration, development and production activities, from managing and directing the drilling and completion of wells, to formulating and executing plans of development and monitoring and regulating production rates to achieve optimal results. We believe operating our wells enables us to better control the timing of the development of our projects and manage our costs more efficiently. We operate all of our wells in the Aldwell Unit in West Texas and ten of our Gulf of Mexico fields, comprising approximately 66% of our proved reserve base as of December 31, 2004.
      Continue Internal Prospect Generation. We intend to continue to focus on generating a substantial number of prospects using our experienced exploration staff. By generating most of our prospects internally, we believe we maintain a more consistent inventory of quality drillable prospects, thereby increasing our chances for commercial success. We are currently working on numerous exploratory prospects for future drilling and have 36 identified prospects in our inventory.
      Our technical professionals average more than 20 years of experience in the exploration and production business, much of it with major oil companies, including extensive experience in the Gulf of Mexico. Currently, our team of geoscientists has access to seismic data from multiple, recent vintage 3-D seismic databases covering more than 5,000 blocks in the Gulf of Mexico. In April 2005, we entered into an agreement that provides us with access to a third party’s recent vintage 3-D seismic database covering over 1,500 blocks on the Gulf of Mexico shelf. Over the next two years we expect to license seismic data from this database covering up to 1,000 shelf blocks. Seismic data is used to develop new prospects on acreage being evaluated for leasing and to develop and further refine prospects on our 283,000 net acres of leasehold interests in the Gulf of Mexico as of March 31, 2005. Our engineers have extensive experience in offshore completion and production techniques and, in particular, a successful track record in the use of subsea tieback technology to connect wells in deeper water to existing production facilities.
      We intend to continue to utilize our understanding of the geology, geophysics and production technology in the Gulf of Mexico to generate prospects internally, acquire new properties in the Gulf of Mexico at federal lease sales, and grow our reserve base through the drill bit.
      Selectively Acquire Assets. Although we intend to continue to emphasize internally generated growth through the drill bit, we expect to make asset acquisitions through farm-ins, direct purchases and similar methods that will be accretive to stockholder value. Our experienced management and technical professionals have myriad industry contacts to facilitate our acquisition efforts. We expect to acquire assets that have significant potential for further reserve additions through development and exploitation activities,

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or otherwise provide acceptable risk adjusted rates of return. Approximately 3% of our capital expenditures in 2004 were allocated to acquisitions.
      Manage Commodity Price Risk. Managing oil and gas price risk is another means we use to reduce the risk of our exploration and production activities. Oil and gas price volatility can cause fluctuation in the earnings and cash flow of an exploration and production company. We attempt to mitigate this risk with an active hedging program. The volumes we hedged for 2004 represented approximately 75% of our production. As of March 31, 2005, we had hedged 15,917,159 MMBtus of natural gas and 835,950 bbls of oil for 2005. We plan to maintain an active hedging program and as new production comes on line we expect to increase our hedge position to reduce our exposure to fluctuations in oil and gas prices and achieve more stable cash flow.
Significant Properties
      We own oil and gas properties, producing and non-producing, onshore in Texas and offshore in the Gulf of Mexico, primarily in federal waters. Our largest properties, based on the present value of estimated future net proved reserves as of December 31, 2004, are shown in the following table.
                                                     
        Mariner   Approximate   Gross   Date Production   Proved    
        Working   Water Depth   Producing   Commenced/   Reserves   PV10 Value
    Operator   Interest   (Feet)   Wells(1)   Expected   (Bcfe)   (in millions)
                             
        (%)                    
West Texas Permian Basin:
                                               
 
Aldwell Unit
  Mariner     66.5 (2)     Onshore       185     1949     112.7     $ 203.8  
Gulf of Mexico Deepwater:
                                               
 
Mississippi Canyon 296/252 (Rigel)
  Dominion     22.5       5,200       0     Fourth Quarter 2005     22.4       82.9  
 
Viosca Knoll 917/961/962 (Swordfish)
  Mariner     15.0       4,700       0     Third Quarter 2005     13.4       59.3  
 
Green Canyon 516 (Yosemite)
  ENI     44.0       3,900       1     2002     15.1       66.6  
 
Green Canyon 646 (Daniel Boone)
  W&T     40.0       4,230       0     2007     16.4       31.4  
 
Ewing Bank 966 (Black Widow)
  Mariner     69.2       1,850       1     2000     4.9       21.4  
 
Mississippi Canyon 718 (Pluto)
  Mariner     51.0       2,830       0     1999     9.0       31.7  
 
Green Canyon 178 (Baccarat)
  W&T     40.0       1,400       0     Third Quarter 2005     4.0       14.3  
 
Green Canyon 472/473 (King Kong)
  ENI     50.0       3,850       2     2002     1.2       2.0  
Gulf of Mexico Shelf:
                                               
 
South Timbalier 316 (Roaring Fork)
  Kerr McGee     20.0       450       2     2003     7.1       38.0  
 
West Cameron 333 (Royal Flush)
  Mariner     83.5       70       0     February 2005     4.5       20.8  
 
Ewing Bank 977 (Dice)
  W&T     40.0       720       0     January 2005     4.2       21.3  
 
High Island 46 (Green Pepper)
  Mariner     35.0       26       0     January 2005     3.7       17.7  
 
Mississippi Canyon 66 (Ochre)
  Mariner     75.0       1,150       0     2004     3.6       11.7  
 
Brazos A-105 (Bonvillian)
  Unocal     12.5       192       3     1993     2.9       10.5  
 
Galveston 151 (Rembrandt)
  Mariner     33.3       50       3     1997     2.2       7.7  
 
Other Properties
                        34           10.2       26.9  
                                       
   
Total:
                        231           237.5     $ 668.0  
                                       
 
(1)  Wells producing or capable of producing as of December 31, 2004.
(2)  We operate the field and own working interests in individual wells ranging from approximately 33% to 84%.

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West Texas Permian Basin
      Aldwell Unit. We operate and own working interests in individual wells ranging from 33% to 84% (with an average working interest of approximately 66.5%), in the 18,500-acre Aldwell Unit. The field is located in the heart of the Spraberry geologic trend southeast of Midland, Texas, and has produced oil and gas since 1949. We began our recent redevelopment of the Aldwell Unit by drilling eight wells in the fourth quarter of 2002, 43 wells in 2003, and 54 wells in 2004. As of December 31, 2004, there were a total of 185 wells producing or capable of producing in the field. Our aggregate net capital expenditures for the 2004 drilling program in the field were approximately $20.3 million, and we added 27 Bcfe of proved reserves, while producing 4.0 Bcfe.
      During 2005, we have accelerated our development program and intend to drill approximately 60-70 wells in our Aldwell Unit. Through May 31, 2005, we have drilled 36 new wells at our Aldwell and North Stiles Units. All of our drilling in the Aldwell and North Stiles Units has resulted in commercially successful wells that are expected to produce in quantities sufficient to exceed costs of drilling and completion.
      We recently completed construction of our own oil and gas gathering lines and compression facilities in the Aldwell Unit. We began flowing gas production through the new facilities on June 1, 2005. We have also entered into new contracts with third parties to provide processing of our natural gas and transportation of our oil produced in the unit. The new gas arrangement also provides us with the option to sell our gas to one of four firm or five interruptible sales pipelines versus a single outlet under the former arrangement. We expect these arrangements to improve the economics of production from the Aldwell Unit.
      In December 2004, we acquired an approximate 45% working interest in two Permian Basin fields containing over 4,000 acres. We believe the fields contain more than twenty 80-acre infill drilling locations and that either or both may also have 40-acre infill drilling opportunities. We have commenced drilling operations in one of the fields. In February 2005 we acquired five producing wells located in Howard County, Texas, approximately 50 miles north of our Aldwell Unit. The purchase price was $3.5 million, subject to post-closing adjustments.
Gulf of Mexico Deepwater
      Mississippi Canyon 296 (Rigel). Mariner generated the Rigel prospect and acquired its interest in Mississippi Canyon block 296 at a federal offshore Gulf lease sale in March 1999. Pursuant to an agreement with third parties, in September 1999 we cross-assigned leasehold interests in Mississippi Canyon blocks 208, 252 and 296 with the result that our working interest in all three blocks is now 22.5%. The project is located approximately 130 miles southeast of New Orleans, Louisiana, in water depth of approximately 5,200 feet. A successful exploration well was drilled on the prospect in 1999. In September 2003, a successful appraisal well was drilled. This project is currently under development with a single subsea well and a planned 12-mile subsea tie back to an existing subsea manifold that is connected to an existing platform. We expect production to begin in the fourth quarter of 2005.
      Viosca Knoll 917/961/962 (Swordfish). Mariner generated the Swordfish prospect and entered into a farm-out agreement with BP in September 2001. We operate and own a 15% working interest in this project, which is located in the deepwater Gulf of Mexico 105 miles southeast of New Orleans, Louisiana, in a water depth of approximately 4,700 feet. In November and December of 2001, we drilled two successful exploration wells on blocks 917 and 962. In August 2004, a successful appraisal well found additional reserves on block 961. All wells have been completed. Initial production is planned for the third quarter of 2005, following the installation of flowlines, umbilical and host platform facilities on the Neptune Spar.
      Green Canyon 516 (Yosemite). Mariner generated the Yosemite prospect and acquired the prospect at a Gulf of Mexico federal lease sale in 1998. We have a 44% working interest in this project, located in approximately 3,900 feet of water, approximately 150 miles southeast of New Orleans. In 2001, we drilled

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an exploratory well on the prospect, and in February 2002, we commenced production via a joint King Kong/ Yosemite 16 mile subsea tieback to an existing platform.
      Green Canyon 646 (Daniel Boone). Mariner generated the Daniel Boone prospect and acquired a 100% working interest in Green Canyon Block 646 in 1998 at a Gulf of Mexico federal lease sale. The project is located 180 miles south of New Orleans in water depth of approximately 4,230 feet. We farmed out a portion of the project, retaining a 40% working interest. A successful exploratory well was drilled in November 2003. This well is currently intended to be developed via a subsea production system tied back to existing deepwater production facilities, with first production expected in 2007.
      Ewing Bank 966 (Black Widow). Mariner generated the Black Widow prospect and acquired its interest at a federal offshore Gulf of Mexico federal lease sale in March 1997. We operate and own a 69.2% working interest in this project, which is located in the Gulf of Mexico 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.
      Mississippi Canyon 718 (Pluto). Mariner initially acquired an interest in this project in 1997, two years after gas was discovered on the project. We operate the property and own a 51% working interest in the project and the 29-mile flowline that connects to a third-party production platform. We developed the field with a single subsea well which is located in the Gulf of Mexico approximately 150 miles southeast of New Orleans, Louisiana, at a water depth of approximately 2,830 feet. The field was shut-in in April 2004 pending the drilling of a new well and completion of the installation of an extension to the existing infield flowline and umbilical. Installation of the subsea facilities is now complete. Production is expected to recommence in the third quarter of 2005.
      Green Canyon 178 (Baccarat). Mariner generated the Baccarat prospect and acquired a 100% working interest in Green Canyon block 178 at a Gulf of Mexico federal offshore lease sale in July 2003. The project is located in approximately 1,400 feet of water approximately 145 miles southwest of New Orleans, Louisiana. Subsequent to the acquisition, Mariner entered into a farmout agreement, retaining a 40% working interest in the project. A successful exploration well was drilled in May 2004. The project is under development as a subsea tieback to an existing host platform and is expected to be online in the third quarter of 2005.
      Green Canyon 472/473 (King Kong). In July 2000, Mariner acquired a 50% working interest in the King Kong Gulf of Mexico project. The project is located in approximately 3,850 feet of water, approximately 150 miles southeast of New Orleans. Mariner completed the project as a joint King Kong/ Yosemite 16 mile subsea tieback to an existing platform. Production began in February 2002.
Other Prospects and Activity
      In late 2004, we participated in a successful exploratory well in our North Black Widow prospect in Ewing Banks 921, which is located approximately 125 miles south of New Orleans in approximately 1,700 feet of water. We have a 35% working interest in this project. We are in the process of development planning for the North Black Widow prospect and the operator of this project currently anticipates production from this project to begin in the fourth quarter of 2005. We have booked no proved reserves to this project as of December 31, 2004.
      In May 2005, we acquired an additional 18.75% working interest in the Bass Lite project for approximately $5.0 million, bringing our total working interest to 38.75%. The Bass Lite project is located in Atwater Valley blocks 380, 381, 382, 425 and 426, approximately 200 miles southeast of New Orleans in approximately 6,500 feet of water. This project was not included in our proved reserves as of December 31, 2004 because firm commitments for access to third party host facilities for production and processing were not in place. We were elected operator of this project, subject to MMS approval, and negotiations continue with third party host facilities and partners to establish firm development plans.

