Edgar Filing: MARINER ENERGY INC

e424b3

Filed pursuant to Rule 424(b)(3)

Registration No. 333-124858

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. Because all of the shares being offered under this prospectus are being offered by selling stockholders, we cannot currently determine the price or prices at which our shares of common stock may be sold under this prospectus. Prior to the date of this prospectus, we are aware that some of our shares of common stock have been sold in private resale transactions. We understand those sales have been reported to the PORTAL^® Market. To our knowledge, the most recent price at which shares were resold was $20.50 per share on February 7, 2006. Future prices will likely vary from that price and these sales may not be indicative of prices at which our common stock will trade. Until our shares of common stock are listed on the New York Stock Exchange, we expect that the selling stockholders will sell their shares at prices between $19.50 and $21.50, if any shares are sold. Please read “Plan of Distribution.”

Prior to this offering, there has been no public market for our common stock. Our common stock has been approved for listing on the New York Stock Exchange, subject to the completion of our proposed merger with Forest Energy Resources, Inc.

Investing in our common stock involves risks. You should read the section entitled “Risk Factors” beginning on page 24 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 February 10, 2006.

TABLE OF CONTENTS


WHERE YOU CAN FIND MORE INFORMATION			i
SUMMARY			1
SUMMARY SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA			13
RISK FACTORS			24
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS			38
USE OF PROCEEDS			39
CAPITALIZATION			39
DILUTION			40
DIVIDEND POLICY			40
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA			41
UNAUDITED PRO FORMA COMBINED CONDENSED FINANCIAL INFORMATION			44
STRENGTHS AND STRATEGIES OF MARINER FOLLOWING THE MERGER			52
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			55
BUSINESS			79
THE SPIN-OFF AND MERGER			95
THE MERGER AGREEMENT			118
THE DISTRIBUTION AGREEMENT			132
ANCILLARY AGREEMENTS			135
FINANCING ARRANGEMENTS RELATING TO THE SPIN-OFF AND THE MERGER			138
SELECTED CONSOLIDATED STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF THE FOREST GULF OF MEXICO OPERATIONS			140
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF THE FOREST GULF OF MEXICO OPERATIONS			141
THE FOREST GULF OF MEXICO OPERATIONS			146
FOREST OIL CORPORATION			154
MANAGEMENT OF MARINER			155
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			168
CERTAIN TRANSACTIONS WITH AFFILIATES AND MANAGEMENT			170
SELLING STOCKHOLDERS			170
PLAN OF DISTRIBUTION			182
DESCRIPTION OF CAPITAL STOCK			184
REGISTRATION RIGHTS			188
EXPERTS			190
LEGAL MATTERS			190
GLOSSARY OF OIL AND NATURAL GAS TERMS			191
INDEX TO FINANCIAL STATEMENTS			F-1
REPORT OF RYDER SCOTT COMPANY, L.P., INDEPENDENT PETROLEUM ENGINEERS			A-1

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

(i)

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 100 F Street, N.E., 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.

(ii)

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 24 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 191 of this prospectus.

In this prospectus:


	•	The terms “we”, “us”, “our” and like terms, and the term “Mariner,” refer to Mariner Energy, Inc.;

	•	“MEI Sub” refers to MEI Sub, Inc.;

	•	“Forest” refers to Forest Oil Corporation;

	•	“Forest Energy Resources” refers to Forest Energy Resources, Inc.; and

	•	“Forest Gulf of Mexico operations” refers to the offshore Gulf of Mexico operations conducted by Forest that have been contributed to Forest Energy Resources and the shares of which will be spun-off to Forest shareholders.

About Mariner Energy, Inc.

Mariner Energy, Inc. 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. As of December 31, 2004, we had 237.5 Bcfe of estimated 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 estimated proved reserves, before income tax (“PV10”), was approximately $668 million, and our standardized measure of discounted future net cash flows attributable to its estimated proved reserves was approximately $494.4 million. Please see “Business— Estimated Proved Reserves” for a reconciliation of PV10 to the standardized measure of discounted future net cash flows. As of December 31, 2004, approximately 46% of our estimated proved reserves were classified as proved developed. For the year ended December 31, 2004, our total net production was 37.6 Bcfe. Of our estimated proved reserves, 48% are 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 million of capital on acquisitions, exploration and development while adding approximately 191 Bcfe of estimated proved reserves and producing approximately 111 Bcfe.

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.


									Approximate				Date		Estimated
						Mariner			Water		Gross		Production		Proved
						Working			Depth		Producing		Commenced/		Reserves		PV10		Standardized
			Operator			Interest			(Feet)		Wells(1)		Expected		(Bcfe)		Value(2)		Measure

						%											(in $ millions)		(in $ millions)
West Texas Permian Basin:
	Aldwell Unit			Mariner			66.5	(3)		Onshore		185		1949		112.7	$	203.8
Gulf of Mexico Deepwater:
	Mississippi Canyon 296/252 (Rigel)			Dominion			22.5			5,200		0	Second Quarter 2006			22.4		82.9
	Viosca Knoll 917/961/962 (Swordfish)			Mariner(4	)		15.0			4,700		2	Fourth Quarter 2005			13.4		59.3
	Green Canyon 516 (Yosemite)			ENI			44.0			3,900		1		2002		15.1		66.6
	Mississippi Canyon 718 (Pluto)(5)			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		0		2002		1.2		2.0
Gulf of Mexico Shelf:
	Mississippi Canyon 66 (Ochre)(6)			Mariner			75.0			1,150		0		2004		3.6		11.7
	Other Properties											43				56.1		195.7

		Total:										231				237.5	$	668.0	$	494.4


(1)	Wells producing or capable of producing as of December 31, 2004.

(2)	Please see “Business— Estimated Proved Reserves” for a definition of PV10 and a reconciliation of PV10 to the standardized measure of discounted future net cash flows.

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

(4)	Mariner served as operator until December 2005, at which time pursuant to certain contractual arrangements, Noble Energy, Inc., a 60% partner in the project, began serving as operator.

(5)	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 second quarter of 2006.

(6)	Field has been shut in since September 2004 due to destruction of host platform by Hurricane Ivan.

prospects, 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. 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 in West Texas. Through September 30, 2005, we had drilled 65 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. Our net production from onshore wells for the nine months ended September 30, 2005 averaged approximately 17 MMcfe per day. We have completed construction of our own oil and gas gathering system 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 August 2005, but effective in October 2005, we entered into an agreement covering approximately 33,000 acres in West Texas, pursuant to which, upon closing, we acquired an approximate 35% working interest in approximately 200 existing producing wells effective November 1, 2005, and committed to drill an additional 150 wells within a four year period, funding $36.5 million of our partner’s share of drilling costs for such 150-well drilling program. We will obtain an assignment of an approximate 35% working interest in the entire committed acreage upon completion of the 150-well program.


	*Gulf of Mexico Deepwater*

As of September 30, 2005 we held interests in 11 fields in the Gulf of Mexico deepwater, four 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 the nine months ended September 30, 2005 averaged approximately 33 MMcfe per day (see “Recent Developments” below for a discussion of the effects of hurricanes Katrina and Rita). As of September 30, 2005, we held interests in 55 Gulf of Mexico blocks with water depths of over 1,300 feet and had approximately 132,000 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. 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. Currently approximately 7 MMcfe per day of production remains shut-in awaiting repairs due to Hurricanes Katrina and Rita, primarily associated with the Baccarat property. While we believe physical damage to our existing platforms and facilities was relatively minor from both hurricanes, the effects of the storms caused damage to onshore pipeline and processing

facilities that resulted in a portion of our production being temporarily shut-in, or in the case of our Swordfish project, postponed. In addition, Hurricane Katrina caused damage to platforms that host three of our development projects: Pluto, Rigel, and Mississippi Canyon 66 (Ochre). Repairs to these facilities may take up to six months, pushing commencement of production on these projects into 2006.


	*Gulf of Mexico Shelf*

In the past two years, we have increased our drilling activities on the Gulf of Mexico shelf. As of September 30, 2005, we held interests in 21 fields on the Gulf of Mexico shelf, eight 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 the nine months ended September 30, 2005 averaged approximately 32 MMcfe per day (see “Recent Developments” below for a discussion of the effects of hurricanes Katrina and Rita). As of September 30, 2005, we held interests in 59 Gulf of Mexico shelf blocks and had approximately 81,000 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

Approximately 29 Mmcfe per day of natural gas and approximately 3,000 bbls per day of oil and condensate net to our interest were initially shut-in as a result of the effects of Hurricane Katrina in August 2005. The majority of this production was returned within two weeks of the hurricane, and substantially all within three weeks of the hurricane. Additionally, we are experiencing delays in startup of three of our projects primarily as a result of Hurricane Katrina which is anticipated to defer commencement of production to as late as the second quarter of 2006. Approximately 60 MMcfe per day of production net to our interest was shut-in initially as a result of the effects of Hurricane Rita in late September 2005. Approximately 53 MMcfe per day of production, or approximately 90% of our pre-hurricane production, was restored within two weeks of the hurricane. Our operated platforms appear to have sustained minimal damage attributable to the storm. First reports from operators of other facilities handling our production indicated varying degrees of damage to their facilities, the full extent of which may not be known for some time. Although a submersible rig engaged in drilling operations on our East Cameron Block 79 property was moved off location by Hurricane Rita, a substitute rig was subsequently provided, the damage to the well was repaired and drilling recommenced in the last quarter of 2005. Other planned operations also are delayed as a result of the effects of both hurricanes. We cannot estimate a range of loss arising from the hurricanes until we are able to more completely assess the impacts on our properties and the properties of our operational partners. Until we are able to complete all the repair work and submit costs to our insurance underwriters for review, the full extent of our insurance recovery and the resulting net cost to us for Hurricanes Katrina and Rita will be unknown. For the insurance period ending September 30, 2005, we carry a $3.0 million annual deductible and a $.375 million single occurrence deductible.

We entered into an agreement effective in October 2005 covering approximately 33,000 acres in West Texas, pursuant to which, upon closing, we acquired an approximate 35% working interest in approximately 200 existing producing wells effective November 1, 2005, and committed to drill an additional 150 wells within a four year period, funding $36.5 million of our partner’s share of drilling costs for such 150-well drilling program. We will obtain an assignment of an approximate 35% working interest in the entire committed acreage upon completion of the 150-well program.

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		Our common stock has been approved for listing on the New York Stock Exchange, subject to the completion of our proposed merger with Forest Energy Resources, Inc.

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 24 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.

Corporate Information

We were incorporated in August 1983 as a Delaware corporation. We have three subsidiaries, Mariner LP LLC, a Delaware limited liability company, Mariner Energy Texas LP, a Delaware limited partnership, and MEI Sub, Inc., a Delaware corporation.

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, after the private placement an affiliate of our former sole stockholder beneficially owned 5.3% of our outstanding common stock. See “Security Ownership of Certain Beneficial Owners and Management.”

Our principal executive office is located at One Briar Lake Plaza, Suite 2000, 2000 West Sam Houston Parkway South, Houston, Texas 77042. Our telephone number is (713) 954-5500.

Proposed Merger with Forest Energy Resources, Inc.

On September 9, 2005, we entered into a merger agreement with Forest Oil Corporation (which we refer to as Forest), Forest Energy Resources, Inc. (which we refer to as Forest Energy Resources), and MEI Sub, Inc. The consummation of the transactions contemplated by the merger agreement is subject to several conditions, including the adoption of the merger agreement by our stockholders. Accordingly, we cannot assure you that the merger and related transactions will ever be consummated. Our annual stockholder meeting, at which Mariner stockholders will vote to adopt the merger agreement, is scheduled to occur on March 2, 2006.

The following provides a summary of the material terms of the transactions contemplated by the merger agreement.

Overview of the Proposed Transactions

Forest has transferred and contributed the assets and certain liabilities associated with its offshore Gulf of Mexico operations to Forest Energy Resources, a newly formed subsidiary of Forest. Immediately prior to the merger, Forest will distribute all of the outstanding shares of Forest Energy Resources to Forest shareholders on a pro rata basis. Forest Energy Resources will then merge with a newly formed subsidiary of Mariner, and become a new wholly owned subsidiary of Mariner. When the merger is complete, approximately 58% of the Mariner common stock will be held by shareholders of Forest and approximately 42% of Mariner common stock will be held by the pre-merger stockholders of Mariner, each on a pro forma basis.

Following the merger, Mariner will:


	•	be an independent public company;

	•	own both the Mariner operations and the Forest Gulf of Mexico operations; and

	•	have total assets of approximately $2.1 billion and total debt of approximately $279.0 million on a pro forma combined basis, assuming the spin-off and the merger occurred on September 30, 2005.

About Forest and Forest Energy Resources

Forest is an independent oil and gas company engaged in the acquisition, exploration, development and production of natural gas and liquids in North America and selected international locations. Forest was incorporated in New York in 1924, as the successor to a company formed in 1916, and has been a publicly held company since 1969. Forest operates from offices located in Denver, Colorado; Lafayette and Metairie, Louisiana; Anchorage, Alaska; and Calgary, Alberta, Canada.

Forest Energy Resources is a wholly owned subsidiary of Forest. Forest Energy Resources was formed in Delaware on August 18, 2005 for the purpose of completing the spin-off of the Forest Gulf of Mexico operations. As of December 31, 2004, the Forest Gulf of Mexico operations that have been contributed to Forest Energy Resources had 339.7 Bcfe of estimated proved reserves, of which approximately 79% were natural gas and 21% were oil and condensate. As of December 31, 2004, the PV10 of the Forest Gulf of Mexico operations was approximately $1,222.2 million, and the standardized measure of discounted future net cash flows attributable to its estimated proved reserves was approximately $925.8 million. Please see “The Forest Gulf of Mexico Operations— Estimated Proved Reserves” for a reconciliation of PV10 to the standardized measure of discounted future net cash flows. As of December 31, 2004, approximately 76% of the Forest Gulf of Mexico operations’ estimated proved reserves were classified as proved developed. For the year ended December 31, 2004, the Forest Gulf of Mexico operations’ total net production was 81.1 Bcfe. In the three-year period ended December 31, 2004, the Forest Gulf of Mexico operations deployed approximately $560 million of capital on acquisitions, exploration and development while adding approximately 182 Bcfe of estimated proved reserves and producing approximately 215 Bcfe.

Transaction Structure

The following diagrams and accompanying descriptions serve to describe generally the transactions that will take place in connection with the spin-off and merger. For more information, please read “The Spin-off and Merger.”


1.	*Current Corporate Ownership Structure*

Forest Energy Resources is a wholly owned subsidiary of Forest. MEI Sub is a wholly owned subsidiary of Mariner.


2.	*The Contribution and Spin-Off*

Forest has contributed the assets and certain liabilities associated with its Gulf of Mexico operations to Forest Energy Resources. Forest will, immediately prior to the merger, distribute all of the shares of Forest Energy Resources to its shareholders on a pro rata basis.


3.	*The Merger*

MEI Sub will merge with and into Forest Energy Resources, with Forest Energy Resources surviving as a wholly owned subsidiary of Mariner. Forest Energy Resources will be renamed Mariner Energy Resources, Inc. In conjunction with the merger, shares of Forest Energy Resources stock will automatically be converted into shares of Mariner stock.


4.	*Corporate Ownership Structure following the Spin-Off and Merger*

At the conclusion of the merger, Forest shareholders will own approximately 58% of Mariner and the stockholders of Mariner who owned shares prior to the merger will own the remaining approximately 42% of Mariner.

What Forest and Mariner Stockholders Will Receive

If the merger is completed, each Forest shareholder will ultimately receive shares of Mariner common stock. As a result of the spin-off, Forest shareholders will initially receive shares of Forest Energy Resources, which will then be converted in the merger into the right to receive shares of Mariner. After the merger, Forest shareholders will be entitled to receive approximately 0.8 shares of Mariner for each Forest share that they own. Forest shareholders will not be required to pay for the shares of Forest Energy Resources distributed in the spin-off transaction or the shares of Mariner issued in the merger.

Mariner stockholders will keep the shares of Mariner common stock they currently own, but will not receive any additional shares in the merger.

Proposal to Amend Mariner’s Certificate of Incorporation

We are proposing to amend Mariner’s certificate of incorporation to increase the number of authorized shares of stock from 90 million to 200 million, subject to completion of the merger. Mariner’s certificate of incorporation currently does not authorize a sufficient number of shares of common stock to complete the merger. Mariner currently is authorized to issue 70 million shares of Mariner common stock and 20 million shares of Mariner preferred stock. As of February 1, 2006, approximately 35.6 million shares of Mariner common stock were issued and outstanding. Under the terms of the merger agreement, Mariner must issue approximately 50.6 million shares (representing approximately 0.8 shares of Mariner common stock for each share of Forest common stock) of common stock in the merger, which would result in approximately 86 million shares of Mariner common stock outstanding. Therefore, the number of authorized shares of Mariner common stock must be increased in order to complete the merger.

Recommendation of Mariner’s Board of Directors

The Mariner board of directors has determined that the merger is fair to and in the best interests of Mariner and its stockholders, and that the merger agreement is advisable. The Mariner board of directors has unanimously approved the merger agreement and the other proposals and recommends that the Mariner stockholders vote “for” the adoption of the merger agreement and the other proposals. A more detailed description of the background and reasons for the merger is set forth under “The Spin-Off and Merger” beginning on page 95.

When considering the recommendations of the Mariner board of directors, you should be aware that the directors and executive officers of Mariner have interests and arrangements that may be different from your interests as stockholders, including:


	•	arrangements regarding the appointment of directors and officers of Mariner following the merger; and

	•	arrangements whereby the executive officers of Mariner will receive a cash payment of $1,000 each in exchange for the waiver of certain rights under their employment agreements, including the automatic vesting or acceleration of restricted stock and options upon the completion of the merger and the right to receive a lump sum cash payment if the officer voluntarily terminates employment without good reason within nine months following the completion of the merger.

At the close of business on February 1, 2006, directors and executive officers of Mariner and their affiliates as a group beneficially owned and were entitled to vote approximately 3.7 million shares of Mariner common stock (including restricted stock subject to vesting), representing approximately 10.4% of the shares of Mariner common stock outstanding on that date. All of the directors and executive officers of Mariner who are entitled to vote at the annual meeting of stockholders have indicated that they intend to vote their shares of Mariner common stock in favor of adoption of the merger agreement.

In reaching its decision on the merger, the Mariner board of directors considered a number of factors, including the following among others:


	•	the increased size of the combined company could reduce volatility and allow it to participate in larger scale drilling projects and acquisition opportunities;

	•	the merger would be expected to increase Mariner’s estimated proved reserves and undeveloped acreage;

	•	the merger could generate increased visibility in the capital markets and trading liquidity for the combined company;

	•	the merger would increase the number of Mariner’s producing fields, thereby reducing Mariner’s dependence on a concentrated number of properties;

	•	the merger would be consummated only if approved by the holders of a majority of the Mariner common stock; and

	•	the merger is structured as a tax-free reorganization for U.S. federal income tax purposes and, accordingly, would not be taxable either to Mariner or its stockholders.

The Mariner board of directors also identified and considered some risks and potential disadvantages associated with the merger, including, among others, the following:


	•	the risk that there may be difficulties in combining the business of Mariner and the Forest Gulf of Mexico operations;

	•	the risk that the potential benefits sought in the merger might not be fully realized;

	•	the risk that the proved undeveloped, probable and possible reserves of the Forest Gulf of Mexico operations may never be converted to proved developed reserves; and

	•	the fact that, in order to preserve the tax-free treatment of the spin-off, Mariner would be required to abide by restrictions that could reduce its ability to engage in certain business transactions.

In the judgment of the Mariner board of directors, the potential benefits of the merger outweigh the risks and the potential disadvantages.

Opinion of Mariner’s Financial Advisor

Lehman Brothers Inc., Mariner’s financial advisor, has delivered to Mariner’s board of directors a written opinion that, as of September 9, 2005, based upon and subject to the factors and assumptions set forth in the opinion, the exchange ratio in the merger was fair from a financial point of view to Mariner.

Directors and Officers of Mariner Following the Merger

If the merger is completed, Mariner’s board will consist of seven members, five of whom will be the current directors of Mariner, and two of whom will be mutually agreed between Mariner and Forest prior to the completion of the merger. The Chairman of the Mariner board will be Mr. Scott D. Josey, the current Chairman, Chief Executive Officer and President of Mariner. The two Mariner directors to be mutually agreed by Forest and Mariner pursuant to the terms of the merger agreement have not yet been designated.

The current executive officers of Mariner will remain in their current positions following the merger.

Material United States Federal Tax Consequences of the Merger

It is a condition to the completion of the merger that Forest, Forest Energy Resources and Mariner receive opinions from their respective tax counsels to the effect that the merger will constitute a tax-free reorganization for U.S. federal income tax purposes. As a tax-free reorganization for U.S. federal income tax purposes, the merger will be tax-free to the stockholders of Mariner and tax-free to the shareholders of Forest, except for cash received in lieu of fractional shares of Mariner for shares of Forest Energy Resources.

We encourage you to consult your own tax advisor for a full understanding of the tax consequences of the merger to you.

Conditions to the Completion of the Merger

The merger will be completed only if certain conditions, including the following, are satisfied (or waived in certain cases):


	•	the adoption of the merger agreement by Mariner stockholders holding a majority of the Mariner common stock and the approval of the proposed amendment to Mariner’s certificate of incorporation;

	•	the absence of legal restrictions that would prevent the completion of the transactions;

	•	the receipt by Forest, Mariner and Forest Energy Resources of an opinion from their respective counsel to the effect that the merger will be treated as a reorganization for federal income tax purposes;

	•	the completion of the spin-off in accordance with the distribution agreement;

	•	the receipt of material consents, approvals and authorizations of governmental authorities;

	•	the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Act;

	•	the SEC declaring effective the registration statements of Mariner relating to the shares of Mariner common stock to be issued in the merger and those shares held by its existing stockholders;

	•	the representations and warranties contained in the merger agreement being materially true and correct, and the performance in all material respects by the parties of their covenants and other agreements in the merger agreement;

	•	the approval for listing on the New York Stock Exchange or Nasdaq of Mariner’s common stock; and


	•	Mariner and Forest receiving the consents required pursuant to their credit facilities (with Mariner or Forest Energy Resources having entered into a new or amended credit facility sufficient to operate the combined businesses), and Forest receiving any consents required from its bondholders.

