Edgar Filing: MARINER ENERGY INC

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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

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.

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

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.

TABLE OF CONTENTS


WHERE YOU CAN FIND INFORMATION			i
SUMMARY			1
RISK FACTORS			8
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS			17
USE OF PROCEEDS			18
CAPITALIZATION			18
DILUTION			19
DIVIDEND POLICY			19
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA			20
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			23
BUSINESS			42
MANAGEMENT			59
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			69
CERTAIN TRANSACTIONS WITH AFFILIATES AND MANAGEMENT			70
SELLING STOCKHOLDERS			70
PLAN OF DISTRIBUTION			80
DESCRIPTION OF CAPITAL STOCK			82
REGISTRATION RIGHTS			86
LEGAL MATTERS			88
EXPERTS			88
GLOSSARY OF OIL AND NATURAL GAS TERMS			89
INDEX TO FINANCIAL STATEMENTS			F-1
REPORT OF RYDER SCOTT COMPANY, L.P., INDEPENDENT PETROLEUM ENGINEERS			A-1
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.

(i)

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.

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.

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.

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


		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

(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.

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.

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

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.


	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;


	•	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

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

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

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.

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.


	*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.”

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.

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.

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.”

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


		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


	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.

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

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.

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

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.


	*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

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.

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.

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

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.


	*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

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

$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.

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

December 31,

Year Ended

March 3, 2004 to

January 1, 2004 to

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

December 31,

Year Ended

March 3, 2004 to

January 1, 2004 to

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

December 31,

Year Ended

March 3, 2004 to

January 1, 2004 to

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.

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)


								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.

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.


	*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.

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.

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.”

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

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,

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%.


	*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

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.

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.

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

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


(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

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.

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.

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.


	*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.

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

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

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.

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.

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

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

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

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.

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


	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

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

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.

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.

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.

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.

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

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		*


			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		*


			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		*


			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		*


			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		*


			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		*


			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		*


			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		*


			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.

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.

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 or transfer taxes relating to the sale of shares of our common stock.

DESCRIPTION OF CAPITAL STOCK

The authorized capital stock of Mariner consists of 70 million shares of common stock, par value of $.0001 each, and 20 million shares of preferred stock, par value of $.0001 each.

The following summary of the capital stock and certificate of incorporation and bylaws of Mariner does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to our certificate of incorporation and bylaws.

Common Stock

There are a total of 35,615,400 shares of our common stock outstanding, including 2,267,270 shares of restricted stock issued to employees pursuant to our Equity Participation Plan. In addition, our board of directors has reserved 2,000,000 shares for issuance upon the exercise of stock options granted or that may be granted under our Stock Incentive Plan, approximately 798,960 of which have been granted to certain of our employees. Holders of our common or restricted stock are entitled to one vote for each share held on all matters submitted to a vote of stockholders and do not have cumulative voting rights. Holders of a majority of the shares of our common stock entitled to vote in any election of directors may elect all of the directors standing for election. Except as otherwise provided in our certificate of incorporation and bylaws or required by law, all matters to be voted on by our stockholders must be approved by a majority of the votes entitled to be cast by all shares of common stock. Our certificate of incorporation requires approval of 80% of the shares entitled to vote for the removal of a director or to adopt, repeal or amend certain provisions in our certificate of incorporation and bylaws. See “— Anti-Takeover Effects of Provisions of Delaware Law, Our Certificate of Incorporation and Bylaws”.

Holders of our common stock are entitled to receive proportionately any dividends if and when such dividends are declared by our board of directors, subject to any preferential dividend rights of outstanding preferred stock. Upon liquidation, dissolution or winding up of our company, the holders of our common stock are entitled to receive ratably our net assets available after the payment of all debts and other liabilities and subject to the prior rights of any outstanding preferred stock. Holders of our common stock have no preemptive, subscription, redemption or conversion rights. The rights, preferences and privileges of holders of our common stock are subject to, and may be adversely affected by, the rights of the holders of shares of any series of preferred stock that we may designate and issue in the future.

Liability and Indemnification of Officers and Directors

Our certificate of incorporation provides that our directors will not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability (1) for any breach of a director’s duty of loyalty to us or our stockholders, (2) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (3) under Section 174 of the Delaware General Corporation Law, or (4) for any transaction from which the director derives an improper personal benefit. If the Delaware General Corporation Law is amended to authorize the further elimination or limitation of directors’ liability, then the liability of our directors will automatically be limited to the fullest extent provided by law. Our certificate of incorporation and bylaws also contain provisions to indemnify our directors and officers to the fullest extent permitted by the Delaware General Corporation Law. These provisions may have the practical effect in certain cases of eliminating the ability of stockholders to collect monetary damages from our directors and officers. We believe that these contractual agreements and the provisions in our certificate of incorporation and bylaws are necessary to attract and retain qualified persons as directors and officers.

Preferred Stock

Our certificate of incorporation authorizes the issuance of up to 20 million shares of preferred stock and no preferred shares are outstanding. The preferred stock may carry such relative rights, preferences and designations as may be determined by our board of directors in its sole discretion upon the issuance of any shares of preferred stock. The shares of preferred stock could be issued from time to time by the

board of directors in its sole discretion (without further approval or authorization by the stockholders), in one or more series, each of which series could have any particular distinctive designations as well as relative rights and preferences as determined by the board of directors. The existence of authorized but unissued shares of preferred stock could have anti-takeover effects because we could issue preferred stock with special dividend or voting rights that could discourage potential bidders.

Approval by the stockholders of the authorization of the preferred stock gave the board of directors the ability, without stockholder approval, to issue these shares with rights and preferences determined by the board of directors in the future. As a result, the Company may issue shares of preferred stock that have dividend, voting and other rights superior to those of the common stock, or that convert into shares of common stock, without the approval of the holders of common stock. This could result in the dilution of the voting rights, ownership and liquidation value of current stockholders.

Anti-Takeover Effects of Provisions of Delaware Law, Our Certificate of Incorporation and Bylaws


	*General*

Our certificate of incorporation and bylaws contain the following additional provisions, some of which are intended to enhance the likelihood of continuity and stability in the composition of our board of directors and in the policies formulated by our board of directors. In addition, some provisions of the Delaware General Corporation Law, if applicable to us, may hinder or delay an attempted takeover without prior approval of our board of directors. Provisions of the Delaware General Corporation Law and of our certificate of incorporation and bylaws could discourage attempts to acquire us or remove incumbent management even if some or a majority of our stockholders believe this action is in their best interest. These provisions could, therefore, prevent stockholders from receiving a premium over the market price for the shares of common stock they hold.


	*Classified Board*

Our certificate of incorporation provides that our board of directors will be divided into three classes of directors, with the classes to be as nearly equal in number as possible. As a result, approximately one-third of our board of directors will be elected each year. The classification of directors will have the effect of making it more difficult for stockholders to change the composition of our board of directors. Our certificate of incorporation and bylaws provide that the number of directors will be fixed from time to time exclusively pursuant to a resolution adopted by the board of directors.


	*Filling Board of Directors Vacancies; Removal*

Our certificate of incorporation provides that vacancies and newly created directorships resulting from any increase in the authorized number of directors may be filled by the affirmative vote of a majority of our directors then in office, though less than a quorum. Each director will hold office until his or her successor is elected and qualified, or until the director’s earlier death, resignation, retirement or removal from office. Any director may resign at any time upon written notice to us. Our certificate of incorporation provides, in accordance with Delaware General Corporation Law, that the stockholders may remove directors only by a super-majority vote and for cause. We believe that the removal of directors by the stockholders only for cause, together with the classification of the board of directors, will promote continuity and stability in our management and policies and that this continuity and stability will facilitate long-range planning.


	*No Stockholder Action by Written Consent*

Our certificate of incorporation precludes stockholders from initiating or effecting any action by written consent and thereby taking actions opposed by the board of directors.


	*Call of Special Meetings*

Our bylaws provide that special meetings of our stockholders may be called at any time only by the board of directors acting pursuant to a resolution adopted by the board and not the stockholders.


	*Advanced Notice Requirements for Stockholder Proposals and Director Nominations*

Our bylaws provide that stockholders seeking to bring business before or to nominate candidates for election as directors at an annual meeting of stockholders must provide timely notice of their proposal in writing to the corporate secretary. With respect to the nomination of directors, to be timely, a stockholder’s notice must be delivered to or mailed and received at our principal executive offices (i) with respect to an election of directors to be held at the annual meeting of stockholders, not later than 120 days prior to the anniversary date of the proxy statement for the immediately preceding annual meeting of the stockholders and (ii) with respect to an election of directors to be held at a special meeting of stockholders, not later than the close of business on the 10th day following the day on which such notice of the date of the special meeting was first mailed to the Company’s stockholders or public disclosure of the date of the special meeting was first made, whichever first occurs. With respect to other business to be brought before a meeting of stockholders, to be timely, a stockholder’s notice must be delivered to or mailed and received at our principal executive offices not less than 120 days prior to the anniversary date of the proxy statement for the immediately preceding annual meeting of the stockholders. Our bylaws also specify requirements as to the form and content of a stockholder’s notice. These provisions may preclude stockholders from bringing matters before an annual meeting of stockholders or from making nominations for directors at an annual meeting of stockholders or may discourage or defer a potential acquirer from conducting a solicitation of proxies to elect its own slate of directors or otherwise attempting to obtain control of us.


	*No Cumulative Voting*

The Delaware General Corporation Law provides that stockholders are not entitled to the right to cumulate votes in the election of directors unless our certificate of incorporation provides otherwise. Under cumulative voting, a majority stockholder holding a sufficient percentage of a class of shares may be able to ensure the election of one or more directors. Our certificate of incorporation expressly precludes cumulative voting.


	*Authorized but Unissued Shares*

Our certificate of incorporation provides that the authorized but unissued shares of preferred stock are available for future issuance without stockholder approval and does not preclude the future issuance without stockholder approval of the authorized but unissued shares of our common stock. These additional shares may be utilized for a variety of corporate purposes, including future public offerings to raise additional capital, corporate acquisitions and employee benefit plans. The existence of authorized but unissued shares of common stock and preferred stock could make it more difficult or discourage an attempt to obtain control of the Company by means of a proxy contest, tender offer, merger or otherwise.


	*Delaware Business Opportunity Statute*

As permitted by Section 122(17) of the Delaware General Corporation Law, our certificate of incorporation provides that the Company renounces any interest or expectancy in any business opportunity or transaction in which any of our original institutional investors or their affiliates participate or seek to participate. Nothing contained in our certificate of incorporation, however, is intended to change any obligation or duty that a director may have with respect to confidential information of the Company or prohibit the Company from pursuing any corporate opportunity.


	*Amendments to our Certificate of Incorporation and Bylaws*

Pursuant to the Delaware General Corporation Law and our certificate of incorporation, certain anti-takeover provisions of our certificate of incorporation may not be repealed or amended, in whole or in part, without the approval of at least 80% of the outstanding stock entitled to vote.

Our certificate of incorporation permits our board of directors to adopt, amend and repeal our bylaws. Our certificate of incorporation also provides that our bylaws can be amended by the affirmative vote of the holders of at least 80% of the voting power of the outstanding shares of our common stock.


	*Delaware Anti-Takeover Statute*

We are subject to Section 203 of the Delaware General Corporation Law, an anti-takeover law. In general, this section prevents certain Delaware companies under certain circumstances, from engaging in a “business combination” with (1) a stockholder who owns 15% or more of our outstanding voting stock (otherwise known as an “interested stockholder”); (2) an affiliate of an interested stockholder; or (3) an associate of an interested stockholder, for three years following the date that the stockholder became an “interested stockholder.” A “business combination” includes a merger or sale of 10% or more of our assets.

Transfer Agent and Registrar

Our transfer agent and registrar for our common stock is The Continental Stock Transfer & Trust Company.

REGISTRATION RIGHTS

We entered into a registration rights agreement in connection with our recent private equity placement in March 2005. In the registration rights agreement we agreed, for the benefit of FBR, the purchasers of our common stock in the private equity placement, MEI Acquisitions Holdings, LLC and holders of the common stock issued under our Equity Participation Plan or Stock Incentive Plan, that we will, at our expense:


	•	file with the SEC (which occurs pursuant to the filing of the shelf registration statement of which this prospectus is a part), within 210 days after the closing date of the private equity placement, a registration statement (a “shelf registration statement”);

	•	use our commercially reasonable efforts to cause the shelf registration statement to become effective under the Securities Act as soon as practicable after the filing;

	•	continuously maintain the effectiveness of the shelf registration statement under the Securities Act until the first to occur of:


	•	the sale of all of the shares of common stock covered by the shelf registration statement pursuant to a registration statement;

	•	the sale, transfer or other disposition of all of the shares of common stock covered by the shelf registration statement or pursuant to Rule 144 under the Securities Act;

	•	such time as all of the shares of our common stock sold in this offering and covered by the shelf registration statement and not held by affiliates of us are, in the opinion of our counsel, eligible for sale pursuant to Rule 144(k) (or any successor or analogous rule) under the Securities Act;

	•	the shares have been sold to us or any of our subsidiaries; or

	•	the second anniversary of the initial effective date of the shelf registration statement.

We have filed the registration statement of which this prospectus is a part to satisfy our obligations under the registration rights agreement.