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      In June 2005, we increased our working interest in the LaSalle project (East Breaks 558, 513, and 514) to 100% by acquiring the remaining working interest owned by a third party for $1.5 million. The blocks contain an undeveloped discovery, as well as exploration potential. As of December 31, 2004, we have booked no proved reserves to this project. We have recently executed a participation agreement with Kerr McGee to jointly develop the LaSalle project and Kerr McGee’s nearby NW Nansen exploitation project (East Breaks 602). Under the proposed participation agreement, Mariner owns a 33% working interest in the NW Nansen project and a 50% working interest in the LaSalle project. The LaSalle and NW Nansen projects are located approximately 150 miles south of Galveston, Texas in water depths of approximately 3,100 and 3,300 feet, respectively. The development of these projects may require the drilling of up to four wells in 2005 and related completion and facility capital in 2006.
      At the King Kong/ Yosemite field (Green Canyon blocks 516, 472, and 473) we have planned, in conjunction with the operator, a two well drilling program to exploit potential new reserve additions. We anticipate drilling one exploration well and one development well— the first on block 472 in 2005 and the second on block 473 in 2006. We own a 50% working interest in blocks GC 472 and 473 and a 44% working interest in block 516.
Gulf of Mexico Shelf
      South Timbalier 316 (Roaring Fork). Mariner entered into a farmout agreement in October 2001 to participate in the drilling of the Roaring Fork prospect. We acquired a 20% working interest in this project, which is located in the Gulf of Mexico 135 miles south of New Orleans, Louisiana, in a water depth of approximately 450 feet. A successful exploration well was drilled on the prospect followed by two successful appraisal wells.
      West Cameron 333 (Royal Flush). Mariner acquired West Cameron block 333 in the 2003 federal lease sale. The property was acquired to exploit reserves left behind by the previous operator due to lack of compression. As operator, we drilled two successful wells and set a platform in approximately 76 feet of water in 2004. The structure is located approximately 45 miles south of Cameron, Louisiana. Production commenced in the February of 2005. The property accounted for approximately 4.5 Bcfe of proved reserves net to our interest as of December 31, 2004.
      Ewing Bank 977 (Dice). Mariner generated the Dice prospect and acquired a 100% working interest at a Gulf of Mexico federal offshore lease sale in July 2003. The project is located in approximately 720 feet of water approximately 130 miles southwest of New Orleans, Louisiana. Subsequent to the acquisition, Mariner entered into a farm-out agreement, retaining a 40% working interest in the project. A successful exploratory well was drilled in January 2004. The project was completed as a subsea tieback to an existing host platform and began production in January 2005. The property contributed approximately 4.2 Bcfe of proved reserves net to our interest as of December 31, 2004. The Dice project is currently producing at rates lower than expected from a zone that appears to be compartmentalized. We expect to sidetrack the Dice well in the second half of 2005 to access a better location in the producing horizon.
      High Island 46 (Green Pepper). Mariner acquired its 35% working interest in High Island block 46 via farm-in from Unocal in 2004. After drilling an exploration well resulting in the discovery of 3.7 Bcfe of net proved reserves, we set a platform in approximately 26 feet of water approximately 35 miles southwest of Cameron, Louisiana. This Mariner-operated property began producing in January 2005.
      Mississippi Canyon 66 (Ochre). Mariner acquired its Ochre prospect at a Gulf of Mexico federal lease sale in March 2002. We operate and own a 75% working interest in this project, which is located in the Gulf of Mexico approximately 100 miles southeast of New Orleans, Louisiana, in a water depth of approximately 1,150 feet. In late 2002, we drilled a successful exploration well on the prospect and commenced production in the first quarter of 2004 via subsea tieback of approximately 7 miles to the Taylor Mississippi Canyon 20 platform. In September 2004, Hurricane Ivan destroyed the Taylor platform. We recently entered into a production handling agreement with the operator of a nearby replacement host facility, and production is expected to recommence in the fourth quarter of 2005.

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      Brazos A-105 (Bonvillian). Mariner generated the Brazos A-105 prospect and owns a 12.5% working interest in this property. This project is located approximately 110 miles southwest of Galveston, Texas, in a water depth of approximately 192 feet. Four wells exploit a single gas reservoir.
      Galveston 151 (Rembrandt). Mariner generated the Rembrandt prospect and acquired its interest at a Gulf of Mexico federal lease sale in 1995. We currently own a 33.33% working interest in and operate this project, which is located approximately 60 miles southeast of Houston, Texas, in a water depth of approximately 50 feet. Three wells produce from this property. We propose to drill two additional wells in this field during 2005.
Other Activity
      In the March 2005 Central Gulf of Mexico federal lease sale, we were awarded West Cameron block 386 located in water depth of approximately 85 feet.
      In May 2005 we drilled the Capricorn discovery well, which encountered approximately 104 net feet of pay in four zones. The Capricorn project is located in High Island block A341 approximately 115 miles south southwest of Cameron, Louisiana in approximately 240 feet of water. We anticipate drilling an appraisal well and installing the necessary platform and facilities in the fourth quarter of 2005, with first production anticipated in 2006. We are the operator and own a 60% working interest in the project.
Proved Reserves
      The following tables set forth certain information with respect to our proved reserves by geographic area as of December 31, 2004. Reserve volumes and values were determined under the method prescribed by the SEC which requires the application of period-end prices and costs held constant throughout the projected reserve life. The reserve information as of December 31, 2004 is based on estimates made in a reserve report prepared by Ryder Scott. A summary of Ryder Scott’s report on our proved reserves as of December 31, 2004 is attached to this memorandum as Annex A and is consistent with filings we make with federal agencies.
Proved Reserves as of December 31, 2004
                                                           
    Proved Reserve Quantities   PV10 Value    
        (millions)    
    Oil   Natural   Total       Standardized
Geographic Area   (MMbbls)   Gas (Bcf)   (Bcfe)   Developed   Undeveloped   Total   Measure
                             
West Texas Permian Basin
    8.7       62.8       114.8     $ 141.1     $ 64.4     $ 205.5          
Gulf of Mexico Deepwater(1)
    4.5       59.8       86.7       91.1       219.6       310.7          
Gulf of Mexico Shelf(2)
    1.1       29.3       36.0       103.2       48.6       151.8          
                                           
 
Total
    14.3       151.9       237.5     $ 335.4     $ 332.6     $ 668.0     $ 494.4  
                                           
Proved Developed Reserves
    6.3       71.4       109.4                                  
                                           
 
(1)  Deepwater refers to water depths greater than 1,300 feet (the approximate depth of deepwater designation for royalty purposes by the U.S. Minerals Management Service).
(2)  Shelf refers to water depths less than 1,300 feet and includes an insignificant amount of Gulf Coast onshore properties.
      PV10 is our estimated present value of future net revenues from proved reserves before income taxes. PV10 may be considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe PV10 to be an important measure for evaluating the relative significance of our natural gas and oil properties and that PV10 is widely used by professional analysts and investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides

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greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV10 on the same basis. Management also uses PV10 in evaluating acquisition candidates. PV10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. The table below provides a reconciliation of PV10 to the standardized measure of discounted future net cash flows.
                         
    At December 31,
     
    2004   2003   2002
             
PV10
  $ 667,975     $ 533,544     $ 514,995  
Future income taxes, discounted at 10%
    173,593       115,385       51,423  
                   
Standardized measure of discounted future net cash flows
  $ 494,382     $ 418,159     $ 463,572  
                   
      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 or acquisitions, the Company’s reserves and production will decline. See “Risk Factors” and Note 10 to the financial statements included elsewhere in this prospectus for a discussion of the risks inherent in oil and natural gas estimates and for certain additional information concerning the proved reserves.
      The weighted average prices of oil and natural gas at December 31, 2004 used in the proved reserve and future net revenues estimates above were calculated using NYMEX prices at December 31, 2004, of $43.45 per bbl of oil and $6.15 per MMBtu of gas, adjusted for our price differentials but excluding the effects of hedging.
Production
      The following table presents certain information with respect to net oil and natural gas production attributable to our properties, average sales price received and expenses per unit of production during the periods indicated.
                                   
        Year Ended December 31,
    Three Months Ended    
    March 31, 2005   2004   2003   2002
                 
    (Unaudited)            
Production:
                               
 
Natural Gas (Bcf)
    5.3       23.8       23.8       29.6  
 
Oil (MMbbls)
    0.5       2.3       1.6       1.7  
 
Total natural gas equivalent (Bcfe)
    8.3       37.6       33.4       39.8  
Average realized sales price per unit (excluding effects of hedging):
                               
 
Natural gas ($/Mcf)
  $ 6.52     $ 6.12     $ 5.43     $ 3.35  
 
Oil ($/bbl)
    46.57       38.52       26.85       21.60  
 
Total natural gas equivalent ($/Mcfe)
    6.96       6.23       5.15       3.41  
Average realized sales price per unit (including effects of hedging):
                               
 
Natural gas ($/Mcf)
  $ 6.54     $ 5.80     $ 4.40     $ 4.03  
 
Oil ($/bbl)
    38.61       33.17       23.74       22.85  
 
Total natural gas equivalent ($/Mcfe)
    6.50       5.70       4.27       3.97  
Expenses ($/Mcfe):
                               
 
Lease operating
  $ 0.74     $ 0.68     $ 0.74     $ 0.65  
 
Transportation
    0.12       0.08       0.19       0.26  
 
General and administrative, net(1)
    0.62       0.23       0.24       0.19  
 
Depreciation, depletion and amortization (excluding impairments)
    1.82       1.73       1.45       1.78  

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(1)  Net of overhead reimbursements received from other working interest owners and amounts capitalized under the full cost accounting method. General and administrative expenses for the three months ended March 31, 2005 include compensation expense of $1.3 million for restricted stock granted in March 2005.
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, 2003 and December 31, 2004.
                                   
    Total Productive Wells at
     
    December 31,   December 31,
    2004   2003
         
    Gross   Net   Gross   Net
                 
Oil
    197       127.9       141       101.3  
Gas
    34       9.5       37       10.1  
                         
 
Total
    231       137.4       178       111.4  
                         
Acreage
      The following table sets forth certain information with respect to the developed and undeveloped acreage as of December 31, 2004.
                                   
    Developed Acres(1)   Undeveloped Acres(2)
         
    Gross   Net   Gross   Net
                 
West Texas
    22,413       14,448              
Gulf of Mexico Deepwater(3)
    79,200       30,275       224,640       124,588  
Gulf of Mexico Shelf(4)
    130,302       36,979       130,186       84,242  
Other Onshore
    3,232       732       856       243  
                         
 
Total
    235,147       82,434       355,682       209,073  
                         
 
(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.
(3)  Deepwater refers to water depths greater than 1,300 feet (the approximate depth of deepwater designated for royalty purposes by the U.S. Minerals Management Service).
(4)  Shelf refers to water depths less than 1,300 feet.
      The following table sets forth our offshore undeveloped acreage that is subject to expiration during the three years ended December 31, 2007. The amount of onshore undeveloped acreage subject to expiration is not material.
                                                   
    Undeveloped Acreage
    Subject to Expiration in the Year Ended December 31,
     
    2005   2006   2007
             
    Gross   Net   Gross   Net   Gross   Net
                         
Gulf of Mexico Deepwater
                46,080       12,988       28,800       9,360  
Gulf of Mexico Shelf
    9,298       3,100       10,760       6,260       46,000       31,183  
                                     
 
Total
    9,298       3,100       56,840       19,248       74,800       40,543  
                                     

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Drilling Activity
      Certain information with regard to our drilling activity during the years ended December 31, 2002, 2003, and 2004 is set forth below.
                                                     
    Year Ended December 31,
     
    2004   2003   2002
             
    Gross   Net   Gross   Net   Gross   Net
                         
Exploratory wells:
                                               
 
Producing
    7       3.34       6       2.03       2       1.00  
 
Dry
    7       2.65       6       2.35       5       2.10  
   
Total
    14       5.99       12       4.38       7       3.10  
Development wells:
                                               
 
Producing
    56       34.84       45       30.07       11       6.65  
 
Dry
    1       0.68                          
   
Total
    57       35.52       45       30.07       11       6.65  
Total wells:
                                               
 
Producing
    63       38.18       51       32.10       13       7.65  
 
Dry
    8       3.33       6       2.35       5       2.10  
   
Total
    71       41.51       57       34.45       18       9.75  
      We were in the process of drilling 2 gross (1.16 net) wells as of December 31, 2004.
Property Dispositions
      When appropriate, we consider the sale of discoveries that are not yet producing or have recently begun producing when we believe we can obtain acceptable returns on our investment without holding the investment through depletion. Such sales enable us to maintain 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 ended December 31, 2004. However, we sold an aggregate 50% working interest in our non-producing deepwater Falcon and Harrier projects in two separate sales for $48.8 million in 2002 and $121.6 million in 2003, respectively.

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Marketing and Customers
      We market substantially all of the oil and natural gas production from the properties we operate as well as the 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-based prices. The following table lists customers accounting for more than 10% of our total revenues for the year indicated.
                         
    Percentage of Total
    Revenues for Year Ended
    December 31, 2003
     
Customer   2004   2003   2002
             
Sempra
    *       34%        
Bridgeline Gas Distributing Company
    27%       19%       42%  
Trammo Petroleum Inc. 
    9%       14%        
Conoco Phillips
    *       *       14%  
Duke Energy
    *       6%       9%  
Genesis Crude Oil LP
    *       4%       4%  
Chevron Texaco
    18%              
BP Energy
    12%              
 
Less than 1%
Title to Properties
      Substantially all of our properties currently are subject to liens securing either our credit facility and obligations under hedging arrangements with members of our bank group or the promissory note payable to JEDI. In addition, our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other typical burdens and encumbrances. We do not believe that any of these burdens or encumbrances materially interferes with the use of such properties in the operation of our business. Our properties may also be subject to obligations or duties under applicable laws, ordinances, rules, regulations and orders of governmental authorities.
      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 usually 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.
Competition
      We believe that our leasehold acreage, exploration, drilling and production capabilities, large 3-D seismic database and technical and operational 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 discover reserves in the future is dependent upon our ability to evaluate and select suitable properties and 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. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position.