On November 14, 2005, the waiting period under the Hart-Scott-Rodino Act with respect to the merger expired. On October 19, 2005, Forest received the consent required pursuant to its credit facility. On February 7, 2006, Mariner’s common stock was approved for listing on the New York Stock Exchange upon the completion of the merger. As of February 7, 2006, no other conditions to closing have been satisfied. Mariner is currently negotiating the definitive documents for its new credit facility, which documents also will grant the consent required pursuant to its existing facility. Mariner and Forest are actively working to obtain necessary consents, approvals and authorizations from governmental authorities, including the Minerals Management Service.

Based on its current valuation of the Forest Gulf of Mexico operations and the current amount of distributions permitted by the covenants contained in the indentures governing Forest’s outstanding bonds, Forest believes that no consents of its bondholders will be required for the spin-off and the merger. If Forest’s belief that bondholder consents are not necessary remains unchanged as the merger closing approaches, it intends to waive conditions in the merger agreement and distribution agreement related to such consents.

Neither Mariner nor Forest currently believes that any other condition to closing is likely to be waived.

Pursuant to the terms of the merger agreement, the closing of the merger will occur as promptly as practicable, and in no event later than the second business day following the satisfaction or, if permissible, waiver of the conditions to closing set forth in the merger agreement, or at such other time as Mariner and Forest Energy Resources mutually agree. Unless Mariner consents otherwise, the closing will not occur earlier than the fifth business day following the record date for the spin-off.

Termination of the Merger Agreement

Forest and Mariner may mutually agree to terminate the merger agreement without completing the merger. In addition, either party may terminate the merger agreement if:


	•	the other party breaches its representations, warranties, covenants or agreements under the merger agreement so as to create a material adverse effect, and the breach has not been cured within 30 days after notice was given of such breach;

	•	the parties do not complete the merger by March 31, 2006;

	•	a governmental order prohibits the merger; or

	•	Mariner does not receive the required approval of its stockholders.

In addition, Mariner may terminate the merger agreement if it receives a proposal to acquire Mariner that Mariner’s board of directors determines in good faith to be more favorable to Mariner’s stockholders than the merger. Forest may terminate the merger agreement if Mariner’s board of directors withdraws or modifies its approval of the merger to Mariner’s stockholders.

Termination Fee and Expenses

Mariner must pay Forest a termination fee of $25 million and out-of-pocket fees and expenses of up to $5 million if Mariner terminates the merger agreement to accept an alternative proposal that Mariner’s board of directors determines in good faith to be more favorable to Mariner’s stockholders than the merger. In addition, Mariner must pay Forest a termination fee of $25 million and reimbursement of

out-of-pocket fees and expenses of up to $5 million if the merger agreement is terminated for the other reasons set forth under “The Merger Agreement— Termination Fees and Expenses” on page 130.

Financing Arrangements Relating to the Spin-Off and the Merger

At the closing of the merger Mariner and Mariner Energy Resources expect to enter into a new $500 million senior secured revolving credit facility, and Mariner will enter into an additional $40 million senior secured letter of credit facility. The revolving credit facility will mature on the fourth anniversary of the closing, and the letter of credit facility will mature on the third anniversary of the closing. The outstanding principal balance of loans under the revolving credit facility may not exceed the borrowing base, which will be initially set at $400 million. In addition, Forest Energy Resources expects to enter into a new senior term loan facility in connection with the spin-off, which facility is expected to be repaid with borrowings under Mariner’s and Mariner Energy Resources’ $500 million revolving credit facility.

Ancillary Agreements

In addition to the merger agreement and the distribution agreement, Forest, Forest Energy Resources and Mariner have entered into a tax sharing agreement relating to the allocation of certain tax liabilities. See “Ancillary Agreements— Tax Sharing Agreement” beginning on page 135. In addition, Forest and Forest Energy Resources have entered into an employee benefits agreement addressing certain benefits matters for former Forest employees who become employees of Forest Energy Resources in connection with the spin-off and the merger. See “Ancillary Agreements— Employee Benefits Agreement” beginning on page 136. Finally, Forest and Forest Energy Resources have entered into a transition services agreement under which Forest will provide certain services to Forest Energy Resources for a limited period of time following the merger. See “Ancillary Agreements— Transition Services Agreement” beginning on page 137.

Regulatory Matters

None of the parties is aware of any other material governmental or regulatory approval required for the completion of the merger, other than the effectiveness of the registration statement of which this prospectus is a part and the effectiveness of Mariner’s registration statement on Form S-4 relating to the shares of Mariner common stock to be issued to Forest shareholders in the merger, and compliance with applicable antitrust law (including the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended) and the corporate law of the State of Delaware. On November 14, 2005, the waiting period under the Hart-Scott-Rodino Act with respect to the merger expired.

Mariner Stockholder Vote

Our annual stockholder meeting, at which Mariner stockholders will vote to adopt the merger agreement, is scheduled to occur on Thursday, March 2, 2006. For the merger to occur, the holders of a majority of the outstanding Mariner common stock must adopt the merger agreement and approve the amendment to the certificate of incorporation. Mariner stockholders will have one vote for each share of Mariner common stock they own. On February 1, 2006, the record date for Mariner’s annual meeting, 35,615,400 shares of Mariner common stock were issued and outstanding and entitled to vote at the meeting. The approval of Forest shareholders is not required for the spin-off or the merger.

Closing of the Transactions

If the merger agreement and the proposed amendment to the certificate of incorporation are adopted and approved by the stockholders of Mariner, then Mariner, Forest, Forest Energy Resources and MEI Sub expect to complete the spin-off and the merger as soon as possible after the satisfaction (or waiver, where permissible) of the other conditions to the spin-off and the merger. We currently anticipate that the merger will be completed during the first calendar quarter of 2006.

SUMMARY SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

Sources of Information

The following is summary selected consolidated financial data of Mariner and selected consolidated financial data of the Forest Gulf of Mexico operations. We derived this information from the audited and unaudited financial statements for Mariner and from the audited and unaudited statements of revenues and direct operating expenses of the Forest Gulf of Mexico operations for the periods presented. You should read this information in conjunction with the financial information included elsewhere in this prospectus. See “Index to Financial Statements” on page F-1 and “Unaudited Pro Forma Combined Condensed Financial Information” beginning on page 44.

How We Prepared the Unaudited Pro Forma Combined Condensed Financial Information

The unaudited pro forma combined condensed financial information is presented to show you how Mariner might have looked if the Forest Gulf of Mexico operations had been an independent company and combined with Mariner for the periods presented. We prepared the pro forma financial information using the purchase method of accounting, with Mariner treated as the acquiror. See “The Spin-Off and Merger— Accounting Treatment” beginning on page 117.

If the Forest Gulf of Mexico operations had been an independent company, and if Mariner and the Forest Gulf of Mexico operations had been combined in the past, they might have performed differently. You should not rely on the pro forma financial information as an indication of the financial position or results of operations that Mariner would have reported if the spin-off and merger had taken place earlier or of the future results that Mariner will achieve after the merger. See “Unaudited Pro Forma Combined Condensed Financial Information” beginning on page 44.

Summary Historical Consolidated Financial Data of Mariner

The following table shows Mariner’s summary historical consolidated financial data as of and for each of the four years ended December 31, 2003, the period from January 1, 2004 through March 2, 2004, the period from March 3, 2004 through December 31, 2004, the period from March 3, 2004 through September 30, 2004 and the nine-month period ended September 30, 2005. The summary historical consolidated financial data as of and for the four years ended December 31, 2003, the period from January 1, 2004 through March 2, 2004 and the period from March 3, 2004 through December 31, 2004 are derived from Mariner’s audited financial statements included herein, and the summary historical consolidated financial data for the period from March 3, 2004 through September 30, 2004 and the nine-month period ended September 30, 2005 are derived from unaudited financial statements of Mariner. You should read the following data in connection with “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. Mariner’s historical results are not necessarily indicative of results to be expected in future periods.

On March 2, 2004, Mariner’s former indirect parent, Mariner Energy LLC, merged with MEI Acquisitions, LLC, an affiliate of the private equity funds, Carlyle/ Riverstone Global Energy and Power Fund II, L.P. and ACON Investments LLC. The financial information contained herein is presented in the style of Pre-2004 Merger activity (for all periods prior to March 2, 2004) and Post-2004 Merger activity (for the March 3, 2004 through December 31, 2004 period and the March 3, 2004 through September 30, 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.


			Post-2004 Merger									Pre-2004 Merger

									Period from			Period from
						Period from			March 3,			January 1,
			Nine Months			March 3,			2004			2004
			Ended			2004 through			through			through			Year Ended December 31,
			September 30,			September 30,			December 31,			March 2,
			2005			2004			2004			2004			2003			2002			2001			2000

			(in millions, except per share data)
Statement of Operations Data:
	Total revenues(1)		$	151.2		$	122.5		$	174.4		$	39.8		$	142.5		$	158.2		$	155.0		$	121.1
	Lease operating expenses			20.2			15.1			21.4			4.1			24.7			26.1			20.1			17.2
	Transportation expenses			1.7			3.7			1.9			1.1			6.3			10.5			12.0			7.8
	Depreciation, depletion and amortization			43.4			37.4			54.3			10.6			48.3			70.8			63.5			56.8
	Impairment of production equipment held for use			0.5			1.0			1.0			—			—			—			—			—
	Derivative settlement			—			—			—			—			3.2			—			—			—
	Impairment of Enron related receivables			—			—			—			—			—			3.2			29.5			—
	General and administrative expenses			26.7			6.2			7.6			1.1			8.1			7.7			9.3			6.5

	Operating income			58.7			59.1			88.2			22.9			51.9			39.9			20.6			32.8
	Interest income			0.7			0.2			0.2			0.1			0.8			0.4			0.7			0.1
	Interest expense			(5.4	)		(4.4	)		(6.0	)		—			(7.0	)		(10.3	)		(8.9	)		(11.0	)

	Income before income taxes			54.0			54.9			82.4			23.0			45.7			30.0			12.4			21.9
	Provision for income taxes			(18.4	)		(19.2	)		(28.8	)		(8.1	)		(9.4	)		—			—			—

	Income before cumulative effect of change in accounting method net of tax effects			35.6			35.7			53.6			14.9			36.3			30.0			12.4			21.9
	Income before cumulative effect per common share
		Basic		1.10			1.20			1.80			.50			1.22			1.01			.42			.74
		Diluted		1.07			1.20			1.80			.50			1.22			1.01			.42			.74
	Cumulative effect of changes in accounting method			—			—			—			—			1.9			—			—			—

	Net income		$	35.6		$	35.7		$	53.6		$	14.9		$	38.2		$	30.0		$	12.4		$	21.9

	Net income per common share
		Basic		1.10			1.20			1.80			.50			1.29			1.01			.42			.74
		Diluted		1.07			1.20			1.80			.50			1.29			1.01			.42			.74
Capital Expenditure and Disposal Data:
	Exploration, including leasehold/seismic		$	23.6		$	35.7		$	40.4		$	7.5		$	31.6		$	40.4		$	66.3		$	46.7
	Development and other			106.8			50.2			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		$	130.4		$	85.9		$	133.6		$	15.3		$	(38.3	)	$	53.8		$	74.0		$	79.1

(1) Includes effects of hedging.


		Post-2004 Merger						Pre-2004 Merger

								December 31,
		September 30,			December 31,
		2005			2004			2003		2002			2001			2000

		(in millions)
Balance Sheet Data:(1)
	Property and equipment, net, full cost method	$	393.3		$	303.8		$	207.9	$	287.6		$	290.6		$	287.8
	Total assets		502.2			376.0			312.1		360.2			363.9			335.4
	Long-term debt, less current maturities		79.0			115.0			—		99.8			99.8			129.7
	Stockholder’s equity		178.6			133.9			218.2		170.1			180.1			141.9
	Working capital (deficit)(2)		(30.2	)		(18.7	)		38.3		(24.4	)		(19.6	)		(15.4	)


(1)	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.

(2)	Working capital (deficit) excludes current derivative assets and liabilities, deferred tax assets and restricted cash.


	Post-2004 Merger									Pre-2004 Merger

							Period from			Period from
				Period from			March 3,			January 1,
	Nine Months			March 3,			2004			2004
	Ended			2004 through			through			through			Year Ended December 31,
	September 30,			September 30,			December 31,			March 2,
	2005			2004			2004			2004			2003			2002			2001			2000

	(in millions)
Other Financial Data:
EBITDA(1)	$	102.7		$	97.5		$	143.5		$	33.4		$	100.3		$	113.9		$	113.6		$	89.6
Net cash provided by operating activities		135.4			96.8			135.9			20.3			103.5			60.3			113.5			63.9
Net cash (used) provided by investing activities		(142.1	)		(85.9	)		(133.6	)		(15.3	)		38.3			(53.8	)		(74.0	)		(79.1	)
Net cash (used) provided by financing activities		8.7			(74.9	)		64.9			—			(100.0	)		—			(30.0	)		17.4
Reconciliation of Non-GAAP Measures:
EBITDA(1)	$	102.7		$	97.5		$	143.5		$	33.4		$	100.3		$	113.9		$	113.6		$	89.6
Changes in working capital		25.1			9.7			6.9			(13.2	)		21.8			(20.4	)		7.5			(15.5	)
Non-cash hedge gain(2)		(3.6	)		(5.1	)		(7.9	)		—			(2.0	)		(23.2	)		—			—
Amortization/other		0.9			0.5			0.8			—			—			(0.1	)		0.6			0.7
Stock compensation expense		17.6			—			—			—			—			—			—			—
Net interest expense		(4.7	)		(4.2	)		(5.8	)		0.1			(6.2	)		(9.9	)		(8.2	)		(10.9	)
Income tax expense		(2.6	)		(1.6	)		(1.6	)		—			(10.4	)		—			—			—

Net cash provided by operating activities	$	135.4		$	96.8		$	135.9		$	20.3		$	103.5		$	60.3		$	113.5		$	63.9

(1)

EBITDA means earnings before interest, income taxes, depreciation, depletion and amortization. For the nine months ended September 30, 2005, EBITDA includes $17.6 million in non-cash stock compensation expense related to restricted stock and stock options granted in 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.

(2)	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.

Summary Selected Consolidated Statements of Revenues and Direct Operating Expenses of the Forest Gulf of Mexico Operations

The summary selected financial data for the Forest Gulf of Mexico operations for the nine months ended September 30, 2005 and 2004 and the years ended December 31, 2004, 2003 and 2002 were derived from the historical records of Forest. You should read the following data in connection with “Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Forest Gulf of Mexico Operations” and the consolidated statements of revenues and direct operating expenses of the Forest Gulf of Mexico operations included elsewhere in this prospectus. Complete financial and operating information related to the Forest Gulf of Mexico operations, including balance sheet and cash flow information, are not presented below because the Forest Gulf of Mexico operations were not maintained as a separate business unit, and therefore the assets, liabilities or indirect operating costs applicable to the operations were not segregated.


			Nine Months Ended						Years Ended
			September 30,						December 31

			2005			2004			2004			2003			2002

			(in millions, except production data)
Statement of Operations Data:
	Oil and natural gas revenues(1)		$	326.7		$	324.4		$	453.1		$	342.0		$	228.9
	Direct Operating Expenses:
		Lease operating expenses		57.4			63.0			80.1			45.7			52.1
		Transportation		2.5			1.4			2.2			2.7			3.8
		Production taxes		1.9			1.2			1.5			1.5			1.0

	Total direct operating expenses			61.8			65.6			83.8			49.9			56.9

	Revenues in excess of direct operating expenses		$	264.9		$	258.8		$	369.3		$	292.1		$	172.0

Summary Production Data:
	Production Data:
	Natural gas (MMcf)			41,442			46,036			61,684			58,785			50,566
	Oil and condensate (MBbls)			1,845			2,004			2,624			2,143			1,974
	Natural gas liquids (MBbls)			628			186			606			2			6
	Total (MMcfe)			56,280			59,176			81,064			71,655			62,446
	Per day (MMcfe)			206			216			221			196			171
Average realized sales price per unit:
	Natural gas ($/Mcf):
		Sales price received	$	7.14		$	6.02		$	6.30		$	5.41		$	3.39
		Effects of hedging		(1.13	)		(0.45	)		(0.56	)		(0.63	)		0.17

		Net sales price received		6.01			5.57			5.74			4.78			3.56


			Nine Months Ended						Years Ended
			September 30,						December 31

			2005			2004			2004			2003			2002

			(in millions, except production data)
	Oil ($/bbl):
		Sales price received	$	51.97		$	38.13		$	40.06		$	30.19		$	24.85
		Effects of hedging		(19.95	)		(6.61	)		(8.55	)		(1.90	)		—

		Net sales price received		32.02			31.52			31.51			28.29			24.85

	Natural gas liquids ($/bbl):
		Sales price received	$	29.54		$	25.40		$	27.28		$	19.00		$	12.33
Average realized sales price per Mcfe (including effects of hedging) ($/Mcfe)			$	5.81		$	5.48		$	5.59		$	4.77		$	3.67
	Production costs per Mcfe:
	Lease operating expenses		$	1.02			1.06			0.99			0.64			0.83
	Transportation		$	0.04			0.02			0.03			0.04			0.06
	Production taxes		$	0.03			0.02			0.02			0.02			0.02


(1)	Includes effects of hedging.

Summary Selected Unaudited Pro Forma Combined Condensed Financial Information

The following summary selected unaudited pro forma combined condensed financial information has been prepared to reflect the proposed merger. This unaudited pro forma combined condensed financial information is based on the historical financial statements of Mariner and the historical statements of revenues and direct operating expenses of the Forest Gulf of Mexico operations, all of which are included in this prospectus, and the estimates and assumptions set forth in the Notes to the Unaudited Pro Forma Combined Condensed Financial Information beginning on page 44. The unaudited pro forma combined condensed operating results give effect to the merger as if it had occurred on January 1, 2004. The unaudited pro forma combined condensed balance sheet gives effect to the merger as if it had occurred on September 30, 2005.

The unaudited pro forma combined condensed financial information is for illustrative purposes only. The financial results may have been different had the Forest Gulf of Mexico operations been an independent company and had the companies always been combined. You should not rely on the unaudited pro forma combined condensed financial information as being indicative of the historical results that would have been achieved had the merger occurred in the past or the future financial results that Mariner will achieve after the merger.

The merger will be accounted for using the purchase method of accounting, with Mariner treated as the acquiror. In addition, the purchase price allocation is preliminary and will be finalized following the closing of the merger. The final purchase price allocation will be determined after closing based on the actual fair value of current assets, current liabilities, indebtedness, long-term liabilities, proven and unproven oil and gas properties, identifiable intangible assets and unvested stock options that are outstanding at closing. We are continuing to evaluate all of these items; accordingly, the final purchase price may differ in material respects from that presented in the unaudited pro forma combined condensed balance sheet.


		As of and for the
		Nine Months Ended		For the Year Ended
		September 30, 2005		December 31, 2004

		(in thousands, except per share
		and proved reserve data)
OPERATING RESULTS:
	Revenues	$	477,967	$	667,326
	Net income	$	71,221	$	106,298
Earnings per share
	Basic	$	0.86	$	1.32
	Diluted	$	0.85	$	1.32
Weighted average shares outstanding
	Basic		83,075		80,385
	Diluted		83,950		80,385
BALANCE SHEET DATA:
	Total assets	$	2,118,526
	Total debt	$	279,000
	Stockholders’ equity	$	1,152,134


		As of June 30,			As of December 31,
		2005			2004

ESTIMATED PROVED RESERVES:
	Oil (MBbls)*		29,261			25,905
	Gas (MMcf)		423,352			421,741
	Equivalent (MMcfe)		598,918			577,173
	Proved developed percentage		63.9	%		63.7	%


*	Includes 3,285.6 MBbls of natural gas liquids.

Comparative Per Share Data

The following table presents historical per share data of Mariner common stock and combined per share data of Mariner and the Forest Gulf of Mexico operations on an unaudited pro forma basis after giving effect to the spin-off and the merger. The merger will be accounted for using the purchase method of accounting, with Mariner treated as the acquiror. The combined pro forma per share data was derived from the Unaudited Pro Forma Combined Condensed Financial Information as presented beginning on page 44. The assumptions related to the preparation of the Unaudited Pro Forma Combined Condensed Financial Information are described beginning at page 44. The data presented below should be read in conjunction with the historical consolidated financial statements of Mariner and the historical statements of revenues and direct operating expenses of the Forest Gulf of Mexico operations included elsewhere in this prospectus.

The Mariner unaudited pro forma equivalent data was calculated with reference to the total number of shares of Mariner common stock expected to be outstanding after the merger, including the shares to be issued to Forest shareholders and the currently-outstanding shares of Mariner common stock.

The pro forma combined per share data may not be indicative of the operating results or financial position that would have occurred if the merger had been consummated at the beginning of the periods indicated, and may not be indicative of future operating results or financial position.


			Mariner

					Combined
			Historical		Pro Forma

Earnings per share—
	Nine months ended September 30, 2005(1)
		Basic	$	1.10	$	0.86

		Diluted	$	1.07	$	0.85

	Year ended December 31, 2004(2)
		Basic	$	2.30	$	1.32

		Diluted	$	2.30	$	1.32

Book Value per share—As of September 30, 2005(3)			$	5.01	$	13.36

Cash dividends declared per common share			$	—	$	—


(1)	Mariner’s historical basic and diluted earnings per share calculation for the nine months ended September 30, 2005 assumes Mariner had 32,438,240 and 33,312,831 weighted average shares of common stock outstanding, respectively. Mariner’s pro forma basic and diluted earnings per share calculation for the nine months ended September 30, 2005 assumes Mariner had 83,075,250 and 83,949,841 weighted average shares of common stock outstanding, respectively.