Notwithstanding the foregoing, we will be permitted, under limited circumstances, to suspend the use, from time to time, of the shelf registration statement of which this is a part (and therefore suspend sales under the registration statement) for certain periods, referred to as “blackout periods,” if, among other things, any of the following occurs:


	•	the representative of the underwriters of an underwritten offering of primary shares by us has advised us that the sale of shares of our common stock under the shelf registration statement would have a material adverse effect on our initial public offering;

	•	a majority of our board of directors, in good faith, determines that (1) the offer or sale of any shares of our common stock would materially impede, delay or interfere with any proposed financing, offer or sale of securities, acquisition, merger, tender offer, business combination, corporate reorganization, consolidation or other significant transaction involving us; (2) after the advice of counsel, the sale of the shares covered by the shelf registration statement would require disclosure of non-public material information not otherwise required to be disclosed under applicable law; or (3) either (x) we have a bona fide business purpose for preserving the confidentiality of the proposed transaction, (y) disclosure would have a material adverse effect on us or our ability to consummate the proposed transaction, or (z) the proposed transaction renders us unable to comply with SEC requirements; or

	•	a majority of our board of directors, in good faith, determines, that we are required by law, rule or regulation to supplement the shelf registration statement or file a post-effective amendment to the shelf registration statement in order to incorporate information into the shelf registration statement for the purpose of (1) including in the shelf registration statement any prospectus required under Section 10(a)(3) of the Securities Act; (2) reflecting in the prospectus included in the shelf


		registration statement any facts or events arising after the effective date of the shelf registration statement (or the most-recent post-effective amendment) that, individually or in the aggregate, represents a fundamental change in the information set forth in the prospectus; or (3) including in the prospectus included in the shelf registration statement any material information with respect to the plan of distribution not disclosed in the shelf registration statement or any material change to such information.

The cumulative blackout periods in any 12 month period commencing on the closing of the private equity placement may not exceed an aggregate of 90 days and furthermore may not exceed 60 days in any 90-day period, except as a result of a review of any post-effective amendment by the SEC prior to declaring it effective; provided we have used all commercially reasonable efforts to cause such post-effective amendment to be declared effective.

In addition to this limited ability to suspend use of the shelf registration statement, until we are eligible to incorporate by reference into the registration statement our periodic and current reports, which will not occur until at least one year following the end of the month in which the registration statement of which this prospectus is a part is declared effective, we will be required to amend or supplement the shelf registration statement to include our quarterly and annual financial information and other developments material to us. Therefore, sales under the shelf registration statement will be suspended until the amendment or supplement, as the case may be, is filed and effective.

A holder that sells our common stock pursuant to the shelf registration statement will be required to be named as a selling stockholder in this prospectus, as it may be amended or supplemented from time to time, and to deliver a prospectus to purchasers, will be subject to certain of the civil liability provisions under the Securities Act in connection with such sales and will be bound by the provisions of the registration rights agreement that are applicable to such holder (including certain indemnification rights and obligations). In addition, each holder of our common stock must deliver information to be used in connection with the shelf registration statement in order to have such holder’s shares of our common stock included in the shelf registration statement.

Each holder will be deemed to have agreed that, upon receipt of notice of the occurrence of any event which makes a statement in the prospectus which is a part of the shelf registration statement untrue in any material respect or which requires the making of any changes in such prospectus in order to make the statements therein not misleading, or of certain other events specified in the registration rights agreement, such holder will suspend the sale of our common stock pursuant to such prospectus until we have amended or supplemented such prospectus to correct such misstatement or omission and have furnished copies of such amended or supplemented prospectus to such holder or we have given notice that the sale of the common stock may be resumed.

We have agreed to use our commercially reasonable efforts to satisfy the criteria for listing and list or include (if we meet the criteria for listing on such exchange or market) our common stock on the NYSE, American Stock Exchange or The Nasdaq National Market (as soon as practicable, including seeking to cure in our listing or inclusion application any deficiencies cited by the exchange or market), and thereafter maintain the listing on such exchange.

LEGAL MATTERS

The validity of the shares covered by this prospectus will be passed upon for us by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The consolidated financial statements of Mariner Energy, Inc. as of December 31, 2004 (Post-Merger), December 31, 2003 (Pre-Merger) and for the period from January 1, 2004 through March 2, 2004 (Pre-Merger), for the period from March 3, 2004 through December 31, 2004 (Post-Merger), and for each of the two years in the period ended December 31, 2003 included in this prospectus, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report (which report expresses an unqualified opinion and includes explanatory paragraphs relating to the adoption in 2003 of SFAS No. 143, “Accounting for Asset Retirement Obligations” and the merger in 2004 of the Company’s parent) included in this prospectus, and are included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

The information included in this prospectus regarding estimated quantities of proved reserves, the future net revenues from those reserves and their present value is based, in part, on estimates of the proved reserves and present values of proved reserves of the Company as of December 31, 2002, 2003 and 2004 and prepared by or derived from estimates prepared by Ryder Scott Company, L.P., independent petroleum engineers. Their report is included in this offering as Annex A. These estimates are included in this prospectus in reliance upon the authority of the firm as experts in these matters.

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and gas industry terms used in this prospectus. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definitions of those terms can be viewed on the website at http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.

3-D seismic. (Three-Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two dimensional seismic data.

Appraisal well. A well drilled several spacing locations away from a producing well to determine the boundaries or extent of a productive formation and to establish the existence of additional reserves.

bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

Bcf. Billion cubic feet of natural gas.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

Block. A block depicted on the Outer Continental Shelf Leasing and Official Protraction Diagrams issued by the U.S. Minerals Management Service or a similar depiction on official protraction or similar diagrams issued by a state bordering on the Gulf of Mexico.

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Deepwater. Depths greater than 1,300 feet (the approximate depth of deepwater designation for royalty purposes by the U.S. Minerals Management Service).

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

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

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Dry hole costs. Costs incurred in drilling a well, assuming a well is not successful, including plugging and abandonment costs.

Exploitation. Ordinarily considered to be a form of development within a known reservoir.

Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

Farm-in or farm-out. An agreement under which the owner of a working interest in an oil or gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

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

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

Mbbls. Thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. Thousand cubic feet of natural gas.

Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

MMBls. Million barrels of crude oil or other liquid hydrocarbons.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be.

Net revenue interest. An interest in all oil and natural gas produced and saved from, or attributable to, a particular property, net of all royalties, overriding royalties, net profits interests, carried interests, reversionary interests and any other burdens to which the person’s interest is subject.

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

PV10 or present value of estimated future net revenues. An estimate of the present value of the estimated future net revenues from proved oil and gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future net revenues are discounted at an annual rate of 10%, in accordance with the Securities and Exchange Commission’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the date indicated and held constant for the life of the reserves.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed non-producing reserves. Proved developed reserves expected to be recovered from zones behind casing in existing wells.

Proved developed producing reserves. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production to market.

Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

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

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Shelf. Areas in the Gulf of Mexico with depths less than 1,300 feet. Our shelf area and operations also includes a small amount of properties and operations in the onshore and bay areas of the Gulf Coast.

Subsea tieback. A method of completing a productive well by connecting its wellhead equipment located on the sea floor by means of control umbilical and flow lines to an existing production platform located in the vicinity.

Subsea trees. Wellhead equipment installed on the ocean floor.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether or not such acreage contains proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

INDEX TO FINANCIAL STATEMENTS


Report of Independent Registered Public Accounting Firm			F-2
Balance Sheets at March 31, 2005 (unaudited), December 31, 2004 and 2003			F-3
Statements of Operations for the three months ended March 31, 2005 (unaudited); the period from March 3, 2004 through March 31, 2004 (unaudited); the period from January 1, 2004 through March 2, 2004; the period from March 3, 2004 through December 31, 2004; and the years ended December 31, 2003 and 2002			F-4
Statements of Stockholder’s Equity and Comprehensive Income for the three months ended March 31, 2005 (unaudited); the period from January 1, 2004 through March 2, 2004; the period from March 3, 2004 through December 31, 2004; and the years ended December 31, 2003 and 2002			F-5
Statements of Cash Flows for the three months ended March 31, 2005 (unaudited); the period from March 3, 2004 through March 31, 2004 (unaudited); the period from January 1, 2004 through March 2, 2004; the period from March 3, 2004 through December 31, 2004; and the years ended December 31, 2003 and 2002			F-7
Notes to the Financial Statements			F-8

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholder

Mariner Energy, Inc.

Houston, Texas

We have audited the accompanying balance sheets of Mariner Energy, Inc. (the “Company”) as of December 31, 2004 (Post-merger) and December 31, 2003 (Pre-merger) and the related statements of operations, stockholder’s equity and comprehensive income and cash flows for the period from January 1, 2004 through March 2, 2004 (Pre-merger), for the period from March 3, 2004 through December 31, 2004 (Post merger), and for each of the two years in the period ended December 31, 2003 (Pre-merger). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Mariner Energy, Inc. as of December 31, 2004 (Post-merger) and December 31, 2003 (Pre-merger), and the results of its operations and cash flows for the period from January 1, 2004 through March 2, 2004 (Pre-merger), for the period from March 3, 2004 through December 31, 2004 (Post-merger), and for each of the two years in the period ended December 31, 2003 (Pre-merger) in conformity with accounting principles generally accepted in the United States of America.

The Company changed its method of accounting for asset retirement obligations in 2003. This change is discussed in Note 1 to the financial statements.

As described in Note 1 to the consolidated financial statements, on March 2, 2004, Mariner Energy LLC, the Company’s parent company, merged with an affiliate of the private equity funds Carlyle/ Riverstone Global Energy and Power Fund II, L.P. and ACON Investments LLC.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

May 11, 2005

F-2

MARINER ENERGY, INC.

BALANCE SHEETS


				Post-Merger						Pre-Merger

				March 31,			December 31,			December 31,
				2005			2004			2003

				(unaudited)
							(in thousands except
							share data)
Current Assets:
	Cash and cash equivalents			$	1,478		$	2,541		$	60,174
	Restricted cash				—			—			621
	Receivables				59,512			52,734			33,272
	Deferred tax asset				16,275			—			—
	Prepaid expenses and other				10,797			10,471			9,014

			Total current assets		88,062			65,746			103,081
Property and Equipment:
	Oil and gas properties, full cost method:
		Proved			354,335			319,553			599,762
		Unproved, not subject to amortization			40,583			36,245			36,619

			Total		394,918			355,798			636,381
	Other property and equipment				1,033			960			5,651
	Accumulated depreciation, depletion and amortization				(67,609	)		(52,985	)		(434,160	)

			Total property and equipment, net		328,342			303,773			207,872
Deferred Tax Asset					—			3,029			—
Other Assets, Net of Amortization					2,363			3,471			1,151

			TOTAL ASSETS	$	418,767		$	376,019		$	312,104


LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
	Accounts payable			$	8,269		$	2,526		$	28,640
	Accrued liabilities				90,747			81,831			35,486
	Accrued interest				317			79			—
	Derivative liability				41,715			16,976			2,464

			Total current liabilities		141,048			101,412			66,590
Long-Term Liabilities:
	Abandonment liability				20,544			19,268			15,027
	Taxes payable to parent company				—			—			5,664
	Deferred income tax				5,227			—			4,769
	Derivative liability				14,788			5,432			1,897
	Bank debt				55,000			105,000			—
	Note payable				4,000			10,000			—
	Other long-term liabilities				—			1,000			—

			Total long-term liabilities		99,559			140,700			27,357
Stockholder’s Equity:
	Common stock, $.0001 par value; 70,000,000 shares authorized, issued and outstanding, 35,615,400, 29,748,130 and 29,748,130 shares at March 31, 2005, December 31, 2004 and December 31, 2003, respectively				4			1			1
	Additional paid-in-capital				171,876			91,917			227,318
	Unearned compensation				(30,419	)		—			—
	Accumulated other comprehensive (loss)				(34,695	)		(11,630	)		(4,360	)
	Accumulated retained earnings (deficit)				71,394			53,619			(4,802	)

			Total stockholder’s equity		178,160			133,907			218,157

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY				$	418,767		$	376,019		$	312,104

The accompanying notes are an integral part of these financial statements

F-3

MARINER ENERGY, INC.