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Royalty Relief
      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
      Leases offered for bid within five years of the RRA are referred to as “post-Act leases.” The RRA also allows mineral interest owners the opportunity to apply for discretionary royalty relief for new production on leases acquired before the RRA was enacted (“pre-Act leases”) and on leases acquired after November 28, 2000 (“post-2000 leases”). If the MMS determines that new production under a pre-Act lease or post-2000 lease would not be economical without royalty relief, then the MMS may relieve a portion of the royalty to make the project economical.
      In addition to granting discretionary royalty relief, the MMS has elected to include automatic royalty relief provisions in many post-2000 leases, even though the RRA no longer applies. For each post-2000 lease sale that has occurred to date, the MMS has specified the water depth categories and royalty suspension volumes applicable to production from leases issued in the sale.
      In 2004, the MMS adopted additional royalty relief incentives for production of natural gas from reservoirs located deep under shallow waters of the Gulf of Mexico. These incentives apply to gas produced in water depths of less than 200 meters and from deep gas accumulations located at depths of greater than 15,000 feet below the shelf. Drilling of qualified wells must have started on or after March 26, 2003, and production must begin prior to January 26, 2009.
      The impact of royalty relief can be significant. The normal royalty due for leases in water depths of 400 meters or less is 16.7% of production, and the normal royalty for leases in water depths greater than 400 meters is 12.5% of production. Royalty relief can substantially improve the economics of projects located in deepwater or in shallow water and involving deep gas.
      Many of our leases from the MMS contain language suspending royalty relief if commodity prices exceed predetermined threshold levels for a given calendar year. As a result, royalty relief for a lease in a particular calendar year may be contingent upon average commodity prices staying below the threshold price specified for that year. In 2000, 2001, 2003 and 2004 natural gas prices exceeded the applicable price thresholds for a number of our projects, and we have been required to pay royalties for natural gas produced in those years. However, we contested the MMS authority to include price thresholds in two of our post-Act leases, Black Widow and Garden Banks 367. We believe that post-Act leases are entitled to automatic royalty relief under the RRA regardless of commodity prices. For more information concerning the contested royalty payments, see “— Legal Proceedings” below.
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.

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Transportation and Sale of Natural Gas
      Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (FERC). In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of natural gas sales by producers began with the enactment of the Natural Gas Policy Act of 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining Natural Gas Act of 1938 and Natural Gas Policy Act of 1978 price and non-price controls affecting producer sales of natural gas effective January 1, 1993. Congress could, however, re-enact price controls in the future. The FERC regulates interstate natural gas pipeline transportation rates and service conditions, which affect the marketing of gas produced by us and the revenues received by us for sales of such natural gas. The FERC requires interstate pipelines to provide open-access transportation on a non-discriminatory basis for all natural gas shippers. The FERC frequently reviews and modifies its regulations regarding the transportation of natural gas with the stated goal of fostering competition within all phases of the natural gas industry. In addition, with respect to production onshore or in state waters, the intra-state transportation of natural gas would be subject to state regulatory jurisdiction as well.
      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.
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. Texas and Louisiana, the 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, the spacing of wells, and the plugging and abandonment of wells and removal of related production equipment. Texas and Louisiana also restrict production to the market demand for oil and natural gas and several states have indicated interests in revising applicable regulations. These regulations can limit the amount of oil and natural gas we can produce from our wells, limit the number of wells, or limit the locations at which we can conduct drilling operations. 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. Such leases require compliance with detailed MMS regulations and orders pursuant to the Outer Continental Shelf Lands Act that are subject to interpretation and change by the MMS. Among other things, we are required to obtain prior MMS approval for our exploration plans and development and production plans at each lease. MMS regulations also impose construction requirements for production facilities located on federal offshore leases, as well as detailed technical requirements for plugging and abandonment of wells, and removal of platforms and other production facilities on such leases. The MMS requires lessees to post surety bonds, or provide other acceptable financial assurances, to ensure all obligations are satisfied on federal offshore leases. The cost of these surety bonds or other financial assurances can be substantial, and there is no assurance that bonds or other financial assurances can be obtained in all cases. We are currently in compliance with all MMS financial assurance requirements. Under certain circumstances, the MMS is authorized to suspend or terminate operations on federal offshore leases. Any suspension or termination of operations on our offshore leases could have an adverse effect on our financial condition and results of operations.

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      In 2000, the MMS issued a final rule that governs the calculation of royalties and the valuation of crude oil produced from federal leases. That rule amended the way that the MMS values crude oil produced from federal leases for determining royalties by eliminating posted prices as a measure of value and relying instead on arm’s-length sales prices and spot market prices as indicators of value. On May 5, 2004, the MMS issued a final rule that changed certain components of its valuation procedures for the calculation of royalties owed for crude oil sales. The changes include changing the valuation basis for transactions not at arm’s-length from spot to NYMEX prices adjusted for locality and quality differentials, and clarifying the treatment of transactions under a joint operating agreement. We believe that the changes will not have a material impact on our financial condition, liquidity or results of operations.
Environmental Regulations
      Our operations are subject to numerous stringent and complex laws and regulations at the federal, state and local levels governing the discharge of materials into the environment or otherwise relating to human health and environmental protection. These laws and regulations may, among other things:
  require acquisition of a permit before drilling commences;
 
  restrict the types, quantities and concentrations of various materials that can be released into the environment in connection with drilling and production activities; and
 
  limit or prohibit construction or drilling activities in certain ecologically sensitive and other protected areas.
      Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements and the imposition of injunctions to force future compliance. Offshore drilling in some areas has been opposed by environmental groups and, in some areas, has been restricted. Our business and prospects could be adversely affected to the extent laws are enacted or other governmental action is taken that prohibits or restricts our exploration and production activities or imposes environmental protection requirements that result in increased costs to us or the oil and natural gas industry in general.
      Spills and Releases. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund”, and analogous state laws, impose joint and several 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” and “operator” of the site where the release occurred, past owners and operators of the site, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Responsible parties under CERCLA may be liable for the costs of cleaning up hazardous substances that have been released into the environment and for damages to natural resources. Additionally, it is not uncommon for neighboring landowners and other third parties to file tort claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. In the course of our ordinary operations, we may generate waste that may fall within CERCLA’s definition of a “hazardous substance.”
      We currently own, lease or operate, and have in the past owned, leased or operated, numerous properties that for many years have been used for the exploration and production of oil and gas. 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. It is possible that hydrocarbons or other wastes may have been disposed of or released on or under such properties, or on or under other locations where such wastes may have been taken for disposal. 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, or to pay the costs of such remedial measures. Although we believe we have utilized operating and disposal practices that are standard in the industry, during the course of operations hydrocarbons and other wastes have been released on some of the

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properties we own, lease or operate. We are not presently aware of any pending clean-up obligations that could have a material impact on our operations or financial condition.
      The Oil Pollution Act. The OPA and regulations thereunder impose strict, joint and several liability on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the U.S. 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 establishes a liability limit for onshore facilities of $350 million, while the liability limit for offshore facilities is equal to all removal costs plus up to $75 million in other damages. These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up.
      The OPA also requires the lessee or permittee of an offshore area in which a covered offshore facility is located to provide financial assurance in the amount of $35 million to cover liabilities related to an oil spill. The amount of financial assurance required under the OPA may be increased up to $150 million depending on the risk represented by the quantity or quality of oil that is handled by a facility. The failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative 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 assurance and other operating requirements will not have a material impact on our operations or financial condition.
      Water Discharges. The Federal Water Pollution Control Act of 1972, (the “Clean Water Act”), imposes restrictions and controls on the discharge of produced waters and other oil and gas pollutants into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions may 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 (“NPDES”) 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 of oil and other pollutants, 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 pollutants, into state waters.
      In furtherance of the Clean Water Act, the EPA promulgated the Spill Prevention, Control, and Countermeasure, or SPCC, regulations, which require facilities that possess certain threshold quantities of oil that could impact navigable waters or adjoining shorelines to prepare SPCC plans and meet specified construction and operating standards. The SPCC regulations were revised in 2002 and required the amendment of SPCC plans before February 18, 2006, if necessary, and requires compliance with the implementation of such amended plans by August 18, 2006. We may be required to prepare SPCC plans for some of our facilities where a spill or release of oil could reach or impact jurisdictional waters of the U.S.
      Air Emissions. The Federal Clean Air Act, and associated state laws and regulations, restrict the emission of air pollutants from many sources, including oil and natural gas operations. New facilities may be required to obtain permits before operations can commence, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. We believe that compliance with the Clean Air Act and analogous state laws and regulations will not have a material impact on our operations or financial condition.
      Waste Handling. The Resource Conservation and Recovery Act (“RCRA”) and analogous state and local laws and regulations govern the management of wastes, including the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such

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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. RCRA specifically excludes from the definition of hazardous waste drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil and natural gas. 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. However, these wastes may be regulated by EPA or state agencies as solid waste. In addition, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils, may be regulated under RCRA as hazardous waste. We do not believe the current costs of managing our wastes, as they are presently classified, to be significant. However, any repeal or modification of the oil and natural gas exploration and production exemption, or modifications of similar exemptions in analogous state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses.
Employees
      As of December 31, 2004, we had 53 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.
Legal Proceedings
      Mariner operates numerous properties in the Gulf of Mexico. Two of these properties were leased from the MMS subject to the RRA. The RRA relieved the obligation to pay royalties on certain predetermined leases until a designated volume is produced. These two leases contained language that limited royalty relief if commodity prices exceeded predetermined levels. In 2000, 2001, 2003 and 2004 commodity prices exceeded the predetermined levels. Management believes the MMS did not have the authority to set pricing limits and we filed an administrative appeal contesting the MMS’ order and have withheld royalties regarding this matter. The MMS filed a motion to dismiss our appeal with the Board of Land Appeals of the Department of the Interior. On April 6, 2005, the Board of Land Appeals granted MMS’ motion and dismissed our appeal. We are currently reviewing our legal options. The Company has recorded a liability for 100% of the potential exposure on this matter, which on December 31, 2004 was $10.9 million.
      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.
Insurance Matters
      In September 2004, the Company incurred damage from Hurricane Ivan that affected its Mississippi Canyon 66 (Ochre) and Mississippi Canyon 357 fields. Production from Mississippi Canyon 357 was shut-in until March 2005, when necessary repairs were completed and production recommenced. Production from Ochre is currently shut-in awaiting rerouting of umbilical and flow lines to another host platform. Prior to Hurricane Ivan, this field was producing at a net rate of approximately 6.5 MMcfe per day. Production from Ochre is expected to recommence by the end of the fourth quarter of 2005. In addition, a semi-submersible rig on location at the Company’s Viosca Knoll 917 (Swordfish) field was blown off location by the hurricane and incurred damage. Until we are able to complete all the repair work and submit costs to the insurance underwriters for review, the full extent of our insurance recovery and the resulting net cost to the Company is unknown. We expect the net cost to the Company to be at least equal to the amount of our annual deductible of $1.25 million plus the single occurrence deductible of $.375 million.
Enron Related Matters
      In 1996, JEDI, an indirect wholly owned subsidiary of Enron Corp., acquired approximately 96% of Mariner Energy LLC, which at the time of acquisition indirectly owned 100% of Mariner Energy, Inc.

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After JEDI acquired us, we continued our prior business as an independent oil and natural gas exploration, development and production company. In 2001, Enron Corp. and certain of its subsidiaries (excluding JEDI) became debtors in Chapter 11 bankruptcy proceedings. Mariner Energy, Inc. was not one of the debtors in those proceedings. While the bankruptcy proceedings were ongoing, we continued to operate our business as an indirect subsidiary of JEDI. We remained an indirect subsidiary of JEDI until March of 2004 when our former indirect parent company, Mariner Energy LLC, merged with an affiliate of the private equity funds Carlyle/ Riverstone Global Energy and Power Fund II, L.P. and Acon Investments LLC. In the merger, all the shares of common stock in Mariner Energy LLC were converted into the right to receive cash and certain other consideration. As a result, since March 2004, JEDI no longer owns any direct or indirect interest in Mariner, and we are no longer affiliated with JEDI or Enron Corp. Also in connection with the merger, warrants to purchase common stock of Mariner Energy LLC that were held by another Enron Corp. affiliate were exercised and the holders received their pro rata portion of the merger consideration, and a term loan owed by Mariner Energy LLC to the same Enron Corp. affiliate was repaid in full.
      Prior to the merger, we filed two proofs of claim in the Enron Corp. bankruptcy proceedings. These claims, aggregating $10.7 million, were for unpaid amounts owed to us by Enron Corp. subsidiaries under the terms of various physical commodity contracts and hedging contracts entered into prior to the Enron Corp. bankruptcy filing. We assigned these claims to JEDI as part of the merger consideration payable to JEDI under the terms of the merger agreement. Thus, as of this date, we have no claims pending in the Enron Corp. bankruptcy proceedings.
      As part of the merger consideration payable to JEDI, we also issued a term promissory note to JEDI in the amount of $10 million. The note matures on March 2, 2006, and bears interest, paid in kind, at a rate of 10% per annum until March 2, 2005, and 12% per annum thereafter unless paid in cash in which event the rate remains at 10% per annum. The JEDI promissory note is secured by a lien on three of our properties located in the Outer Continental Shelf of the Gulf of Mexico. We can offset against the note the amount of certain claims for indemnification that can be asserted against JEDI under the terms of the merger agreement. We used a portion of proceeds from the common stock we sold in our March 2005 private equity placement to repay $6 million of the JEDI Note.
      Under the merger agreement, JEDI and the other former stockholders of our parent company were entitled to receive on or before February 28, 2005, additional contingent merger consideration based upon the results of a five-well drilling program. In September 2004, we prepaid, with a 10% prepayment discount, approximately $161,000 as the additional contingent merger consideration due with respect to the program.
      Prior to the closing of the merger, we may have been within the Enron Corp. “controlled group of corporations” as defined under the Employee Retirement Income Security Act of 1974, as amended (“ERISA”) and its related regulations due to Enron Corp.’s indirect ownership and/or control over Mariner. As a member of such “controlled group of corporations,” we may have had potential liability for certain employee benefit plan obligations of Enron Corp. However, the order of the United States Bankruptcy Court for the Southern District of New York that approved the merger states that upon consummation of the merger, our former indirect parent company, Mariner Energy LLC, as the surviving corporation in the merger, would have good title to the interests in its subsidiaries (including Mariner) and their assets free and clear of all claims and encumbrances, and rights of setoff, deduction, netting and recoupment asserted by the Pension Benefit Guaranty Corporation. Furthermore, pursuant to merger agreement, Enron Corp. has agreed to indemnify us from any liabilities imposed against us or any of our assets arising as a result of Mariner being considered an ERISA affiliate of Enron Corp. or relating to any group health insurance plans sponsored or maintained by Enron Corp. or any of its affiliates under Section 4980B of the Internal Revenue Code. Any indemnification claim against Enron Corp. arising under the merger agreement would be treated as an administrative claim in the Enron bankruptcy proceeding and entitled to priority as such. For these reasons, we believe that we have no remaining Enron Corp. control group liability.