(2)	Mariner’s historical basic and diluted earnings per share calculation for the year ended December 31, 2004 assumes Mariner had 29,748,130 and 29,748,130 weighted average shares of common stock outstanding, respectively. Mariner’s pro forma basic and diluted earnings per share calculation for the year ended December 31, 2004 assumes Mariner had 80,385,140 and 80,385,140 weighted average shares of common stock outstanding, respectively.

(3)	Book value per share calculation assumes that Mariner had 35,615,400 shares of common stock outstanding and 86,252,410 combined pro forma shares of common stock outstanding as of September 30, 2005.

Summary Financial and Operational Data for the Year Ended December 31, 2005

Set forth below is summary financial and operational data for the year ended December 31, 2005 for Mariner and for the Forest Gulf of Mexico operations. This information represents the estimates of Mariner’s and Forest’s respective management teams as of the date of this prospectus, but you should be aware that this information has not been audited by Mariner’s and Forest’s independent auditors. Neither Mariner’s nor Forest’s independent auditors, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the information set forth below, nor have they expressed any opinion or any other form of assurance on such information.


	*For Mariner:*


			Year Ended
			December 31,
			2005

Statement of Operations Data:
	Total revenues(1)		$	199.7
	Direct operating expenses			32.2

	Revenues in excess of direct operating expenses		$	167.5

Summary Production Data:
	Production Data:
	Natural gas (MMcf)			18,354
	Oil (MBbls)			1,791
	Total (MMcfe)			29,098
	Per day (MMcfe)			80
Average realized sales price per unit:
	Natural gas ($/Mcf):
		Sales price received	$	8.33
		Effects of hedging		(1.67	)

		Net sales price received	$	6.66

	Oil ($/bbl):
		Sales price received	$	51.66
		Effects of hedging		(10.43	)

		Net sales price received	$	41.23

Average realized sales price per Mcfe (including effects of hedging) ($/Mcfe)			$	6.74


Estimated Proved Reserves as of December 31, 2005:
	Oil (MBbls)	21,647
	Gas (MMcf)	207,686
	Equivalent (MMcfe)	337,568
Estimated Daily Production Rate as of December 31, 2005: 75 MMcfe


(1)	Includes effects of hedging.


	*For the Forest Gulf of Mexico Operations:*


		Year Ended
		December 31,
		2005

Summary Production Data:
	Production Data:
	Natural gas (MMcf)		49,120
	Oil and condensate (MBbls)		2,070
	Natural gas liquids (MBbls)		713
	Total (MMcfe)		65,818
	Per day (MMcfe)		180

Estimated Proved Reserves as of December 31, 2005:
	Oil and condensate (MBbls)		9,271
	Gas (MMcf)		231,142
	Natural gas liquids (MBbls)		3,223
	Equivalent (MMcfe)		306,105

Estimated Daily Production Rate as of December 31, 2005: 130 MMcfe

Comparative Stock Price and Dividends

In March 2005, Mariner completed a private placement of 16,350,000 shares of its common stock to qualified institutional buyers, non-U.S. persons and accredited investors. There is no established public trading market for the shares of Mariner common stock, and it is not expected that a public trading market will be established until the completion of the merger. The shares of Mariner’s common stock issued to qualified institutional buyers in connection with its March 2005 private equity placement are eligible for the PORTAL Market^®.

Forest Energy Resources was incorporated as a wholly owned subsidiary of Forest in August 2005. There is no established public trading market for the shares of Forest Energy Resources common stock.

Mariner has not paid any cash dividends on its shares of common stock for the fiscal years 2003, 2004 or 2005, and it anticipates that it will not pay any dividends in 2006. Forest Energy Resources has not paid any cash dividends on its shares of common stock for the fiscal year 2005, and it anticipates that it will not pay any dividends in 2006. The payment of any dividends by Mariner prior to the merger is subject to the limitations included in the merger agreement and in its credit facility, and following the merger the payment of dividends by Mariner and Forest Energy Resources will be subject to restrictions included in their credit facilities.

RISK FACTORS

You should consider carefully the following risk factors, which we believe include all material risks associated with our business, the merger, and the offering of our common stock, together with all of the other information included in this prospectus, before deciding to invest in our common stock. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations. In that case, the trading price of our common stock could decline and you could lose all or part of your investment.

Risks Related to our Business and to the Combined Operations After the Merger


	*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. Oil and natural gas prices are currently at or near historical highs and may fluctuate and decline significantly in the near future. Prices for oil and natural gas fluctuate 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 (73% on a pro forma basis, including reserves of the Forest Gulf of Mexico operations) 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 and the reserves of the Forest Gulf of Mexico operations, 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 estimates we and Forest project production rates and timing of development expenditures. We and Forest 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. 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 and Forest’s 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 (36% on a pro forma basis, including reserves of the Forest Gulf of Mexico operations) were proved undeveloped.

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—Estimated Proved Reserves” for information about our oil and gas reserves and “The Forest Gulf of Mexico Operations—Estimated Proved Reserves” for more information about the oil and gas reserves of the Forest Gulf of Mexico operations.


	In estimating future net revenues from proved reserves, we and Forest assume that future prices and costs are fixed and apply a fixed discount factor. If these assumptions or discount factor are materially inaccurate, our revenues, profitability and cash flow could be materially less than our estimates.

The present value of future net revenues from our proved reserves and the proved reserves of the Forest Gulf of Mexico operations 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 and Forest base the estimated discounted future net cash flows from our proved reserves and the proved reserves of the Forest Gulf of Mexico operations 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 the proved reserves of the Forest Gulf of Mexico operations and their present value. In addition, the 10% discount factor that we and Forest 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. If the merger is consummated, the proportion of short-lived Gulf of Mexico properties relative to our total properties will increase substantially. Also, our revenues and return on capital will depend significantly on prices prevailing during these relatively short production periods. Our ability to slow or shut in production from producing wells during periods of low prices for oil and natural gas may be limited by reservoir characteristics or by our need to generate revenues to fund ongoing capital commitments or repay debt.


	*Any production problems related to our Gulf of Mexico properties could reduce our revenue, profitability and cash flow materially.*

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.

If any of these factors were to occur with respect to a particular project, we could lose all or a part of our investment in the project, or we could fail to realize the expected benefits from the project, either of which could materially and adversely affect our revenues and profitability.


	*Our exploratory drilling projects are based in part on seismic data, which is costly and cannot ensure the commercial success of the project.*

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, ability to replace reserves 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;

	•	lost or damaged 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 occurs, 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 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. For more information on the impact of recent hurricanes on Mariner’s operations and the Forest Gulf of Mexico operations, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations— Recent Developments” beginning on page 56 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Forest Gulf of Mexico Operations— Recent Developments” beginning on page 141.

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. 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 in the

shallow waters of the Gulf of Mexico. 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 ($76.9 million on a pro forma basis, including the Forest Gulf of Mexico operations). 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 public 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 (subject to certain federal tax limitations during the two-year period following the spin-off). 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 (including the Forest Gulf of Mexico properties) 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, including the Forest Gulf of Mexico properties, 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 wells or delay initial production for lack of a market or because of inadequacy or unavailability of 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 are major and large independent oil and natural gas companies, and 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. The impact of Hurricanes Katrina and Rita have resulted in escalating insurance costs and less favorable coverage terms. See “Business — Insurance Matters” and “The Forest Gulf of Mexico Operations — Insurance Matters” for more information.

Risks Related to our Business if the Merger is not Consummated


	*If the merger is not ultimately consummated, the market value of our common stock could decline, and our ability to consummate alternate acquisition transactions could be reduced.*

If the proposed merger with Forest Energy Resources is not ultimately consummated, whether because our stockholders do not adopt the merger agreement at the annual meeting or because some other condition to closing is not satisfied, the market value of our common stock could be reduced. Our stock price could be adversely affected for other reasons related to the failure to close, including due to our reduced opportunities to consummate alternate transactions, or simply because the market had perceived the failed transaction as accretive to our stockholders. In addition, we may not meet the listing requirements for listing on the New York Stock Exchange if the proposed merger is not consummated, which would disqualify us from listing our common stock on that exchange.

In addition, if the merger is not consummated our ability to enter into other merger or acquisition transactions could be hindered. Under the terms of the merger agreement, if the agreement is terminated in certain circumstances where an alternate proposal to acquire us is outstanding, we could be required to pay Forest a termination fee and expense reimbursement upon the consummation of an alternate transaction. The termination fee and expense reimbursement provisions would therefore have the effect of making it more costly to acquire us, reducing the likelihood that such an acquisition would occur. Moreover, potential acquisition partners could be deterred from pursuing transactions with us, because they may speculate that the failure was caused by due diligence problems or other issues that motivated Forest not to close the transaction.


	If the merger is not consummated, a significant part of the value of our production and reserves will be concentrated in a small number of offshore properties. As a result, any production problems or inaccuracies in reserve estimates related to those properties could reduce our revenue, profitability and cash flow materially.

During December 2005, approximately 69% of our daily production came from 19 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.


	If the merger is not consummated, the smaller size of our operations relative to those of the combined operations could reduce our ability to participate in projects or pursue acquisition opportunities that would increase our profitability.

The proposed merger with Forest Energy Resources would approximately triple the pro forma daily net production of Mariner on a stand-alone basis. If the merger is not consummated, the scale of our operations would be significantly smaller than that of the combined operations. The smaller operational scale could adversely impact our ability, relative to our ability if the merger were consummated, to participate in larger scale exploratory and development drilling projects or to pursue acquisition opportunities. The inability to participate in such transactions could reduce our profitability and adversely affect our results of operations.

Risks Related to the Spin-Off and the Merger


	*The consummation of the merger is subject to numerous conditions, many of which are beyond our control.*

The merger will be completed only if certain conditions, including the following, are satisfied (or waived in certain cases):


	•	the adoption of the merger agreement by Mariner stockholders holding a majority of the Mariner common stock and the approval of the proposed amendment to Mariner’s certificate of incorporation;

	•	the absence of legal restrictions that would prevent the completion of the transactions;

	•	the receipt by Forest, Mariner and Forest Energy Resources of an opinion from their respective counsel to the effect that the merger will be treated as a reorganization for federal income tax purposes;

	•	the completion of the spin-off in accordance with the distribution agreement;

	•	the receipt of material consents, approvals and authorizations of governmental authorities;

	•	the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Act;

	•	the SEC declaring effective the registration statements of Mariner relating to the shares of Mariner common stock to be issued in the merger and those shares held by its existing stockholders;

	•	the representations and warranties contained in the merger agreement being materially true and correct, the performance in all material respects by the parties of their covenants and other agreements in the merger agreement;

	•	the approval for listing on the New York Stock Exchange or Nasdaq of Mariner’s common stock; and

	•	Mariner and Forest receiving the consents required pursuant to their credit facilities (with Mariner or Forest Energy Resources having entered into a new or amended credit facility sufficient to operate the combined businesses), and Forest receiving any consents required from its bondholders.

We cannot assure you that the conditions to the consummation of the merger will be satisfied or waived, or that the closing will occur. Some of the conditions, such as the adoption of the merger

agreement by our stockholders, the absence of legal restrictions and the receipt of required consents are partially or completely beyond our control.


	*The market value of our common stock could decline if large amounts of our common stock are sold following the spin-off and merger.*

The market price of our common stock could decline as a result of sales of a large number of shares in the market after the completion of the spin-off and merger or the perception that these sales could occur. Immediately after the merger, Forest shareholders will hold, in the aggregate, approximately 58% of our common stock on a pro forma basis. Currently, Forest shareholders include index funds tied to various stock indices, and institutional investors subject to various investing guidelines. Because we may not be included in these indices at the time of the merger or may not meet the investing guidelines of some of these institutional investors, these index funds and institutional investors may decide to sell the Mariner common stock they receive in the merger. These sales may negatively affect the price of our common stock and also may make it more difficult for us to obtain additional capital by selling equity securities in the future at a time and at a price that we deem appropriate.

Historically, Forest has operated with properties in diverse geographic locations, including the Gulf Coast, the Western United States, Alaska, Canada and other international locations. In contrast, following the spin-off and merger, Mariner will operate as a stand-alone oil and gas exploration, development and production company with operations primarily in the Gulf of Mexico and in West Texas. Shareholders of Forest who chose to invest in a geographically diverse company may not wish to continue to invest in one that is less geographically diverse, such as Mariner. As a result, such shareholders may seek to sell the shares of our common stock received in the merger.


	*The integration of the Forest Gulf of Mexico operations following the merger will be difficult, and will divert our management’s attention away from our normal operations.*

There is a significant degree of difficulty and management involvement inherent in the process of integrating the Forest Gulf of Mexico operations. These difficulties include:


	•	the challenge of integrating the Forest Gulf of Mexico operations while carrying on the ongoing operations of our business;

	•	the challenge of managing a significantly larger company, with more than twice the PV10 of Mariner on a stand-alone basis;

	•	faulty assumptions underlying our expectations;

	•	the difficulty associated with coordinating geographically separate organizations;

	•	the challenge of integrating the business cultures of the two companies;

	•	attracting and retaining personnel associated with the Forest Gulf of Mexico operations following the merger; and

	•	the challenge and cost of integrating the information technology systems of the two companies.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.


	*If we fail to realize the anticipated benefits of the merger, stockholders may receive lower returns than they expect.*

The success of the merger will depend, in part, on our ability to realize the anticipated growth opportunities from combining the Forest Gulf of Mexico operations with Mariner. Even if we are able to successfully combine the two businesses, it may not be possible to realize the full benefits of the proved reserves, enhanced growth of production volume, cost savings from operating synergies and other benefits that we currently expect to result from the merger, or realize these benefits within the time frame that is currently expected. The benefits of the merger may be offset by operating losses relating to changes in commodity prices, or in oil and gas industry conditions, or by risks and uncertainties relating to the combined company’s exploratory prospects, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from the merger, stockholders may receive lower returns on our stock than they expect.


	*We expect to incur significant charges relating to the integration plan that could materially and adversely affect our period-to-period results of operations following the merger.*

We are developing a plan to integrate the Forest Gulf of Mexico operations with our operations after the merger. Following the merger, we anticipate that from time to time we will incur charges to our earnings in connection with the integration. These charges will include expenses incurred in connection with relocating and retaining employees and increased professional and consulting costs. We also expect to incur significant expenses related to being a public company. We will not be able to quantify the exact amount of these charges or the period(s) in which they will be incurred until after the merger is completed. Some factors affecting the cost of the integration include the timing of the closing of the merger, the training of new employees, the amount of severance and other employee-related payments resulting from the merger, and the limited length of time during which transitional services are provided by Forest.


	The number of shares Forest shareholders will receive in the merger is not subject to adjustment based on the value of the Mariner or the Forest Gulf of Mexico operations. Accordingly, because this value may fluctuate, the market value of the Mariner common stock that Forest shareholders receive in the merger may not reflect the value of the individual companies at the time of the merger.

Following the spin-off and the merger, the holders of Forest common stock will ultimately become entitled to receive approximately 0.8 shares of Mariner common stock for each Forest share they own. This ratio will not be adjusted for changes in the value of our company or the Forest Gulf of Mexico operations. If our value relative to the Forest Gulf of Mexico operations increases (or the value of the Forest Gulf of Mexico operations decreases relative to our value) prior to the completion of the merger, the market value of the Mariner common stock that Forest shareholders receive in the merger may not reflect the then-current relative values of the individual companies.


	*Regulatory agencies may delay or impose conditions on approval of the spin-off and the merger, which may diminish the anticipated benefits of the merger.*

Completion of the spin-off and merger is conditioned upon the receipt of required governmental consents, approvals, orders and authorizations. While we intend to pursue vigorously all required governmental approvals and do not know of any reason why we would not be able to obtain the necessary approvals in a timely manner, the requirement to receive these approvals before the spin-off and merger could delay the completion of the spin-off and merger, possibly for a significant period of time after Mariner stockholders have approved the merger proposal at the annual meeting. In addition, these governmental agencies may attempt to condition their approval of the merger on the imposition of conditions that could have a material adverse effect on our operating results or the value of our common stock after the spin-off and merger are completed.

Any delay in the completion of the spin-off and merger could diminish anticipated benefits of the spin-off and merger or result in additional transaction costs, loss of revenue or other effects associated with uncertainty about the transaction. Any uncertainty over the ability of the companies to complete the spin-off and merger could make it more difficult for us to retain key employees or to pursue business strategies. In addition, until the spin-off and merger are completed, the attention of our management may be diverted from ongoing business concerns and regular business responsibilities to the extent management is focused on matters relating to the transaction, such as obtaining regulatory approvals.


	In order to preserve the tax-free treatment of the spin-off, we will be required to abide by potentially significant restrictions which could limit our ability to undertake certain corporate actions (such as the issuance of our common shares or the undertaking of a change in control) that otherwise could be advantageous.

The tax sharing agreement imposes ongoing restrictions on Forest and on us to ensure that applicable statutory requirements under the Internal Revenue Code and applicable Treasury regulations continue to be met so that the spin-off remains tax-free to Forest and its shareholders. As a result of these restrictions, our ability to engage in certain transactions, such as the redemption of our common stock, the issuance of equity securities and the utilization of our stock as currency in an acquisition, will be limited for a period of two years following the spin-off.

If Forest or Mariner takes or permits an action to be taken (or omits to take an action) that causes the spin-off to become taxable, the relevant entity generally will be required to bear the cost of the resulting tax liability to the extent that the liability results from the actions or omissions of that entity. If the spin-off became taxable, Forest would be expected to recognize a substantial amount of income, which would result in a material amount of taxes. Any such taxes allocated to us would be expected to be material to us, and could cause our business, financial condition and operating results to suffer. These restrictions may reduce our ability to engage in certain business transactions that otherwise might be advantageous to us and our stockholders and could have a negative impact on our business and stockholder value.


	*Some of our directors and executive officers have interests that are different from, or in addition to, the interests of our stockholders.*

When considering the recommendations of our board of directors, you should be aware that some of our directors and executive officers have interests and arrangements that may be different from your interests as stockholders, including:


	•	arrangements regarding the appointment of directors and officers of Mariner following the merger; and

	•	arrangements whereby our executive officers will receive a cash payment of $1,000 each in exchange for the waiver of certain rights under their employment agreements, including the automatic vesting or acceleration of restricted stock and options upon the completion of the merger and the right to receive a lump sum cash payment if the officer voluntarily terminates employment without good reason within nine months following the completion of the merger.

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.

We are a private company, and there is 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 downward revisions in our reserve estimates;

	•	our operating results being less than anticipated;

	•	reductions in oil and gas prices;

	•	publication of unfavorable research reports about us or the exploration and production industry;

	•	increases in market interest rates which may increase our cost of capital;

	•	the enactment of more stringent laws or regulations applicable to our business, or unfavorable court rulings or enforcement or legal actions;

	•	increases in royalties or taxes payable in the operation of our business;

	•	a general decline in market valuations of similar companies;

	•	adverse market reaction to any increased indebtedness we incur in the future;

	•	departures of key management personnel;

	•	increases to our asset retirement obligations;

	•	adverse actions taken by our stockholders;

	•	negative speculation in the press or investment community; and

	•	adverse 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.


	Mariner stockholders will experience substantial and immediate dilution as a result of the merger, and may experience dilution of their ownership interests due to the future issuance of additional shares of our common stock, which could have an adverse effect on our stock price.

If the merger is completed, the current owners of Mariner’s common stock will experience substantial and immediate dilution from the issuance of shares of Mariner common stock to Forest shareholders, such that the Mariner stockholders will own approximately 42% of the Mariner common stock following the merger. Additionally, we may in the future issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present stockholders. 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 a result of the proposed amendment to our certificate of incorporation, our authorized shares would be increased to 180 million shares of common stock and 20 million shares of preferred stock. Pursuant to the proposed addition of shares to our stock incentive plan, the maximum number of shares issuable under the plan would, if the proposal is approved, be increased to 6.5 million shares.

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 (subject to certain federal tax limitations during the two-year period following the spin-off) in connection with the hiring of personnel, future acquisitions, future public offerings or 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 in this prospectus, 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 of the Forest Gulf of Mexico Operations,” “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, liquidity and 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;

	•	the impact of weather and the occurrence of natural disasters such as fires, floods and other catastrophic events and natural disasters;

	•	governmental regulation of the oil and natural gas industry;

	•	developments in oil-producing and natural gas-producing countries;

	•	the proposed merger, including strategic plans, expectations and objectives for future operations, the completion of those transactions, and the realization of expected benefits from the transactions; and

	•	disruption from the merger making it more difficult to manage Mariner’s business.

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 September 30, 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.


			September 30,
			2005

			(in millions)
Long-term debt:
	Credit facility— revolving note due March 2007		$	75.0
	Promissory note to former indirect stockholder(1)			4.0

		Total long-term debt		79.0
Stockholders’ equity(2)				178.6

		Total capitalization	$	257.6


(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 September 30, 2005 was $5.01 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 September 30, 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 $14.99 in the net tangible book value per share of our common stock assuming a sale price of $20.00 per share, representing the September 30, 2005 price at which the shares traded in the PORTAL Market^®. 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				$	20.00
	Net tangible book value per share at September 30, 2005	$	5.01
	Increase per share attributable to new investors		-0-
Net tangible book value per share after this offering					5.01

Dilution per share to new investors				$	14.99

The foregoing discussion and table are based upon the number of shares actually issued and outstanding as of September 30, 2005. As of September 30, 2005, we had 809,000 stock options outstanding at an average exercise price of approximately $14.00 per share, none of which were vested as of September 30, 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 Mariner’s historical consolidated financial data as of and for each of the four years ended December 31, 2003, the period from January 1, 2004 through March 2, 2004, the period from March 3, 2004 through December 31, 2004, the period from March 3, 2004 through September 30, 2004 and the nine-month period ended September 30, 2005. The historical consolidated financial data as of and for the four years ended December 31, 2003, the period from January 1, 2004 through March 2, 2004 and the period from March 3, 2004 through December 31, 2004 are derived from Mariner’s audited financial statements included herein, and the historical consolidated financial data for the period from March 3, 2004 through September 30, 2004 and the nine-month period ended September 30, 2005 are derived from unaudited financial statements of Mariner. You should read the following data in connection with “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. Mariner’s historical results are not necessarily indicative of results to be expected in future periods.