STATEMENTS OF OPERATIONS


			Post-Merger						Pre-Merger			Post-Merger			Pre-Merger

						Period from			Period from			Period from			Period from
						March 3, 2004			January 1, 2004			March 3, 2004			January 1, 2004			Year Ended
			Three Months			through			through			through			through			December 31,
			Ended March 31,			March 31,			March 2,			December 31,			March 2,
			2005			2004			2004			2004			2004			2003			2002

			(unaudited)			(unaudited)
			(in thousands except per share data)
Revenues:
	Oil sales		$	19,084		$	6,887		$	12,709		$	63,498		$	12,709		$	37,992		$	38,792
	Gas sales			34,866			14,351			27,055			110,925			27,055			104,551			119,436
	Other revenues			1,857			—			—			—			—			—			—

		Total revenues		55,807			21,238			39,764			174,423			39,764			142,543			158,228

Costs and Expenses:
	Lease operating expense			6,159			3,126			4,121			21,363			4,121			24,719			26,076
	Transportation expense			990			672			1,070			1,959			1,070			6,252			10,480
	General and administrative expense			5,165			1,544			1,131			7,641			1,131			8,098			7,716
	Depreciation, depletion and amortization			15,129			6,230			10,630			54,281			10,630			48,339			70,821
	Derivative settlements			—			—			—			—			—			3,222			—
	Impairment of Enron-related receivables			—			—			—			—			—			—			3,234
	Impairment of production equipment held for use			—			—			—			957			—			—			—

		Total costs and expenses		27,443			11,572			16,952			86,201			16,952			90,630			118,327

OPERATING INCOME				28,364			9,666			22,812			88,222			22,812			51,913			39,901
Interest:
	Income			514			20			91			225			91			756			390
	Expense, net of amounts capitalized			(1,832	)		(660	)		(5	)		(6,045	)		(5	)		(6,981	)		(10,298	)

Income before taxes				27,046			9,026			22,898			82,402			22,898			45,688			29,993
Provision for income taxes				(9,271	)		(3,093	)		(8,072	)		(28,783	)		(8,072	)		(9,387	)		—

Income before cumulative effect of change in accounting method, net of tax effects				17,775			5,933			14,826			53,619			14,826			36,301			29,993
Cumulative effect of change in accounting method, net of tax effects				—			—			—			—			—			1,943			—

NET INCOME			$	17,775		$	5,933		$	14,826		$	53,619		$	14,826		$	38,244		$	29,993

Earnings per share:
Net income per share — basic
	Income before cumulative effect of change in accounting method, net of tax effects		$	0.58		$	0.20		$	.50		$	1.80		$	.50		$	1.22		$	1.01
	Cumulative effect of change in accounting method, net of tax effects			—			—			—			—			—			.07			—

	Income per share — basic		$	0.58		$	0.20		$	.50		$	1.80		$	.50		$	1.29		$	1.01

Net income per share — diluted
	Income before cumulative effect of change in accounting method, net of tax effects		$	0.58		$	0.20		$	.50		$	1.80		$	.50		$	1.22		$	1.01
	Cumulative effect of change in accounting method, net of tax effects			—			—			—			—			—			.07			—

	Income per share — diluted		$	0.58		$	0.20		$	.50		$	1.80		$	.50		$	1.29		$	1.01

Weighted average shares outstanding — basic				30,588,130			29,748,130			29,748,130			29,748,130			29,748,130			29,748,130			29,748,130
Weighted average shares outstanding — diluted				30,599,152			29,748,130			29,748,130			29,748,130			29,748,130			29,748,130			29,748,130

The accompanying notes are an integral part of these financial statements

F-4

MARINER ENERGY, INC.

STATEMENTS OF STOCKHOLDER’S EQUITY AND COMPREHENSIVE INCOME


												Accumulated			Accumulated
		Common Stock				Additional						Other			Retained			Total
						Paid-In			Unearned			Comprehensive			Earnings			Stockholder’s
		Shares		Amount		Capital			Compensation			Income (Loss)			(Deficit)			Equity

		(in thousands)
Balance at December 31, 2001			29,748	$	1	$	227,318			—		$	25,803		$	(73,039	)	$	180,083

	Net income		—		—		—			—			—			29,993			29,993
	Change in fair value of derivative hedging instruments		—		—		—			—			(17,105	)		—			(17,105	)
	Hedge settlements reclassified to income		—		—		—			—			(22,875	)		—			(22,875	)

	Total comprehensive income (loss)		—		—		—			—			—			—			(9,987	)

Balance at December 31, 2002			29,748	$	1	$	227,318			—		$	(14,177	)	$	(43,046	)	$	170,096

	Net income		—		—		—			—			—			38,244			38,244
	Change in fair value of derivative hedging instruments		—		—		—			—			39,280			—			39,280
	Hedge settlements reclassified to income		—		—		—			—			(29,463	)		—			(29,463	)
										—
	Total comprehensive income		—		—		—			—			—			—			48,061

Balance at December 31, 2003			29,748	$	1	$	227,318			—		$	(4,360	)	$	(4,802	)	$	218,157

Pre-Merger Net Income			—		—		—			—			—			14,826			14,826
	Change in fair value of derivative hedging instruments		—		—		—			—			(7,312	)		—			(7,312	)
	Hedge settlements reclassified to income		—		—		—			—			(745	)		—			(745	)

	Total comprehensive income		—		—		—			—			—			—			6,769

	Pre-Merger Balance at March 2, 2004		29,748	$	1	$	227,318			—		$	(12,417	)	$	10,024		$	224,926


Post-Merger
	Dividend		—		—		—			—			—			(166,432	)		(166,432	)
	Merger adjustments		—		—		(135,401	)		—			12,417			156,408			33,424

Balance at March 3, 2004			29,748	$	1	$	91,917			—		$	—		$	—		$	91,918

	Net income		—		—		—			—			—			53,619			53,619
	Change in fair value of derivative hedging instruments		—		—		—			—			(32,171	)		—			(32,171	)
	Hedge settlements reclassified to income		—		—		—			—			20,541			—			20,541

	Total comprehensive income		—		—		—			—			—			—			41,989

Balance at December 31, 2004			29,748	$	1	$	91,917			—		$	(11,630	)	$	53,619		$	133,907

	Common shares issued — private equity offering (unaudited)		3,600		2		45,161			—			—			—			45,163
	Common shares issued — restricted stock (unaudited)		2,267		1		31,741			(31,742	)		—			—			—
	Amortization restricted stock (unaudited)		—		—		—			1,323			—			—			1,323

F-5


											Accumulated			Accumulated
		Common Stock				Additional					Other			Retained		Total
						Paid-In		Unearned			Comprehensive			Earnings		Stockholder’s
		Shares		Amount		Capital		Compensation			Income (Loss)			(Deficit)		Equity

		(in thousands)
Contributed capital — Mariner Energy, LLC and Mariner Holdings, Inc. (unaudited)			—		—		3,057		—			—			—		3,057
Comprehensive Income:
	Net income (unaudited)		—		—		—		—			—			17,775		17,775
	Other comprehensive income (loss):
	Change in fair value of derivative hedging instruments (unaudited)		—		—		—		—			(26,922	)		—		(26,922	)
	Hedge settlements reclassified to income (unaudited)		—		—		—		—			3,857			—		3,857

	Total comprehensive income (unaudited)		—		—		—		—			—			—		(5,290	)

Balance at March 31, 2005 (unaudited)			35,615	$	4	$	171,876	$	(30,419	)	$	(34,695	)	$	71,394	$	178,160

The accompanying notes are an integral part of these financial statements

F-6

MARINER ENERGY, INC.

STATEMENTS OF CASH FLOWS


				Post-Merger						Pre-Merger			Post-Merger			Pre-Merger

							Period from			Period from			Period from			Period from
							March 3, 2004			January 1, 2004			March 3, 2004			January 1, 2004			Year Ended
				Three Months			through			through			through			through			December 31,
				Ended March 31,			March 31,			March 2,			December 31,			March 2,
				2005			2004			2004			2004			2004			2003			2002

				(unaudited)			(unaudited)
				(in thousands)
Operating Activities:
	Net income			$	17,775		$	5,933		$	14,826		$	53,619		$	14,826		$	38,244		$	29,993
	Adjustments to reconcile net loss to net cash provided by operating activities:
	Deferred income tax				11,050			3,093			8,072			27,162			8,072			—			—
	Depreciation, depletion and amortization				15,415			6,230			10,630			55,067			10,630			48,414			70,588
	Stock compensation expense				1,323			—			—			—			—			—			—
	Hedge activities				—			—			—			—			—			(2,030	)		(23,200	)
	Impairment of Enron-related receivables				—			—			—			—			—			—			3,234
	Impairment of production equipment held for use				—			—			—			957			—			—			—
	Loss on sale of fixed assets				—			—			—			—			—			—			69
	Cumulative effect of changes in accounting method				—			—			—			—			—			(2,988	)		—
	Changes in operating assets and liabilities:
		Receivables			(6,778	)		2,011			(8,847	)		(10,615	)		(8,847	)		(3,599	)		4,449
		Prepaid expenses and other			(327	)		501			551			(965	)		551			(2,257	)		3,249
		Other assets			—			(4,239	)		(963	)		321			(963	)		1,485			344
		Restricted cash			—			—			1			620			1			14,574			(15,195	)
		Accounts payable and accrued liabilities			10,494			(8,303	)		(3,974	)		9,697			(3,974	)		1,208			(13,256	)
		Taxes payable to parent company and deferred income tax			—			—			—			—			—			10,432			—

			Net cash provided by operating activities		48,952			5,226			20,296			135,863			20,296			103,483			60,275

Investing Activities:
	Additions to oil and gas properties				(42,002	)		(4,811	)		(15,264	)		(133,425	)		(15,264	)		(83,228	)		(105,360	)
	Proceeds from property conveyances				18			—			—			—			—			121,625			52,329
	Additions to other property and equipment				(73	)		—			(78	)		(172	)		(78	)		(50	)		(738	)

			Net cash (used) provided by investing activities		(42,057	)		(4,811	)		(15,342	)		(133,597	)		(15,342	)		38,347			(53,769	)

Financing Activities:
	Initial borrowings from revolving credit facility, net of fees				—			135,000			—			131,579			—			—			—
	Repayment of subordinated notes				—			—			—			—			—			(100,000	)		—
	Repayment of term note				(6,000	)		—			—			—			—			—			—
	Credit facility borrowings (repayments), net				(50,000	)		—			—			(30,000	)		—			—			—
	Proceeds from private equity offering				45,163			—			—			—			—			—			—
	Capital contribution from affiliates				2,879			—			—			—			—			—			—
	Dividend to Mariner Energy LLC				—			(166,165	)		—			(166,432	)		—			—			—

			Net cash used in financing activities		(7,958	)		(31,165	)		—			(64,853	)		—			(100,000	)		—

Increase (Decrease) in Cash and Cash Equivalents					(1,063	)		(30,750	)		4,954			(62,587	)		4,954			41,830			6,506
Cash and Cash Equivalents at Beginning of Period					2,541			65,128			60,174			65,128			60,174			18,344			11,838

Cash and Cash Equivalents at End of Period				$	1,478		$	34,378		$	65,128		$	2,541		$	65,128		$	60,174		$	18,344

The accompanying notes are an integral part of these financial statements

F-7

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS

For the Three Month Period Ended March 31, 2005 (Unaudited),

for the Period from March 3, 2004 through March 31, 2004 (Unaudited),

for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),

for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),

and For the Years Ended December 31, 2003 and 2002


1.	Summary of Significant Accounting Policies

Operations— Mariner Energy, Inc. (the “Company”) is 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.

Unaudited Interim Financial Statements— The accompanying unaudited consolidated financial statements as of March 31, 2005 and for the three months ended March 31, 2005 and the period from March 3, 2004 through March 31, 2004 have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and with Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. In the opinion of management, all material adjustments (consisting only of normal and recurring adjustments) necessary to present a fair statement of our financial position and results of operations for the interim periods included herein have been made, and the disclosures contained herein are adequate to make the information presented not misleading. Operating results for the three months ended March 31, 2005 are not necessarily indicative of the results that may be expected for the year ended December 31, 2005.

Organization— On March 2, 2004, Mariner Energy LLC, the parent company of Mariner Energy, Inc. (the “Company”), merged with a subsidiary of 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 (the “Merger”) (See Note 2). Prior to the Merger, Joint Energy Development Investments Limited Partnership (“JEDI”), which is an indirect wholly-owned subsidiary of Enron Corp. (“Enron”), owned approximately 96% of the common stock of Mariner Energy LLC (see Note 3). 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, JEDI no longer owns any interest in Mariner Energy LLC, and the Company is no longer affiliated with JEDI or Enron.

Simultaneously with the Merger, the Company obtained a revolving line of credit with initial advances of $135 million from a group of banks. The loan proceeds and an additional $31.2 million of Company funds distributed to Mariner Energy LLC were used to pay a portion of the gross Merger consideration (which included repayment of $197.6 million of Mariner Energy LLC debt outstanding at the time of the Merger) and estimated transaction costs and expenses associated with the Merger and bank financing. The Company also issued a $10 million note and assigned a fully reserved receivable valued at $1.9 million to Joint Energy Development Investments Limited Partnership (“JEDI”), an Enron Corp. affiliate and the majority owner of Mariner Energy LLC prior to the Merger, as part of JEDI’s Merger consideration. In addition, pursuant to the Merger agreement, JEDI has agreed to indemnify the Company from certain liabilities and the Company has agreed to pay additional Merger consideration contingent upon the outcome of a certain five well drilling program that was completed in the second quarter of 2004. In September 2004, the Company paid approximately $161,000 as additional Merger consideration related to the five well drilling program and the Company believes it has fully discharged its obligations thereunder.