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MANAGEMENT
Executive Officers and Directors
      Set forth below are the names, ages and positions of our executive officers and directors as of the date of this prospectus. 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 Company
         
Scott D. Josey
    48     Chairman of the Board, Chief Executive Officer and President
Dalton F. Polasek
    53     Chief Operating Officer
Rick G. Lester
    53     Vice President, Chief Financial Officer and Treasurer
Jesus G. Melendrez
    46     Vice President— Corporate Development
Mike C. van den Bold
    43     Vice President and Chief Exploration Officer
Teresa G. Bushman
    56     Vice President, General Counsel and Secretary
Judd A. Hansen
    49     Vice President— Shelf and Onshore
Cory L. Loegering
    50     Vice President— Deepwater
Bernard Aronson
    59     Director
Jonathan Ginns
    41     Director
Pierre F. Lapeyre, Jr. 
    42     Director
David M. Leuschen
    54     Director
      Scott D. Josey—Mr. Josey has served as Chairman of the Board since August 2001. Mr. Josey was appointed Chief Executive Officer in October 2002 and President in February 2005. From 2000 to 2001, Mr. Josey served as Vice President of Enron North America Corp. and co-managed its Energy Capital Resources group. From 1995 to 2000, Mr. Josey provided investment banking services to the oil and gas industry and portfolio management services. 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 worked in all phases of drilling, production, pipeline, corporate planning and commercial activities at Texas Oil and Gas Corp. Mr. Josey is a member of the Society of Petroleum Engineers and the Independent Producers Association of America.
      Dalton F. Polasek—Mr. Polasek was appointed Chief Operating Officer in February 2005. From April 2004 to February 2005, Mr. Polasek served as Executive Vice President— Operations and Exploration. From February 2001 to October 2001, Mr. Polasek was self-employed. From October 2001 to April 2004, Mr. Polasek served as Senior Vice President— Operations. Prior to joining Mariner, Mr. Polasek served as: Vice President of Gulf Coast Engineering for Basin Exploration, Inc. from 1996 until February 2001; Vice President of Engineering for SMR Energy from 1994 to 1996; director of Gulf Coast Acquisitions and Engineering for General Atlantic Resources, Inc. from 1991 to 1994; and manager of planning and business development for Mark Producing Company from 1983 to 1991. He began his career in 1975 as a reservoir engineer for Amoco Production Company. Mr. Polasek is a Registered Professional Engineer in Texas and a member of the Independent Producers Association of America, the American Association of Drilling Engineers and the American Petroleum Institute.
      Rick G. Lester—Mr. Lester joined Mariner as Vice President, Chief Financial Officer and Treasurer in October 2004. From January 2004 to October 2004, Mr. Lester was self-employed as a consultant. From 1998 to 2003, Mr. Lester was the Executive Vice President, CFO and Treasurer of Contour Energy Company (which filed for Chapter 11 bankruptcy protection in July 2002 and emerged from bankruptcy in December 2002). From 1991 to 1998, Mr. Lester held the positions of Vice President, CFO and Treasurer for Domain Energy Corporation and its Tenneco Ventures predecessor. Prior to 1991, he held various positions with Tenneco, Inc. and Tenneco Exploration and Production including Corporate Finance

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Manager, International Tax Manager and Business Division Accounting Manager. Mr. Lester has over 30 years of industry experience and is a Certified Public Accountant.
      Jesus G. Melendrez—Mr. Melendrez has served as Vice President—Corporate Development since July 2003. Mr. Melendrez also served as a director of Mariner from April 2000 to July 2003. From February 2000 until July 2003, Mr. Melendrez was a Vice President of Enron North America Corp. in the Energy Capital Resources group where he managed the group’s portfolio of oil and gas investments. He was a Senior Vice President of Trading and Structured Finance with TXU Energy Services from 1997 to 2000, and from 1992 to 1997, Mr. Melendrez was employed by Enron in various commercial positions in the areas of domestic oil and gas financing and international project development. From 1980 to 1992, Mr. Melendrez was employed by Exxon in various reservoir engineering and planning positions.
      Mike C. van den Bold—Mr. van den Bold was appointed Vice President and Chief Exploration Officer in April 2004. From October 2001 to April 2004, he served as Vice President—Exploration. Mr. van den Bold joined Mariner in July 2000 as Senior Development Geologist. From 1996 to 2000, Mr. van den Bold worked for British-Borneo Oil & Gas plc. He began his career at British Petroleum. Mr. van den Bold has over 17 years of industry experience. He is a Certified Petroleum Geologist, Texas Board Certified Geologist and member of the American Association of Petroleum Geologists.
      Teresa G. Bushman—Ms. Bushman joined Mariner as Vice President, General Counsel and Secretary in June 2003. From 1996 until joining Mariner in 2003, Ms. Bushman was employed by Enron North America Corp., most recently as Assistant General Counsel representing the Energy Capital Resources group, which provided debt and equity financing to the oil and gas industry. Prior to joining Enron, Ms. Bushman was a partner with Jackson Walker, LLP, in Houston.
      Judd A. Hansen—Mr. Hansen has served as Vice President—Shelf and Onshore since February 2002. From February 2001 to February 2002, Mr. Hansen was self-employed as a consultant. From 1997 until February 2001, Mr. Hansen was employed as Operations Manager of the Gulf Coast Division for Basin Exploration, Inc. From 1991 to 1997, he was employed in various engineering positions at Greenhill Petroleum Corporation, including Senior Production Engineer and Workover/Completion Superintendent. Mr. Hansen started his career with Shell Oil Company in 1978 and has 26 years of experience in conducting operations in the oil and gas industry.
      Cory L. Loegering—Mr. Loegering has served as Vice President—Deepwater since August 2002. Mr. Loegering joined Mariner in July 1990 and since 1998 has held various positions including Vice President of Petroleum Engineering and Director of Deepwater development. Mr. Loegering was employed by Tenneco from 1982 to 1989, in various positions including as senior engineer in the economic, planning and analysis group in Tenneco’s corporate offices. Mr. Loegering began his career with Conoco in 1977 and held positions in the construction, production and reservoir departments responsible for Gulf of Mexico production and development.
      Bernard Aronson—Mr. Aronson was elected as a director in March 2004. He is a founding partner of ACON Investments, a private equity fund. Prior to founding ACON Investments in 1996, Mr. Aronson was International Advisor to Goldman Sachs & Co. for Latin America from 1994 to 1996. From 1989 through 1993, Mr. Aronson served as Assistant Secretary of State for Inter-American Affairs. He is a member of the Council on Foreign Relations and the President’s Advisory Commission on Trade Promotions and Negotiations. Mr. Aronson currently serves on the boards of directors of Liz Claiborne, Inc., Royal Caribbean International Inc., Tropigas S.A. and Hyatt International Corp.
      Jonathan Ginns—Mr. Ginns was elected as a director in March 2004. He is a founding partner of ACON Investments. Prior to founding ACON Investments, a private equity fund, in 1996, Mr. Ginns served as a Senior Investment Officer for the Global Environment-Emerging Markets Fund, part of the GEF Funds group, from 1994 to 1995. Mr. Ginns currently serves on the boards of directors of The Optimal Group, Signal International, Tropigas S.A. and The Commonwealth Broadcasting Corporation.
      Pierre F. Lapeyre, Jr.—Mr. Lapeyre was elected as a director in March 2004. He is a Founder and Managing Director of Riverstone Holdings, LLC, a private equity fund, and serves on its Managing

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Committee responsible for all portfolio activities. Prior to founding Riverstone in May 2000, Mr. Lapeyre served as a Managing Director of Goldman Sachs in its Global Energy and Power Group since 1996. Mr. Lapeyre joined Goldman Sachs in 1986 and spent his 14-year investment banking career focused on the energy and power sectors. Mr. Lapeyre currently serves on the boards of directors of Legend Natural Gas II, LP, SemGroup L.P., Seabulk International, Inc., CDM Resource Management, Ltd., Frontier Holdings, Ltd, Belden & Blake Corporation, Stallion Oilfield Services, Capital C Energy, LLC and Topaz Power Group, LLC.
      David M. Leuschen— Mr. Leuschen was elected as a director in March 2004. He is a Founder and Managing Director of Riverstone Holdings, LLC, a private equity fund, and serves on its Managing Committee responsible for all portfolio activities. Prior to founding Riverstone May 2000, Mr. Leuschen spent 22 years with Goldman Sachs. He joined the firm in 1977, established their Global Energy and Power Group in 1982, became a Partner in 1986, and remained a Partner with the firm until leaving to found Riverstone in 2000. Mr. Leuschen currently serves as a Director of Seabulk International Inc., Frontier Holdings, Ltd, Legend Natural Gas II, LP, Belden & Blake Corporation, Buckeye GP, LLC, the general partner of Buckeye Partners, L.P., Petroplus International N.V. and Mega Energy LLC as well as a number of other industry-related businesses and nonprofit boards of directors. He is also owner and President of Switchback Ranch LLC, an integrated cattle ranching operation in the western U.S.
      Messrs. Aronson, Ginns, Lapeyre and Leuschen, all of whom serve on the board of managers of our former sole stockholder, MEI Acquisitions Holdings, LLC, were elected to the board of directors in connection with the merger in March 2004 pursuant to which MEI Acquisitions Holdings, LLC became our sole stockholder. Since that time, MEI Acquisitions Holdings, LLC has sold approximately 94.7% of the shares it acquired in the merger. See “Security Ownership of Certain Beneficial Owners and Management.”
Board of Directors
      Our board of directors currently consists of five directors. The board of directors is engaged in an active search to expand the board of directors by electing four new directors meeting independence criteria under SEC rules and under the corporate governance rules of the Nasdaq. Messrs Lapeyre and Leuschen have indicated their intention to resign, and upon their resignation, the first two new independent directors elected by the board of directors will fill their vacancies.
      We have agreed that Friedman, Billings, Ramsey & Co., Inc. (“FBR”) may propose individuals to us and MEI Acquisitions Holdings, LLC for consideration for nomination to serve as an independent director. FBR served as the initial purchaser and private placement agent in our March 2005 private placement. As part of the private placement negotiations between FBR and us, FBR negotiated the right to propose individuals for consideration for nomination to serve as an independent director on our board. FBR receives no fee in connection with proposing any independent directors. If any individual proposed by FBR is not selected for nomination, we may propose an individual for nomination, and FBR shall have the right to consent to one individual so nominated, provided that FBR’s consent shall not be unreasonably withheld.
      Our certificate of incorporation and bylaws provide for a classified board of directors consisting of three classes of directors, each serving staggered three-year terms. As a result, stockholders will elect a portion of our board of directors each year. Class I directors’ terms will expire at the annual meeting of stockholders to be held in 2006, Class II directors’ terms will expire at the annual meeting of stockholders to be held in 2007 and Class III directors’ terms will expire at the annual meeting of stockholders to be held in 2008. Currently, the Class I director is Mr. Aronson, the Class II directors are Messrs. Lapeyre and Leuschen, and the Class III directors are Messrs. Ginns and Josey. At each annual meeting of stockholders held after the initial classification, the successors to directors whose terms will then expire will be elected to serve from the time of election until the third annual meeting following election. The division of our board of directors into three classes with staggered terms may delay or prevent a change of our management or a change in control. See “Description of Capital Stock— Anti-Takeover Effects of

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Provisions of Delaware Law, Our Certificate of Incorporation and Bylaws— Amendments to our Certificate of Incorporation and Bylaws.”
      In addition, our bylaws provide that the authorized number of directors, which shall constitute the whole board of directors, may be changed by resolution duly adopted by the board of directors. Any additional directorships resulting from an increase in the number of directors will be distributed among the three classes so that, as nearly as possible, each class will consist of one-third of the total number of directors. Vacancies and newly created directorships may be filled by the affirmative vote of a majority of our directors then in office, even if less than a quorum.
Committees of the Board
      Our board of directors currently consists of five persons, but we expect to expand our board to seven  directors, including four additional independent directors, during the year following this offering. The board of directors intends to establish three committees, the audit committee, the compensation committee and the nominating and corporate governance committee. Although we are not required to have separate compensation and nominating and corporate governance committees, we have determined that it is in the best interests of the Company to maintain independent compensation and nominating and corporate governance committees.
                           will be the initial member of our audit committee. He is “independent” under the listing standards of National Association of Securities Dealers, Inc. and SEC rules. In addition, the board of directors has determined that he is an “audit committee financial expert,” as defined under the rules of the SEC. Within 90 days of the effectiveness of the registration statement of which this prospectus is a part, we will expand our board of directors to include an additional independent director who will serve on the audit committee, and, within one year of the effectiveness of the registration statement, we will expand our board of directors by one more independent director who will also serve on the audit committee. The audit committee will recommend to the board of directors the independent public accountants to audit our financial statements and will oversee the annual audit. The committee will also approve any other services provided by public accounting firms. The audit committee will provide assistance to the board of directors in fulfilling its oversight responsibility to the stockholders, the investment community and others relating to the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence and the performance of our internal audit function. The committee will oversee our system of disclosure controls and procedures and system of internal controls regarding financial, accounting, legal compliance and ethics that management and the board of directors have established. In doing so, it will be the responsibility of the committee to maintain free and open communication between the committee and our independent auditors, the internal accounting function and management of the Company.
                           will serve on the nominating and corporate governance committee of our board of directors. This committee will nominate candidates to serve on our board of directors and approves director compensation. The committee will also be responsible for monitoring a process to assess board effectiveness, developing and implementing our corporate governance guidelines and in taking a leadership role in shaping the corporate governance of the Company.
                           will serve on the compensation committee of our board of directors. The compensation committee will review the compensation and benefits of our executive officers, establish and review general policies related to our compensation and benefits and administers our Equity Participation Plan and Stock Incentive Plan. Under the compensation committee charter, the compensation committee will determine the compensation of our CEO.
Compensation Committee Interlocks and Insider Participation
      None of our executive officers serves as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of our board of directors or compensation committee.