On March 2, 2004, Mariner’s former indirect parent, Mariner Energy LLC, merged with MEI Acquisitions, LLC, an affiliate of the private equity funds, Carlyle/ Riverstone Global Energy and Power Fund II, L.P. and ACON Investments LLC. The financial information contained herein is presented in the style of Pre-2004 Merger activity (for all periods prior to March 2, 2004) and Post-2004 Merger activity (for the March 3, 2004 through December 31, 2004 period and the March 3, 2004 through September 30, 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.


			Post-2004 Merger									Pre-2004 Merger

									Period from			Period from
						Period from			March 3,			January 1,
			Nine Months			March 3,			2004			2004
			Ended			2004 through			through			through			Year Ended December 31,
			September 30,			September 30,			December 31,			March 2,
			2005			2004			2004			2004			2003			2002			2001			2000

			(in millions, except per share data)
Statement of Operations Data:
	Total revenues(1)		$	151.2		$	122.5		$	174.4		$	39.8		$	142.5		$	158.2		$	155.0		$	121.1
	Lease operating expenses			20.2			15.1			21.4			4.1			24.7			26.1			20.1			17.2
	Transportation expenses			1.7			3.7			1.9			1.1			6.3			10.5			12.0			7.8
	Depreciation, depletion and amortization			43.4			37.4			54.3			10.6			48.3			70.8			63.5			56.8
	Impairment of production equipment held for use			0.5			1.0			1.0			—			—			—			—			—
	Derivative settlement			—			—			—			—			3.2			—			—			—
	Impairment of Enron related receivables			—			—			—			—			—			3.2			29.5			—
	General and administrative expenses			26.7			6.2			7.6			1.1			8.1			7.7			9.3			6.5

	Operating income			58.7			59.1			88.2			22.9			51.9			39.9			20.6			32.8
	Interest income			0.7			0.2			0.2			0.1			0.8			0.4			0.7			0.1
	Interest expense			(5.4	)		(4.4	)		(6.0	)		—			(7.0	)		(10.3	)		(8.9	)		(11.0	)

	Income before income taxes			54.0			54.9			82.4			23.0			45.7			30.0			12.4			21.9
	Provision for income taxes			(18.4	)		(19.2	)		(28.8	)		(8.1	)		(9.4	)		—			—			—

	Income before cumulative effect of change in accounting method net of tax effects			35.6			35.7			53.6			14.9			36.3			30.0			12.4			21.9
	Income before cumulative effect per common share
		Basic		1.10			1.20			1.80			.50			1.22			1.01			.42			.74
		Diluted		1.07			1.20			1.80			.50			1.22			1.01			.42			.74
	Cumulative effect of changes in accounting method			—			—			—			—			1.9			—			—			—

	Net income		$	35.6		$	35.7		$	53.6		$	14.9		$	38.2		$	30.0		$	12.4		$	21.9

	Net income per common share
		Basic		1.10			1.20			1.80			.50			1.29			1.01			.42			.74
		Diluted		1.07			1.20			1.80			.50			1.29			1.01			.42			.74
Capital Expenditure and Disposal Data:
	Exploration, including leasehold/seismic		$	23.6		$	35.7		$	40.4		$	7.5		$	31.6		$	40.4		$	66.3		$	46.7
	Development and other			106.8			50.2			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		$	130.4		$	85.9		$	133.6		$	15.3		$	(38.3	)	$	53.8		$	74.0		$	79.1


(1)	Includes effects of hedging.


		Post-2004 Merger						Pre-2004 Merger

								December 31,
		September 30,			December 31,
		2005			2004			2003		2002			2001			2000

		(in millions)
Balance Sheet Data:(1)
	Property and equipment, net, full cost method	$	393.3		$	303.8		$	207.9	$	287.6		$	290.6		$	287.8
	Total assets		502.2			376.0			312.1		360.2			363.9			335.4
	Long-term debt, less current maturities		79.0			115.0			—		99.8			99.8			129.7
	Stockholder’s equity		178.6			133.9			218.2		170.1			180.1			141.9
	Working capital (deficit)(2)		(30.2	)		(18.7	)		38.3		(24.4	)		(19.6	)		(15.4	)


(1)	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.

(2)	Working capital (deficit) excludes current derivative assets and liabilities, deferred tax assets and restricted cash.


	Post-2004 Merger									Pre-2004 Merger

							Period from			Period from
				Period from			March 3,			January 1,
	Nine Months			March 3,			2004			2004
	Ended			2004 through			through			through			Year Ended December 31,
	September 30,			September 30,			December 31,			March 2,
	2005			2004			2004			2004			2003			2002			2001			2000

	(in millions)
Other Financial Data:
EBITDA(1)	$	102.7		$	97.5		$	143.5		$	33.4		$	100.3		$	113.9		$	113.6		$	89.6
Net cash provided by operating activities		135.4			96.8			135.9			20.3			103.5			60.3			113.5			63.9
Net cash (used) provided by investing activities		(142.1	)		(85.9	)		(133.6	)		(15.3	)		38.3			(53.8	)		(74.0	)		(79.1	)
Net cash (used) provided by financing activities		8.7			(74.9	)		64.9			—			(100.0	)		—			(30.0	)		17.4
Reconciliation of Non-GAAP Measures:
EBITDA(1)	$	102.7		$	97.5		$	143.5		$	33.4		$	100.3		$	113.9		$	113.6		$	89.6
Changes in working capital		25.1			9.7			6.9			(13.2	)		21.8			(20.4	)		7.5			(15.5	)
Non-cash hedge gain(2)		(3.6	)		(5.1	)		(7.9	)		—			(2.0	)		(23.2	)		—			—
Amortization/other		0.9			0.5			0.8			—			—			(0.1	)		0.6			0.7
Stock compensation expense		17.6			—			—			—			—			—			—			—
Net interest expense		(4.7	)		(4.2	)		(5.8	)		0.1			(6.2	)		(9.9	)		(8.2	)		(10.9	)
Income tax expense		(2.6	)		(1.6	)		(1.6	)		—			(10.4	)		—			—			—

Net cash provided by operating activities	$	135.4		$	96.8		$	135.9		$	20.3		$	103.5		$	60.3		$	113.5		$	63.9

(1)


	accordance with generally accepted accounting principles or as a measure of a company’s profitability or liquidity.

(2)	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.

UNAUDITED PRO FORMA COMBINED CONDENSED FINANCIAL INFORMATION

The following unaudited pro forma combined financial information and explanatory notes present how the combined financial statements of Mariner and the Forest Gulf of Mexico operations may have appeared had the businesses actually been combined as of September 30, 2005 (with respect to the balance sheet information using currently available fair value information) or as of January 1, 2004 (with respect to statements of operations information). The unaudited pro forma combined financial information shows the impact of the merger on the historical financial position and results of operations under the purchase method of accounting with Mariner treated as the acquirer. Under this method of accounting, the assets and liabilities of the Forest Gulf of Mexico operations are recorded by Mariner at their estimated fair values as of the date the merger is completed.

The unaudited pro forma combined balance sheet as of September 30, 2005 assumes the merger was completed on that date. The unaudited pro forma combined statements of operations gives effect to the merger as if it had been completed on January 1, 2004. The merger agreement was executed on September 9, 2005 and provides for Mariner to issue approximately 50.6 million shares of common stock as consideration to Forest Energy Resources common stockholders.

The unaudited pro forma combined financial information has been derived from and should be read together with the historical consolidated financial statements of Mariner and the statements of revenues and direct operating expenses of the Forest Gulf of Mexico operations, which are included herein. The statements of revenues and direct operating expenses of the Forest Gulf of Mexico operations do not include all of the costs of doing business.

In addition, the purchase price allocation is preliminary and will be finalized following the closing of the merger. The final purchase price allocation will be determined after closing based on the actual fair value of current assets, current liabilities, indebtedness, long-term liabilities, proven and unproven oil and gas properties, identifiable intangible assets and the final number of shares of Mariner common stock issued in the merger and for unvested stock options that are outstanding at closing. We are continuing to evaluate all of these items; accordingly, the final purchase price may differ in material respects from that presented in the unaudited pro forma combined condensed balance sheet.

The combination of the Forest Gulf of Mexico operations with Mariner’s is expected to cause the average reserve life of Mariner’s oil and gas properties to decrease from current levels and to result in a higher rate of depreciation, depletion, and amortization for the combined operations. For example, the estimated proved reserves of the Forest Gulf of Mexico properties as of June 30, 2005 were 328 Bcfe and production for the six months ended June 30, 2005 (prior to hurricane related disruptions) was approximately 40.8 Bcfe, a reserve life on an annualized basis of 4.0. This ratio is indicative of the relatively higher productive rates of offshore oil and gas properties when compared to most onshore fields. While the higher productive rates generally result in a faster return on investment than onshore fields, they also result in a faster depletion of the underlying proved reserves and a resulting higher rate of depreciation, depletion, and amortization. As of June 30, 2005, Mariner’s proved reserves totaled 328 Bcfe and production for the six months ended June 30, 2005 (prior to hurricane disruptions) was approximately 16.5 Bcfe, a reserve life on an annualized basis of 9.9. For the combined operations, as of June 30, 2005, proved reserves would have totaled approximately 599 Bcfe and production for the six months ended June 30, 2005 would have totaled 57.3 Bcfe, a reserve life on an annualized basis of 5.7. Mariner will also write-up the Forest Gulf of Mexico operations to estimated fair value as of the merger date, which is also expected to cause the underlying DD&A rate to increase for the combined operations.

In connection with the merger, Mariner and Mariner Energy Resources expect to enter into a $500 million senior secured revolving credit facility, and Mariner also expects to obtain a $40 million senior secured letter of credit facility. The initial borrowing base of the revolving credit facility will be $400 million. The revolving credit facility will mature on the fourth anniversary of the closing and may be used for general corporate purposes. The letter of credit facility will mature on the third anniversary of the closing.

In connection with the spin-off and the payment of the cash amount by Forest Energy Resources to Forest pursuant to the distribution agreement, Forest Energy Resources intends to enter into a new senior term loan facility with Union Bank of California, or UBOC, as lender, in an amount equal to the lesser of the cash amount, plus the amount of the arrangement and upfront fees and expenses associated with the facility, and $200 million, plus the amount of the arrangement and upfront fees and expenses associated with the facility. At Forest Energy Resources’ election, interest will be determined by reference to (1) the UBOC Reference Rate or (2) the London interbank offered rate, or LIBOR, plus 1.50% per annum. In the event that any portion of the facility is outstanding after 30 days, the interest rate will increase, at Forest Energy Resources’ election, to (1) the UBOC Reference Rate, plus 5% per annum or (2) LIBOR plus 6.50% per annum. Interest will be payable at the applicable maturity date for LIBOR-loans and quarterly for UBOC Reference Rate loans.

The Forest Energy Resources facility is expected to be repaid with borrowings under Mariner’s and Mariner Energy Resources’ $500 million revolving credit facility. The facility will mature 90 days from closing of the spin-off and merger and the principal will be due at maturity. Prepayments will be permitted at any time without premium or penalty (except for breakage and related costs associated with prepayments of Eurodollar loans), subject to minimum amount requirements. The facility will be unsecured with a negative pledge on Forest Energy Resources’ existing oil and gas properties and all other assets of Forest Energy Resources.

The facility will contain various covenants that limit Forest Energy Resources’ ability to do the following, among other things, except as contemplated by the distribution agreement and the merger agreement:


	•	incur indebtedness;

	•	grant certain liens;

	•	merge or consolidate with another entity;

	•	sell assets except in the ordinary course of business;

	•	make certain loans and investments; and

	•	permit trade payables to exceed 90 days.

If an event of default exists under the facility, the lender will be able to accelerate the maturity of the facility and exercise other rights and remedies. Events of default include defaults in payment or performance under the facility, misrepresentations, cross-defaults to other debt or material obligations of Forest Energy Resources, and insolvency, material judgments, certain changes of ownership and any material adverse change affecting Forest Energy Resources.

MARINER ENERGY, INC.

UNAUDITED PRO FORMA COMBINED CONDENSED BALANCE SHEET

As of September 30, 2005


									Mariner
			Mariner			Merger			Pro Forma
			Historical			Adjustments(1)			Combined

			(in thousands)
ASSETS
Current Assets:
	Cash and cash equivalents		$	4,564		$	—		$	4,564
	Receivables			50,259			—			50,259
	Deferred tax asset			30,480			—			30,480
	Prepaid expenses and other			18,732			2,874	(2)		21,606

		Total current assets		104,035			2,874			106,909
Property and Equipment, net				393,258			1,463,846	(3)		1,857,104
Goodwill				—			142,000	(3)		142,000
Other Assets, net of amortization				4,916			7,597	(2)		12,513

		TOTAL ASSETS	$	502,209		$	1,616,317		$	2,118,526


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
	Accounts payable		$	14,573		$	—		$	14,573
	Accrued liabilities			88,993			32,491	(2)		121,484
	Accrued interest			141			—			141
	Derivative liability			76,902			108,031	(2)		184,933

		Total current liabilities		180,609			140,522			321,131
Long-Term Liabilities:
	Abandonment liability			26,314			116,203	(2)		142,517
	Deferred income tax			6,468			168,852	(4)		175,320
	Derivative liability			28,221			17,203	(2)		45,424
	Bank debt			75,000			200,000	(5)		275,000
	Note payable			4,000			—			4,000
	New debt			—			—			—
	Other long-term liabilities			3,000			—			3,000

		Total long-term liabilities		143,003			502,258			645,261
Stockholders’ Equity:
	Common stock			4			5	(6)		9
	Additional paid-in capital			171,667			973,532	(3)		1,145,199
	Unearned compensation			(14,548	)		—			(14,548	)
	Accumulated other comprehensive (loss)			(67,708	)		—			(67,708	)
	Accumulated retained earnings			89,182			—			89,182

		Total stockholders’ equity		178,597			973,537			1,152,134

		TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	502,209		$	1,616,317		$	2,118,526

MARINER ENERGY, INC.

UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENT OF OPERATIONS

For the Nine Months Ended September 30, 2005


						Forest Energy					Mariner
			Mariner			Resources, Inc.		Merger			Pro Forma
			Historical			Historical(7)		Adjustments(1)			Combined

			(in thousands, except per share data)
Revenues:
	Oil & gas sales		$	148,492		$	326,722	$	—		$	475,214
	Other revenues			2,753			—		—			2,753

		Total revenues		151,245			326,722		—			477,967
Costs and Expenses:
	Lease operating expenses			20,170			59,379		—			79,549
	Transportation expenses			1,697			2,484		—			4,181
	General and administrative expenses			26,726			—		—			26,726
	Depreciation, depletion and amortization			43,457			—		201,255	(8)		244,712
	Impairment of production equipment held for use			498			—		—			498

		Total costs and expenses		92,548			61,863		201,255			355,666

OPERATING INCOME				58,697			264,859		(201,255	)		122,301
Interest:
	Income			696					—			696
	Expense, net of amounts capitalized			(5,416	)				(8,010	)(9)		(13,426	)

Income before taxes				53,977					(209,265	)		109,571
Provision for income taxes				(18,414	)				(19,936	)(10)		(38,350	)

NET INCOME				35,563					(229,201	)		71,221

Earnings per share:
Net Income per share—basic				1.10								0.86

Net Income per share—diluted				1.07								0.85

Weighted average shares outstanding—basic				32,438					50,637			83,075
Weighted average shares outstanding—diluted				33,313					50,637			83,950

MARINER ENERGY, INC.

UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENT OF OPERATIONS

For the Year Ended December 31, 2004


						Forest Energy					Mariner
			Mariner			Resources, Inc.		Merger			Pro Forma
			Historical			Historical(7)		Adjustments(1)			Combined

			(in thousands, except per share data)
Revenues:
	Oil & gas sales		$	214,187		$	453,139	$	—		$	667,326
	Other revenues			—			—		—			—

		Total revenues		214,187			453,139		—			667,326
Costs and Expenses:
	Lease operating expenses			25,484			81,627		—			107,111
	Transportation expenses			3,029			2,175		—			5,204
	General and administrative expenses			8,772			—		—			8,772
	Depreciation, depletion and amortization			64,911			—		303,261	(8)		368,172
	Impairment of production equipment held for use			957			—		—			957

		Total costs and expenses		103,153			83,802		303,261			490,216

OPERATING INCOME				111,034			369,337		(303,261	)		177,110
Interest:
	Income			316					—			316
	Expense, net of amounts capitalized			(6,050	)				(7,840	)(9)		(13,890	)

Income before taxes				105,300					(311,101	)		163,536
Provision for income taxes				(36,855	)				(20,383	)(10)		(57,238	)

NET INCOME				68,445					(331,484	)		106,298

Earnings per share:
Net Income per share—basic				2.30								1.32

Net Income per share—diluted				2.30								1.32

Weighted average shares outstanding—basic				29,748					50,637			80,385
Weighted average shares outstanding—diluted				29,748					50,637			80,385

Notes to Unaudited Pro Forma Combined Condensed Financial Data

The unaudited “Mariner Pro Forma Combined” financial data have been prepared to give effect to Mariner’s acquisition of the Forest Gulf of Mexico operations, which will be spun off to Forest shareholders. Information under the heading “Merger Adjustments” gives effect to the adjustments related to the acquisition of the Forest Gulf of Mexico operations. The unaudited pro forma combined condensed statements are not necessarily indicative of the results of Mariner’s future operations.

The unaudited pro forma combined financial information has been derived from and should be read together with the historical consolidated financial statements of Mariner and the statements of revenues and direct operating expenses of the Forest Gulf of Mexico operations. The statements of revenues and direct operating expenses of the Forest Gulf of Mexico operations do not include all of the costs of doing business.


(1)	Transaction costs consisting of accounting, consulting and legal fees are anticipated to be approximately $12 million. These costs are directly attributable to the transaction and have been excluded from the pro forma financial statements as they represent material nonrecurring charges.

(2)	To record other current and long-term assets that we will receive in the spin-off and liabilities that we will assume as a result of the spin-off reflected at their estimated fair market values, including inventory of $2.1 million, abandonment escrows of $0.7 million, gas imbalances of $7.6 million, asset retirement obligations of $146.6 million and derivative liabilities of $125.2 million.

(3)	To record the preliminary purchase price allocation to the fair value of assets acquired, including oil and gas properties and goodwill. These adjustments also adjust depreciation, depletion and amortization expense to give effect to the acquisition of the Forest Gulf of Mexico operations and their step-up in value using the unit of production method under the full cost method of accounting.

(4)	To record the deferred tax position of the combined company, inclusive of the deferred tax gross-up in connection with the acquisition.

(5)	To record $200.0 million of debt that Forest Energy Resources, Inc. will incur under the terms of the distribution agreement. The actual amount of debt to be incurred will be adjusted to reflect the net cash proceeds generated by the Forest Gulf of Mexico operations since June 30, 2005 pursuant to the terms of the distribution agreement. Mariner plans to refinance the debt, which will mature 90 days after the closing, with a revolving credit facility that matures on the fourth anniversary of the closing. Forest Energy Resources, Inc. will be primarily liable for all indebtedness incurred in connection with the spin-off or any refinancing thereof.

(6)	To record issuance of 50,637,010 shares of common stock at par value of $.0001 per share.

(7)	The Forest Gulf of Mexico operations historically have been operated as part of Forest’s total oil and gas operations. No historical GAAP-basis financial statements exist for the Forest Gulf of Mexico operations on a stand-alone basis; however, statements of revenues and direct operating expenses are presented for the year ended December 31, 2004 (audited) and for the nine months ended September 30, 2005 (unaudited).

(8)	To adjust depreciation, depletion and amortization expense to give effect to the acquisition of the Forest Gulf of Mexico operations and their step-up in value using the unit of production method under the full cost method of accounting.

(9)	To adjust interest expense to give effect to the financing activities in connection with the organization of Forest Energy Resources, Inc. assuming an interest rate of 5.34% for the nine months ended September 30, 2005 and 3.92% for the year ended December 31, 2004 based on the terms of the senior term loan facility to be obtained by Forest Energy Resources. The interest rates used reflect 30-day LIBOR plus 1.50%, or 5.34% as of September 30, 2005 and 3.92% as of December 31, 2004. A change in interest rates of ¹/8 percent would result in a change in interest expense of approximately $0.1 million and $0.2 million for the nine months ended September 30, 2005, and the year ended December 31, 2004, respectively.


(10)	To record income tax expense on the combined company results of operations based on a statutory combined federal and state tax rate of 35%.

Supplemental Pro Forma Combined Oil and Gas Reserve and Standardized Measure Information (Unaudited)

The following unaudited supplemental pro forma oil and natural gas reserve tables present how the combined oil and gas reserve and standardized measure information of Mariner and the Forest Gulf of Mexico operations may have appeared had the businesses actually been combined as of December 31, 2004. The Supplemental Pro Forma Combined Oil and Gas Reserve and Standardized Measure Information is for illustrative purposes only. You should refer to footnote 10 in Mariner’s Notes to the Financial Statements beginning on page F-32 and footnote 3 in Forest’s Gulf of Mexico Operations Notes to Statements of Revenues and Direct Operating Expenses beginning on page F-39 for additional information presented in accordance with the requirements of Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Gas Producing Activities.