F-8

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

The sources and uses of funds related to the Merger were as follows:


Mariner Energy, Inc. bank loan proceeds		$	135.0
Note payable issued by Mariner Energy, Inc. to former parent			10.0
Equity from new owners			100.0
Distributions from Mariner Energy, Inc.			31.2
Assignment by Mariner Energy, Inc. of receivables			1.9

	Total	$	278.1

Repayment of former parent debt obligation		$	197.6
Merger consideration to stockholders and warrant holders			73.5
Acquisition costs and other expenses			7.0

	Total	$	278.1

As a result of the change in control, accounting principles generally accepted in the United States requires the Merger and the resulting acquisition of Mariner Energy LLC by MEI Acquisitions Holdings, LLC to be accounted for as a purchase transaction in accordance with Statement of Financial Accounting Standards No. 141, “Business Combinations”. Staff Accounting bulletin No. 54 (“SAB 54”) requires the application of “push down accounting” in situations where the ownership of an entity has changed, meaning that the post-transaction financial statements of the Company reflect the new basis of accounting. Accordingly, the financial statements as of December 31, 2004 reflect the Company’s fair value basis resulting from the acquisition that has been pushed down to the Company. The aggregate purchase price has been allocated to the underlying assets and liabilities based upon the respective estimated fair values at March 2, 2004 (date of Merger). The allocation of the purchase price has been finalized. Carryover basis accounting applies for tax purposes. All financial information presented prior to March 2, 2004 represents the basis of accounting used by the pre-Merger entity. The period January 1, 2004-March 2, 2004 is referred to as 2004 Pre-Merger and the period March 3, 2004-December 31, 2004 is referred to as 2004 Post-Merger.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the March 2, 2004 acquisition:

ALLOCATION OF PURCHASE PRICE TO MARINER ENERGY, INC.


		March 2, 2004

		($ in millions)
Oil and natural gas properties—proved		$	203.5
Oil and natural gas properties—unproved			25.2
Other property and equipment and other assets			0.7
Current assets			83.2
Deferred tax asset(1)			9.1
Other assets			4.6
Accounts payable and accrued expenses			(62.2	)
Long-Term Liability			(14.7	)
Fair value of oil and natural gas derivatives			(12.4	)
Debt			(145.0	)

	Total Allocation	$	92.0

F-9

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)


(1)	Represents deferred income taxes recorded at the date of the Merger due to differences between the book basis and the tax basis of assets. For book purposes, we had a step-up in basis related to purchase accounting while our existing tax basis carried over.

The following reflects the unaudited pro forma results of operations as though the Merger had been consummated at January 1, 2004.


	Twelve Months
	Ending
	December 31,
	2004

	(in millions)
Revenues and other income	$	214.2
Income before taxes and change in accounting method		103.0
Net income		67.0

On February 10, 2005, in anticipation of the Company’s private placement of 31,452,500 shares of common stock (the “Private Equity Offering”), Mariner Holdings, Inc. (the direct parent of Mariner Energy, Inc.) and Mariner Energy LLC (the direct parent of Mariner Holdings, Inc.) were merged into Mariner Energy, Inc. and ceased to exist. The mergers of Mariner Holdings, Inc. and Mariner Energy, LLC into the Company had no operational or financial impact on the Company; however $2.9 million in cash held by the affiliates was transferred to the Company in February 2005 and accounted for as additional paid-in capital.

Net Income Per Share—Basic earnings per share is calculated by dividing net income by the weighted average number of shares of common stock outstanding during the period. No dilution for any potentially dilutive securities is included. Fully diluted earnings per share assumes the conversion of all potentially

F-10

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

dilutive securities and is calculated by dividing net income by the sum of the weighted average number of shares of common stock outstanding plus all potentially dilutive securities.


	Post-Merger				Pre-Merger		Post-Merger		Pre-Merger

			Period from		Period from		Period from		Period from
			March 3, 2004		January 1, 2004		March 3, 2004		January 1, 2004		Years Ended
	Three Months		through		through		through		through		December 31,
	Ended March 31,		March 31,		March 2,		December 31,		March 2,
	2005		2004		2004		2004		2004		2003		2002

	(unaudited)		(unaudited)
Numerator:
Income before cumulative effect of change in accounting method, net of tax effects	$	17,775	$	5,933	$	14,826	$	53,619	$	14,826	$	36,301	$	29,993
Cumulative effect of change in accounting method, net of tax effects		—		—		—		—		—		1,943

Net income	$	17,775	$	5,933	$	14,826	$	53,619	$	14,826	$	38,244	$	29,993

Denominator:
Weighted average shares outstanding		30,588		29,748		29,748		29,748		29,748		29,748		29,748
Add dilutive securities: Stock options		11		—		—		—		—		—		—

Total weighted average shares outstanding and dilutive securities		30,599		29,748		29,748		29,748		29,748		29,748		29,748

Earnings per share — basic:
Income before cumulative effect of change in accounting method, net of tax effects	$	0.58	$	0.20	$	.50	$	1.80	$	.50	$	1.22	$	1.01
Cumulative effect of change in accounting method, net of tax effects		—		—		—		—		—		.07		—

Net income per share — basic	$	0.58	$	0.20	$	.50	$	1.80	$	.50	$	1.29	$	1.01

Earnings per share — diluted:
Income before cumulative effect of change in accounting method, net of tax effects	$	0.58	$	0.20	$	.50	$	1.80	$	.50	$	1.22	$	1.01
Cumulative effect of change in accounting method, net of tax effects		—		—		—		—		—		.07		—

Net income per share — diluted	$	0.58	$	0.20	$	.50	$	1.80	$	.50	$	1.29	$	1.01

Effective March 3, 2005, we effected a stock split increasing our authorized shares from 2,000,000 to 70,000,000 and our outstanding shares from 1,380 to 29,748,130. We also changed the stated par value of our

F-11

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

stock from $1 to $.0001 per share. The accompanying financial and earnings per share information has been restated utilizing the post-split shares. Effective with our merger on March 2, 2004, all company stock option plans and associated outstanding stock options were canceled. For the reported periods, there was no diluted earnings effect for outstanding but unexercised stock options.

For the periods presented prior to 2005, Mariner Energy, Inc. had no outstanding stock options so the basic and diluted earnings per share are the same. In March 2005, 2,267,270 restricted stock awards were granted under the Equity Participation Plan and 787,360 stock options were granted under the Stock Incentive Plan. There was no diluted earnings effect for outstanding but unexercised restricted stock or stock options for the three months ended March 31, 2005.

Cash and Cash Equivalents—All short-term, highly liquid investments that have an original maturity date of three months or less are considered cash equivalents.

Receivables—Substantially all of the Company’s receivables arise from sales of oil or natural gas, or from reimbursable expenses billed to the other participants in oil and gas wells for which the Company serves as operator.

Oil and Gas Properties—Oil and gas properties are accounted for using the full-cost method of accounting. All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and gas properties are capitalized. Amortization of oil and gas properties is provided using the unit-of-production method based on estimated proved oil and gas reserves. No gains or losses are recognized upon the sale or disposition of oil and gas properties unless the sale or disposition represents a significant quantity of oil and gas reserves, which would have a significant impact on the depreciation, depletion and amortization rate. The net carrying value of proved oil and gas properties is limited to an estimate of the future net revenues (discounted at 10%) from proved oil and gas reserves based on period-end prices and costs plus the lower of cost or estimated fair value of unproved properties.

Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date.

The ceiling test is calculated using natural gas and oil prices in effect as of the balance sheet date and adjusted for “basis” or location differential, held constant over the life of the reserves. We use derivative financial instruments that qualify for cash flow hedge accounting under SFAS 133 to hedge against the volatility of natural gas prices, and in accordance with SEC guidelines, we include estimated future cash flows from our hedging program in our ceiling test calculation. In addition, subsequent to the adoption of SFAS 143, “Accounting for Asset Retirement Obligations,” the future cash outflows associated with settling asset retirement obligations are not included in the computation of the discounted present value of future net revenues for the purposes of the ceiling test calculation.

Unevaluated Properties— The costs associated with unevaluated properties and properties under development are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination together with interest costs capitalized for these projects. Unevaluated leasehold costs are transferred to the amortization base once determination has been made or upon expiration of a lease. Geological and geophysical costs associated with a specific unevaluated property are transferred to the amortization base with the associated leasehold costs on a

F-12

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

specific project basis. Geological and geophysical costs not directly associated with a specific unevaluated property are currently being transferred to the full cost pool by amortizing the costs over a three-year period from the date of purchase, representing the development plan of our unproved properties and related unevaluated reserves. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. All items included in our unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value. We estimate these costs will be evaluated within a three-year period.

Other Property and Equipment—Depreciation of other property and equipment is provided on a straight-line basis over their estimated useful lives, which range from three to seven years.

Prepaid Expenses and Other—Prepaid expenses and other includes $3.6 million of oil and gas lease and well equipment held in inventory. In 2004, we reduced the carrying cost of our inventory by $957,000 to account for a reduction in the estimated value, primarily related to subsea trees held in inventory.

Other Assets—Other assets as of December 31, 2004 were primarily comprised of $2.5 million of amortizable bank fees and various deposits held by third parties. Other assets as of December 31, 2003 were primarily comprised of a $977,000 receivable from Mariner Energy LLC and various deposits held by third parties. Accumulated amortization as of December 31, 2004 and 2003 was $0.9 and $6.6, respectively.

Production Costs— All costs relating to production activities, including workover costs incurred to maintain production, are charged to expense as incurred.

General and Administrative Costs and Expenses— Under the full cost method of accounting, a portion of our general and administrative expenses that are attributable to our acquisition, exploration and development activities are capitalized as part of our full cost pool. These capitalized costs include salaries, employee benefits, costs of consulting services and other costs associated with our exploration activities. We capitalized general and administrative costs related to our acquisition, exploration and development activities, during 2004, 2003 and 2002, of $6.9 million, $6.6 million and $9.5 million, respectively.

We receive reimbursement for administrative and overhead expenses incurred on behalf of other working interest owners on properties we operate. These reimbursements totaling $4.4 million, $1.8 million and $2.8 million for the years ended December 31, 2004, 2003 and 2002, respectively, were allocated as reductions to general and administrative expenses incurred. Generally, we do not receive any reimbursements or fees in excess of the costs incurred; however, if we did, we would credit the excess to the full cost pool to be recognized through lower cost amortization as production occurs.

Income Taxes—The Company’s taxable income is included in a consolidated United States income tax return with Mariner Energy LLC. The intercompany tax allocation policy provides that each member of the consolidated group compute a provision for income taxes on a separate return basis. The Company records its income taxes using an asset and liability approach which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax bases of assets and liabilities. Valuation allowances are established when necessary to reduce deferred tax assets to the amount more likely than not to be recovered.

Capitalized Interest Costs—The Company capitalizes interest based on the cost of major development projects which are excluded from current depreciation, depletion, and amortization calculations. Capitalized interest costs were approximately $-0- and $434,000 for 2004 Pre-merger and 2004 Post-merger, respectively, and $727,000, and $1,022,000 for the years ended December 31, 2003 and 2002, respectively.

Accrual for Future Abandonment Costs—Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations,” addresses accounting and reporting for

F-13

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 was adopted on January 1, 2003. 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.

The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record (i) an $11.3 million increase in the carrying values of proved properties, and (ii) a $4.5 million increase in current abandonment liabilities. The net impact of these items was to record a pre-tax gain of $3.0 million as a cumulative effect adjustment of a change in accounting principle in the Company’s statements of operations upon adoption on January 1, 2003.

The following roll forward is provided as a reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation.


	(in millions)
Abandonment liability as of January 1, 2003 (Pre-Merger)	$	15.7
Liabilities incurred		1.8
Claims settled		(3.9	)
Accretion expense		1.4

Abandonment liability as of December 31, 2003 (Pre-Merger)	$	15.0

Liabilities Incurred		—
Claims Settled		(1.5	)
Accretion Expense		0.2

Abandonment Liability as of March 2, 2004 (Pre-merger)	$	13.7

Abandonment Liability as of March 3, 2004 (Post-merger)	$	13.7
Liabilities Incurred		11.5
Claims Settled		(2.7	)
Accretion Expense		1.5

Abandonment Liability as of December 31, 2004 (Post-merger)(1)	$	24.0

Liabilities Incurred		3.8
Claims Settled		(0.1	)
Accretion Expense		0.5

Abandonment Liability as of March 31, 2005 (Post-merger)(2)	$	28.2


(1)	Includes $4.7 million classified as a current accrued liability at December 31, 2004.


(2)	Includes $7.7 million classified as a current accrued liability at March 31, 2005.

Hedging Program—The Company utilizes derivative instruments 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 and fixed-price crude oil and natural gas purchase and sale commitments. Such agreements are accounted for as hedges using the deferral method of accounting. Gains and losses resulting from these transactions, recorded at market value, are deferred and recorded in Accumulated Other Comprehensive Income (“AOCI”) as appropriate, until recognized as operating income in the Company’s Statement of Operations as the physical production hedged by the contracts is delivered.

F-14

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

Revenue Recognition—We use the entitlements method of accounting for the recognition of natural gas and oil revenues. Under this method of accounting, income is recorded based on our net revenue interest in production or nominated deliveries. We incur production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over-and-under deliveries or by cash settlement, as required by applicable contracts. Production imbalances are marked-to-market at the end of each month at the lowest of (i) the price in effect at the time of production; (ii) the current market price; or (iii) the contract price, if a contract is in hand.

Oil and gas volumes sold are not significantly different from the Company’s share of production.

Financial Instruments—The Company’s financial instruments consist of cash and cash equivalents, receivables, payables and outstanding debt. The carrying amount of the Company’s other instruments noted above approximate fair value due to the short-term nature of these investments. The carrying amount of our long-term debt approximates fair value as the interest rates are generally indexed to current market rates.