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      During the fiscal year 2004, the board of directors determined executive compensation.
Director Compensation
      We currently do not pay director fees to our directors. We expect in the future to establish and pay directors fees for board and committee participation at a level consistent with those of similar companies, especially as we add independent directors.
Indemnification
      We maintain directors’ and officers’ liability insurance. Our certificate of incorporation and bylaws include provisions limiting the liability of directors and officers and indemnifying them under certain circumstances, as described under “Description of Capital Stock— Liability and Indemnification of Officers and Directors.” We have also entered into indemnification agreements with our executive officers and directors providing our executive officers and directors with additional assurances in a manner consistent with Delaware law.
Executive Compensation
      The following table shows the annual compensation for our chief executive officer, the four other most highly compensated executive officers and one former executive officer, for the three fiscal years ended December 31, 2004.
Summary Compensation Table
                                     
                All Other
Name and Principal Position   Year   Salary   Bonuses   Compensation (1)
                 
Scott D. Josey
    2004     $ 350,000     $ 550,000     $ 590,133  
 
Chairman of the Board, Chief
    2003       300,290       850,000       514,895  
    Executive Officer and President     2002       90,909       281,250       221,439  
Mike C. van den Bold
    2004       192,500       215,000       336,949  
 
Vice President and Chief
    2003       170,150       350,000       45,430  
    Exploration Officer     2002       154,788       46,000       30,932  
Dalton F. Polasek
    2004       215,000       300,000       263,636  
 
Chief Operating Officer
    2003       176,698       325,000       280,677  
          2002             173,438       230,568  
Michael A. Wichterich(2)
    2004       132,307             279,349  
 
Former Vice President, Chief
    2003       170,120       250,000       45,412  
    Financial Officer and Treasurer     2002       155,330       46,000       31,125  
Judd A. Hansen
    2004       180,000       185,000       199,059  
 
Vice President— Shelf and Onshore
    2003       156,023       250,000       191,189  
          2002             116,250       226,674  
Teresa G. Bushman
    2004       190,000       215,000       74,634  
 
Vice President, General Counsel
    2003       97,750       200,000       23,270  
    and Secretary     2002                    
 
(1)  Amounts shown reflect insurance premiums paid by us with respect to term life insurance for the benefit of the named executive officers and retention payments paid during the year. For Mr. Josey, the amounts shown also include amounts payable to Enron North America Corp. under a Corporate Services Agreement. In 2002 Mr. Josey became an employee of Mariner and subsequently the Corporate Services Agreement was terminated. The amounts for 2004 for Messrs. Josey, van den Bold, Polasek, Wichterich and Hansen include $6,500 of employer matching contributions made pursuant to our 401(k) plan and $8,200 made pursuant to the profit sharing portion of our 401(k) plan. In addition, the 2004 amount for Mr. Josey includes $575,000 paid with respect to Mariner’s Long-Term Incentive Plan and $433 of insurance premiums under our group term life insurance. The

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2004 amount for Mr. van den Bold also includes $322,000 paid with respect to Mariner’s Long-Term Incentive Plan and $249 of insurance premiums under our group term life insurance. The 2004 amount for Mr. Polasek also includes $248,400 paid with respect to Mariner’s Long-Term Incentive Plan and $536 of insurance premiums under our group term life insurance. The 2004 amount for Mr. Wichterich also includes $264,500 paid with respect to Mariner’s Long-Term Incentive Plan and $149 of insurance premiums under our group term life insurance. The 2004 amount for Mr. Hansen also includes $184,000 paid with respect to Mariner’s Long-Term Incentive Plan and $359 of insurance premiums under our group term life insurance. The 2004 amount for Ms. Bushman includes $5,573 of employer matching contributions made pursuant to our 401(k) plan, $8,200 made pursuant to the profit sharing portion of our 401(k) plan, $59,800 paid with respect to Mariner’s Long-Term Incentive Plan and $1,061 of insurance premiums under our group term life insurance.
 
(2)  Mr. Wichterich resigned as an officer of Mariner October 8, 2004. Amounts shown for 2004 include payments made to Mr. Wichterich for his work as a part-time employee.
Employment Agreements and Other Arrangements
      We have entered into an employment agreement with each of the current executive officers named in the above compensation table. Each employment agreement has an initial term that runs through March 2, 2007. The employment agreements automatically renew each March 3 for an additional one-year period unless prior notice is given. Each employment agreement provides for a base salary, a discretionary bonus, and participation in our benefit plans and programs. Mr. Josey’s agreement also provides for life insurance equal to two times his base salary.
      The base salaries for 2005 for our Chief Executive Officer and each of our other current named executive officers are as follows: Scott D. Josey—$375,000; Mike C. van den Bold—$200,000; Dalton F. Polasek—$250,000; Judd A. Hansen—$187,500; and Teresa G. Bushman—$200,000.
      Under the employment agreements, the officers are entitled to severance benefits in the event of a resignation for good reason, a termination without cause or, in the case of Mr. Josey’s agreement, our non-renewal of the agreement: (i) a payment equal to 2.0 (2.5 for Mr. Polasek and 2.99 for Mr. Josey) times the sum of executive’s base salary and three year average annual bonus, (ii) health care coverage for a period of eighteen months (two years for Mr. Josey and Mr. Polasek), (iii) 100% vesting of all restricted shares under our Equity Participation Plan, and (iv) 50% vesting of all other rights under any other equity plans, including our Stock Incentive Plan.
      The employment agreements also provide for certain change of control benefits. Upon termination for any reason other than cause at any time on or within nine months after a change of control that occurs while the executive is employed, or upon the occurrence of a change of control within nine months following resignation of employment for good reason or termination without cause, the agreements provide for the following benefits: (i) a lump sum payment equal to 2.0 (2.5 for Mr. Polasek and 2.99 for Mr. Josey) times the sum of the officer’s base salary and three year average annual bonus, and (ii) 100% vesting of all rights under any equity plans, including our Equity Participation Plan and our Stock Incentive Plan. The officers are entitled to a full tax gross-up payment if the aggregate payments and benefits to be provided constitute a “parachute payment” subject to a Federal excise tax.
      The agreements also include confidentiality and non-solicitation provisions.
Overriding Royalty Arrangements
      Mariner’s geologist and geophysicist employees are eligible to participate in the Company’s Amended and Restated Gulf of Mexico Overriding Royalty Interest Plan. Pursuant to the terms of the plan, overriding royalty interests (“ORRIs”) may be awarded to participants in the plan for prospects in the Gulf of Mexico that are generated or identified and acquired during the term of the participant’s employment at Mariner. The maximum ORRI for all participants is 1.8% for shelf leases and 0.9% for deepwater leases, subject to proportionate reduction. The maximum ORRI per participant is 1/2 of one

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percent for shelf leases and 1/4 of one percent for deepwater leases, subject to proportionate reduction. Unless approved by Mariner’s overriding royalty interest committee, no ORRIs are awarded for developed or undeveloped reserve acquisitions.
      To avoid potential conflicts of interest, Mariner’s geologist and geophysicist employees that participate in the Overriding Royalty Interest Plan (the “ORRI Plan Participants”) do not make decisions with respect to the pursuit of the acquisition, exploration or development of prospects. When an ORRI Plan Participant develops a lead for a prospect, executive management makes the decision whether to pursue to the acquisition, exploration or development of the prospect. In addition, ORRI Plan Participants are required at the time they become eligible for participation in the plan and periodically thereafter to disclose oil and gas properties in which they or their immediate family members have any interest and to abstain from participation in the evaluation of any property in which they or their immediate family members have any interest.
      Currently six employees are participants in the plan. None of Mariner’s officers or managers are eligible to participate in the plan. Since the inception of the plan in July 2002 through December 31, 2004, approximately $252,000 has been distributed to participants with respect to ORRIs granted to them under the plan.
      In 2002, two of our current executive officers, Dalton F. Polasek, Executive Vice President—Operations and Exploration and Judd A. Hansen, Vice President—Shelf and Onshore, received assignments of ORRIs in certain leases acquired by us under a consulting arrangement. A consulting company owned in part by Mr. Polasek was assigned a 2% ORRI from us in four federal offshore leases as partial consideration for having brought the related prospect to us. With our knowledge and consent, the consulting company subsequently assigned portions of the ORRIs to Mr. Hansen and a company owned by Mr. Polasek. At the time of the assignments, Messrs. Polasek and Hansen served the Company as officers and consultants but were not employed by the Company. No payments were made in respect of these ORRIs until 2004, when each received less than $60,000 with respect to his ORRI.
      We may have obligations under previously terminated employment and consulting agreements to assign additional ORRIs in some of our oil and natural gas prospects to current and former employees and consultants. Cory L. Loegering, Vice President of Deepwater, is the only current executive officer who may be entitled to receive ORRIs under any of these agreements.
      All ORRIs assigned to these parties are excluded from Mariner’s interests evaluated in our reserve report.
Equity Participation Plan
      We have adopted an Equity Participation Plan that provided for the one-time grant at the closing of our private equity placement on March 11, 2005 of 2,267,270 restricted shares of our common stock to certain of our employees. No further grants will be made under the Equity Participation Plan, although persons who receive such a grant will be eligible for future awards of restricted stock or stock options under our Stock Incentive Plan described below.
      We intended the grants of restricted stock under the Equity Participation Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common stock. Therefore, Equity Participation Plan grantees did not pay any consideration for the common stock they received, and we received no remuneration for the stock.
      The table below includes information regarding the restricted stock awards granted in March of 2005 under the Equity Participation Plan to our chief executive officer, our four other most highly compensated executive officers as of the year 2004, and all officers as a group. Grantees are entitled to vote, and accrue

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dividends on, the restricted stock prior to vesting; provided, however that any dividends that accrue on the restricted stock prior to vesting will only be paid to grantees to the extent the restricted stock vests.
Equity Participation Plan
Restricted Stock Awards
                 
Officer or Group   No. of Shares   Value at Grant (1)
         
Scott D. Josey
    680,181     $ 9,522,534  
Mike C. van den Bold
    226,727       3,174,178  
Dalton F. Polasek
    308,349       4,316,886  
Judd A. Hansen
    158,709       2,221,926  
Teresa G. Bushman
    137,170       1,920,380  
Officers as a group (8 persons)
    1,803,613       25,250,582  
 
(1)  Based on a price of $14.00 per share.
      Except as described below, the restricted shares will be automatically forfeited in the event a grantee’s employment terminates prior to the vesting date of the awards. The restricted stock granted will vest, and restrictions will terminate, on the later of (i) the first anniversary of the grant date, which was March 11, 2005, and (ii) the occurrence of a “Public Sale Date”; but in no event later than the second anniversary of the date of grant. For purposes of grants under the Equity Participation Plan, “Public Sale Date” means the earlier to occur of:
  the 90th day following the date on which our common stock is listed on the New York Stock Exchange or admitted to trading and quoted on the Nasdaq National Market or Nasdaq SmallCap Market; and
 
  the first date on which both of the following conditions are met: (a) a registration statement covering the resale of the restricted stock has been declared effective by the SEC, and no stop order suspending the effectiveness of such registration statement is in effect and (b) the common stock is listed on the New York Stock Exchange or admitted to trading and quoted on the Nasdaq National Market or Nasdaq SmallCap Market;
provided, however, that if either of the above events occurs and the restricted shares are subject to restrictions on resale as a result of any lock-up agreement or arrangement in connection with a public offering, the Public Sale Date shall be the earlier of the first business day following the date of expiration of the lock-up period and a date 181 days from the date the lock-up period commences.
      Notwithstanding the above vesting schedule, the unvested shares of restricted stock will become fully vested upon death or disability of the employee, or if employment is terminated by us for reasons other than for “cause,” or if the employee elects to terminate employment with “good reason,” or upon the occurrence of a “change of control,” as those terms are defined in the agreement with us governing the grant.
      In accordance with GAAP, we expect to incur significant compensation expense as a result of the grants of restricted stock under the Equity Participation Plan. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Critical Accounting Policies— Deferred Compensation Expense” for a discussion of these charges.
      Stock may be withheld by us upon vesting to satisfy our tax withholding obligations with respect to the vesting of the restricted stock. Participants in the Equity Participation Plan will have the right to elect to have us withhold and cancel shares of the restricted stock to satisfy withholding obligations. In such events, we would be required to pay any tax withholding obligation in cash.

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      The Equity Participation Plan will be administered by our board of directors. The board of directors may delegate administration of the plan to a committee of the board of directors. The Equity Participation Plan will expire upon the vesting or forfeiture of all shares granted thereunder.
Stock Incentive Plan
      We have adopted a Stock Incentive Plan for issuances of equity based awards based on our common stock to our current or future employees and directors. The Stock Incentive Plan consists of two components: restricted stock and stock options. The Stock Incentive Plan limits the number of shares of our common stock that may be delivered pursuant to awards to 2,000,000 shares, 798,960 of which have been granted to certain of our employees at an initial exercise price of $14 per share. Stock withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. The Stock Incentive Plan is administered by our board of directors. The board of directors may delegate administration of the Stock Incentive Plan to a committee of the board. The table below includes information regarding stock options under the Stock Incentive Plan granted in March of 2005 to our chief executive officer, our four other most highly compensated executive officers in 2004 and all officers as a group.
Stock Incentive Plan
Grants of Stock Options— $14 Exercise Price
         
Officer or Group   No. of Option Shares
     
Scott D. Josey
    200,000  
Mike C. van den Bold
    74,000  
Dalton F. Polasek
    102,000  
Judd A. Hansen
    48,000  
Teresa G. Bushman
    40,000  
Executive officers as a group (8 persons)
    584,000  
      Our board of directors may terminate or amend the Stock Incentive Plan at any time with respect to any shares of stock for which a grant has not yet been made. Our board of directors also has the right to alter or amend the Stock Incentive Plan or any part thereof from time to time, including increasing the number of shares of stock that may be granted subject to stockholder approval. However, no change in the Stock Incentive Plan or in any outstanding grant may be made that would materially reduce the benefits of the participant without the consent of the participant. The Stock Incentive Plan will expire on the earlier of the tenth anniversary of its approval by stockholders or its adoption or its termination by the board of directors. Awards then outstanding will continue pursuant to the terms of their grants.
      Restricted Stock. Restricted stock is stock that vests over a period of time and that during such time is subject to forfeiture. At any time in the future, the board of directors may determine to make grants of restricted stock under the Stock Incentive Plan to employees and directors containing such terms as the board of directors shall determine. The board of directors will determine the period over which restricted stock granted to employees and members of our board of directors will vest. The board of directors may base its determination upon the achievement of specified financial or other objectives.
      If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s restricted stock will be automatically forfeited unless, and to the extent, the board of directors or the terms of the award agreement provide otherwise. Shares of common stock to be delivered as restricted stock may be newly issued common stock, common stock already owned by us, common stock acquired by us from any other person or any combination of the foregoing. If we issue new common stock upon the grant of the restricted stock, the total number of common stock outstanding will increase.