ESTIMATED PRO FORMA COMBINED QUANTITIES OF PROVED RESERVES


										Forest Energy Resources, Inc.
	Mariner Historical									Historical									Mariner Pro Forma Combined

							Natural Gas									Natural Gas									Natural Gas
	Oil			Natural Gas			Equivalent			Liquids			Natural Gas			Equivalent			Liquids			Natural Gas			Equivalent
	(Mbbl)			(MMcf)			(Mmcfe)			(Mbbl)			(MMcf)			(Mmcfe)			(Mbbl)			(MMcf)			(Mmcfe)

December 31, 2003		13,079			127,584			206,060			11,357			295,347			363,489			24,436			422,931			569,549

Revisions of previous estimates		1,249			19,797			27,291			1,693			(2,860	)		7,298			2,942			16,937			34,589
Extensions, discoveries and other additions		2,225			28,334			41,684			630			14,449			18,229			2,855			42,783			59,913
Sales of reserves in place		—			—			—			—			—			—			—			—			—
Production		(2,298	)		(23,782	)		(37,570	)		(3,230	)		(61,684	)		(81,064	)		(5,528	)		(85,466	)		(118,634	)
Purchases of reserves in place		—			—			—			1,200			24,556			31,756			1,200			24,556			31,756

December 31, 2004		14,255			151,933			237,465			11,650	(1)		269,808			339,708			25,905	(1)		421,741			577,173


(1)	Includes 598 Mbbls of natural gas liquids.

ESTIMATED PRO FORMA COMBINED QUANTITIES OF PROVED DEVELOPED RESERVES

Forest Energy Resources, Inc.

Mariner Historical

Historical

Mariner Pro Forma Combined

Natural Gas

Oil

Natural Gas

Equivalent

Liquids

Natural Gas

Equivalent

Liquids

Natural Gas

Equivalent

(Mbbl)

(MMcf)

(Mmcfe)

(Mbbl)

(MMcf)

(Mmcfe)

(Mbbl)

(MMcf)

(Mmcfe)

December 31, 2004

6,339

71,361

109,395

9,471

201,759

258,585

15,810

273,120

367,980

PRO FORMA COMBINED STANDARDIZED MEASURE OF DISCOUNTED

FUTURE NET CASH FLOWS


		For the Year Ending December 31, 2004

					Forest Energy			Mariner Pro
		Mariner			Resources, Inc.			Forma
		Historical			Historical			Combined

Future cash inflows		$	1,601,240		$	2,155,217		$	3,756,457
Future production costs			(308,190	)		(272,020	)		(580,210	)
Future development costs			(193,689	)		(357,592	)		(551,281	)
Future income taxes			(285,701	)		(412,477	)		(698,178	)

Future net cash flows			813,660			1,113,128			1,926,788
Discount of future net cash flows at 10% per annum			(319,278	)		(187,291	)		(506,569	)

Standardized measure of discounted future net cash flows		$	494,382		$	925,837		$	1,420,219


Balance, beginning of period		$	418,159		$	949,421		$	1,367,580
Increase (decrease) in discounted future net cash flows:
	Sales and transfers of oil and gas produced, net of production costs		(185,673	)		(426,405	)		(612,078	)
	Net changes in prices and production costs		27,767			11,628			39,395
	Extensions and discoveries, net of future development and production costs		102,905			88,999			191,904
	Development costs during period and net change in development costs		44,417			79,642			124,059
	Revision of previous quantity estimates		89,814			28,701			118,515
	Sales of reserves in place		—			—			—
	Net change in income taxes		(27,634	)		(28,550	)		(56,184	)
	Purchases of reserves in place		—			100,681			100,681
	Accretion of discount before income taxes		41,816			121,720			163,536
	Changes in production rates (timing) and other		(17,189	)		—			(17,189	)

Balance, end of period		$	494,382		$	925,837		$	1,420,219

STRENGTHS AND STRATEGIES OF MARINER FOLLOWING THE MERGER

Following the merger we expect Mariner to be an independent oil and gas exploration, development and production company focused offshore in the Gulf of Mexico and onshore in the Permian Basin of West Texas. On a pro forma basis as of December 31, 2004, the combined company had 577 Bcfe of estimated proved reserves. Approximately 64% of these reserves were developed; 36% were undeveloped. Approximately 73% of our estimated proved reserves were natural gas and natural gas liquids, and 27% were oil and condensate. The reserves are geographically distributed approximately 62% on the Gulf of Mexico shelf, 18% in the Gulf of Mexico deepwater and 20% in the Permian Basin in West Texas. As of December 31, 2004, the pro forma PV10 of the combined company was approximately $1.9 billion, and the pro forma standardized measure of discounted future net cash flows attributable to its estimated proved reserves was approximately $1.4 billion. Please see “Business—Estimated Proved Reserves” and “The Forest Gulf of Mexico Operations—Estimated Proved Reserves” for a definition of PV10 and reconciliations of PV10 to the standardized measure of discounted future net cash flows.

Mariner is focused on the generation and development of new Gulf of Mexico deepwater, deep shelf and shelf projects and the development of its existing asset base in West Texas. Historically, Mariner has achieved growth through the drill bit; however, as part of our growth strategy, we also seek to acquire assets that provide acceptable risk-adjusted rates of return and have significant potential for further reserve additions through development and exploitation activities.

We believe Mariner’s core resources and strengths include:


	•	our high-quality assets with geographic and geological diversity;

	•	our successful track record of finding and developing oil and gas reserves; and

	•	our depth of operating experience.

The integration and further development and exploitation of the Forest Gulf of Mexico operations into our business will further diversify and, in our view, complement our existing business, provide additional resources for future growth beyond the producing assets acquired, and afford a larger scale to increase our ability to compete effectively. We expect the effectiveness of our growth strategy to be enhanced by the addition of the Forest Gulf of Mexico assets.

High-Quality Assets. We believe our asset base has significant potential:


	•	Our deepwater projects have the potential to provide large reserves, high production volumes and substantial cash flow. Approximately 65 Bcfe of our undeveloped estimated proved reserves as of December 31, 2004, are located in our high-impact deepwater projects—Swordfish, Pluto, Rigel, Baccarat, and Daniel Boone. The Baccarat project commenced production in July 2005 (although production was shut-in due to Hurricane Rita and recommenced in January 2006), and the Swordfish project commenced production in October 2005. Notwithstanding delays caused primarily by 2005 hurricane activity, we believe Pluto and Rigel will commence production in the second quarter of 2006. Proved undeveloped reserves attributable to those projects have been recategorized as proved developed reserves. Daniel Boone is currently scheduled for production in 2008.

	•	The Gulf of Mexico is an area that offers substantial growth opportunities, and we expect to continue to generate shelf, deep shelf and deepwater Gulf of Mexico prospects. The Forest Gulf of Mexico assets will more than double our existing undeveloped acreage position to approximately 465,000 net acres and increase our total net leasehold acreage offshore to nearly 1 million acres, providing numerous exploration, exploitation and development opportunities. We believe the additional acreage also will provide increased exposure to farm-out opportunities from other oil and gas operators. Our team of geoscientists currently has access to seismic data from multiple, recent vintage 3-D seismic databases covering more than 6,600 blocks in the Gulf of Mexico that we intend to continue to use to develop prospects on acreage being evaluated for leasing and to develop and further refine prospects on our expanded acreage position. The combination of our


		undeveloped acreage position, inventory of development prospects, seismic data and technical knowledge should enhance our ability to select projects with the greatest return potential for future development. We will also gain access to a significant infrastructure in the shelf that we believe will provide substantial cost efficiencies to the combined operations.

	•	Our West Texas assets provide stable cash flow and long-lived reserves, with significant development opportunities. In West Texas, during the three years ended December 31, 2004, we drilled 105 wells, all commercially successful, added approximately 76 Bcfe of estimated proved reserves, and increased our average daily production by more than 400%. Our 52 Bcfe of undeveloped estimated proved reserves in West Texas includes 162 locations. Our recent West Texas acquisition adds to our asset base an approximate 35% working interest in over 200 existing producing wells and, we believe, will provide future infill development opportunities, much like our Aldwell unit. This recent acquisition, in conjunction with our existing West Texas acreage, gives Mariner an inventory of multi-year development drilling opportunities.

Successful Track Record of Finding and Developing Oil and Gas Reserves. In the three-year period ended December 31, 2004, Mariner deployed approximately $337 million of capital on acquisitions, exploration and development, while adding approximately 191 Bcfe of proved reserves and producing approximately 111 Bcfe. In addition to our successful West Texas drilling program, in the three-year period ended December 31, 2004, we have participated in the drilling of 33 exploration wells in the Gulf of Mexico, with 15 of these wells resulting in the discovery of commercial oil and gas reserves.

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. The addition of experienced Forest personnel to Mariner’s team of geoscientists and technical and operational professionals should further enhance our ability to generate and maintain an inventory of high-quality drillable prospects and to further develop and exploit our assets.

We seek to mitigate our risk in drilling projects by entering into arrangements with industry partners in which they agree to pay a disproportionate share of 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 sell entire interests in offshore prospects in order to better diversify our portfolio. We also enter into trades or farm-in transactions whereby we acquire interests in third-party generated prospects. We expect more opportunities to participate in these prospects as a result of the scale and increased cash flow the merger will bring.

Depth of Operating Experience. Our engineers have extensive experience in offshore Gulf of Mexico completion and production techniques, both in the deepwater and on the shelf. We have extensive experience and a successful track record in the use of subsea tieback technology to connect offshore wells to existing production facilities. This technology facilitates production from offshore properties without the necessity of fabrication and installation of more costly platforms and top side facilities that typically require longer lead times. We believe the use of subsea tiebacks in appropriate projects enables us to bring production online more quickly, makes target prospects more profitable, and allows us to exploit reserves that may otherwise be considered non-commercial because of the high cost of infrastructure. In the Gulf of Mexico, in the three years ended December 31, 2004, we were directly involved in thirteen projects (five of which we operated) utilizing subsea tieback systems in water depths ranging from 475 feet to more than 7,000 feet, and in five projects (three of which we operated) developed through the use of platforms.

Mariner has proven to be an effective and efficient operator in West Texas, as evidenced by our results there in recent years. In addition to conducting a successful drilling program, increasing our production and expanding our asset base, we have improved our net operating margin by reducing our operating costs and increasing our realized share of production.

We expect that our acquisition of the Forest Gulf of Mexico assets and the scale it brings to our business will:


	•	reduce our concentration risk;

	•	provide many exploration, exploitation and development opportunities;

	•	enable us to increase the number of our internally-generated prospects;

	•	expand our sphere of influence and enhance our ability to participate in prospects generated by other operators; and

	•	add a significant cash flow generating resource that will improve our ability to compete effectively in the Gulf of Mexico and provide funding for acquisition projects.

We believe we are well positioned to optimize the Forest Gulf of Mexico assets through aggressive and timely exploitation. Our diverse, high-quality assets, our ability to find and develop oil and gas reserves, and our operating experience should provide a strong platform from which to grow and create value for our shareholders.

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, 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 Mariner), $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-2004 Merger activity (for all periods prior to March 2, 2004) and Post-2004 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-2004 Merger (for the January 1 through March 2, 2004 period), Post-2004 Merger (for the March 3, 2004 through December 31, 2004 period), Combined (for the full period from January 1 through December 31, 2004), Post-2004 Merger (for the March 3, 2004 through September 30, 2004 period) and Combined (for the full period from January 1, 2004 through September 30, 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, after the private placement, an affiliate of MEI Acquisitions Holdings, LLC beneficially owned approximately 5.3% of our outstanding common stock. See “Security Ownership of Certain Beneficial Owners and Management.”

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 are currently at or near historical highs 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.


	*Recent Developments*


	*Nine Months Ended September 30, 2005 Highlights*

During the first nine months of 2005, we recognized net income of $35.6 million on total revenues of $151.2 million compared to net income of $50.5 million on total revenues of $162.3 million in the first nine months of 2004. Net income decreased 30% compared to the first nine months of 2004, primarily due to recognizing $17.6 million of stock compensation expense in the first nine months of 2005, and a 21% decrease in production, partially offset by higher realized net oil and gas prices. We produced approximately 22.5 Bcfe during the first nine months of 2005 and our average daily production rate was 82 Mmcfe compared to 28.4 Bcfe, or 104 Mmcfe per day, for the same period in 2004. Production during the third quarter of 2005 was negatively impacted by the effects of the 2005 hurricane season. We invested approximately $130.3 million in oil and natural gas properties in the first nine months of 2005, compared to $101.0 million in the same period in 2004.

Our first nine months 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 809,000 shares of stock in the first nine months of 2005 and recorded compensation expense of $17.6 million in the first nine months of 2005 related to the restricted stock and options.


	*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 production for the first nine months of 2005 averaged approximately 53 MMcf of natural gas per day and approximately 4,900 barrels of oil per day or a total of approximately 82 MMcfe per day.

In the third quarter of 2005 our production was negatively impacted by Hurricanes Katrina and Rita. Production shut-in and deferred because of the hurricanes’ impact totaled approximately 1.3 Bcfe during the third quarter of 2005. Currently approximately 7 MMcfe per day of production remains shut-in awaiting repairs, primarily associated with our Baccarat property. While we believe physical damage to our existing platforms and facilities was relatively minor from both hurricanes, the effects of the storms caused damage to onshore pipeline and processing facilities that resulted in a portion of our production being temporarily shut-in, or in the case of our Viosca Knoll 917 (Swordfish) project, postponed. In addition, Hurricane Katrina caused damage to platforms that host three of our development projects: Mississippi Canyon 718 (Pluto), Mississippi Canyon 296 (Rigel), and Mississippi Canyon 66 (Ochre). Repairs to these facilities may take up to six months, pushing commencement of production on these projects into 2006.

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, Mariner 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. Production from Mississippi Canyon 66 (Ochre) remains shut-in and is expected to recommence in the first quarter of 2006. 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 commenced production at our Green Canyon 178 (Baccarat) project in the third quarter of 2005. However, damage sustained by the host facility during Hurricane Rita caused production to be shut-in. Production is expected to recommence in the first quarter of 2006. We commenced production at our Swordfish project in the fourth quarter of 2005. We currently anticipate commencing production in the second quarter of 2006 at our Pluto, Rigel and Ewing Banks 921 (North Black Widow) projects. However, as described above, Hurricanes Katrina and Rita have delayed start up of these projects from their original anticipated commencement dates. Other uncertainties, including scheduling, weather, and construction lead times, could cause further delays in the start up of any one or all of the projects.


	*Oil and Gas Property Costs*

In the nine months ended September 30, 2005, we incurred approximately $130.4 million in capital expenditures with 70% related to development activities primarily at our Aldwell Unit and for our Viosca Knoll 917 (Swordfish), Mississippi Canyon 718 (Pluto) and Mississippi Canyon 296 (Rigel) offshore projects. We also expended $10.0 million for the acquisition of oil and gas property interests in the first nine months of 2005, comprised of $3.5 million for properties located in the West Texas Permian Basin area, $5.0 million for Atwater Valley 426 (Bass Lite) and $1.5 million for East Breaks 513/514/558 (LaSalle). We incurred approximately $23.6 million of exploration capital expenditures in the first nine months 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 expenditures for exploration activities relate to offshore projects, and approximately 30% of exploration capital expended during 2004 was 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 $250 million with approximately 48% allocated to development projects, 27% to exploration activities, 21% to acquisitions and the remainder to other items (primarily capitalized overhead and interest). However, the effects of Hurricanes Katrina and Rita may delay some planned operations into 2006.


	*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 and a standardized measure of discounted future net cash flows attributable to our estimated proved reserves of approximately $494.4 million. Please see “Business—Estimated Proved Reserves” for a definition of PV10 and a reconciliation of PV10 to the standardized measure of discounted future net cash flows. To generate our net proved reserves as of June 30, 2005, our management reviewed and updated our historical lease operating expenses, updated our transportation and basis differentials, updated NYMEX prices, adjusted for roll-off and production performance since December 31, 2004, added any new proved undeveloped reserves (including those resulting from our Bass Lite project), updated the categorization of our projects

as either proved undeveloped, proved developed producing or proved behind pipe, and adjusted capital expenditures and timing of cash outlays. See “Business—Estimated 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. 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 12 deepwater projects. Of those projects, ten have either been converted to proved developed reserves or sold as indicated in the following table.


	Net Proved
	Undeveloped
	Reserves		Year
Property	(Bcfe)(1)		Added		Year Converted to 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 579 (Falcon)		66.8		2001	2002 (50% of Mariner’s interest sold) 2003 (all of Mariner’s remaining interest sold)
Viosca Knoll 917 (Swordfish)		13.4		2001	2005 (100% converted to proved developed)
Green Canyon 178 (Baccarat)		4.0		2004	2005 (100% converted to proved developed)
Mississippi Canyon 296/252 (Rigel)		22.4		2003	2005 (75% converted to proved developed/ 25% remains undeveloped)


(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 second quarter of 2006.

The proved undeveloped reserves attributable to the remaining two deepwater projects were added as follows:

Net Proved

Undeveloped

Year Expected to

Reserves

Year

Convert to Proved

Property

(Bcfe)(1)

Added

Developed Status

Green Canyon 646 (Daniel Boone)

16.4

2003

2007

Atwater Valley 380/381/382/425/426 (Bass Lite)

30.7

2005

2007


(1)	Net proved undeveloped reserves attributable to the project as of June 30, 2005.


	*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 September 30, 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.”

For the year ended December 31, 2004, assuming a totally unhedged position, our price sensitivity for 2004 historical net revenues for a 10% change in average oil prices and average gas prices received is approximately $8.9 million and $14.5 million, respectively. For the nine months ended September 30, 2005, assuming a totally unhedged position, our price sensitivity for net revenues in the first nine months of 2005 for a 10% change in average oil prices and average gas prices received is approximately $6.7 million and $10.5 million, respectively.


	*Operating Costs*

We classify our operating costs as lease operating expense, transportation expense, and general and administrative expenses. Lease operating expenses are comprised of those costs and expenses necessary to produce oil and gas after an individual well or field has been completed and prepared for production. These costs include direct costs such as field operations, general maintenance expenses, work-overs, and the costs associated with production handling agreements for most of our deep water fields. Lease operating expenses also include indirect costs such as oil and gas property insurance and overhead allocations in accordance with joint operating agreements. We also include severance, production, and ad valorem taxes as lease operating expenses.

Transportation costs are generally variable costs associated with transportation of product to sales meters from the wellhead or field gathering point. General and administrative include employee compensation costs (including stock compensation expense), the costs of third party consultants and professionals, rent and other costs of leasing and maintaining office space, the costs of maintaining computer hardware and software, and insurance and other items.

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 and stock options that were granted on March 11, 2005 pursuant to our Equity Participation Plan and Stock Incentive 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.

The fair value of restricted stock that we granted following the closing of the private equity placement pursuant to our Equity Participation Plan was estimated to be $31.7 million. The fair value will be amortized to compensation expense over the applicable vesting periods. Stock options and restricted stock granted 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 of Mariner—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.

Mariner 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 Mariner 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.”


	*Nine Months Ended September 30, 2005 compared to Nine Months Ended September 30, 2004*

Operating and Financial Results for the Nine Months Ended September 30, 2005 Compared

to the Nine Months Ended September 30, 2004


				Non-GAAP
				Combined			Post-Merger			Pre-Merger

	Nine Months Ended						Period from			Period from
	September 30,						March 3, 2004			January 1, 2004
							through September 30,			through March 2,
Summary Operating Information:	2005			2004			2004			2004

	(in thousands, except average sales price)
Net production:
Oil (MBbls)		1,336			1,748			1,335			413
Natural gas (MMcf)		14,508			17,959			13,726			4,233
Total (Mmcfe)		22,521			28,444			21,731			6,713
Average daily production (Mmcfe/d)		82			104			102			112
Hedging activities:
Oil revenues (loss)	$	(13,421	)	$	(6,874	)	$	(6,188	)	$	(686	)
Gas revenues (loss)		(9,979	)		(1,010	)		(2,441	)		1,431

Total hedging revenues (loss)	$	(23,400	)	$	(7,884	)	$	(8,629	)	$	745


			Non-GAAP
			Combined		Post-Merger		Pre-Merger

	Nine Months Ended				Period from		Period from
	September 30,				March 3, 2004		January 1, 2004
					through September 30,		through March 2,
Summary Operating Information:	2005		2004		2004		2004

	(in thousands, except average sales price)
Average Sales Prices:
Oil (per Bbl) realized(1)	$	40.12	$	32.78	$	33.41	$	30.75
Oil (per Bbl) unhedged		50.17		36.71		38.05		32.41
Natural gas (per Mcf) realized(1)		6.54		5.85		5.68		6.39
Natural gas (per Mcf) unhedged		7.23		5.90		5.86		6.05
Total natural gas equivalent ($/Mcfe) realized(1)		6.59		5.71		5.64		5.92
Total natural gas equivalent ($/Mcfe) unhedged		7.63		5.98		6.04		5.81
Oil and gas revenues:
Oil sales	$	53,579	$	57,285	$	44,576	$	12,709
Gas sales		94,913		105,005		77,950		27,055

Total oil and gas revenues	$	148,492	$	162,290	$	122,526	$	39,764
Other revenues		2,753		—		—		—
Lease operating expenses		20,170		19,194		15,073		4,121
Transportation expenses		1,697		4,814		3,744		1,070
Depreciation, depletion and amortization		43,457		48,094		37,464		10,630
General and administrative expenses		26,726		7,305		6,174		1,131
Net interest expense (income)		4,720		4,127		4,213		(86	)
Income before taxes		53,977		77,799		54,901		22,898
Provision for income taxes		18,414		27,293		19,221		8,072


(1)	Average realized prices include the effects of hedges.

Net production during the nine months ended September 30, 2005 decreased approximately 21% to 22.5 Bcfe from 28.4 Bcfe in the same period of 2004 primarily due to decreased Gulf of Mexico production, partially offset by increased onshore production. Mariner’s production was negatively impacted during the third quarter of 2005 due to hurricane activity, primarily Katrina and Rita. Production shut-in and deferred because of the hurricanes’ impact totaled approximately 1.3 Bcfe during the third quarter of 2005. As of September 30, 2005, approximately 7 MMcfe per day of production remained shut-in awaiting repairs, primarily associated with our Baccarat property (although, production therefrom recommenced in January 2006). Additionally, production that was anticipated to commence in the third quarter of 2005 at our Swordfish, Pluto, and Rigel development projects has been delayed until the fourth quarter of 2005 for Swordfish, and into 2006 at Pluto and Rigel, awaiting repairs to host facilities.