Use of Estimates in the Preparation of Financial Statements—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from these estimates.

Major Customers—During the twelve months ended December 31, 2004, sales of oil and gas to three purchasers, including an Enron affiliate, accounted for 27%, 18% and 12% of total revenues. During the year ended December 31, 2003, sales of oil and gas to three purchasers, including an Enron affiliate, accounted for 34%, 19% and 14% of total revenues. During the year ended December 31, 2002, sales of oil and gas to three purchasers, including an Enron affiliate, accounted for 42%, 14% and 9% of total revenues. Management believes that the loss of any of these purchasers would not have a material impact on the Company’s financial condition or results of operations.

Stock Options—The Company (as allowed by SFAS No. 123 “Accounting for Stock Based Compensation” as amended by SFAS No. 148 “Accounting for Stock-Based Compensation—Transition and Disclosure”) has historically applied APB Opinion No. 25 “Accounting for Stock Issued to Employees” for its grants made pursuant to its employee stock option plans. The Company applies APB Opinion 25 and related interpretations in accounting for the Stock Option Plan. Accordingly, no compensation cost has been

F-15

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

recognized for the Stock Option Plan. Had compensation cost for the Stock Option Plan been determined based on the fair value at the grant date for awards under the Stock Option Plan consistent with the method of SFAS No. 123, the Company’s net income for the years ended December 31, 2004, 2003 and 2002 would not have changed. Effective January 1, 2005, we adopted the fair value expense recognition provisions of SFAS 123(R). Using the modified retrospective application, the Company would be required to give effect to the fair-value based method of accounting for awards granted, modified, or settled in cash in fiscal years beginning after December 15, 1994 on a basis consistent with the pro forma disclosures required for those periods by Statement 123, as amended by FASB Statement No. 14 “Accounting for Stock Based Compensation— Transition and Disclosure”. Since the Company had no employee stock options plans in effect at January 1, 2005, adoption of this method is expected to have no impact on historical information presented by the Company.

As a result of the adoption of the above described SFAS No. 123(R), we expect to record compensation expense for the fair value of restricted stock that was granted pursuant to our Equity Participation Plan (see Management— Equity Participation Plan) and for subsequent grants of stock options or restricted stock made pursuant to the Mariner Energy, Inc. Stock Incentive Plan (see Management— Stock Incentive Plan). We expect to record compensation expense for the restricted stock grants equal to their fair value at the time of the grant, amortized pro rata over the restricted period. General and administrative expense for the three months ended March 31, 2005 includes $1.3 million of compensation expense related to restricted stock granted in March 2005.

Recent Accounting Pronouncements— In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” or SFAS No. 150. SFAS No. 150 establishes standards on how a company classifies and measures certain financial instruments with characteristics of both liabilities and equity. The statement requires that the Company classify as liabilities the fair value of all mandatorily redeemable financial instruments that had previously been recorded as equity or elsewhere in the consolidated financial statements. This statement is effective for financial instruments entered into or modified after May 31, 2003, and is otherwise effective for all existing financial instruments beginning in the third quarter of 2003. SFAS No. 150 did not impact the Company.

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,” (“FSP FAS 142-2”) addressing whether the scope exception within Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”) 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 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

F-16

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

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.


2.	Related Party Transactions

Organization and Ownership of the Company— Until February 10, 2005, the Company was a wholly-owned subsidiary of Mariner Holdings, Inc., which was a wholly-owned subsidiary of Mariner Energy LLC. From April 1, 1996, until October 1998, Mariner Holdings, Inc. was a majority-owned subsidiary of JEDI, an affiliate of Enron. In October 1998, JEDI and other stockholders of Mariner Holdings, Inc. exchanged all of their common shares of Mariner Holdings, Inc. for an equivalent ownership percentage in Mariner Energy LLC. From October 1998 until the Merger, Mariner Energy LLC was a majority-owned subsidiary of JEDI.

During the period of JEDI’s ownership of the Company, Mariner Energy LLC and the Company entered into various financing and operating transactions, such as oil and gas sale transactions, commodity price hedge transactions, and financial transactions with affiliates of Enron. Below is a summary of key transactions between the Company or Mariner Energy LLC and Enron-affiliated entities.

On February 10, 2005, in anticipation of the Private Equity Offering, Mariner Holdings, Inc. (the direct parent of Mariner Energy, Inc.) and Mariner Energy LLC (the direct parent of Mariner Holdings, Inc.) were merged into Mariner Energy, Inc. and ceased to exist. The mergers of Mariner Holdings, Inc. and Mariner Energy, LLC into the Company had no operational or financial impact on the Company.


	*Mariner Energy LLC*

Enron Affiliate Term Loan— In March 2000, Mariner Energy LLC established an unsecured term loan with Enron North America Corp. (“ENA”), an affiliate of Enron, to repay amounts outstanding under various affiliate credit facilities at Mariner Energy LLC and the Company and provide additional working capital. The loan bore interest at 15%, which interest accrued and was added to the loan principal. In conjunction with the loan, warrants were issued to ENA providing the right to purchase up to 900,000 common shares of Mariner Energy LLC for $0.01 per share. The loan and warrants were subsequently assigned by ENA to another Enron affiliate. In connection with the Merger, the loan balance, which was approximately $192.8 million as of December 31, 2003, was repaid in full, and the warrants were exercised and the holders received their pro rata portion of the Merger consideration.


	*Mariner Energy, Inc.*

Oil and Gas Production Sales to Enron Affiliates— During the three years ending December 31, 2004, 2003 and 2002, sales of oil and gas production to Enron affiliates were $62.6 million, $32.6 million and $56.4 million, respectively. These sales were generally made on one to three month contracts. At the time Enron filed its petition for bankruptcy protection in December 2001, the Company immediately ceased selling its physical production to Enron Upstream Company, LLC, an Enron affiliate; however, it continued to sell its production to Bridgeline Gas Marketing, LLC, another Enron affiliate. No default in payment by Bridgeline

F-17

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

has occurred. As of December 31, 2001, after Enron filed for bankruptcy protection, the Company had an outstanding receivable of $3.0 million from ENA Upstream related to sales of production. This amount was not paid as scheduled. In 2001, we fully allowed for its uncollectability and reduced the outstanding receivable to $-0-. The Company submitted a proof of claim to the bankruptcy court presiding over the Enron bankruptcy for amounts owed to it by ENA Upstream. As part of the Merger consideration, the Company assigned this and another receivable to JEDI at an agreed value of approximately $1.9 million.

Price Risk Management Activities— The Company engages in price risk management activities from time to time. These activities are intended to manage its exposure to fluctuations in commodity prices for natural gas and crude oil. The Company primarily utilizes price swaps as a means to manage such risk. Prior to the Enron bankruptcy, all of the Company’s hedging contracts were with ENA. As a result of ENA’s bankruptcy, the November 2001 through April 30, 2002 settlements for oil and gas were not paid when due. On May 14, 2002, the Company elected under its ISDA Master Agreement with ENA to terminate all open hedge contracts. The effect of this termination was to fix the nominal value on all remaining contracts on May 14, 2002. Subsequent to this termination, the value of all oil and natural gas unpaid hedge contracts was $7.7 million. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137 and No. 138, the Company de-designated its contracts effective December 2, 2001 and recognized all market value changes subsequent to such de-designation in its earnings. The value recorded up to the time of de-designation and included in Accumulated Other Comprehensive Income (“AOCI”), was reclassified out of AOCI and into earnings as the original corresponding production, as hedged by the contracts was produced. As of December 31, 2003, approximately $25.8 million was reclassified to earnings.

The following table sets forth the results of hedging transactions during the periods indicated that were made with ENA (all amounts shown are non-cash items):


	Year Ending
	December 31,

	2004		2003

Natural gas quantity hedged (MMbtu)		—		3,650,000
Increase (decrease) in natural gas sales (thousands)		—	$	2,603
Crude oil quantity hedged (MBbls)		—		—
Increase (decrease) in crude oil sales (thousands)		—		—

F-18

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

Supplemental ENA Affiliate Data— provided below is supplemental balance sheet and income statement information for affiliate entities and reflect net balances, net of any allowances:


		December 31,		December 31,
		2004		2003

		(amount in millions)
Balance Sheet Data
Related Party Receivable:
	Derivative Asset	$	—	$	—
	Settled Hedge Receivable		—		—
	Oil and Gas Receivable		—		—
Accrued Liabilities:
	Transportation Contract		—		0.1
	Service Agreement		—		0.4
Stockholder’s Equity:
	Common Stock	$	—	$	.001
	Additional Paid in Capital		—		227.3
	Accumulated other Comprehensive Income	$	—	$	227.3


	Year Ended
	December 31,

	2004		2003

Income Statement Data
Oil and Gas Sales	$	—	$	32.6
General and Administrative Expenses		—		0.4
Transportation Expenses		—		1.9
Unrealized gain and other non-cash derivative instrument adjustments		—		—


	*Controlled Group Liability*

Prior to the closing of the Merger, Mariner Energy LLC and its subsidiaries (collectively, “Mariner”) may have been within the Enron “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’s indirect ownership and/or control over Mariner. As a result, Mariner may have had potential liability for certain employee benefit plan obligations of Enron. 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, Mariner Energy LLC, as the surviving corporation, will be vested with good title to the interests in its subsidiaries and the assets thereof free and clear of all claims and encumbrances, and rights of setoff, deduction, netting and recoupment, if any, which have, or could have, been asserted by the Pension Benefit Guaranty Corporation. Pursuant to the Merger agreement, Enron agreed to indemnify Mariner from any liabilities imposed against Mariner or any of its assets arising as a result of Mariner being considered an ERISA affiliate of Enron or relating to any group health insurance plans sponsored or maintained by Enron or any of its affiliates under Section 4980B of the Internal Revenue Code.


	*Post-Merger Related Party Transactions*

In connection with the Merger, Mariner Energy LLC entered into management agreements with two affiliates of MEI Acquisitions Holdings, LLC, the Company’s post-Merger parent company. These agreements provided for the payment by Mariner Energy LLC of an aggregate of $2.5 million to the affiliates in

F-19

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

connection with the provision of management services. Such payments have been made. Mariner Energy LLC has also entered into monitoring agreements with two affiliates of MEI Acquisitions Holdings, LLC, providing for the payment by Mariner Energy LLC of an aggregate of one percent of its annual EBITDA to the affiliates in connection with certain monitoring activities. 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.

Effective February 7, 2005, these contracts were terminated in consideration of lump sum cash payments by Mariner totalling $2.3 million. The Company recorded the termination payments as general and administrative expenses for the three months ended March 31, 2005.


3.	Property Conveyances

In April 2002, the Company sold 50% of its working interest in its Falcon discovery and surrounding blocks, located in East Breaks Block 579 in the western Gulf of Mexico, for $48.8 million. After the sale, the Company had a 25% working interest in the discovery and surrounding blocks. No gain or loss was recognized as a result of this sale, as the sale did not significantly affect the Company’s depletion rate.

In March 2003, the Company sold its remaining 25% working interest in its Falcon and Harrier discoveries and surrounding blocks, located in East Breaks area in the western Gulf of Mexico, for $121.6 million. The Company retained a 4¹/4 percent overriding royalty interest on seven non-producing blocks. The proceeds from the sale were used for debt reduction, capital expenditures, and other corporate purposes. At March 31, 2003, the Falcon and Harrier projects had approximately 44 Bcfe assigned as proven oil and gas reserves to the Company’s interest. No gain or loss was recognized as a result of this sale, as the sale did not significantly affect the Company’s depletion rate.


4.	Long-Term Debt

10¹/2% Senior Subordinated Notes—On August 14, 1996, the Company sold $100 million principal amount of 10¹/2% Senior Subordinated Notes Due 2006 (the “Notes”). The Notes bore interest at 10¹/2% payable semiannually in arrears on February 1 and August 1 of each year and were unsecured obligations of the Company. On August 1, 2003, the Company repaid the Notes at par value.

Bank Credit Facility—On March 2, 2004, simultaneously with the closing of the Merger, the Company obtained a revolving line of credit with initial advances of $135 million from a group of seven banks (since reduced to six banks) led by Union Bank of California, N.A. and BNP Paribas. Proceeds of these advances were used to pay a portion of the Merger consideration (which included repayment of the debt of Mariner Energy LLC) and transaction costs and expenses associated with the Merger. The bank credit facility provides up to $150 million of revolving borrowing capacity, subject to a borrowing base, and a $25 million term loan. The initial advance was made in two tranches: a $110 million Tranche A and a $25 million Tranche B.

The Tranche A revolving note matures on March 2, 2007. The borrowing capacity under the Tranche A note is subject to a borrowing base initially set at $110 million. The borrowing base initially is subject to redetermination by the lenders quarterly. After the Tranche B note is repaid, provided that at least $10 million of unused availability exists under Tranche A, the borrowing base will be redetermined semi-annually. The borrowing base is based upon the evaluation by the lenders of the Company’s oil and gas reserves and other factors. Any increase in the borrowing base requires the consent of all lenders.

Borrowings under the Tranche A note bear interest, at the option of the Company, 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 (prime rate), plus 0.00% to 0.50% depending upon utilization.