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      We intend the restricted stock under the Stock Incentive Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common stock. Therefore, Stock Incentive Plan participants will not pay any consideration for the common stock they receive, and we will receive no remuneration for the stock.
      Stock Options. The Stock Incentive Plan permits the grant of options covering our common stock. Options may be incentive stock options, within the meaning of Section 422 of the Internal Revenue Code, or nonqualified stock options as determined by the board of directors. At any time in the future, the board of directors may determine to make grants under the Stock Incentive Plan to employees and members of our board of directors containing such terms as the committee shall determine. Stock options will have an exercise price that may not be less than the fair market value of the stock on the date of grant. In general, stock options granted will become exercisable over a period determined by the board of directors. If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s unvested stock options will be automatically forfeited unless, and to the extent, the option agreement or the board of directors provides otherwise.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
      The following table sets forth information as of March 11, 2005 with respect to the beneficial ownership of our common stock by (i) 5% stockholders, (ii) current directors, (iii) five most highly compensated executive officers during 2004 and (iv) executive officers and directors as a group.
      Unless otherwise indicated in the footnotes to this table, each of the stockholders named in this table has sole voting and investment power with respect to the shares indicated as beneficially owned.
                 
        Percent
Name of Beneficial Owner   Amount(1)   of Class
         
5% Stockholder:
               
FMR Corp.(2)
    4,335,200       12.2 %
ACON E&P, LLC(3)
    1,895,630       5.3 %
Officers and Directors(4):
               
Scott D. Josey
    680,181       1.9 %
Mike C. van den Bold
    226,727       *  
Dalton F. Polasek
    308,349       *  
Judd A. Hansen
    158,709       *  
Teresa G. Bushman
    137,170       *  
Bernard Aronson(5)
    1,895,630       5.3 %
Jonathan Ginns(6)
    1,895,630       5.3 %
Pierre F. Lapeyre, Jr. 
           
David M. Leuschen
           
Executive officers and directors as a group (12 persons)
    3,699,244       10.4 %
 
  * Less than 1%.
(1)  Includes grants of restricted stock to executive officers under our Equity Participation Plan. These shares may be voted, but not disposed of, prior to vesting.
 
(2)  Of the amount shown, 1,847,200 shares are held by Fidelity Contrafund, 1,439,700 shares are held by Fidelity Puritan Fund: Fidelity Low-Priced Stock Fund, 527,600 shares are held by Variable Insurance Products Fund II: Contra-Fund Portfolio, 516,300 shares are held by Fidelity Puritan Trust: Fidelity Balanced Fund, and 4,400 shares are held by Fidelity Management Trust Company on behalf of accounts managed by it. Fidelity may be deemed a beneficial owner of these shares by virtue of its affiliation with these holders of record.
 
(3)  The address of ACON E&P, LLC is c/o ACON Investments LLC, 1133 Connecticut Avenue, N.W., Suite 1100, Washington, D.C. 20036. The shares beneficially owned by ACON E&P, LLC are held of record by MEI Acquisitions Holdings, LLC.
 
(4)  The address of each officer and director is c/o Mariner Energy, Inc., 2101 CityWest Blvd., Bldg. 4, Suite 900, Houston, Texas 77042.
 
(5)  Mr. Aronson is a manager of ACON E&P, LLC. Mr. Aronson disclaims beneficial ownership of these shares except to the extent of his pecuniary interest therein. Mr. Aronson’s address is c/o ACON Investments, LLC, 1133 Connecticut Avenue, N.W., Suite 1100, Washington, D.C. 20036.
 
(6)  Mr. Ginns is a managing member of Burns Park Investments LLC, a manager of ACON E&P, LLC. Mr. Ginns disclaims beneficial ownership of these shares except to the extent of his pecuniary interest therein. Mr. Ginns’ address is c/o ACON Investments, LLC, 1133 Connecticut Avenue, N.W., Suite 1100, Washington D.C. 20036.

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CERTAIN TRANSACTIONS WITH AFFILIATES AND MANAGEMENT
      In connection with the merger in March 2004, Mariner Energy LLC, our former indirect parent, entered into management agreements with each of Carlyle/ Riverstone Energy Partners II, L.P. (“C/R Energy Partners”) and ACON E&P III, LLC (“ACON E&P”), pursuant to which we paid aggregate fees in the amount of $2,500,000 to C/R Energy Partners and ACON E&P. C/R Energy Partners was, and ACON E&P is, an affiliate of MEI Acquisitions Holdings, LLC, our former sole stockholder. No additional fees are payable under these agreements.
      Under a C/R Monitoring Agreement with C/R Energy Partners and under an ACON Monitoring Agreement with ACON, each dated as of March 2, 2004, we were obligated to pay monitoring fees in the aggregate amount of 1% of our annual consolidated EBITDA to C/R Energy Partners and ACON payable on a calendar quarter basis. Under the terms of the monitoring agreements, the affiliates provided financial advisory services in connection with the ongoing operations of Mariner subsequent to the merger. We accrued $1.4 million in monitoring fees under these agreements for 2004. The parties terminated these agreements on February 7, 2005 in return for lump sum cash payments by Mariner totalling $2.3 million. We intend to engage in transactions with our affiliates in the future only when the terms of any such transactions are no less favorable than transactions that could be obtained from third parties.
      We used $166 million of the net proceeds from our sale of 12,750,000 share of common stock in our recent private placement to purchase and retire an equal number of shares of our common stock shares then held by MEI Acquisitions Holdings, LLC, our former sole stockholder.
      The estimated $1.9 million in expenses related to the recent private placement included approximately $.8 million of expenses incurred by our former sole stockholder, MEI Acquisitions Holdings, LLC, and its members in connection with the offering.
      We currently have obligations concerning ORRI arrangements with two of our officers who received assignments of ORRIs in certain leases acquired by us under a consulting agreement and with another officer who may be entitled to assignments of ORRIs under a previously terminated employment agreement, as described in “Management—Overriding Royalty Arrangements.”
SELLING STOCKHOLDERS
      This prospectus covers shares currently owned by an affiliate of our former sole stockholder as well as shares sold in our recent private equity placement. Some of the shares sold in the private equity placement were sold directly to “accredited investors” as defined by Rule 501(a) under the Securities Act pursuant to an exemption from registration provided in Regulation D, Rule 506 under Section 4(2) of the Securities Act. In addition, we and our former sole stockholder sold shares to FBR, who acted as initial purchaser and sole placement agent in the offering. FBR sold the shares it purchased from us and our sole stockholder in transactions exempt from the registration requirements of the Securities Act to persons that it reasonably believed were “qualified institutional buyers,” as defined by Rule 144A under the Securities Act or to non-U.S. persons pursuant to Regulation S under the Securities Act. An affiliate of our former sole stockholder, the selling stockholders who purchased shares from us or FBR in the private equity placement and their transferees, pledgees, donees, assignees or successors, may from time to time offer and sell under this prospectus any or all of the shares listed opposite each of their names below.
      The following table sets forth information about the number of shares owned by each selling stockholder that may be offered from time to time under this prospectus. Certain selling stockholders may be deemed to be “underwriters” as defined in the Securities Act. Any profits realized by the selling stockholder may be deemed to be underwriting commissions.
      The table below has been prepared based upon the information furnished to us by the selling stockholders as of March 30, 2005. The selling stockholders identified below may have sold, transferred or otherwise disposed of some or all of their shares since the date on which the information in the following table is presented in transactions exempt from or not subject to the registration requirements of the Securities Act. Information concerning the selling stockholders may change from time to time and, if

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necessary, we will supplement this prospectus accordingly. We cannot give an estimate as to the amount of shares of common stock that will be held by the selling stockholders upon termination of this offering because the selling stockholders may offer some or all of their common stock under the offering contemplated by this prospectus. The total amount of shares that may be sold hereunder will not exceed the number of shares offered hereby. Please read “Plan of Distribution.”
      Except as noted below, to our knowledge, none of the selling stockholders has, or has had within the past three years, any position, office or other material relationship with us or any of our predecessors or affiliates, other than their ownership of shares described below.
                 
        Percentage of
    Number of Shares of   Common
    Common Stock That   Stock
Selling Stockholder   May Be Sold   Outstanding
         
ACON E&P, LLC(1)
    1,895,630       5.32 %
ADAR Investment Fund Ltd
    350,000       *  
Alexander, Leslie
    450,000       1.26 %
Alexandra Global Master Fund, Ltd
    350,000       *  
Alexis A. Shehata-Personal Portfolio
    1,840       *  
Allied Funding, Inc. 
    17,000       *  
Alpha US Sub Fund 1, LLC
    31,400       *  
America
    40,000       *  
Anita L. Rankin Revocable Trust-U/ A DTD 4/28/1995-Anita L. Rankin, TTEE
    380       *  
Ann K. Miller-Personal Portfolio
    6,300       *  
Anne Marie Romer-Personal Portfolio
    1,290       *  
Anthony L. Kremer Revocable Living Trust-U/ A DTD 1/27/1998-Anthony L. Kremer TTEE
    1,000       *  
Anthony L. Kremer-IRA
    1,010       *  
Atlas (QP), LP
    5,550       *  
Atlas Capital (Q.P.), L.P. 
    102,600       *  
Atlas Capital Master Fund Ltd
    197,400       *  
Atlas Master Fund
    10,920       *  
Auto Disposal Systems-401(k)-All Cap Value Account
    650       *  
Auto Disposal Systems-401(k)-Balanced 60 Account
    480       *  
Auto Disposal Systems-401(k)-Small Cap Value Account
    850       *  
Aviation Sales Inc.-401(k) Profit Sharing Plan-Rick J. Penwell TTEE
    1,470       *  
Axia Offshore Partners, LTD
    143,500       *  
Axia Partners Qualified, LP
    258,950       *  
Axia Partners, LP
    66,150       *  
Baker-Hazel Funeral Home, Inc.-401(k) Plan
    550       *  
Baker-Hazel Funeral Home-Corporate Investment Fund
    330       *  
Basso Multi-Strategy Holding Fund Ltd
    56,550       *  
Basso Private Opportunity Holding Fund Ltd. 
    15,950       *  
BBT Fund, L.P. 
    505,811       1.42 %
BBVA
    321,429       *  
Beach, Patrick & Christine
    6,666       *  
Belmont, Francis E
    1,500       *  
Bennett Family LLC
    2,000       *  
Benny L. & Alexandra P. Tumbleston JT WROS
    1,890       *  
Bermuda Partners, LP
    33,000       *  
Black Sheep Partners, LLC
    18,000       *  
BLT Enterprises, LLLP-Partnership
    1,100       *  

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        Percentage of
    Number of Shares of   Common
    Common Stock That   Stock
Selling Stockholder   May Be Sold   Outstanding
         
Blueprint Partners, L.P. 
    20,000       *  
Borman, Casey 1
    5,000       *  
Boston Partners All Cap Value Fund
    1,875       *  
Bradley J. Hausfeld-IRA
    400       *  
Brady Partners
    27,500       *  
Brunswick Master Pension Trust
    23,600       *  
Calm Waters Partnership
    142,857       *  
Camine Guerro-IRA Rollover
    2,090       *  
Canyon Capital Balanced Equity Master Fund, Ltd
    71,429       *  
Canyon Value Realization Fund (Cayman) Ltd. 
    500,000       1.40 %
Canyon Value Realization Fund L.P. 
    121,428       *  
Canyon Value Realization MAC- 18 Ltd
    7,143       *  
Carmine and Wendy Guerro Living Trust-U/ A DTD 7/31/2000-C Guerro and W Guerro, TTEES
    1,080       *  
Carol D. Shellabarger Green-Revocable Trust DTD 4/21/00-Carol Downing Green TTEE
    890       *  
Carol Downing Green-IRA
    470       *  
Carol V. Hicks-Personal Portfolio
    30       *  
Castle Rock Fund Ltd
    126,800       *  
Castlerock Partners II, L.P. 
    15,800       *  
Castlerock Partners, L.P. 
    392,000       1.10 %
Catalyst Fund Offshore Ltd. 
    3,242       *  
Caxton International Limited
    375,000       1.05 %
Ceisel, Charles B
    1,500       *  
Chamberlain Investments Ltd. 
    8,762       *  
Charles L. & Miriam L. Bechtel-Joint Personal Portfolio
    450       *  
Cheyne Special Situations Fund LP
    200,000       *  
Chimermine, Lawrence
    2,000       *  
Christine Hausfeld-IRA
    160       *  
Christopher M. Ruff-IRA Rollover
    200       *  
Cindu International Pension Fund
    2,900       *  
Citi Canyon Ltd
    7,143       *  
Clam Partners, LLC
    36,000       *  
Clark Manufacturing Co.-Pension Plan DTD 5/16/1998-John A. Barron TTEE
    180       *  
Clark Manufacturing Co.-PSP DTD 5/16/98-John A. Barron TTEE
    360       *  
Concentrated Alpha Partners, L.P. 
    185,619       *  
Congress Ann Hazel-IRA
    590       *  
Cynthia Mollica Barron-Personal Portfolio
    150       *  
David Keith Ray-IRA
    940       *  
David M. Morad Jr.-IRA Rollover
    2,800       *  
David R. Kremer Revocable Living Trust-DTD 5/7/1996-David R. Kremer & Ruth E. Kremer, TTEES
    1,230       *  
Deanne W. Joseph-IRA Rollover
    370       *  
Deephaven Event Trading Ltd.
    450,000       1.26 %
Deephaven Growth Opportunities Trading Ltd.
    550,000       1.54 %
Delaware Street Capital Master Fund L.P. 
    650,000       1.83 %
Deutsche Bank AG London
    53,571       *  