Increased development drilling at our Aldwell unit in West Texas contributed to a 61% increase in onshore production to an average of approximately 17.1 Mmcfe per day in the first nine months of 2005 from an average of approximately 10.5 Mmcfe per day in the first nine months of 2004.

In the deepwater Gulf of Mexico, production decreased approximately 30% to an average of approximately 33 Mmcfe per day in the first nine months of 2005 compared to an average of approximately 47 Mmcfe per day in the first nine months of 2004. The decrease was largely due to reduced production at our Black Widow, Yosemite 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 and Yosemite are undergoing expected declines.

In the Gulf of Mexico shelf, production decreased by approximately 30% to an average of approximately 32 Mmcfe per day in the first nine months of 2005 from an average of approximately 46 Mmcfe per day in the first nine months 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) and production from the 2004 acquisition of interests in five offshore fields offset normal declines at our other Gulf of Mexico shelf fields.

Hedging activities in the first nine months of 2005 decreased our average realized natural gas price received by $0.69 per Mcf and revenues by $10.0 million, compared with a decrease of $0.05 per Mcf and revenues of $1.0 million for the same period in 2004. Our hedging activities with respect to crude oil during the first nine months of 2005 decreased the average sales price received by $10.05 per barrel and revenues by $13.4 million compared with a decrease of $3.93 per barrel and revenues of $6.9 million for the same period in 2004.

Oil and gas revenues decreased 6% to $148.5 million in the first nine months of 2005 when compared to first nine months 2004 oil and gas revenues of $162.3 million, due to the aforementioned 21% decrease in production, partially offset by a 16% increase in realized prices (including the effects of hedging) to $6.59 per Mcfe in the first nine months of 2005 from $5.71 per Mcfe in the same period in 2004.

Other revenues of $2.7 million in the first nine months of 2005 represent an indemnity payment received from our former stockholder related to the merger of $1.9 million and $0.8 million generated by our West Texas Aldwell unit gathering system.

Lease operating expenses increased 5% to $20.2 million in the first nine months of 2005 from $19.2 million in the first nine months of 2004. The increased costs were primarily attributable to the addition of new producing wells at our Aldwell Unit offset by reduced costs on our Black Widow, King Kong/Yosemite, and Pluto deep water fields. On a per unit basis, lease operating expenses were $0.90 per Mcfe in the first nine months of 2005 compared to $0.67 per Mcfe in the first nine months of 2004. The increased per unit costs also reflect lower production rates in the 2005 period, including hurricane-related disruptions.

Transportation expenses were $1.7 million or $0.08 per Mcfe in the first nine months of 2005, compared to $4.8 million or $0.17 per Mcfe in the first nine months of 2004. The reduction is primarily attributable to our deepwater fields and includes reductions caused by the filing of new and higher transportation allowances with the MMS on two of our deepwater fields for purpose of royalty calculation.

Depreciation, depletion, and amortization expense decreased 10% to $43.5 million during the first nine months of 2005 from $48.1 million for the first nine months of 2004 as a result of decreased production of 5.9 Bcfe in the first nine months of 2005 compared to the first nine months of 2004, partially offset by an increase in the unit-of-production depreciation, depletion and amortization rate to $1.93 per Mcfe for the first nine months of 2005 from $1.69 per Mcfe for the same period in 2004. The per unit increase was primarily the result of an increase in future development costs on our deepwater development fields.

General and administrative expenses (“G&A”), which are net of $3.1 million and $2.2 million of overhead reimbursements billed or received from other working interest owners in the first nine months of 2005 and 2004, respectively, increased 266% to $26.7 million during the first nine months of 2005 compared to $7.3 million in the first nine months of 2004. The increase was primarily due to recognizing $17.6 million in stock compensation expense related to restricted stock and options granted in the first nine months of 2005. We also paid $2.3 million to our former stockholders to terminate a services agreement in the first nine months of 2005, compared to $1.0 million under the same agreement in the first nine months of 2004. In addition, G&A expenses increased by $1.8 million due to a reduction in the amount of G&A capitalized in the first nine months of 2005 compared to the first nine months of 2004.

Net interest expense for the first nine months of 2005 increased 14% to $4.7 million from $4.1 million in the first nine months of 2004, primarily due to lower average debt levels in the first nine months of 2004 compared to the first nine months of 2005. In connection with the Merger on March 2, 2004, Mariner

incurred $135 million in new bank debt and issued a $10 million promissory note to JEDI. For comparison purposes, approximately seven months of interest related to such borrowings is reflected in the first nine months of 2004 compared to nine months of interest in 2005.

Income before income taxes decreased to $54.0 million for the first nine months of 2005 compared to $77.8 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 and transportation expenses.

Provision for income taxes decreased to $18.4 million for the first nine months of 2005 from $27.3 million for the first nine months of 2004 as a result of decreased operating income for the nine months ended September 30, 2005 compared to the prior period.


	*Year Ended December 31, 2004 compared to Year Ended December 31, 2003*

Operating and Financial Results for the Year Ended December 31, 2004 Compared to

the Year Ended December 31, 2003


				Non-GAAP
				Combined			Post-Merger			Pre-Merger

							Period from			Period from
	Year Ended December 31,						March 3, 2004			January 1, 2004
							through December 31,			through March 2,
Summary Operating Information:	2003			2004			2004			2004

	(in thousands, except average sales price)
Net production:
Oil (MBbls)		1,600			2,298			1,885			413
Natural gas (MMcf)		23,772			23,782			19,549			4,233
Total (Mmcfe)		33,374			37,569			30,856			6,713
Average daily production (Mmcfe/d)		91			103			101			112
Hedging activities:
Oil revenues (loss)	$	(4,969	)	$	(12,299	)	$	(11,613	)	$	(686	)
Gas revenues (loss)		(24,494	)		(7,498	)		(8,929	)		1,431

Total hedging revenues (loss)	$	(29,463	)	$	(19,797	)	$	(20,542	)	$	745
Average Sales Prices:
Oil (per Bbl) realized(1)	$	23.74		$	33.17		$	33.69		$	30.75
Oil (per Bbl) unhedged		26.85			38.52			39.85			32.41
Natural gas (per Mcf) realized(1)		4.40			5.80			5.67			6.39
Natural gas (per Mcf) unhedged		5.43			6.12			6.13			6.05
Total natural gas equivalent ($/Mcfe) realized(1)		4.27			5.70			5.65			5.92
Total natural gas equivalent ($/Mcfe) unhedged		5.15			6.23			6.32			5.81


			Non-GAAP
			Combined		Post-Merger		Pre-Merger

					Period from		Period from
	Year Ended December 31,				March 3, 2004		January 1, 2004
					through December 31,		through March 2,
Summary Operating Information:	2003		2004		2004		2004

	(in thousands, except average sales price)
Oil and gas revenues:
Oil sales	$	37,992	$	76,207	$	63,498	$	12,709
Gas sales		104,551		137,980		110,925		27,055

Total oil and gas revenues	$	142,543	$	214,187	$	174,423	$	39,764
Lease operating expenses		24,719		25,484		21,363		4,121
Transportation expenses		6,252		3,029		1,959		1,070
Depreciation, depletion and amortization		48,339		64,911		54,281		10,630
General and administrative expenses		8,098		8,772		7,641		1,131
Impairment of production equipment held for use		—		957		957		—
Net interest expense (income)		6,225		5,734		5,820		(86	)
Income before taxes and change in accounting method		45,688		105,300		82,402		22,898
Provision for income taxes		9,387		36,855		28,783		8,072


(1)	Average realized prices include the effects of hedges.

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.

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 Mariner 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 September 30, 2005 was negative $30.2 million, excluding current derivative liabilities and related tax effects. Accounts payable and accrued liabilities at September 30, 2005 increased by approximately 23% over levels at December 31, 2004 primarily due to increased current obligations for our Swordfish and Pluto development projects 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 Mariner utilizes excess cash. At year-end 2003, Mariner 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, Mariner 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 $250 million with approximately 48% allocated to development projects, 27% to exploration activities, 21% to acquisitions and the remainder to other items (primarily capitalized overhead and interest). This is an increase of approximately $98 million over our original 2005 budget. The increase is primarily driven by acquisitions of interests in properties, by new drilling projects at LaSalle/ NW Nansen, and by the cost of remediating a flow line obstruction at our Pluto project.

With the anticipated increase in capital expenditures and reduced production, partially from the impact of hurricanes, 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 $185 million with approximately $75 million drawn as of September 30, 2005. Because of increased capital expenditures in the fourth quarter of 2005 (including about $40 million for acquisitions) and reduced cash flows, borrowings under the revolving credit facility increased to approximately $152.0 million by year-end 2005.

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 addition, 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 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.

Our existing proved reserves are comprised of West Texas and Gulf of Mexico properties. The West Texas properties are relatively long-life in nature characterized by relatively low decline rates (lower productive rates) while the Gulf of Mexico properties are shorter-life in nature characterized by relatively high decline rates (higher productive rates). For the nine months ended September 30, 2005, our Gulf of Mexico properties comprised about 79% of our total production. We plan to maintain an active drilling program on our onshore properties with the intention of maintaining or increasing production in those areas. Although production from our existing offshore wells will decline more rapidly over time than our onshore wells, the percentage of production attributable to our offshore wells is expected to increase in the coming years as more of our undeveloped deep water projects commence production. While we expect this trend to continue for the near future, oil and gas production (especially for our offshore properties) can be heavily affected by reservoir characteristics and unforeseen events (such as hurricanes and other casualties), so we can not predict with any certainty the timing of declines in production or the commencement of production from new projects.

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.

For the year ended December 31, 2004 and the nine months ended September 30, 2005, our interest rate sensitivity for a change in interest rates of ¹/8 percent on average outstanding debt under our credit facility is approximately $0.2 million and $0.1 million, respectively. The LIBOR rate on which our bank borrowings are primarily based was 4.19% as of November 23, 2005.

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.

Pre-Merger

Combined

Post-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

(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 Mariner.

Pre-Merger

Combined

Post-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

(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.

Pre-Merger

Combined

Post-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

(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 September 30, 2005, Mariner had the following hedge contracts outstanding:


						September 30, 2005
				Fixed		Fair Value
Fixed Price Swaps		Quantity		Price		Gain/(Loss)

						(in millions)
Crude Oil (Bbls)
	October 1—December 31, 2005		138,000	$	25.22	$	(5.7	)
	January 1—December 31, 2006		140,160		29.56		(5.2	)
Natural Gas (MMBtus)
	October 1—December 31, 2005		1,352,400		5.00		(12.3	)
	January 1—December 31, 2006		1,827,547		5.53		(13.6	)

	Total					$	(36.8	)


								September 30, 2005
								Fair Value
Costless Collars		Quantity		Floor		Cap		Gain/(Loss)

								(in millions)
Crude Oil (Bbls)
	October 1—December 31, 2005		57,960	$	35.60	$	44.77	$	(1.2	)
	January 1—December 31, 2006		251,850		32.65		41.52		(6.2	)
	January 1—December 31, 2007		202,575		31.27		39.83		(4.8	)
Natural Gas (MMBtus)
	October 1—December 31, 2005		2,189,600		6.01		8.02		(12.3	)
	January 1—December 31, 2006		7,347,450		5.78		7.85		(29.1	)
	January 1—December 31, 2007		5,310,750		5.49		7.22		(14.7	)

	Total							$	(68.3	)

As of December 31, 2004, Mariner 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 September 30, 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 $200 million of revolving borrowing capacity, subject to a borrowing base limitation. We currently expect to replace this credit facility when the merger is completed. See “Financing Arrangements Relating to the Spin-Off and the Merger” beginning on page 138. The borrowing capacity is currently subject to a borrowing base of $185 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.

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 September 30, 2005, $75.0 million was outstanding under the credit facility, and the weighted average interest rate was 5.84%. This debt matures on March 2, 2007. Because of increased capital expenditures in the fourth quarter of 2005 (including about $40 million for acquisitions) and reduced cash flows, borrowings under the revolving credit facility increased to approximately $152.0 million by year-end 2005.

Our management is considering a possible sale in a private placement of between $150 and $250 million in aggregate principal amount of notes. The notes would not be registered under the Securities Act or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from registration. We expect that the notes would be offered only to qualified institutional buyers under Rule 144A and non-U.S. persons under Regulation S. We anticipate that the net proceeds from the offering would be used to repay borrowings under our credit facility, and that the terms of the notes would be no more restrictive than the terms of our credit facility.


	*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 September 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.


						Pre-Merger

		Combined		Post-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

		(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(1)	$	115.0	$	—	$	115.0	$	—	$	—
Interest obligations(2)		0.6		0.5		0.1		—		—
Operating leases		1.1		0.6		0.5		—		—
Abandonment liabilities		24.0		4.7		7.2		7.7		4.4
Derivative liability(3)		22.4		17.0		5.4		—		—
Other long-term liabilities		3.0		2.0		1.0		—		—

Total contractual cash commitments	$	166.1	$	24.8	$	129.2	$	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. As of November 30, 2005, we had incurred debt obligations under our credit facility of $75 million and under the JEDI promissory note of $4 million.

(2)	Interest obligations represent approximately 14 months of interest due on the JEDI promissory note at 10%. Future interest obligations under our credit facility are uncertain, due to the variable interest rate on fluctuating balances. Based on a 5.2% weighted average interest rate on amounts outstanding under our credit facility as of December 31, 2004, $5.5 million, $5.5 million and $0.9 million would be due under the credit facility in 2005, 2006 and 2007, respectively.

(3)	As of September 30, 2005, the fair value of the derivative liabilities was $105.1 million, including $76.9 million due in less than one year.

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 Mariner 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. On October 3, 2005, we filed suit in the U.S. District Court for the Southern District of Texas seeking judicial review of the dismissal of our appeal by the Board of Land Appeals. Mariner has recorded a liability for 100% of the exposure on this matter which on September 30, 2005 was $14.6 million. For additional information concerning the contested royalty payments and the MMS’s demands, see “Business—Legal Proceedings” below.

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, Mariner 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 Mariner or liabilities that are based on the fair value of Mariner’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. Mariner adopted the provisions of the new standard on January 1, 2005.

As a result of the adoption of the above described SFAS No. 123(R), we recorded compensation expense for the fair value of restricted stock that was granted pursuant to our Equity Participation Plan (see “Management of Mariner—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 of Mariner—Stock Incentive Plan”). We recorded 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 nine months ended September 30, 2005 includes $17.2 million of compensation expense related to restricted stock granted in 2005 and $0.4 million of compensation expense related to stock options outstanding as of September 30, 2005.

On September 2, 2004, the FASB issued FASB Staff Position No. FAS 142-2, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Producing Entities,” addressing whether the scope exception within SFAS No. 142, “Goodwill and Other Intangible Assets” includes the balance sheet classification and disclosures for drilling and mineral rights of oil and gas producing properties. The FASB staff concluded that the accounting framework for oil and gas entities is based on the level of established reserves, not whether an asset is tangible or intangible, and thus the scope exception extended to the balance sheet classification and disclosure provisions for such assets.

On September 28, 2004, the SEC released Staff Accounting Bulletin (“SAB”) 106 regarding the application of SFAS 143, “Accounting for Asset Retirement Obligations (“AROs”),” by oil and gas producing companies following the full cost accounting method. Pursuant to SAB 106, oil and gas producing companies that have adopted SFAS 143 should exclude the future cash outflows associated with settling AROs (ARO liabilities) from the computation of the present value of estimated future net 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

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 estimated proved reserves, of which approximately 64% were natural gas and 36% were oil and condensate. The estimated pre-tax PV10 value of our estimated proved reserves as of December 31, 2004 was approximately $668 million, and the standardized measure of discounted future net cash flows attributable to our estimated proved reserves was approximately $494.4 million. Please see “—Estimated Proved Reserves” for a definition of PV10 and a reconciliation of PV10 to the standardized measure of discounted future net cash flows. As of December 31, 2004, approximately 46% of our estimated proved reserves were classified as proved developed. For the year ended December 31, 2004, our total net production was 37.6 Bcfe. Our estimated 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, including select deep shelf prospects, 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.”

The following discussion includes statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. See “Cautionary Statement Concerning Forward-Looking Statements” for more details. Also, the discussion uses terms that pertain to the oil and gas industry, and you should see “Glossary of Oil and Natural Gas Terms” for the definition of certain terms.

Significant Properties


								Approximate				Date		Estimated
					Mariner			Water		Gross		Production		Proved				Standardized
					Working			Depth		Producing		Commenced/		Reserves		PV10 Value		Measure
			Operator		Interest			(Feet)		Wells(1)		Expected		(Bcfe)		(In $ Millions)(2)		(In $ Millions)

					%
West Texas Permian Basin:
	Aldwell Unit			Mariner		66.5	(3)		Onshore		185		1949		112.7	$	203.8
Gulf of Mexico Deepwater:
	Mississippi Canyon 296/252 (Rigel)			Dominion		22.5			5,200		0	Second Quarter 2006			22.4		82.9
	Viosca Knoll 917/961/962 (Swordfish)			Mariner(4)		15.0			4,700		2	Fourth Quarter 2005			13.4		59.3
	Green Canyon 516 (Yosemite)			ENI		44.0			3,900		1		2002		15.1		66.6
	Mississippi Canyon 718 (Pluto)(5)			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		0		2002		1.2		2.0
Gulf of Mexico Shelf:
	Mississippi Canyon 66 (Ochre)(6)			Mariner		75.0			1,150		0		2004		3.6		11.7
	Other Properties										43				56.1		195.7

		Total:									231				237.5	$	668.0	$	494.4


(1)	Wells producing or capable of producing as of December 31, 2004.

(2)	Please see “—Estimated Proved Reserves” for a definition of PV10 and a reconciliation of PV10 to the standardized measure of discounted future net cash flows.

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

(4)	Mariner served as operator until December 2005, at which time pursuant to certain contractual arrangements, Noble Energy, Inc., a 60% partner in the project, began serving as operator.

(5)	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 second quarter of 2006.

(6)	Field has been shut in since September 2004 due to destruction of host platform by Hurricane Ivan.


	*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.

We have completed construction of our own oil and gas gathering system 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 second quarter of 2006.

Viosca Knoll 917/961/962 (Swordfish). Mariner generated the Swordfish prospect and entered into a farm-out agreement with BP in September 2001. We operated Swordfish until December 2005 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. Due to the impact of Hurricane Katrina on the host facility, initial production was delayed until the fourth quarter of 2005.

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.

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. During start–up operations, a paraffin plug was discovered in the flow–line between the Pluto field and the host facility. Remediation efforts are in progress and nearing completion. Production is expected to recommence in the second quarter of 2006, following completion of repairs to the host facilities necessitated by damage inflicted by Hurricane Katrina.

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 was brought online in the third quarter of 2005. The host platform sustained damage during Hurricane Rita, resulting in production being shut-in. Production recommenced in January 2006.

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. A development plan for the North Black Widow prospect has been approved and the operator of this project currently anticipates production from this project to begin in the second quarter of 2006. At June 30, 2005 approximately 4.5 Bcfe of estimated proved reserves have been assigned net to Mariner’s interest.

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. 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. At June 30, 2005 approximately 30.7 Bcfe of estimated proved reserves have been assigned net to Mariner’s interest.

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 2006 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 development well and one exploration well—the first on block 473 and the second on block 472, both in the first quarter of 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*

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 first quarter of 2006, following completion of repairs to the host facility necessitated by damage inflicted by Hurricane Katrina and the installation of the flowline and umbilical.


	Other Activity

In connection with 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 connection with the August 2005 Western Gulf of Mexico lease sale, we were awarded one shelf block (High Island A2) and four deepwater blocks (East Breaks 344, East Breaks 843, East Breaks 844 and East Breaks 709).

In May 2005 we drilled the Capricorn discovery well, which encountered over 100 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 first quarter of 2006, with first production anticipated in 2006. We are the operator and own a 60% working interest in the project.

Estimated Proved Reserves

The following tables set forth certain information with respect to our estimated 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 prospectus as Annex A and is consistent with filings we make with federal agencies.


		Estimated Proved
		Reserve Quantities

				Natural				PV10 Value(3)
		Oil		Gas		Total								Standardized
Geographic Area		(MMbbls)		(Bcf)		(Bcfe)		Developed		Undeveloped		Total		Measure

														(millions)
								(millions)
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.

(3)	Please see “—Estimated Proved Reserves” for a definition of PV10 and a reconciliation of PV10 to the standardized measure of discounted future net cash flows.

Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond the control of Mariner. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and the interpretation thereof. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing, and production subsequent to the date of an estimate, as well as economic factors such as change in product prices, may require revision of such estimates. Accordingly, oil and gas quantities ultimately recovered will vary from reserve estimates.

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, Mariner’s reserves and production will decline. See “Risk Factors” and Note 10 to the Mariner 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,
		Nine Months Ended
		September 30, 2005		2004		2003		2002

Production:
	Natural Gas (Bcf)		14.5		23.8		23.8		29.6
	Oil (MMbbls)		1.3		2.3		1.6		1.7
	Total natural gas equivalent (Bcfe)		22.5		37.6		33.4		39.8
Average realized sales price per unit (excluding effects of hedging):
	Natural gas ($/Mcf)	$	7.23	$	6.12	$	5.43	$	3.35
	Oil ($/bbl)		50.17		38.52		26.85		21.60
	Total natural gas equivalent ($/Mcfe)		7.63		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 ($/bbl)		40.12		33.17		23.74		22.85
	Total natural gas equivalent ($/Mcfe)		6.59		5.70		4.27		3.97
Expenses ($/Mcfe):
	Lease operating	$	0.90	$	0.68	$	0.74	$	0.65
	Transportation		0.08		0.08		0.19		0.26
	General and administrative, net(1)		1.18		0.23		0.24		0.19
	Depreciation, depletion and amortization (excluding impairments)		1.93		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 nine months ended September 30, 2005 include compensation expense of $17.6 million for restricted stock and options 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 as of December 31, 2004 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,

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, and have pursued administrative and judicial remedies in this dispute with the MMS. For more information concerning the contested royalty payments and the MMS’s demands, 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.