F-20

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

Borrowings under the Tranche B note bear interest at a rate equal to the greater of (a) the Federal Funds Rate plus 0.50% or (b) the Reference Rate, plus 3.00%. In July 2004 (prior to its December 2, 2004 maturity date) the outstanding Tranche B note was converted to a Tranche A note, and all subsequent advances under the credit facility are Tranche A advances. Once repaid, the Tranche B advances may not be reborrowed.

Substantially all of the Company’s assets, other than the assets securing the term Promissory Note issued to JEDI, are pledged to secure the bank credit facility. In addition, the Company’s parent entities, Mariner Energy LLC and Mariner Holdings, Inc., have guaranteed the Company’s obligations under the bank credit facility. The Company must pay a commitment fee of 0.25% to 0.50% per year on the unused availability under the bank credit facility, depending upon utilization.

The bank credit facility contains various restrictive covenants and other usual and customary terms and conditions of a revolving bank 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 the Company’s oil and natural gas production. Financial covenants require the Company 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 the current portion of hedge liabilities) of not less than (i) 0.75 to 1.00 until June 30, 2004 and (ii) 1.00 to 1.00 thereafter;

	•	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 the period and 20% (on an annualized basis) of outstanding Tranche A 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 by the Company of bonds as described in the credit agreement and 3.00 to 1.00 thereafter.

The bank credit facility also contains customary events of default, including the occurrence of a change of control or default in the payment or performance of any other indebtedness equal to or exceeding $2.0 million.

As of December 31, 2004, $105.0 million was outstanding under the bank credit facility, and the weighted average interest rate was 5.20%. The borrowing base under the bank credit facility is $135 million at December 31, 2004.

As of March 31, 2005, $55.0 million was outstanding under the bank credit facility, and the weighted average interest rate was 4.93%. Net proceeds of approximately $39.0 million generated by the private placement in March 2005 were used to repay existing bank debt.


	*JEDI Term Promissory Note*

As part of the Merger consideration payable to JEDI, the Company 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 chose to pay interest in cash rather than in kind. The JEDI note is secured by a lien on three of the Company’s non-proven, non-producing properties located in the Outer Continental Shelf of the Gulf of Mexico. The Company 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 the occurrence of an event of default under the Company’s bank credit facility.

F-21

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

In March 2005, the Company repaid $6.0 million of the note utilizing proceeds from the private placement in March 2005.


	*Cash Interest Expense*

Cash paid for interest was -0- million and $5.4 million for 2004 Pre-Merger and 2004 Post-Merger, respectively, and $4.0 million and $6.2 million for the years ending December 31, 2003 and 2002, respectively.


5.	Stockholder’s Equity

Stock Option Plan—During June 1996, Mariner Holdings, Inc. established the Mariner Holdings, Inc. 1996 Stock Option Plan (as amended, the “Stock Option Plan”) providing for the granting of stock options to key employees and consultants. In connection with the Merger, all outstanding options were cancelled in accordance with the Stock Option Plan. No payments were due to the holders of the options.

The exercise price of options granted under the Stock Option Plan could not be less than the fair market value of the shares at the date of grant. The maximum number of common shares of Mariner Holdings, Inc. that could be issued under the Stock Option Plan was 142,800. In May 1998, the Stock Option Plan was amended to increase the number of eligible shares to be issued to 202,800. In September 1998, concurrent with the exchange of each common share of Mariner Holdings for twelve common shares of Mariner Energy LLC, the Stock Option Plan was amended to make Mariner Energy LLC the Stock Option Plan sponsor. The maximum number of shares of common shares that could have been issued under the Stock Option Plan was correspondingly increased to 2,433,600.

During the three years ended December 31, 2004, 2003 and 2002, no options were granted under the Stock Option Plan. No options were exercised, but 212,882 options were canceled during the three-year period ended December 30, 2003. At December 31, 2003, options to purchase 437,940 shares were outstanding and exercisable. The exercise price for the outstanding options was $14.58 per share. The options would have expired in various months between 2008 through 2010. In connection with the Merger, all outstanding options were cancelled in accordance with the Stock Option Plan and no payments were due to the holders of the options.

For the three years ended December 31, 2004, 2003, and 2002, Mainer Energy, Inc. had no outstanding stock options. During the three months ended March 31, 2005, we granted 2,267,270 shares of restricted stock and options to purchase 787,360 shares of stock and recorded compensation expense of $1.3 million in the first quarter of 2005 related to the restricted stock. We also issued 3.6 million shares of common stock in the first quarter of 2005 in connection with our private placement offering.


6.	Employee Benefit And Royalty Plans

Employee Capital Accumulation Plan—The Company provides all full-time employees (who are at least 18 years of age) participation in the Employee Capital Accumulation Plan (the “Plan”) which is comprised of a contributory 401(k) savings plan and a discretionary profit sharing plan. Under the 401(k) feature, the Company, at its sole discretion, may contribute an employer-matching contribution equal to a percentage not to exceed 50% of each eligible participant’s matched salary reduction contribution as defined by the Plan. Under the discretionary profit sharing contribution feature of the Plan, the Company’s contribution, if any, must be determined annually and must be 4% of the lesser of the Company’s operating income or total employee compensation and shall be allocated to each eligible participant pro rata to his or her compensation. During the years ended 2004, 2003 and 2002, the Company contributed $193,521, $159,241 and $190,792, respectively, to the Plan related to the discretionary feature. Currently there are no plans to terminate the Plan.

F-22

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

Overriding Royalty Interests—Pursuant to agreements, certain employees and consultants of the Company are entitled to receive, as incentive compensation, overriding royalty interests (“Overriding Royalty Interests”) in certain oil and gas prospects acquired by the Company. Such Overriding Royalty Interests entitle the holder to receive a specified percentage of the gross proceeds from the future sale of oil and gas (less production taxes), if any, applicable to the prospects. Cash payments made by the Company to current employees and consultants with respect to Overriding Royalty Interests was $.2 million and $2.5 million for 2004 Pre-Merger and 2004 Post-Merger, respectively, and for the two years ended December 31, 2003 and 2002 were $2.0 and $1.2 million, respectively.


7.	Commitments And Contingencies

Minimum Future Lease Payments— The Company leases certain office facilities and other equipment under long-term operating lease arrangements. Minimum rental obligations under the Company’s operating leases in effect at December 31, 2004 are as follows (in thousands):


2005	$	561
2006		446
2007		148
2008		—
2009		—

Rental expense, before capitalization, was approximately $78,000 and $486,000 for 2004 Pre-Merger and 2004 Post-Merger, respectively, and $569,000 and $1,723,000 for the years ended December 31, 2003 and 2002, respectively.

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

As of March 31, 2005, the Company had the following fixed price swaps 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	)

F-23

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

As of March 31, 2005, the Company had the following costless collars outstanding:


								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	)

The Company has not entered into any hedge transactions subsequent to March 31, 2005.

As of December 31, 2004, the Company had the following fixed price swaps 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	)

As of December 31, 2004, the Company had the following costless collars outstanding:


								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	)

The Company has reviewed the financial strength of its counterparties and believes the credit risk associated with these swaps and costless collars to be minimal.

F-24

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

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


		Post-Merger			Pre-Merger

		Period from			Period from
		March 3, 2004			January 1
		through			through			December 31,
		December 31,			March 2,
		2004			2004			2003			2002

Natural Gas
	Quantity hedged (MMbtu)		16,723,063			2,100,000			25,520,000			—
	Increase (Decrease) in Natural Gas Sales (in thousands)	$	(12,223	)	$	1,431		$	(27,097	)		—
Crude Oil
	Quantity hedged (MBbls)		1,375			179			730			353
	Increase (Decrease) in Crude Oil Sales (in thousands)	$	(16,221	)	$	(686	)	$	(4,969	)	$	(762	)

The Company’s hedge transactions resulted in a $.7 million gain for 2004 Pre-Merger and a $28.4 million loss for 2004 Post-Merger. $7.9 million of the Post-Merger loss relates to the hedge liability recorded at the merger date. In addition, in 2003 the Company recorded $3.2 million of expense related to the settlement of derivatives that were not accounted for as hedges.

Other Commitments—In the ordinary course of business, the Company enters into long-term commitments to purchase seismic data. The minimum annual payments under these contracts are $2.0 and $1.0 million in 2005 and 2006, respectively.

Deepwater Rig—In February 2000, the Company and Noble Drilling Corporation entered into an agreement whereby the Company committed to using a Noble deepwater rig for a minimum of 660 days over a five-year period. The Company assigned to Noble working interests in seven of the Company’s deepwater exploration prospects and agreed to pay Noble’s share of certain costs of drilling the initial test well on the prospects. As of December 31, 2003, the Company had no further obligation under the agreement for the use of the rig and had drilled five of the seven prospects. Subsequent to year end 2003, the Company and Noble Drilling Corporation agreed to exchange Noble’s interest in one of the two remaining undrilled prospects for an interest in another prospect drilled in the first quarter of 2004 and exchange Noble’s carried working interest in the other remaining undrilled prospect for a larger un-carried working interest in the prospect, and the Company agreed to use one of two Noble drilling rigs for an aggregate of 75 days. Mariner has no further obligations under this agreement.

MMS Appeal—Mariner operates numerous properties in the Gulf of Mexico. Two of such properties were leased from the Mineral Management Service subject to the 1996 Royalty Relief Act. This Act relieved the obligation to pay royalties on certain leases until a designated volume is produced. These 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. The Company believes the MMS did not have the authority to set pricing limits in these leases and has filed an administrative appeal with the MMS regarding this matter and withheld payment of royalties on the leases. The Company has recorded a liability for 100% of the exposure on this matter which on December 31, 2004 was $10.9 million. In April 2005, the MMS denied the administrative appeal. The Company is reviewing its options regarding this matter.

Flowline Commitment— The Company entered into a firm transportation contract with MEGS LLC at a rate of $0.26 per Mmbtu to transport the Company’s share of 133 Bcf of natural gas through the MEGS flowline from the Company Mississippi Canyon 718 well from the commencement of production through March 2009. The Company’s working interest in the well at December 31, 2003 was 51%. The remaining volume commitment is 14,707,107 mmbtu or $3.8 million net to the Company. Pursuant to the contract, the

F-25

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

Company must deliver minimum quantities through the flowline or be subject to minimum monthly payment requirements. Subsequent to year end 2003, the Company and the other 49% working interest owner in the well entered into an agreement to acquire the flowline for approximately $1.9 million net to the Company. The acquisition also extinguished a $2.3 million minimum throughput liability.

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.

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


8.	Income Taxes

The components of the federal income tax provision are:


		Post-Merger		Pre-Merger

		Period from		Period from
		March 3, 2004		January 1		Year Ending
		through		through		December 31,
		December 31,		March 2,
		2004		2004		2003		2002

		$		$		$		$

Current			—		—		—		—
Deferred			28,783		8,072		10,432		—

	Total		28,783		8,072		10,432		—

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


	Post-Merger					Pre-Merger

	Period from					Period from
	March 3, 2004					January 1				Year Ending December 31,
	through					through
	December 31,					March 2,
	2004					2004				2003						2002

	$			%		$		%		$			%			$			%

Income before income taxes including change in accounting in 2003		82,402			—		22,898		—		48,676			—			29,993			—
Income tax expense (benefit) computed at statutory rates		28,841			35		8,014		35		17,037			35			10,498			35
Change in valuation allowance		—			—		—		—		(7,090	)		(14	)		(11,507	)		(38	)
Other		(58	)		—		58		—		485			—			1,009			3

Tax Expense		28,783			35		8,072		35		10,432			21			—			—

Federal income taxes of $1.6 million were paid by the Company for the 2004 Post-Merger period for alternative minimum tax liability, and no federal income taxes were paid by the Company in the years ended

F-26

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

December 31, 2003 and 2002. Income tax benefit of $1,045,000 was included as a reduction in “Change in Accounting Principle” for the adoption of SFAS No. 143 in 2003. The increase in federal income tax expense for 2003 is a direct result of the Company utilizing 100% of its stand alone entity net operating losses.

The Company’s deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Significant components of the deferred tax assets and liabilities are as follows (in thousands):


			Year Ending
			December 31,

			2004			2003

Deferred Tax Assets:
	Net operating loss carry forwards		$	15,639		$	—
	Alternative minimum Tax Credit			1,606			—
	Differences between book and tax basis of receivables			—			676
	Other comprehensive income-derivative instruments			6,262			—
	Valuation allowance			(5,909	)		—

		Total net deferred tax assets		17,598			676
Deferred Tax Liabilities:
	Differences between book and tax basis of properties			(14,569	)		(5,445	)

		Total net deferred asset (liability)	$	3,029		$	(4,769	)


9.	Oil and Gas Producing Activities and Capitalized Costs (Unaudited)

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


		Year Ending December 31,

		2004			2003			2002

Oil and gas sales		$	214,187		$	142,543		$	158,228
Lease operating costs			(25,484	)		(24,719	)		(26,076	)
Transportation			(3,029	)		(6,252	)		(10,480	)
Depreciation, depletion and amortization			(64,911	)		(48,339	)		(70,821	)

	Results of operations	$	120,763		$	63,233		$	50,851

The following table summarizes the Company’s capitalized costs of oil and gas properties.