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        Percentage of
    Number of Shares of   Common
    Common Stock That   Stock
Selling Stockholder   May Be Sold   Outstanding
         
Don A. Keasel and Judith Keasel-JTWROS
    120       *  
Don Keasel-IRA Rollover
    810       *  
Donald G. Tekamp Revocable Trust-DTD 8/16/2000-Donald G. Tekamp TTEE
    1,460       *  
Donald L. and Edythe Aukeman-Joint Personal Portfolio
    400       *  
Donald L. Aukerman-IRA
    620       *  
Donna M. Ruff-IRA Rollover
    80       *  
Dorothy W. Savage-Kemp-IRA
    440       *  
Dorothy W. Savage-Kemp-TOD
    820       *  
Douglas & Melissa Marchal-Joint Personal Portfolio
    290       *  
Dr. Donald H. Nguyen & Lynn A. Buffington-JTWROS
    540       *  
Dr. Juan M. Palomar-IRA Rollover
    1,520       *  
Drake Associates LP
    38,929       *  
Edenworld International Ltd. 
    4,470       *  
Edison Sources Ltd. 
    33,600       *  
Edward W. Eppley-IRA — SEP
    600       *  
Edythe M. Aukeman-IRA
    140       *  
Elaine S. Berman Trust-DTD 6/30/95-Elaine S. Berman TTEE
    550       *  
Elaine S. Berman-Inherited IRA-Beneficiary of Freda Levine
    460       *  
Elaine S. Berman-SEP-IRA
    540       *  
Electrical Workers Pension Funds Part A
    1,855       *  
Electrical Workers Pension Funds Part B
    1,335       *  
Electrical Workers Pension Funds Part C
    645       *  
Emerson Electric Company
    32,300       *  
Emerson Partners
    60,000       *  
Emerson, J. Steven
    200,000       *  
Emerson, J. Steven IRA R/ O II
    740,000       2.08 %
Emerson, J. Steven Roth IRA
    400,000       1.12 %
Endeavor Asset Management
    20,000       *  
Ernst Enterprises-Deferred Compensation DTD 05/20/90-fbo Mark Van de Grift
    1,360       *  
Ernst Enterprises-Deferred Compensation Plan DTD 05/20/90-fbo Terry Killian
    1,560       *  
Excelsior Value and Restructuring Fund
    1,200,000       3.37 %
Farallon Capital Institutional Partners II, L.P. 
    10,700       *  
Farallon Capital Institutional Partners III, L.P. 
    12,500       *  
Farallon Capital Institutional Partners, L.P. 
    128,600       *  
Farallon Capital Offshore Investors, Inc. 
    364,300       1.02 %
Farallon Capital Partners, L.P. 
    194,586       *  
Farvane Limited
    1,216       *  
FBO Marjorie G. Kasch-U/ A/ D 3/21/80-Thomas A. Holton TTEE
    700       *  
Fidelity Contrafund(2)
    1,847,200       5.19 %
Fidelity Management Trust Company on behalf of accounts managed by it(3)
    4,400       *  
Fidelity Puritan Trust: Fidelity Balanced Fund(2)
    516,300       1.45 %
Fidelity Puritan Trust: Fidelity Low-Priced Stock Fund(2)
    1,439,700       4.04 %
Flagg Street Offshore, LP
    86,725       *  

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        Percentage of
    Number of Shares of   Common
    Common Stock That   Stock
Selling Stockholder   May Be Sold   Outstanding
         
Flagg Street Partners LP
    41,395       *  
Flagg Street Partners Qualified LP
    46,880       *  
Fleet Maritime, Inc. 
    19,731       *  
Fondo America
    40,000       *  
Fondo Attivo
    17,000       *  
Fondo Trading
    55,000       *  
Fort Mason Master, L.P. 
    188,100       *  
Fort Mason Partners, L.P. 
    11,900       *  
Framtidsfonden
    25,000       *  
Gallatin, Ronald
    25,000       *  
Gary M. Youra, M.D.-IRA Rollover
    2,060       *  
Geary Partners
    95,000       *  
George Hicks-Personal Portfolio
    860       *  
Gerald Allen-IRA
    420       *  
Gerald E. & Deanne W. Joseph-Joint Personal Portfolio
    1,180       *  
Gerald J. Allen-Personal Portfolio
    3,580       *  
GLG Market Neutral Fund
    178,570       *  
GLG North American Opportunity Fund
    892,859       2.50 %
Global Capital Ltd. 
    20,000       *  
GMI Master Retirement Trust
    33,395       *  
Goldman Sachs & Co., Inc. 
    317,756       *  
Goldstein, Robert B. & Candy K
    4,000       *  
Gracie Capital International
    225,000       *  
Gracie Capital LP
    150,000       *  
Greek, Cathy & Frank
    3,900       *  
Gregory A. & Bibi A. Reber-Joint Personal Portfolio
    580       *  
Gregory J. Thomas-IRA — SEP
    370       *  
Grelsamer, Philippe
    2,500       *  
Gruber & McBaine International
    15,000       *  
Gruber, Jon D. & Linda W
    15,000       *  
Guggenheim Portfolio Company LLC
    40,000       *  
H. Joseph & Rosemary Wood-Joint Personal Portfolio
    880       *  
Hancock, David H
    20,000       *  
Harbert Event Driven Master Fund Ltd. 
    37,500       *  
Harbor Advisors, LLC FBO Butterfield Bermuda General Account
    20,000       *  
Harold & Congress Hazel Trust-U/ A DTD 4/21/1991-Congress Ann Hazel, TTEE
    740       *  
Harold A. & Lois M. Ferguson-Joint Personal Portfolio
    1,040       *  
HCM Energy Holdings LLC
    78,571       *  
HFR HE Systematic Master Trust
    28,500       *  
Highbridge Event Driven/ Relative Value Fund, L.P. 
    94,957       *  
Highbridge Event/ Driven/ Relative Value Fund Ltd
    662,186       1.86 %
Highbridge International LLC
    671,428       1.88 %
Highland Equity Focus Fund, LP
    70,000       *  
Highland Equity Fund, LP
    30,000       *  
HSBC Guyerzeller Trust Company
    5,829       *  
Hsien-Ming Meng-IRA Rollover
    990       *  

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        Percentage of
    Number of Shares of   Common
    Common Stock That   Stock
Selling Stockholder   May Be Sold   Outstanding
         
Idnani, Rajesh
    7,500       *  
Institutional Benchmarks Master Fund Ltd
    7,143       *  
Ironman Energy Capital, L.P. 
    100,000       *  
James R. Goldstein-Personal Portfolio
    570       *  
Jan Munroe Trust
    10,000       *  
Janice S. Hamon-Personal Portfolio
    410       *  
Jeannine E. Philpot-Personal Portfolio
    820       *  
JMG Capital Partners, LP
    125,000       *  
JMG Triton Offshore Fund Ltd
    125,000       *  
John & Lisa O’Neil-Joint Personal Portfolio
    1,290       *  
John A. Barron-IRA Rollover
    2,300       *  
John A. Barron-Personal Portfolio
    170       *  
John A. Barron-Personal Portfolio
    390       *  
John B. Maynard Jr.-Irrevocable Trust U/ A DTD 12/12/93-John B. Maynard Sr., TTEE
    320       *  
John C. & Sarah L. Kunesh-JTWROS
    610       *  
John Eubel-IRA Rollover
    5,100       *  
John F. Carroll-IRA — SEP
    130       *  
John H. Lienesch-IRA
    2,080       *  
John M. Walsh, Jr.-IRA Rollover
    980       *  
John O’Meara-IRA Rollover
    400       *  
John T. Dahm-IRA
    1,870       *  
Johnson Revocable Living Trust
    10,000       *  
Jon R. Yanor-IRA Rollover
    910       *  
Jon R. Yenor & Caroline L. Breckner-Joint Tenants
    1,230       *  
Joseph D. Maloney-Personal Portfolio
    810       *  
Judith Keasel-IRA Rollover
    340       *  
Julber, Evan L
    4,000       *  
Kandythe J. Miller-Personal Portfolio
    850       *  
Kathleen J. Lienesch Family Trust-DTD 2/2/00-Kathleen J. Lienesch TTEE
    1,500       *  
Kathleen J. Lienesch-IRA
    240       *  
Kathryn A. Leeper-Revocable Living Trust DTD 06/29/95-Kathryn A. Leeper, TTEE
    540       *  
Keith L. Aukeman-IRA Rollover
    1,600       *  
Kenneth E. Shelton-IRA Rollover
    820       *  
Kettering Anesthesia Associates-Profit Sharing Plan-FBO David J. Pappenfus
    1,230       *  
Kevin E. Slattery-Trust B DTD 5/17/99-De Ette Rae Hart TTEE
    1,270       *  
Kirby C. Leeper-IRA Rollover
    590       *  
Lagunitas Partners LP
    70,000       *  
Lamb Partners LP
    96,000       *  
Lawrence J. Harmon Trust A-DTD 1/29/2001-G Harmon & T Harmon & H Wall TTEES
    680       *  
Leo K. & Katherine H. Wingate-Joing Personal Portfolio
    580       *  
Lester J. & Susan A. Chamock-JTWROS
    2,140       *  
Linda M. Meister-Personal Portfolio
    1,000       *  

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        Percentage of
    Number of Shares of   Common
    Common Stock That   Stock
Selling Stockholder   May Be Sold   Outstanding
         
LJB Inc. Savings Plan & Trust-U/ A DTD 1/1/1985 FBO T. Beach-Stephen D. Williams TTEE
    490       *  
Loyola University Employee’s Retirement Plan Trust
    8,400       *  
Loyola University of Chicago Endowment Fund
    8,450       *  
Margaret S. Adam Revocable TRUST-DTD 4/10/02-Margaret S. Adam, TTEE
    360       *  
Marily E. Lipson-IRA
    140       *  
Marilyn E. Lehman-IRA Rollover
    1,600       *  
Martha S. Senklw-Revocable Living Trust DTD 11/02/98-Martha S. Senkiw, TTEE
    240       *  
Martin J. Grunder, Jr.-IRA — SEP
    450       *  
Marvin E. Nevins-Personal Portfolio
    920       *  
Mary Ellen Kremer Living Trust-U/ A DTD 01/27/1998-Mary Ellen Kremer TTEE
    1,100       *  
Mary K. Scullion-IRA
    1,400       *  
Maureen K. Aukeman-Personal Portfolio
    190       *  
Maureen K. Aukerman-IRA Rollover
    880       *  
Melodee Ruffo-Personal Portfolio
    720       *  
Metal Trades
    4,500       *  
Miami Valleo Cardiologists, Inc.-Profit Sharing Plan
               
Trust-EBS Small Cap
    6,800       *  
Miami Valley Cardiologists, Inc.-Profit Sharing Plan Trust-EBS Equity 100
    10,060       *  
Michael & Marilyn E. Lipson-JTWROS
    290       *  
Michael A. Houser & H. Stephen Wargo-JTWROS
    270       *  
Michael F. & Renee D. Ciferri-Joint Personal Portfolio
    700       *  
Michael G. & Dara L. Bradshaw-Joint Personal Portfolio
    1,440       *  
Michael G. Lunsford-IRA
    640       *  
Michael J. Suttman-Personal Portfolio
    620       *  
Michael Lipson-IRA
    190       *  
Milo Noble-Personal Portfolio
    3,690       *  
Minnesota Mining & Manufacturing Company
    184,300       *  
Monte R. Black-Personal Portfolio
    5,380       *  
Morgan Stanley Arbitrage Value Fund
    450,000       1.26 %
Mulholland Fund, L.P. 
    25,000       *  
Munder Micro-Cap Equity Fund
    144,000       *  
Neal L. & Kandythe J. Miller-Joint Personal Portfolio
    560       *  
Neal L. Miller-IRA Rollover
    270       *  
Neelam Idnani Julian
    7,500       *  
Northwestern Mutual Life Insurance
    1,775,714       4.99 %
Ospraie Portfolio Ltd
    1,100,000       3.09 %
OZ Master Fund, Ltd. 
    527,464       1.48 %
Pam Graeser-Personal Portfolio
    430       *  
Parsons, Thomas B. -
    1,000       *  
Passport Master Fund II, LP
    176,000       *  
Passport Master Fund, LP
    224,000       *  
Patricia A. Kremer Revocable Trust -DTD 4/29/04-Donald G. Kremer, TTEE
    1,250       *  
Patricia Meyer Dorn-Personal Portfolio
    2,800       *  

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        Percentage of
    Number of Shares of   Common
    Common Stock That   Stock
Selling Stockholder   May Be Sold   Outstanding
         