In August, 2005, Congress enacted the Energy Policy Act of 2005 (“EP Act 2005”). Among other matters, EP Act 2005 amends the Natural Gas Act (“NGA”) to make it unlawful for “any entity”, including otherwise non-jurisdictional producers such as Mariner and Forest, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. On January 19, 2006, the FERC issued regulations implementing this provision. The regulations make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EP Act 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of the FERC’s enforcement authority. We do not anticipate we will be affected any differently than other producers of natural gas.

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 February 1, 2006, we had 80 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. On October 3, 2005, we filed suit in the U.S. District Court for the Southern District of Texas seeking judicial review of the dismissal of our appeal by the Board of Land Appeals. Mariner has recorded a liability for 100% of the potential exposure on this matter, which on September 30, 2005 was $14.6 million.

In addition to the foregoing, by letter dated December 2, 2005, the MMS notified Mariner that 2004 commodity prices exceeded the predetermined levels and, accordingly, that royalties were due on natural gas and oil produced in calendar year 2004 from federal offshore leases with confirmed royalty suspension volumes as defined by the RRA. On December 29, 2005, Mariner filed a notice of intent to appeal this royalty demand from the MMS. Mariner has paid royalties on calendar year 2004 production from federal offshore leases in which it owns an interest except for 2004 production from Ewing Bank 966 and Garden Banks 367, being the two leases at issue in the lawsuit discussed above.

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, we 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. 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 first quarter of 2006. In addition, a semi-submersible rig on location at Mariner’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 Mariner is unknown. For the insurance period ending September 30, 2004, we carried an annual deductible of $1.25 million and a single occurrence deductible of $.375 million.

Until we are able to complete all the repair work and submit costs to our insurance underwriters for review, the full extent of our insurance recovery and the resulting net cost to us for Hurricanes Katrina and Rita will be unknown. For the insurance period ending September 30, 2005, we carried a $3.0 million annual deductible and a $.375 million single occurrence deductible.

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.

THE SPIN-OFF AND MERGER

Background of the Merger

At regular meetings of Forest’s board held on November 10, 2004 and February 23, 2005, Forest’s management made presentations regarding the estimated value of Forest’s business units. Forest’s board and management agreed to examine alternatives to increase the value of the Forest Gulf of Mexico operations. The alternatives were taxable and non-taxable divestments of the Forest Gulf of Mexico operations, and included an outright cash sale of those operations, an initial public offering, and some form of a merger transaction. Forest’s board determined that an initial public offering would require much more time than the other alternatives and, due to the need to create and manage a new corporation for potentially an extended period of time, with associated job overlap and reassignments, would place a significant burden on employee retention and staffing. Forest’s board also determined that, due to the disparity in the market value and tax basis of the Forest Gulf of Mexico operations, a non-taxable alternative would be most attractive to Forest and its shareholders. One specific alternative presented by management was merging the Forest Gulf of Mexico operations with another company that was more focused on offshore activities and possessed a complementary asset base. Forest’s directors instructed Forest’s management to consider means to accomplish such a merger and to discuss such a strategy with financial advisors and legal and tax counsel.

On April 18, 2005, Mr. David Keyte, the Chief Financial Officer of Forest, spoke briefly with Mr. Scott Josey, the Chief Executive Officer, President and Chairman of Mariner, at a meeting of the Independent Petroleum Association of America in New York City. Mr. Keyte told Mr. Josey that Forest was interested in examining the possibility of spinning off its Gulf of Mexico operations utilizing a “reverse Morris Trust” structure. In general terms, a reverse Morris Trust structure in this context would entail a Forest distribution of the stock of one of its subsidiaries (preexisting or newly formed) to Forest shareholders, followed by a merger between such subsidiary and Mariner. Mr. Josey expressed interest in a potential transaction, and Messrs. Keyte and Josey agreed to discuss the matter with greater specificity at a later date.

Forest’s initial contact with Mariner regarding a potential transaction was not the result of affiliations between the parties. Forest and Mariner do not have common directors, and no member of senior management of either party is a former employee of, or is otherwise affiliated with, the other party. Mariner’s largest stockholder, FMR Corp. (which holds approximately 12.2% of Mariner’s outstanding shares), is also the second largest shareholder of Forest (holding approximately 12.7% of Forest’s outstanding shares). FMR Corp. has no board representation or other management control over either party. Mr. Forrest E. Hoglund, the Chairman of Forest’s board of directors, served as Chairman of the Board of EOG Resources, Inc., an affiliate of Enron Corp., from 1987 to 1999 and as President from 1990 to 1996. During part of this period, Mariner was also an affiliate of Enron Corp., though the companies’ respective management teams were separate. Neither Mr. Hoglund nor Mariner is currently affiliated with Enron Corp.

On May 10, 2005, at a regularly scheduled board meeting at Forest’s offices in Denver, Colorado, Forest management made a presentation to the Forest board of directors regarding a potential spin-off and merger of the Forest Gulf of Mexico operations, utilizing a reverse Morris Trust structure. Forest’s management identified five potential merger parties that met certain criteria relating to size and complementary Gulf of Mexico asset base. In order to use a reverse Morris Trust structure, Forest required a merger party of a size such that, when combined with the Forest Gulf of Mexico operations, the relative values of the party and the Forest Gulf of Mexico operations would result in Forest’s shareholders owning more than 50% of the combined entity. Also, Forest sought a merger party that already capably managed a significant Gulf of Mexico asset base. It was desirable that the merger party’s asset base be in reasonable proximity, and complementary in terms of acreage, to the Forest Gulf of Mexico operations, such that the combination of the two might produce a significant scale of operations and operational efficiencies and synergies.

The Forest board authorized Forest management to begin efforts to evaluate and pursue the potential spin-off. As a result, during the week of May 16, 2005, Mr. Keyte contacted each of the five potential

merger parties. These potential merger parties, which included Mariner, will be referred to herein as Mariner, Party A, Party B, Party C and Party D.

On or about May 21, 2005, Forest sent to Mariner a confidentiality agreement regarding the proposed transaction and any subsequent due diligence reviews. From May 21, 2005 through May 23, 2005, Forest and Mariner negotiated the terms of the confidentiality agreement and on May 23, 2005, Forest and Mariner executed the confidentiality agreement. Over the course of the following week, Forest executed confidentiality agreements with Party A, Party B and Party C, and Forest management made presentations regarding a possible spin-off and merger to each such party. Party D declined to execute a confidentiality agreement, stating that it had concluded that it could not devote the necessary time and focus required to proceed with Forest in a timely fashion. Forest had no further substantive discussions with Party D. After Forest made its presentation regarding the possible spin-off and merger, Party C stated that it could not meet Forest’s timing requirements and had decided not to proceed. Forest had no further substantive discussions with Party C.

On May 24, 2005, Mr. Keyte, Mr. Michael Kennedy, the Investor Relations Manager of Forest, and Mr. Josey met in Houston, Texas. At the meeting, Mr. Keyte made a presentation detailing the transaction contemplated by Forest. The presentation described the transaction structure and provided information on the assets, reserves, acreage, personnel and performance metrics (including production and EBITDA) of the Forest Gulf of Mexico operations. The presentation also covered the pro forma operational and financial characteristics of the combined company based on preliminary figures. Mr. Keyte identified several potential advantages to Mariner of undertaking the proposed transaction, including increased liquidity, an attractive, balanced asset portfolio in the Gulf of Mexico, and property prospects for future development. Mr. Keyte did not propose economic terms for the transaction, such as the ownership stake Forest shareholders would hold in Mariner after the completion of the transaction. After this, Mr. Josey made a presentation regarding Mariner and the merits of consummating a transaction with Mariner. The presentation provided an overview of Mariner’s operations, properties, production and reserves; management structure; exploration and development projects, including the Swordfish project (please see “Mariner — Significant Properties — Gulf of Mexico Deepwater” for more information on this project); and financial data, including capital expenditures. Prior to the conclusion of the meeting, Mr. Keyte requested that Mariner’s management team make a presentation to Forest’s board of directors at a later date.

On June 2, 2005, Forest made available to Mariner, for purposes of its due diligence review, electronic data regarding the reserves, lease operating expenses, capital expenditures, production, general and administrative expenses and financial performance of the Forest Gulf of Mexico operations. Forest also made the same information available to Party A and Party B. Representatives of Mariner, Party A and Party B conducted reviews of these materials on an ongoing basis over the course of the following weeks.

On June 16, 2005, the executive committee of Forest’s board of directors, consisting of Messrs. Forrest E. Hoglund, James H. Lee and Craig Clark, met in Houston, Texas with members of Forest management and representatives of Citigroup Global Markets Inc. (“Citigroup”) (one of Forest’s financial advisors) to discuss the contemplated spin-off and merger. Representatives of Party A and Party B then sequentially joined the meeting and made presentations to the executive committee.

On June 22, 2005, the executive committee of Forest’s board of directors held a meeting in Forest’s offices in Denver, Colorado. Members of Forest management and representatives of Citigroup were also present at the meeting. At this meeting, the executive committee was briefed on the status of discussions with Mariner, Party A and Party B. Mr. Josey, accompanied by Messrs. Dalton Polasek, Chief Operating Officer, Rick Lester, Vice President and Chief Financial Officer, Mike van den Bold, Vice President and Chief Exploration Officer, and Jesus Melendrez, Vice President — Corporate Development of Mariner, then joined the meeting and made a presentation to the executive committee and the other attendees. The presentation provided an overview of Mariner’s operations, properties, production and reserves; management structure; exploration and development projects, including the King Kong/Yosemite, Pluto II, Bass Lite, LaSalle, Swordfish, Green Pepper and Rigel projects; prospect inventory; drilling programs; seismic

databases; and financial data, including a capital expenditure budget for 2005. Mr. Josey presented Mariner’s views on its own enterprise value and discussed a proposed method for establishing an exchange ratio focused primarily upon the PV10 values of the parties’ estimated proved reserves. He did not propose an exchange ratio for the transaction or other specific economic terms. Mr. Josey advised Forest that Mariner would require that the evaluation of Mariner for purposes of establishing an exchange ratio give effect to its anticipated West Texas acquisition.

On June 23, 2005, a special committee of Forest’s board of directors was formed to consider proposals to spin-off the Forest Gulf of Mexico operations. The directors named to be members of the committee were Messrs. Hoglund, Dod A. Fraser, Mr. Lee, James D. Lighter, and Patrick R. McDonald.

On June 28, 2005, Mariner, Party A and Party B received a written request from Forest for a non-binding, preliminary proposal to acquire the Forest Gulf of Mexico operations. The proposal was requested to be submitted no later than July 6 and to include certain information, including the percentage of shares of the combined entity to be held by Forest shareholders, key assumptions used in arriving at the level of consideration to be offered, transaction structure, and a statement of intent with respect to employees of the Forest Gulf of Mexico operations.

On June 29, 2005, Mr. Clark, Forest’s Chief Executive Officer, and other members of Forest’s management and technical teams made a presentation to Party A on the attributes and upside potential of the Forest Gulf of Mexico operations. Representatives of Citigroup were also present at the meeting. The size of Party A in comparison to the Forest Gulf of Mexico operations was identified as an issue that might preclude Forest from structuring the spin-off as a tax-free transaction. Therefore, Forest could be required to include more assets in the transaction, either in the form of additional oil and gas operations or cash.

On July 6, 2005, Mariner submitted to Forest a non-binding preliminary written proposal to acquire the Forest Gulf of Mexico operations. In the proposal, Mariner indicated its willingness to consummate a transaction in which Forest shareholders would hold between 53% and 56% of Mariner’s shares after the transaction, and Mariner would assume $300 million of indebtedness as part of the merger, which would be incurred by Forest’s subsidiary prior to being spun off by Forest in order to fund a distribution to Forest prior to the spin-off. Mariner stated that it had based its valuation of the Forest Gulf of Mexico operations at between 90% and 100% of the value of the Forest Gulf of Mexico operations estimated proved reserves and 100% of the value of Mariner’s estimated proved reserves. The proposal was subject to due diligence, and assumed an economic effective date of June 30, 2005 (i.e., all revenues and expenditures of the Forest Gulf of Mexico operations would accrue to the account of Mariner from that date). Mariner also included supporting schedules providing details on Mariner’s calculations of the respective values of the companies, based on the parties’ respective PV10 values at June 30, 2005. Mariner’s schedules estimated Mariner’s value, based upon PV10 values for its estimated proved reserves, and adjusted for debt, working capital and derivatives, at approximately $883 million. Mariner’s schedules estimated the Forest Gulf of Mexico operations’ value, based upon PV10 values for its estimated proved reserves, and adjusted for $300 million of debt, in a range from $978 million to $1.1 billion.

Also on July 6, 2005, Party A submitted a written proposal to Forest to acquire the Forest Gulf of Mexico operations and certain other substantial assets of Forest for a maximum valuation of $1.335 billion in stock. In its proposal, Party A used a different valuation method than Mariner had employed. Party A determined an implicit dollar-per-unit valuation of its own reserves, based on its stock price at the time of the proposal, number of outstanding shares of stock, total reserves and cash on hand. Party A then took that implicit valuation and applied it to the reserves of the Forest Gulf of Mexico operations. On that basis, which differed from Mariner’s basis, Party A established a comparative valuation for the reserves of the Forest Gulf of Mexico operations of approximately $1.2 billion based on the value of its stock at that time. Party A’s proposal provided for no cash payment to Forest, and for a repurchase by Party A of Party A’s stock to accommodate Party A’s assessment of relative value.

Party B declined to make a written proposal in the form and timing requested to acquire the Forest Gulf of Mexico operations. Forest had no further substantive discussions with Party B.

On July 11, 2005, the special committee of Forest’s board of directors met by teleconference with members of Forest management and representatives of Citigroup and Credit Suisse First Boston (“CSFB”) (another of Forest’s financial advisors). At this meeting, the special committee was briefed on the status of discussions with Mariner, Party A and Party B and with Mariner’s and Party A’s July 6 proposals. After discussion, the special committee concluded that, with respect to the Forest Gulf of Mexico operations, the valuation contained in Party A’s proposal was comparable to the valuation contained in Mariner’s proposal but that, with respect to Forest’s other assets, Party A’s valuation was insufficient. Further, Party A’s transaction structure was very complex, which Forest believed made the transaction less viable.

On July 14, 2005, Mr. Clark and other members of Forest’s management and technical teams made a presentation to Mr. Josey and other members of Mariner’s management and technical teams in Houston, Texas, on the attributes and upside potential of the Forest Gulf of Mexico operations. Representatives of Citigroup and CSFB were also present at the meeting. The presentation provided detail on several pending exploration and development projects.

On July 15, 2005, members of Forest management, together with representatives of Citigroup and CSFB, met in Houston, Texas with Party A to discuss the potential benefits of a transaction. Following the July 15 meeting, Party A declined to revise its proposal.

Following further technical and reserve due diligence, on July 21, 2005, Mariner submitted a revised non-binding preliminary written proposal to Forest. In the proposal, Mariner stated that it had revised the basis of its valuation to 100% of the value of the proved reserves of the Forest Gulf of Mexico operations, and was therefore confirming its willingness to enter into a transaction in which Forest shareholders would hold approximately 56% of Mariner’s shares, subject to due diligence and adjustment based upon material changes occurring prior to the execution of the merger agreement. As with the July 6, 2005 proposal, Mariner would assume $300 million of indebtedness, and the transaction would have an economic effective date of June 30, 2005. Mariner also requested that Forest enter into an exclusivity agreement, whereby Forest would agree to negotiate exclusively with Mariner for a period of 45 days.

On July 25, 2005, in accordance with Forest’s instructions, representatives of Citigroup met with Mr. Josey by teleconference. At the conclusion of the discussion, Mr. Josey indicated that he would ask the Mariner board to consider a transaction in which Forest shareholders would hold approximately 57% of the equity interests of the combined company after the merger, subject to due diligence and adjustment based upon material changes occurring prior to execution of the merger agreement.

On July 27, 2005, the special committee of Forest’s board of directors met by teleconference. Members of Forest management and representatives of Citigroup, CSFB and Vinson & Elkins L.L.P., outside counsel to Forest, were also present at the meeting. At this meeting, the special committee was updated on discussions with Mariner and Party A since the committee’s July 11th meeting and on the proposals of Mariner and Party A. The special committee also discussed alternative transactions involving the Forest Gulf of Mexico operations, including an initial public offering, an outright sale of the underlying assets, and the creation of a net-profits master limited partnership. The special committee instructed Forest management to pursue negotiations with Mariner. The special committee based its decision on the following factors: (i) Mariner’s deepwater property portfolio was complementary to Forest’s Gulf of Mexico portfolio, (ii) a spin-off followed by a merger transaction could be done with Mariner without having to involve assets other than the Forest Gulf of Mexico operations, and (iii) Party A’s valuation of Forest’s other producing operations did not appear to be sufficient.

In evaluating Mariner’s offer, Forest believed that the combination of stock and assumed liabilities offered by Mariner could be worth an amount in a range of approximately $1.1 billion to $1.4 billion, depending upon the trading value of Mariner’s common stock when the stock begins to trade upon the closing of the merger.

On July 27, 2005, in accordance with Forest’s instructions, a representative of Citigroup advised Mr. Josey that Forest’s board had approved management’s pursuit of a transaction with Mariner.

Subsequently, Mr. Josey advised Mr. Clark by teleconference that Mariner was not willing to proceed unless Forest would agree to an exchange ratio adjustment for changes in Mariner’s working capital and debt since June 30, 2005.

On July 28, 2005, Mr. Clark and Mr. Josey again met by teleconference. They discussed the proposed exchange ratio and adjustments and agreed to commence negotiating definitive documentation. Mr. Clark advised Mr. Josey that Forest would give Mariner access to additional due diligence materials.

On July 29, 2005, Forest distributed a draft non-binding term sheet for the transaction. The term sheet reflected the 57% exchange ratio and other agreed-upon terms, and was subject to mutual due diligence. Over the following three days, representatives of Forest and Mariner discussed various provisions in the term sheet, including whether interim operating covenants would apply to Mariner as well as the Forest Gulf of Mexico operations, board representation and whether or in what manner transaction expenses would be split between the parties.

Subsequently, Forest and Mariner executed an exclusivity agreement effective August 1, 2005, whereby the parties agreed to negotiate exclusively with each other through August 22, 2005. The agreement also contained a customary standstill provision, which provided that neither company would pursue an acquisition of the other party without that party’s consent.

On August 2, 2005, Forest and Mariner finalized the terms of the non-binding term sheet for the transaction. The term sheet reflected the 57% exchange ratio, provided that interim operating covenants would be applicable to both Mariner and the Forest Gulf of Mexico operations, provided for the addition of two mutually agreeable members to Mariner’s board and provided that transaction costs would be borne by both parties.

On August 4 and 5, 2005, representatives of Forest conducted a due diligence review of certain legal and employee benefits materials of Mariner at the offices of Baker Botts L.L.P., Mariner’s outside counsel, in Houston, Texas. Materials provided included general corporate materials, litigation summaries, material contracts, employment agreements, benefits arrangements and summaries, licenses and permits and environmental and regulatory information.

On August 5, 2005, Vinson & Elkins distributed a draft merger agreement to Mariner and Baker Botts.

On August 7, 2005, Mr. Josey met with representatives of Lehman Brothers (Mariner’s financial advisor) in the offices of Mariner. They discussed the general terms and structure of the transaction and the proposed exchange ratio.

On August 8 and 9, 2005, technical teams from Forest conducted a due diligence review and valuation analysis of Mariner’s proved reserves, drilling inventory and undeveloped acreage. Forest continued its technical, reserve, accounting, employee benefits, title and legal due diligence review over the course of the following weeks.

On August 9, 2005, representatives of Mariner and Baker Botts began a due diligence review of certain legal, title and employee benefits materials at the offices of Forest in Denver, Colorado, and Mariner’s technical team conducted further due diligence and continued its evaluation of Forest’s proved reserves, drilling inventory and undeveloped acreage. Materials provided included general corporate materials, litigation summaries, land, lease and title materials, material contracts, employment agreements, benefits arrangements and summaries, licenses and permits and environmental and regulatory information. With the assistance of appropriate legal, title, financial, tax, engineering, and human resources consultants, Mariner continued its technical, reserve, accounting, employee benefits, title and legal due diligence review over the course of the following weeks.

On August 10, 2005, Messrs. Clark and Keyte, Mr. Matthew Wurtzbacher, Senior Vice President, Corporate Planning and Development of Forest, and Mr. Cyrus Marter, Vice President and General Counsel of Forest, and Messrs. Josey, Lester, and Melendrez, and Ms. Teresa Bushman, Vice President and General Counsel of Mariner, together with representatives of Vinson & Elkins, Baker Botts, Citigroup

and Lehman Brothers, met in the offices of Vinson & Elkins in Houston, Texas. Vinson & Elkins explained how the draft merger agreement had addressed some of the details of the proposed transaction structure, which led to a discussion of whether Mariner or Forest Energy Resources would be the surviving entity in the business combination. Discussion of the structural issue was postponed pending further analysis. The parties also discussed interim operations following the execution of the merger agreement, with Mariner suggesting that both parties covenant to continue their exploration and development programs in accordance with their capital budgets. Forest indicated that it was amenable to this approach. Finally, the draft agreement proposed superior offer termination provisions in favor of Forest, which Mariner and Baker Botts stated would not be acceptable. Also, Mariner and Baker & Botts objected to the Mariner fiduciary provisions since they did not include a fiduciary termination provision. A fiduciary termination provision allows a party’s board of directors, if required by its fiduciary duties, to terminate the agreement in order to accept a subsequent superior offer. Representatives of Forest, Mariner, Baker Botts and Vinson & Elkins negotiated and exchanged drafts of the merger agreement, distribution agreement and other ancillary agreements over the course of the following week.