		As of December 31,

		2004			2003			2002

Unevaluated properties, not subject to amortization		$	36,245		$	36,619		$	44,630
Properties subject to amortization			319,553			599,762			620,949

	Capitalized costs		355,798			636,381			665,579
Accumulated depreciation, depletion and amortization			(52,680	)		(429,323	)		(379,543	)

Net capitalized costs		$	303,118		$	207,058		$	286,036

F-27

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

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


		Year Ending December 31,

		2004		2003		2002

Property acquisition costs
	Unproved properties	$	4,844	$	4,746	$	14,813
Exploration costs			43,022		26,823		25,545
Development costs			100,823		51,659		65,002

	Total costs incurred		148,689	$	83,228	$	105,360

Depreciation, depletion and amortization rate per equivalent Mcf before impairment		$	1.73	$	1.45	$	1.78

The Company capitalizes internal costs associated with exploration activities in progress. These capitalized costs were approximately $7,334,000, $7,360,000 and $10,508,000 for the years ended December 31, 2004, 2003 and 2002, respectively.

The following table summarizes costs related to unevaluated properties which have been excluded from amounts subject to amortization at December 31, 2004. Two relatively significant projects were included in unproved properties with balances of $8.0 million and $5.3 million at December 31, 2004. These projects are expected to be evaluated within the next twelve months. The Company regularly evaluates these costs to determine whether impairment has occurred. The majority of these costs are expected to be evaluated and included in the amortization base within three years.


		Period Incurred

		Year Ended December 31,										Total at
												December 31,
		2004		2003			2002			Prior		2004

Unproved leasehold acquisition and geological and geophysical costs		$	4,354	$	76		$	10,251		$	7,324	$	22,005
Unevaluated exploration and development costs			8,955		(51	)		(209	)		5,150		13,845
Capitalized interest			267		118			10			—		395

	Total	$	13,576	$	143		$	10,052		$	12,474	$	36,245

All of the excluded costs at December 31, 2004 relate to activities in the Gulf of Mexico.


10.	Supplemental Oil and Gas Reserve and Standardized Measure Information (Unaudited)

Estimated proved net recoverable reserves as shown below include only those quantities that are expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved developed reserves represent only those reserves expected to be recovered through existing wells. Proved undeveloped reserves include those reserves expected to be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure is required for recompletion. Also included in the Company’s proved undeveloped reserves as of December 31, 2004 were reserves expected to be recovered from wells for which certain drilling and completion operations had occurred as of that date, but for which significant future capital expenditures were required to bring the wells into commercial production.

Reserve estimates are inherently imprecise and may change as additional information becomes available. Furthermore, estimates of oil and gas reserves, of necessity, are projections based on engineering data, and

F-28

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

there are uncertainties inherent in the interpretation of such data as well as in the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. There also can be no assurance that the reserves set forth herein will ultimately be produced or that the proved undeveloped reserves set forth herein will be developed within the periods anticipated. It is likely that variances from the estimates will be material. In addition, the estimates of future net revenues from proved reserves of the Company and the present value thereof are based upon certain assumptions about future production levels, prices and costs that may not be correct when judged against actual subsequent experience. The Company emphasizes with respect to the estimates prepared by independent petroleum engineers that the discounted future net cash flows should not be construed as representative of the fair market value of the proved reserves owned by the Company since discounted future net cash flows are based upon projected cash flows which do not provide for changes in oil and natural gas prices from those in effect on the date indicated or for escalation of expenses and capital costs subsequent to such date. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Actual results will differ, and are likely to differ materially, from the results estimated.

ESTIMATED QUANTITIES OF PROVED RESERVES


								Natural Gas
		Oil			Natural Gas			Equivalent
		(Mbbl)			(MMcf)			(MMcfe)

		(in thousands)
December 31, 2001			10,101			176,461			237,069

	Revisions of previous estimates		541			5,523			8,769
	Extensions, discoveries and other additions		2,108			18,791			31,439
	Sale of reserves in place		(35	)		(35,088	)		(35,298	)
	Production		(1,697	)		(29,632	)		(39,814	)

December 31, 2002			11,018			136,055			202,165

	Revisions of previous estimates		900			(3,076	)		2,324
	Extensions, discoveries and other additions		2,795			62,609			79,379
	Sale of reserves in place		(34	)		(44,233	)		(44,437	)
	Production		(1,600	)		(23,771	)		(33,371	)

December 31, 2003			13,079			127,584			206,060

	Revisions of previous estimates		1,249			19,797			27,291
	Extensions, discoveries and other additions		2,225			28,334			41,684
	Sale of reserves in place		—			—			—
	Production		(2,298	)		(23,782	)		(37,570	)

December 31, 2004			14,255			151,933			237,465

F-29

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

ESTIMATED QUANTITIES OF PROVED DEVELOPED RESERVES


					Natural Gas
	Oil		Natural Gas		Equivalent
	(Mbbl)		(MMcf)		(MMcfe)

	(in thousands)
December 31, 2002		3,609		64,586		86,240
December 31, 2003		5,951		60,881		96,587
December 31, 2004		6,339		71,361		109,395

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

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS


	Year Ending December 31,

	2004			2003			2002

	(in thousands)
Future cash inflows	$	1,601,240		$	1,182,509		$	992,700
Future production costs		(308,190	)		(196,695	)		(154,661	)
Future development costs		(193,689	)		(138,694	)		(110,474	)
Future income taxes		(285,701	)		(183,199	)		(72,648	)

Future net cash flows		813,660			663,921			654,917

Discount of future net cash flows at 10% per annum		(319,278	)		(245,762	)		(191,345	)

Standardized measure of discounted future net flows	$	494,382		$	418,159		$	463,572

During recent years, there have been significant fluctuations in the prices paid for crude oil in the world markets and in the United States, including the posted prices paid by purchasers of the Company’s crude oil. The NYMEX prices of oil and gas at December 31, 2004, 2003 and 2002, used in the above table, were $43.45, $32.52 and $31.20 per Bbl, respectively, and $6.15, $5.96 and $4.74 per Mmbtu, respectively, and do not include the effect of hedging contracts in place at period end.

F-30

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

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


	Year Ending December 31,

	2004			2003			2002

Sales and transfers of oil and gas produced, net of production costs	$	(185,673	)	$	(111,572	)	$	(125,610	)
Net changes in prices and production costs		27,767			27,403			331,085
Extensions and discoveries, net of future development and production costs		102,905			180,237			50,085
Development costs during period and net change in development costs		44,417			31,709			28,474
Revision of previous quantity estimates		89,814			6,276			7,480
Sales of reserves in place		—			(138,016	)		(25,887	)
Net change in income taxes		(27,634	)		(63,962	)		(51,423	)
Accretion of discount before income taxes		41,816			51,500			29,488
Changes in production rates (timing) and other		(17,189	)		(28,988	)		(12,148	)

Net change	$	76,223		$	(45,413	)	$	231,544

F-31

Annex A

MARINER ENERGY, INC.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

(SEC Parameters)

As of

December 31, 2004

January 28, 2005

Mariner Energy, Inc.

2101 CityWest Blvd., Suite 1900

Houston, Texas 77042-3020

Gentlemen:

At your request, we have prepared an estimate of the reserves, future production, and cash flow attributable to certain leasehold and royalty interests of Mariner Energy, Inc. (Mariner) as of December 31, 2004. The subject properties are located in the states of Mississippi and Texas and in the federal waters offshore Louisiana and Texas. The cash flow data were estimated using the Securities and Exchange Commission (SEC) guidelines for future price and cost parameters.

The estimated reserves and future cash flow amounts presented in this report are related to hydrocarbon prices. December 2004 hydrocarbon prices were used in the preparation of this report as required by SEC guidelines; however, actual future prices may vary significantly from December 2004 prices. Therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Cash Flow Data

Certain Leasehold and Royalty Interests of

Mariner Energy, Inc.

As of December 31, 2004


			Proved

			Developed
									Total
			Producing		Non-Producing		Undeveloped		Proved

*Net Remaining Reserves*
		Oil/ Condensate—Barrels		6,171,886		167,142		7,916,458		14,255,486
		Gas—MMCF		57,788		13,573		80,572		151,933
*Cash Flow Data (M$)*
	Future Gross Revenue		$	621,366.9	$	91,410.3	$	836,425.2	$	1,549,202.4
	Deductions			143,343.3		27,769.0		278,728.5		449,840.8

	Future Net Cash Flow		$	478,023.6	$	63,641.3	$	557,696.7	$	1,099,361.6
	(Before Taxes)
	Present Value @ 10%		$	281,479.0	$	53,887.8	$	332,608.3	$	667,975.1
	(PV10)

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

A-1

Mariner Energy, Inc.

January 28, 2005

Page 2

The estimates of the reserves, future production, and cash flow attributable to properties in this report were prepared using the economic software package Aries for Windows, a copyrighted program of Landmark. The program was used solely at the request of Mariner. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions are comprised of the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. The future net cash flow is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. Gas reserves account for approximately 63 percent and liquid hydrocarbons account for approximately 37 percent of total future gross revenue from proved reserves.

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


		Present Value
		As of December 31, 2004
		(M$)

Discount Rate		Total
Percent		Proved

	5	$	815,643.4
	15	$	575,781.8
	20	$	511,036.7
	25	$	462,061.6

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

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulation S-X Part 210.4-10(a) as clarified by subsequent Commission Staff Accounting Bulletins. The definitions of proved reserves are included under the tab “Petroleum Reserves Definitions” in this report.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled.

The proved developed non-producing reserves included herein are comprised of the behind pipe and shut in categories. The various reserve status categories are defined under the tab “Petroleum Reserves Definitions” in this report.

A-2

Mariner Energy, Inc.

January 28, 2005

Page 3

Estimates of Reserves

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

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

Future Production Rates

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

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

Hydrocarbon Prices

Mariner furnished us with hydrocarbon prices of $43.45 per barrel for oil and $6.149 per MMBTU for gas in effect at December 31, 2004. In accordance with FASB Statement No. 69, December 31, 2004 market prices were determined using the daily oil price or daily gas sales price (“spot price”) adjusted for oilfield or gas gathering hub and wellhead price differences (e.g. grade, transportation, gravity, sulfur and BS&W) as appropriate. Also in accordance with SEC and FASB specifications, changes in market prices subsequent to December 31, 2004 were not considered in this report.

Costs

Operating costs were supplied by Mariner. We did not review these costs and make no assurances of their accuracy. Development costs were furnished to us by Mariner and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The estimated net cost of abandonment after salvage was included for the offshore properties where abandonment costs net of salvage were significant. At the request of Mariner, their estimate of zero abandonment costs after salvage value for onshore properties was used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Mariner’s estimates.

A-3

Mariner Energy, Inc.

January 28, 2005

Page 4

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

Reversion Interests

Mariner furnished us with the dates of interest reversions on all of the applicable properties. We did not verify these dates and make no assurances of their accuracy. We used these dates presented by Mariner in our evaluations.

Royalty Relief

Mariner has also furnished us with the ownership interests in the subject properties and we used these without independent verification. In the deepwater areas of the Gulf of Mexico, it is not uncommon for the Mineral Management Service (MMS) to grant leases which are subject to Federal royalty relief. This relief is commonly suspended when a certain amount of hydrocarbons are recovered from the lease or when product prices rise above a predetermined amount. Mariner states the lease they signed with the MMS for Mississippi Canyon block 296 allows for royalty relief without regard to hydrocarbon prices.

General

Table A presents a one line summary of proved reserve and cash flow for each of the subject properties which are ranked according to their present value discounted at 10 percent per year. Table B presents a one line summary of gross and net reserves and cash flow data for each of the subject properties. Table C presents a one line summary of initial basic data for each of the subject properties. Tables 1 through 653 present our estimated projection of production and cash flow by years beginning January 1, 2005, by state, field, and lease or well.

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

The estimates of reserves presented herein were based upon a detailed study of the properties in which Mariner owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities which may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. Mariner has informed us that they have furnished us all of the accounts, records, geological and engineering data, and reports and other data required for this investigation. The ownership interests, prices, and other factual data furnished by Mariner were accepted without independent verification. The estimates presented in this report are based on data available through December 2004.

Mariner has assured us of their intent and ability to proceed with the development activities included in this report, and that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans.

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

A-4

Mariner Energy, Inc.

January 28, 2005

Page 5

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


	Very truly yours,

	RYDER SCOTT COMPANY, L.P.



	Timothy J. Torres, P.E.
	Vice President

TJT/pl

A-5

PETROLEUM RESERVES DEFINITIONS

SECURITIES AND EXCHANGE COMMISSION

INTRODUCTION

Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. It should be noted that Securities and Exchange Commission Regulation S-K prohibits the disclosure of estimated quantities of probable or possible reserves of oil and gas and any estimated value thereof in any documents publicly filed with the Commission.

Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. Reserves do not include quantities of petroleum being held in inventory, and may be reduced for usage or processing losses if required for financial reporting.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

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


	(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:


	(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

	(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.