Paul R. & Dina E. Cmkovich-Joint Personal Portfolio
    4,750       *  
Paul S. & Cynthia J. Guthrie-Joint Personal Portfolio
    1,530       *  
Paul S. Guthrie-IRA
    130       *  
Paul W. Nordt III-IRA Rollover
    80       *  
Paul W. Nordt III-IRA Rollover — 401(k)
    1,390       *  
Peck Family Investments, Ltd. 
    1,090       *  
Perennial Partners LP
    250,000       *  
Peter D. Senkiw-Revocable Living Trust DTD 11/02/98-Peter D. Senkiw, TTEE
    320       *  
Peter McInnes-IRA Rollover
    8,800       *  
Peter R. Newman-IRA Rollover
    2,430       *  
Philip M. Haisley-IRA Rollover
    330       *  
Precept Capital Master Fund, G.P
    20,000       *  
Presidio Partners
    127,500       *  
Prism Partners I, L.P. 
    107,143       *  
Prism Partners II Offshore Fund
    42,857       *  
Prism Partners III Leveraged L.P. 
    128,571       *  
Prism Partners IV Leveraged Offshore Fund
    150,000       *  
Producers-Writers Guild of America
    11,700       *  
Raymond W. Lane-Personal Portfolio
    1,700          
Raytheon Combined DB/ DC Master Trust
    30,800       *  
Raytheon Company Combined DB/ DC Master Trust
    23,000       *  
Raytheon Master Pension Trust
    96,100       *  
Rebecca A. Nelson-IRA Rollover
    1,200       *  
Renee D. Ciferri-IRA Rollover
    410       *  
Richard D. Smith-Personal Portfolio
    1,300       *  
Richard H. LeSourd, Jr.-IRA — SEP
    1,200       *  
RNR II, LP
    360,400       1.01 %
RNR III, LP
    73,900       *  
RNR III (Offshore) Ltd. 
    27,700       *  
Robert A. Riley Beneficiary-Inherited IRA
    1,390       *  
Robert A. Riley-Revocable Family Trust DTD 5/8/97-Robert A. Riley TTEE
    380       *  
Robert F. Mays Trust-DTD 12/7/95-Robert F. Mays TTEE
    1,470       *  
Robert N. Sturwold-Personal Portfolio
    520       *  
Robert W. Lowry-Personal Portfolio
    2,020       *  
Ronald Lee Devore MD & Duneen Lynn Devore-JTWROS
    270       *  
Rosemary Winner Wood-IRA
    650       *  
Ruth E. Kremer Revocable Living Trust-DTD 5/7/96-David R. Kremer & Ruth E. Kremer, TTEES
    830       *  
SAB Capital Partners, LP
    430,000       1.20 %
SAB Overseas Master Fund, LP
    570,000       1.60 %
Sandra E. Nischwitz-Personal Portfolio
    1,240          
Savannah International Longshoremen’s Association Employers Pension Trust
    10,200       *  
Seneca Capital International Ltd
    451,700       1.27 %
Seneca Capital LP
    273,300       *  
SF Capital Partners Ltd
    500,000       1.40 %
Sharon A. Lowry-IRA-Robert W. Lowry, POA
    1,560       *  

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        Percentage of
    Number of Shares of   Common
    Common Stock That   Stock
Selling Stockholder   May Be Sold   Outstanding
         
Sisters of St. Joseph Carondelet
    4,700       *  
Slovin, Bruce
    10,000       *  
Sniper Fund
    3,300       *  
Sound Energy Capital Offshore Fund, Ltd. 
    41,900       *  
Southport Energy Plus Offshore Fund, Inc. 
    139,300       *  
Southport Energy Plus Partners L.P. 
    318,800       *  
Spring Street Partners L.P. 
    10,000       *  
SRI Fund, L.P. 
    22,856       *  
Stanley J. Katz-IRA
    350          
State Street Research Energy & Natural Resources Hedge Fund LLC
    147,300       *  
Steamfitters
    1,745       *  
Steven & Victoria Conover-Joint Personal Portfolio
    470       *  
Susan J. Gagnon-Revocable Living Trust UA 8/30/95-Susan J. Gagnon TTEE
    2,100       *  
Talkot Crossover Fund, L.P. 
    55,000       *  
Tanya P. Hrinyo Pavlina-Revocable Trust DTD 11/21/95-Tanya P. Hrinyo Pavlina TTEE
    1,200       *  
Tetra Capital Partners, LP
    15,000       *  
The Anderson Family-Revocable Trust, DTD 09/23/02-J. Kendall & Tamera L. Anderson, TTEES
    1,740       *  
The Catalyst Fund Offshore, Ltd. 
    3,242       *  
The Charles T. Walsh Trust-DTD 12/6/2000-Charles T
               
Walsh TTEE
    2,500       *  
The Johnson Irrevocable Living Trust
    10,000       *  
The Louis J. Thomas-Irrevocable Trust DTD 12/6/2000-Gregory J. Thomas, TTEE
    530       *  
Thomas L. Hausfeld-IRA
    250       *  
Thomas V. & Charlotte E. Moon Family Trust-Joint Personal Trust
    740       *  
Timothy A. Pazyniak-IRA Rollover
    2,830       *  
Timothy J. and Karen A. Beach-JTWROS
    460       *  
Tinicum Partners, L.P. 
    3,600       *  
TNM Investments LTD-Partnership
    310       *  
Town of Darien Employee Pension
    3,300       *  
Town of Darien Police Pension
    2,900       *  
TPG-Axon Partners (Offshore), Ltd
    812,500       2.28 %
TPG-Axon Partners, LP
    437,500       1.23 %
Treaty Oak Ironwood
    74,295       *  
Treaty Oak Master Fund
    59,235       *  
Tumbleston-JTWROS
    1,890       *  
Turnberry Asset Management
    10,000       *  
United Capital Management
    17,000       *  
University of Richmond Endowment Fund
    10,400       *  
University of Southern California Endowment Fund
    23,000       *  
Variable Insurance Products Fund II: Contrafund Portfolio(2)
    527,600       1.48 %
Verizon
    122,700       *  
Verle McGillivray-IRA Rollover
    680       *  
Victoire Finance Capital LLC
    35,714       *  

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        Percentage of
    Number of Shares of   Common
    Common Stock That   Stock
Selling Stockholder   May Be Sold   Outstanding
         
Virginia & Edward O’Neil JTWROS
    1,650       *  
Walter A. Mauck-IRA Rollover
    870       *  
Warren Foundation
    25,000       *  
Wildlife Conservation Society
    5,800       *  
William J. Turner Revocable Living Trust-DTD 05/20/98 Schwab Account-William J. Turner, TTEE
    570       *  
William U. Warren Fund K
    25,000       *  
York Capital Management, L.P. 
    101,266       *  
York Credit Opportunities Fund L.P. 
    97,046       *  
York Global Value Partners, L.P. 
    122,363       *  
York Investment Limited
    451,476       1.27 %
York Select Unit Trust
    103,376       *  
York Select, L.P. 
    124,473       *  
Yvette Van de Grift-Personal Portfolio
    220       *  
Zelin, Leonard IRA
    40,000       *  
 
  * Less than 1%.
(1)  Following our merger in March 2004, but prior to our recent private equity placement in March 2005, MEI Acquisitions Holdings, LLC, an affiliate of ACON E&P, LLC, was our sole stockholder. At the time of the private equity placement, MEI Acquisitions Holdings, LLC was managed by a board of managers consisting of four of our directors, Messrs. Ginns, Aronson, Lapeyre and Leuschen and two of our former directors, Messrs. Beard and Lancaster. See “Certain Transactions with Affiliates and Management.”
 
(2)  The entity is a registered investment fund (the “Fund”) advised by Fidelity Management & Research Company (“FMR Co.”), a registered investment adviser under the Investment Advisers Act of 1940, as amended. FMR Co., 82 Devonshire Street, Boston, Massachusetts 02109, a wholly owned subsidiary of FMR Corp. and an investment adviser registered under Section 203 of the Investment Advisers Act of 1940, is the beneficial owner of 4,330,800 shares of the common stock outstanding of the Company as a result of acting as investment adviser to various investment companies registered under Section 8 of the Investment Company Act of 1940.
  Edward C. Johnson 3d, FMR Corp., through its control of FMR Co., and the Fund each has sole power to dispose of the securities owned by the Fund.
 
  Neither FMR Corp. nor Edward C. Johnson 3d, Chairman of FMR Corp., has the sole power to vote or direct the voting of the shares owned directly by the Fund, which power resides with the Fund’s Board of Trustees.
 
  The Fund is an affiliate of a broker-dealer. The Fund purchased the shares in the ordinary course of business and, at the time of the purchase of the shares to be resold, the Fund did not have any agreements or understandings, directly or indirectly, with any person to distribute the shares.
(3)  Shares indicated as owned by the entity are owned directly by various private investment accounts, primarily employee benefit plans for which Fidelity Management Trust Company (“FMTC”) serves as trustee or managing agent. FMTC is a wholly owned subsidiary of FMR Corp. and a bank as defined in Section 3(a)(6) of the Securities Exchange Act of 1934, as amended. FMTC is the beneficial owner of 4,400 shares of the common stock of the Company as a result of its serving as investment manager of the institutional account(s).
  Edward C. Johnson 3d and FMR Corp., through its control of Fidelity Management Trust Company, each has sole dispositive power over 4,400 shares and sole power to vote or to direct the voting of 4,400 shares of common stock owned by the institutional account(s) as reported above.

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PLAN OF DISTRIBUTION
      We are registering the common stock covered by this prospectus to permit selling stockholders to conduct public secondary trading of these shares from time to time after the date of this prospectus. Under the Registration Rights Agreement we entered into with selling stockholders, we agreed to, among other things, bear all expenses, other than brokers’ or underwriters’ discounts and commissions, in connection with the registration and sale of the common stock covered by this prospectus. We will not receive any of the proceeds of the sale of the common stock offered by this prospectus. The aggregate proceeds to the selling stockholders from the sale of the common stock will be the purchase price of the common stock less any discounts and commissions. A selling stockholder reserves the right to accept and, together with their agents, to reject, any proposed purchases of common stock to be made directly or through agents.
      The common stock offered by this prospectus may be sold from time to time to purchasers:
  directly by the selling stockholders and their successors, which includes their donees, pledgees or transferees or their successors-in-interest, or
 
  through underwriters, broker-dealers or agents, who may receive compensation in the form of discounts, commissions or agent’s commissions from the selling stockholders or the purchasers of the common stock. These discounts, concessions or commissions may be in excess of those customary in the types of transactions involved.
      The selling stockholders and any underwriters, broker-dealers or agents who participate in the sale or distribution of the common stock may be deemed to be “underwriters” within the meaning of the Securities Act. The selling stockholders identified as registered broker-dealers in the selling stockholders table above (under “Selling Stockholders”) are deemed to be underwriters. As a result, any profits on the sale of the common stock by such selling stockholders and any discounts, commissions or agent’s commissions or concessions received by any such broker-dealer or agents may be deemed to be underwriting discounts and commissions under the Securities Act. Selling stockholders who are deemed to be “underwriters” within the meaning of Section 2(11) of the Securities Act will be subject to prospectus delivery requirements of the Securities Act. Underwriters are subject to certain statutory liabilities, including, but not limited to, Sections 11, 12 and 17 of the Securities Act.
      The common stock may be sold in one or more transactions at:
  fixed prices;
 
  prevailing market prices at the time of sale;
 
  prices related to such prevailing market prices;
 
  varying prices determined at the time of sale; or
 
  negotiated prices.
      These sales may be effected in one or more transactions:
  on any national securities exchange or quotation on which the common stock may be listed or quoted at the time of the sale;
 
  in the over-the-counter market;
 
  in transactions other than on such exchanges or services or in the over-the-counter market;
 
  through the writing of options (including the issuance by the selling stockholders of derivative securities), whether the options or such other derivative securities are listed on an options exchange or otherwise;
 
  through the settlement of short sales; or
 
  through any combination of the foregoing.

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      These transactions may include block transactions or crosses. Crosses are transactions in which the same broker acts as an agent on both sides of the trade.
      In connection with the sales of the common stock, the selling stockholders may enter into hedging transactions with broker-dealers or other financial institutions which in turn may:
  engage in short sales of the common stock in the course of hedging their positions;
 
  sell the common stock short and deliver the common stock to close out short positions;
 
  loan or pledge the common stock to broker-dealers or other financial institutions that in turn may sell the common stock;
 
  enter into option or other transactions with broker-dealers or other financial institutions that require the delivery to the broker-dealer or other financial institution of the common stock, which the broker-dealer or other financial institution may resell under the prospectus; or
 
  enter into transactions in which a broker-dealer makes purchases as a principal for resale for its own account or through other types of transactions.
      To our knowledge, there are currently no plans, arrangements or understandings between any selling stockholders and any underwriter, broker-dealer or agent regarding the sale of the common stock by the selling stockholders.
      We have applied to list our common stock on The Nasdaq Stock Market under the symbol MRNR. However, we can give no assurances as to the development of liquidity or any trading market for the common stock.
      There can be no assurance that any selling stockholder will sell any or all of the common stock under this prospectus. Further, we cannot assure you that any such selling stockholder will not transfer, devise or gift the common stock by other means not described in this prospectus. In addition, any common stock covered by this prospectus that qualifies for sale under Rule 144 or Rule 144A of the Securities Act may be sold under Rule 144 or Rule 144A rather than under this prospectus. The common stock covered by this prospectus may also be sold to non-U.S. persons outside the U.S. in accordance with Regulation S under the Securities Act rather than under this prospectus. The common stock may be sold in some states only through registered or licensed brokers or dealers. In addition, in some states the common stock may not be sold unless it has been registered or qualified for sale or an exemption from registration or qualification is available and complied with.
      The selling stockholders and any other person participating in the sale of the common stock will be subject to the Exchange Act. The Exchange Act rules include, without limitation, Regulation M, which may limit the timing of purchases and sales of any of the common stock by the selling stockholders and any other such person. In addition, Regulation M may restrict the ability of any person engaged in the distribution of the common stock to engage in market-making activities with respect to the particular common stock being distributed. This may affect the marketability of the common stock and the ability of any person or entity to engage in market-making activities with respect to the common stock.
      We have agreed to indemnify the selling stockholders against certain liabilities, including liabilities under the Securities Act.
      We have agreed to pay substantially all of the expenses incidental to the registration, offering and sale of the common stock to the public, including the payment of federal securities law and state blue sky registration fees, except that we will not bear any underwriting discounts or commissions o