	(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

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PETROLEUM RESERVES DEFINITIONS

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	(iii) Estimates of proved reserves do not include the following:


	(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

	(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

	(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

	(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

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

Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? ... The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

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PETROLEUM RESERVES DEFINITIONS

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Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

The staff believes that since coalbed methane gas can be recovered from coal in its natural and original location, it should be included in proved reserves, provided that it complies in all other respects with the definition of proved oil and gas reserves as specified in Rule 4-10(a)(2) including the requirement that methane production be economical at current prices, costs, (net of the tax credit) and existing operating conditions. (extracted from SAB-85)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

SUB-CATEGORIZATION OF DEVELOPED RESERVES (SPE/ WPC DEFINITIONS)

In accordance with guidelines adopted by the Society of Petroleum Engineers (SPE) and the World Petroleum Congress (WPC), developed reserves may be sub-categorized as producing or non-producing.

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

Non-Producing. Reserves sub-categorized as non-producing include shut-in and behind pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shut-in awaiting pipeline connections or as a result of a market interruption, or (3) wells not capable of production for mechanical reasons. Behind pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production.

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33,348,130 Shares

Common Stock

Prospectus

, 2005

Until (25 days after the commencement of this offering), all dealers that effect transactions in our common stock, whether or not participating in this offering, may be required to deliver a prospectus.

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS


Item 13.	*Other Expenses of Issuance and Distribution.*

The following table sets forth estimates of all expenses payable by the registrant in connection with the sale of common stock being registered. The selling stockholders will not bear any portion of such expenses. All the amounts shown are estimates except for the registration fee.


SEC registration fee		$	56,000
NASD filing fee			50,000
Listing fee			5,000
Legal fees and expenses			970,000
Printer fees			247,000
Transfer agent fees			18,000
Blue sky fees and expenses			19,000
Accounting fees and expenses			365,000
Miscellaneous			170,000

	Total	$	1,900,000


Item 14.	*Indemnification of Officers and Directors.*

Our second amended and restated certificate of incorporation provides that a director will not be liable to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, except for liability (1) for any breach of the director’s duty of loyalty to the corporation or its stockholders, (2) for acts or omissions not in good faith or which involved intentional misconduct or a knowing violation of the law, (3) under section 174 of the Delaware General Corporate Law (“DGCL”) for unlawful payment of dividends or improper redemption of stock or (4) for any transaction from which the director derived an improper personal benefit. In addition, if the DGCL is amended to authorize the further elimination or limitation of the liability of directors, then the liability of a director of the corporation, in addition to the limitation on personal liability provided for in our charter, will be limited to the fullest extent permitted by the amended DGCL. Our bylaws provide that the corporation will indemnify, and advance expenses to, any officer or director to the fullest extent authorized by the DGCL.

Section 145 of the DGCL provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses, including attorneys’ fees, judgments, fines and amounts paid in settlement in connection with specified actions, suits and proceedings whether civil, criminal, administrative, or investigative, other than a derivative action by or in the right of the corporation, if they acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe their conduct was unlawful. A similar standard is applicable in the case of derivative actions, except that indemnification extends only to expenses, including attorneys’ fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation. The statute provides that it is not exclusive of other indemnification that may be granted by a corporation’s charter, bylaws, disinterested director vote, stockholder vote, agreement, or otherwise.

Our charter also contains indemnification rights for our directors and our officers. Specifically, the charter provides that we shall indemnify our officers and directors to the fullest extent authorized by the DGCL. Further, we may maintain insurance on behalf of our officers and directors against expense, liability or loss asserted incurred by them in their capacities as officers and directors.

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We have obtained directors’ and officers’ insurance to cover our directors, officers and some of our employees for certain liabilities.

We have entered into written indemnification agreements with our directors and executive officers. Under these agreement, if an officer or director makes a claim of indemnification to us, either a majority of the independent directors or independent legal counsel selected by the independent directors must review the relevant facts and make a determination whether the officer or director has met the standards of conduct under Delaware law that would permit (under Delaware law) and require (under the indemnification agreement) us to indemnify the officer or director.

The registration rights agreement and purchase/placement agent agreement we entered into in connection with our earlier financings provide for the indemnification by the investors in those financings of our officers and directors for certain liabilities.


Item 15.	*Recent Sales of Unregistered Securities.*

In the last three years, we have sold and issued the following unregistered securities:


	1. On March 11, 2005, we issued 16,350,000 shares of our common stock in consideration of $212,877,000 before expenses to qualified institutional buyers, non-U.S. persons and accredited investors in transactions exempt from registration under Section 4(2) of the Securities Act. We paid Friedman, Billings, Ramsey & Co., Inc., who acted as placement agent in this transaction, $16,023,000 in discounts and placement fees. A selling stockholder in the offering paid an additional $10,035,200 in discounts and placement fees to Friedman, Billings, Ramsey & Co., Inc.

	2. On March 11, 2005, we issued 2,267,270 shares of restricted common stock to employees pursuant to our Equity Participation Plan. The issuance of these shares was exempt from the registration requirements of the Securities Act pursuant to Rule 701.


	3. We issued 787,360, 1,200, 5,400 and 5,000 options to purchase our common stock to employees pursuant to our Stock Incentive Plan on March 11, 2005, May 16, 2005, July 18, 2005 and July 25, 2005, respectively. The issue of those options was exempt from the registration requirements of the Securities Act pursuant to Rule 701.


	4. On March 2, 2004, we issued 29,748,130 shares of our common stock in connection with a merger of our former parent, Mariner Energy LLC, into MEI Acquisitions Holdings, LLC. The issue of those shares was exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act.


Item 16.	*Exhibits and Financial Statement Schedules.*


Exhibit
Number			Description of Document

	*3	.1	Second Amended and Restated Certificate of Incorporation of Mariner Energy, Inc.
	*3	.2	Fourth Amended and Restated Bylaws of Mariner Energy, Inc.
	*4	.1	Registration Rights Agreement among Mariner Energy, Inc. and each of the investors identified therein, dated March 11, 2005.
	*4	.2	Specimen Common Stock Certificate.
	**5	.1	Opinion of Baker Botts L.L.P. regarding legality of securities being issued.
	*10	.1	Credit Agreement by and among Mariner Energy Inc. and the Lenders party thereto, dated March 2, 2004.
	*10	.2	Amendment No. 1 and Assignment Agreement among Mariner Energy, Inc., Mariner Holdings, Inc. and Mariner Energy LLC, the Union Bank of California, N.A. and the Lenders party thereto, dated July 14, 2004.
	*10	.3	Waiver and Consent among Mariner Energy, Inc., Mariner Holdings, Inc., Mariner Energy LLC, the Union Bank of California, N.A. and the Lenders party thereto, dated December 29, 2004.

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Exhibit
Number			Description of Document

	*10	.4	Amendment No. 2 and Consent among Mariner Energy, Inc., Mariner Holdings, Inc., Mariner Energy LLC, the Union Bank of California, N.A., and the Lenders party thereto, dated February 7, 2005.
	*10	.5	Amendment No. 3 and Consent among Mariner Energy, Inc., Mariner LP LLC, Mariner Energy Texas LP, the Union Bank of California, N.A., and the Lenders party thereto, dated March 3, 2005.
	*10	.6	Form of Indemnification Agreement between Mariner Energy, Inc. and each of its directors and officers.
	*10	.7	Mariner Energy, Inc. Stock Incentive Plan, effective as of March 11, 2005.
	*10	.8	Form of Non-Qualified Stock Option Agreement, Mariner Energy, Inc. Stock Incentive Plan for employees without employment agreements.
	*10	.9	Form of Non-Qualified Stock Option Agreement, Mariner Energy, Inc. Stock Incentive plan for employees with employment agreements.
	*10	.10	Mariner Energy, Inc. Equity Participation Plan, effective March 11, 2005.
	*10	.11	Form of Restricted Stock Agreement, Mariner Energy, Inc. Equity Participation Plan for employees with employment agreements.
	*10	.12	Form of Restricted Stock Agreement, Mariner Energy, Inc. Equity Participation Plan for employees without employment agreements.
	*10	.13	Employment Agreement by and between Mariner Energy, Inc. and Scott D. Josey, dated February 7, 2005.
	*10	.14	Employment Agreement by and between Mariner Energy, Inc. and Dalton F. Polasek, dated February 7, 2005.
	*10	.15	Employment Agreement by and between Mariner Energy, Inc. and Michiel C. van den Bold, dated February 7, 2005.
	*10	.16	Employment Agreement by and between Mariner Energy, Inc. and Judd Hansen, dated February 7, 2005.
	*10	.17	Employment Agreement by and between Mariner Energy, Inc. and Teresa Bushman, dated February 7, 2005.
	*21		List of subsidiaries.
	23	.1	Consent of Deloitte & Touche LLP.
	23	.2	Consent of Ryder Scott Company, L.P.
	**23	.3	Consent of Baker Botts L.L.P. (included in Exhibit 5.1).
	*24		Power of Attorney.


*	Previously filed.


**	To be filed by amendment.

Item 17. Undertakings.

(a) The undersigned registrant hereby undertakes:


	(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:


	(i) To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933, as amended;

	(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement; and

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	(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;


	(2) That, for the purpose of determining any liability under the Securities Act of 1933, as amended, each such post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

	(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

(b) Insofar as indemnification for liabilities arising under the Securities Act of 1933, as amended, may be permitted to directors, officers, and controlling persons of the registrant pursuant to the provisions described in Item 14 or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission, such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer, or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on July 26, 2005.


	Mariner Energy, Inc.


	By: /s/ Scott D. Josey


	Name: Scott D. Josey


	Title:	Chairman of the Board, Chief Executive


	Officer and President


Signature		Title


* Scott D. Josey		Chairman of the Board, Chief Executive Officer and President (Principal Executive Officer)

/s/ Rick G. Lester Rick G. Lester		Vice President, Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)

* Bernard Aronson		Director

* Jonathan Ginns		Director

* Pierre F. Lapeyre, Jr.		Director

* David M. Leuschen		Director

*By:	/s/ Rick G. Lester Attorney-in-fact

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INDEX TO EXHIBITS


Exhibit
Number			Description of Document

	*3	.1	Second Amended and Restated Certificate of Incorporation of Mariner Energy, Inc.
	*3	.2	Fourth Amended and Restated Bylaws of Mariner Energy, Inc.
	*4	.1	Registration Rights Agreement among Mariner Energy, Inc. and each of the investors identified therein, dated March 11, 2005.
	*4	.2	Specimen Common Stock Certificate.
	**5	.1	Opinion of Baker Botts L.L.P. regarding legality of securities being issued.
	*10	.1	Credit Agreement by and among Mariner Energy Inc. and the Lenders party thereto, dated March 2, 2004.
	*10	.2	Amendment No. 1 and Assignment Agreement among Mariner Energy, Inc., Mariner Holdings, Inc. and Mariner Energy LLC, the Union Bank of California, N.A. and the Lenders party thereto, dated July 14, 2004.
	*10	.3	Waiver and Consent among Mariner Energy, Inc., Mariner Holdings, Inc., Mariner Energy LLC, the Union Bank of California, N.A. and the Lenders party thereto, dated December 29, 2004.
	*10	.4	Amendment No. 2 and Consent among Mariner Energy, Inc., Mariner Holdings, Inc., Mariner Energy LLC, the Union Bank of California, N.A., and the Lenders party thereto, dated February 7, 2005.
	*10	.5	Amendment No. 3 and Consent among Mariner Energy, Inc., Mariner LP LLC, Mariner Energy Texas LP, the Union Bank of California, N.A., and the Lenders party thereto, dated March 3, 2005.
	*10	.6	Form of Indemnification Agreement between Mariner Energy, Inc. and each of its directors and officers.
	*10	.7	Mariner Energy, Inc. Stock Incentive Plan, effective as of March 11, 2005.
	*10	.8	Form of Non-Qualified Stock Option Agreement, Mariner Energy, Inc. Stock Incentive Plan for employees without employment agreements.
	*10	.9	Form of Non-Qualified Stock Option Agreement, Mariner Energy, Inc. Stock Incentive Plan for employees with employment agreements.
	*10	.10	Mariner Energy, Inc. Equity Participation Plan, effective March 11, 2005.
	*10	.11	Form of Restricted Stock Agreement, Mariner Energy, Inc. Equity Participation Plan for employees with employment agreements.
	*10	.12	Form of Restricted Stock Agreement, Mariner Energy, Inc. Equity Participation Plan for employees without employment agreements.
	*10	.13	Employment Agreement by and between Mariner Energy, Inc. and Scott D. Josey, dated February 7, 2005.
	*10	.14	Employment Agreement by and between Mariner Energy, Inc. and Dalton F. Polasek, dated February 7, 2005.
	*10	.15	Employment Agreement by and between Mariner Energy, Inc. and Michiel C. van den Bold, dated February 7, 2005.
	*10	.16	Employment Agreement by and between Mariner Energy, Inc. and Judd Hansen, dated February 7, 2005.
	*10	.17	Employment Agreement by and between Mariner Energy, Inc. and Teresa Bushman, dated February 7, 2005.
	*21		List of subsidiaries.
	23	.1	Consent of Deloitte & Touche LLP.
	23	.2	Consent of Ryder Scott Company, L.P.
	**23	.3	Consent of Baker Botts L.L.P. (included in Exhibit 5.1).
	*24		Power of Attorney (contained on the signature page hereto).


*	Previously filed.


**	To be filed by amendment.