On August 15, 2005, Messrs. Keyte and Marter of Forest, and Messrs. Josey, Lester and Melendrez and Ms. Bushman of Mariner, together with representatives of Citigroup, Vinson & Elkins and Baker Botts, met by teleconference to discuss the draft distribution agreement. The companies discussed, and reached agreement in principle on, the manner in which known and unknown liabilities, including environmental and plugging and abandonment liabilities, would be allocated between Mariner and Forest. The companies also discussed the mechanism for handling revenues and expenses associated with the Forest Gulf of Mexico operations between July 1, 2005 and the closing of the merger.

On August 16, 2005, representatives of Baker Botts and Vinson & Elkins met by teleconference to discuss the “deal protection” provisions proposed by Forest in the draft merger agreement. Vinson & Elkins indicated Forest’s unwillingness to proceed with a transaction in which it did not have the right to terminate the agreement in the face of a superior proposal to purchase the Forest Gulf of Mexico operations or Forest as a whole. Baker Botts indicated that Mariner would not be willing to enter into a merger agreement that included such a termination right.

On August 18, 2005, representatives of Mariner, Forest, Baker Botts and Weil, Gotshal & Manges LLP (Forest’s outside tax counsel) met by teleconference to discuss the draft tax sharing agreement and related documents. During the meeting, Forest and Weil, Gotshal & Manges discussed certain factual circumstances involving forward contracts to sell Forest stock entered into by a Forest shareholder who held more than 10% of Forest stock, the effect of which could have imposed increased restraints on Mariner in the future in order to maintain favorable tax treatment of the spin-off.

Also on August 18, representatives of Mariner, Forest, Citigroup, Baker Botts and Vinson & Elkins met by teleconference to discuss the other transaction agreements. Following this teleconference, Lehman Brothers contacted Citigroup to notify them of Mariner’s unwillingness to proceed further until the potential tax issue regarding how the forward contracts entered into by the 10% Forest shareholder could impact the tax-free nature of the spin-off was resolved to Mariner’s satisfaction.

On August 19, 2005, Lehman Brothers contacted Citigroup to discuss various matters pertaining to the transaction and to propose that, in order to resolve the potential tax issue raised on August 18, the cash distribution to Forest be decreased by $100 million (thereby decreasing the amount of debt to be incurred in the transaction) and the number of Mariner shares to be issued to Forest shareholders be correspondingly increased.

On August 21, 2005, Mr. Josey of Mariner sent Messrs. Clark and Keyte of Forest a list of the most significant outstanding issues, including the potential tax issue, the superior offer termination provision, the representations on diligence materials and public filings, the treatment of Forest stock options, retention arrangements, the allocation of specified abandonment and derivative liabilities and the status of Mariner’s then-pending drill-to-earn transaction in West Texas. The parties agreed to meet in person to attempt to resolve the issues identified.

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On August 22, 2005, Messrs. Josey, Clark, Keyte and Melendrez met in Forest’s offices in Denver, Colorado. At the meeting, the parties agreed, in order to resolve the potential tax issue, to decrease the cash distribution to Forest by $100 million, to have Mariner assume certain mark-to-market derivative liabilities of approximately $50 million at June 30, 2005, and to increase the number of Mariner shares to be issued to Forest shareholders to approximately 58%. They also discussed the superior offer termination provision and the amount of the termination fee, without reaching agreement. The parties’ respective counsels revised the transaction agreements accordingly, and the transaction teams continued to negotiate various provisions in the agreements and to discuss various diligence issues over the course of the week.

On August 23, 2005, Messrs. Keyte and Josey met briefly by teleconference to discuss, among other things, the West Texas drill-to-earn transaction, the superior offer termination provision and the amount of the termination fee. That same day, the parties agreed to extend the exclusivity period under their existing agreement until August 29.

On August 24, 2005, Forest’s board of directors held a regular meeting at Forest’s offices in Denver, Colorado. Members of Forest management and representatives of Citigroup and CSFB were also present during the portion of the meeting devoted to the potential spin-off and merger transaction. At this meeting, the board was briefed on financial and other aspects of the transaction, including the status of negotiations with Mariner and the current terms of the transaction agreements. Also on August 24, 2005, Messrs. Clark and Josey met by teleconference to discuss additional diligence requests regarding reserves, current projects and plugging and abandonment costs from Mariner and Forest. Mr. Clark and Mr. Josey agreed to speak again when responsive data had been gathered.

On August 25, 2005, Messrs. Clark and Josey met by teleconference, during which the requested diligence information described above was exchanged and additional diligence matters were discussed.

On August 27, 2005, Mr. Marter of Forest, and Messrs. Lester and Melendrez and Ms. Bushman of Mariner, together with representatives of Vinson & Elkins and Baker Botts, met in the offices of Vinson & Elkins in Houston, Texas. The parties discussed and negotiated some of the outstanding issues remaining with respect to the transaction agreements, including the scope and pricing of the transition services to be provided by Forest after the closing, and the allocation of certain specified abandonment and environmental liabilities of the Forest Gulf of Mexico operations. The parties reached substantial agreement on transition services, but did not agree which party would bear the abandonment and environmental liabilities associated with two properties.

On August 28, 2005, Messrs. Keyte, Wurtzbacher and Marter of Forest, and Messrs. Lester and Melendrez and Ms. Bushman of Mariner, together with representatives of Vinson & Elkins and Baker Botts, met in the offices of Vinson & Elkins in Houston, Texas. The parties negotiated and discussed the outstanding issues remaining with respect to the transaction agreements, including Forest’s proposed superior offer termination right, the status of Mariner’s then-pending drill-to-earn transaction in West Texas and the specified abandonment and environmental liabilities. The parties agreed that Mariner would obtain a performance bond to secure its performance in the drill-to-earn program, and that it would assume a portion of the abandonment and environmental liabilities, subject to a cap. Mr. Keyte stated that Forest would be willing to proceed without a superior offer termination provision in favor of Forest. The parties also agreed that Mariner would have the ability to terminate the agreement in certain circumstances in order to accept a superior proposal to acquire Mariner. Finally, the parties agreed on a termination fee of $25 million and an expense reimbursement provision payable by Mariner if the merger agreement were terminated or rejected by its stockholders in order to accept an alternative transaction. The Mariner representatives did not insist on a termination fee or reimbursement provision applicable to Forest because there would be no provisions in the merger agreement pursuant to which Forest could terminate the agreement in order to accept an alternative transaction. The parties concluded the meeting by agreeing to keep each other updated on developments related to Hurricane Katrina, which was expected to reach the parties’ properties in the Gulf of Mexico that evening.

On August 29, 2005, Messrs. Clark and Josey met in Mariner’s offices in Houston, Texas to discuss retention arrangements for Mariner’s executive officers and for the employees of the Forest Gulf of Mexico

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operations. During the meeting, they reviewed organizational charts and discussed the companies’ benefits and incentive plans. The parties discussed the basic retention parameters for both sets of employees, including the terms of Mariner’s executive officers’ waivers of change of control benefits, with details to be agreed upon later. The parties also agreed to exchange periodic updates on the impact of Hurricane Katrina on the companies’ respective assets and equipment. Baker Botts and Vinson & Elkins exchanged drafts of the transaction documents over the course of the day. That same day, the Forest board of directors held a special meeting by teleconference. Members of Forest management and representatives of Citigroup, Vinson & Elkins and Weil, Gotshal & Manges were also present at the meeting. Forest management and a representative of Vinson & Elkins briefed the board on the status of negotiations with Mariner and the current form of the transaction agreements. Mr. Kenneth Heitner of Weil, Gotshal & Manges briefed the board regarding the various tax issues that were relevant to the spin-off, how those issues were addressed in the transaction agreements, and the constraints that Mariner and Forest would face in the future in order to maintain favorable tax treatment of the spin-off. Vinson & Elkins advised the board regarding various corporate law matters and confirmed that a superior offer termination provision in favor of Forest was not necessary from a legal point of view. Forest management also briefed the board regarding Forest’s on-going investigation of the potential impact of Hurricane Katrina on both Forest and Mariner.

On August 30, 2005, the board of directors of Mariner held a special meeting by teleconference, at which Mariner’s management, together with Lehman Brothers and Baker Botts, updated the board on the proposed transaction and related matters, including the strategic and business considerations relating to the transaction, the ongoing diligence review, the status of discussions between the parties and the principal terms of the transaction agreements. Lehman Brothers discussed with the board the expected financial terms of the transaction and the preliminary valuation analyses it had performed with respect to Mariner and the Forest Gulf of Mexico operations, noting that the valuation inputs and ranges used in the analysis were subject to change until due diligence was completed and the terms of the transaction were finalized. A representative of Baker Botts reviewed in detail the fiduciary termination provisions of the agreement and certain other principal terms of the transaction agreements. Following extensive discussion, including discussions regarding the potential impact of Hurricane Katrina on both Mariner and the Forest Gulf of Mexico operations, the Mariner board authorized continuing discussions regarding the proposed transaction.

On August 31, 2005, Messrs. Clark and Josey met by teleconference to finalize their agreement with respect to retention arrangements and to provide one another with updates regarding the potential impact of Hurricane Katrina on the companies’ respective assets.

On September 1, 2005, the Forest board of directors met by teleconference. Members of Forest management and representatives of Citigroup, Vinson & Elkins and Weil, Gotshal & Manges were also present at the meeting. At this meeting, the Forest board was updated on financial and other aspects of the transaction, including Forest’s investigation of the potential impact of Hurricane Katrina on Forest and Mariner and the status of negotiations with Mariner. The Forest board then granted full authority to the executive committee to finalize the transaction agreements.

On September 3 and 4, 2005, representatives from Forest and Mariner conducted visual inspections by helicopter and fixed-wing aircraft of certain of Forest’s and Mariner’s properties in the Gulf of Mexico in order to assess the damage sustained as a result of Hurricane Katrina.

From September 2 through September 6, 2005, the parties exchanged revised drafts of the transaction agreements. On September 6, 2005, the executive committee of Forest’s board met by teleconference. Members of Forest management were also present at the meeting. The executive committee was briefed by management on the status of discussions with Mariner and regarding Forest’s investigation of the potential impact of Hurricane Katrina on Forest and Mariner. The executive committee instructed Forest management regarding necessary changes to the transaction agreements, focusing on the need to clarify the impact of Hurricane Katrina.

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On September 7, 2005, Mr. Keyte of Forest and Mr. Melendrez of Mariner met by teleconference to resolve the remaining issues relating to the transaction, including the limitation applicable to the specified abandonment and environmental liabilities and the scope of the condition to closing that Forest obtain the consent of its bondholders. The parties reached compromises on both points and also agreed to exchange written reports detailing the damage sustained to their respective assets as a result of Hurricane Katrina, which reports, along with finalized projections for both companies, were subsequently exchanged on September 8, 2005.

On September 9, 2005, the board of directors of Mariner held a special meeting by teleconference, to review the proposed transaction. At the meeting, Mariner’s management, together with representatives of Lehman Brothers and Baker Botts, apprised the Mariner board of the status of discussions and reviewed the terms of the transaction as reflected in the final forms of the transaction agreements. Lehman Brothers delivered its oral opinion (subsequently confirmed in writing) to the board that, as of September 9, 2005, based upon and subject to the factors and assumptions set forth in the opinion, the exchange ratio in the merger was fair from a financial point of view to Mariner. There were no material differences between Lehman Brothers’ written opinion and the oral opinion given at the board meeting. Baker Botts advised the board regarding certain corporate law matters. Following extensive discussion, the Mariner board approved the merger and the merger agreement and resolved to recommend that Mariner’s stockholders vote to adopt the merger agreement. That same day, the executive committee of Forest’s board of directors met by teleconference. Members of Forest management and representatives of Citigroup and Vinson & Elkins were also present at the meeting. At this meeting, the executive committee was briefed on the final form of the transaction agreements (including the agreed upon financial terms of the transaction as reflected in the transaction documents) and on Forest’s latest assessment of Hurricane Katrina’s impact on Forest and Mariner. After full discussion, the executive committee approved the final form of the merger agreement and other transaction agreements. Shortly after the meetings, the merger agreement and other transaction agreements were executed by the parties to the agreements.

Reasons for the Merger; Recommendation of the Mariner Board of Directors

The Mariner board of directors has determined that the merger is fair to and in the best interests of Mariner and its stockholders, and that the merger agreement is advisable. The Mariner board of directors has unanimously approved the merger agreement, the proposed amendment to the certificate of incorporation and the proposed amendment and restatement of the stock incentive plan, and recommends the adoption of the merger agreement and the approval of the other proposals by the Mariner stockholders.

In considering the recommendation of the Mariner board of directors with respect to the merger, you should be aware that some executive officers and directors of Mariner have interests in the merger that may be different from, or in addition to, the interests of Mariner stockholders generally. The Mariner board of directors was aware of these interests in approving the merger and merger agreement.

These interests can be summarized as follows:

Governance Structure. Under the terms of the merger agreement, the board of directors of Mariner after completion of the merger will be comprised of seven individuals, five of whom are current directors of Mariner, and two of whom will be mutually agreed to by Mariner and Forest prior to the completion of the merger.

Payments for Waivers of Rights under Employment Agreements. The executive officers of Mariner will receive cash payments of $1,000 each in exchange for the waiver of certain rights under their employment agreements, including the automatic vesting or acceleration of restricted stock and options upon the completion of the merger and the right to receive a lump sum cash 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, if the officer voluntarily terminates employment without good reason within nine months following the completion of the merger.

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Severance Arrangements. The executive officers have employment agreements that will remain in effect after the completion of the merger. These agreements generally entitle the officers to severance benefits in the event of a resignation for good reason, a termination without cause or, in the case of Scott Josey’s agreement, Mariner’s non-renewal of the agreement. These severance benefits are comprised of (i) a payment equal to 18 months of salary continuation (two years for Mr. Josey and Mr. Polasek) at the highest rate in effect prior to termination, (ii) health care coverage for a period of eighteen months (two years for Mr. Josey and Mr. Polasek), (iii) an amount equal to the sum of all bonuses paid to the officer in the year prior to the year in which termination occurs, (iv) 100% vesting of all restricted shares under our Equity Participation Plan, and (v) 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 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. Pursuant to the waivers described above, the executive officers will waive their rights to the automatic vesting or acceleration of restricted stock and options upon completion of the merger and to receive a lump sum payment if they terminate their employment with Mariner without good reason within nine months following the completion of the merger.

As of the close of business on February 1, 2006, directors and executive officers of Mariner and their affiliates as a group beneficially owned and were entitled to vote approximately 3.7 million shares of Mariner common stock (including restricted stock subject to vesting), representing approximately 10.4% of the shares of Mariner common stock outstanding on that date. All of the directors and executive officers of Mariner who are entitled to vote at the meeting have indicated that they intend to vote their shares of Mariner common stock in favor of adoption of the merger agreement.

In reaching its decision on the merger, the Mariner board of directors considered a number of factors, including the following:


	•	the increased size of the combined company, which would have approximately three times the pro forma daily net production of Mariner on a stand-alone basis, could reduce volatility related to large-scale deepwater projects, and could allow it to participate in larger scale exploratory and development drilling projects and acquisition opportunities than would be available to Mariner on a stand-alone basis;

	•	the merger would be expected to increase Mariner’s estimated proved reserves, on a pro forma basis as of December 31, 2004, by approximately 243%, making Mariner larger on a reserve basis than many of its peer companies, and would more than double Mariner’s undeveloped acreage;

	•	the integration of the businesses and the realization of expected benefits could be facilitated by the fact that Mariner is already active in the Gulf of Mexico with assets that are complementary to the Forest Gulf of Mexico assets;

	•	the merger could generate increased visibility in the capital markets and trading liquidity for the combined company, which could enhance the market valuation of Mariner common stock;

	•	the merger would increase the number of Mariner’s producing fields by approximately 400%, thereby diversifying Mariner’s asset base and reducing Mariner’s dependence on a concentrated number of properties;

	•	the assets comprising the Forest Gulf of Mexico operations, which historically have been used as a cash flow generator for Forest, could be candidates for increased exploitation;

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	•	oil and natural gas prices are currently at or near historical highs, which could increase the revenues and enhance the profitability of the Forest Gulf of Mexico operations;

	•	the merger would be consummated only if approved by the holders of a majority of the Mariner common stock;

	•	the merger is structured as a tax-free reorganization for U.S. federal income tax purposes and, accordingly, would not be taxable either to Mariner or its stockholders;

	•	the board’s belief that the potential financial benefits stemming from the enhanced growth prospects of the combined company outweigh the anticipated direct and indirect costs of the merger;

	•	the terms of the merger agreement permit Mariner to terminate the merger agreement at any time before the stockholder meeting to accept a superior proposal, subject to its obligation to comply with certain procedural requirements and to pay a termination fee and expense reimbursement; and

	•	the opinion, dated September 9, 2005, of Lehman Brothers Inc. to the Mariner board of directors that, as of that date, based upon and subject to the factors and assumptions set forth in the opinion, the exchange ratio in the merger was fair from a financial point of view to Mariner.

The Mariner board of directors also identified and considered some risks and potential disadvantages associated with the merger, including the following:


	•	the risk that there may be difficulties in combining the business of Mariner and the Forest Gulf of Mexico operations;

	•	the risk that the potential benefits sought in the merger might not be fully realized;

	•	the risk that the proved undeveloped, probable and possible reserves of the Forest Gulf of Mexico operations may never be converted to proved developed reserves;

	•	the risks inherent in owning properties located in the Gulf of Mexico, including the risks of future hurricanes that could damage or destroy the acquired properties;

	•	the risk that current high commodity prices could fall, thereby reducing the profitability of the acquired operations;

	•	the risk that the merger might not be completed;

	•	the fact that, in order to preserve the tax-free treatment of the spin-off, Mariner would be required to abide by restrictions that could reduce its ability to engage in certain business transactions that otherwise might be advantageous;

	•	the fact that under the merger agreement, Mariner could be required to pay Forest a termination fee and expense reimbursement in certain circumstances; and

	•	certain of the other matters described under “Risk Factors” beginning on page 24.

In the judgment of the Mariner board of directors, the potential benefits of the merger outweigh the risks and the potential disadvantages. In view of the variety of factors considered in connection with its evaluation of the proposed merger and the terms of the merger agreement, the Mariner board of directors did not quantify or assign relative weights to the factors considered in reaching its conclusion. Rather, the Mariner board of directors views its recommendation as being based on the totality of the information presented to and considered by it. In addition, individual Mariner directors may have given different weights to different factors.

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Certain Financial Projections

In connection with the due diligence process during negotiations, Mariner and Forest provided each other with financial and operating projections for 2005 and 2006. Mariner’s projections are summarized below.


	2005		2006

Revenue (in millions)	$	230.2	$	421.4
EBITDA (in millions)	$	185.2	$	353.9
Net income (in millions)	$	60.9	$	158.7
Net income per common share	$	1.71	$	4.45
Capital expenditures (in millions)	$	257.4	$	250.5

Mariner’s projections were based on a number of assumptions, including the following:


	•	weighted average common shares outstanding of 35.6 million in both periods;

	•	NYMEX prices for oil and Henry Hub prices for gas, as adjusted for pricing differentials and hedging contracts in place at such date as follows:


	2005		2006

Oil (per Bbl)	$	41.27	$	48.83
Gas (per Mcf)	$	6.86	$	7.87
Total (per Mcfe)	$	6.87	$	7.94


	•	annual production as follows:


	2005		2006

Oil (MBbls)		1.9		2.4
Gas (Bcf)		21.6		38.8
Total (Bcfe)		33.2		53.1


	•	a depreciation, depletion and amortization rate of $1.84 per Mcfe for 2005 and $1.80 per Mcfe for 2006;

	•	an effective income tax rate of 35% in each period; and

	•	various assumptions relating to delays in scheduled commencement of production at Pluto, Swordfish, Ochre and Dice, suspension of production at producing fields and increased capital expenditures due to Hurricane Katrina.

Forest’s projections for the Forest Gulf of Mexico Operations are summarized below.


	Six Months Ended
	December 31,
	2005		2006

Revenue (in millions)	$	214.1	$	529.4
EBITDA (in millions)	$	173.5	$	450.5
Net income (in millions)	$	43.9	$	124.3
Net income per common share	$	0.87	$	2.45
Capital expenditures (in millions)	$	123.0	$	202.3

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Forest’s projections were based on a number of assumptions, including the following:


	•	weighted average common shares outstanding of 50.6 million in each period;

	•	NYMEX prices for oil and Henry Hub prices for gas, as adjusted for pricing differentials and hedging contracts in place at such date as follows:


	Six Months Ended
	December 31,
	2005		2006

Oil (per Bbl)	$	47.42	$	48.41
Gas (per Mcf)	$	6.64	$	7.13
Total (per Mcfe)	$	7.02	$	7.35


	•	production as follows:


	Six Months Ended
	December 31,
	2005		2006

Oil (MBbls)		1.5		2.9
Gas (Bcf)		21.3		54.7
Total (Bcfe)		30.5		72.0


	•	a depreciation, depletion and amortization rate of $3.26 per Mcfe for 2005 and $3.43 per Mcfe for 2006;

	•	an effective income tax rate of 35% in each period;

	•	the allocation from July 1, 2005 to December 31, 2005 of general and administrative expenses as set forth in the distribution agreement;

	•	net hedging losses of $11.7 million for the six months ended December 31, 2005 and $19.5 million in 2006;

	•	various assumptions relating to general and administrative expenses to reflect the allocation set forth in the distribution agreement; and

	•	transaction-related expenses of $12 million for the six months ended December 31, 2005.

Mariner and Forest make public only very limited information as to future performance and neither company provides specific or detailed information as to earnings or performance over an extended period. The foregoing prospective financial information is included in this prospectus only because this information was provided to the other party during negotiations. The prospective financial information of Mariner and Forest, which was prepared by the respective management of Mariner and Forest, was not prepared with a view to public disclosure or with a view toward complying with the published guidelines of the SEC or the guidelines established by the American Institute of Certified Public Accountants regarding prospective financial information. The projections do not purport to present operations in accordance with GAAP. The internal financial forecasts (upon which these projections were based in part) are, in general, prepared solely for internal use and capital budgeting and other management decisions and are subjective in many respects and thus susceptible to interpretations and periodic revision based on actual experience and business developments. Neither Mariner’s nor Forest’s independent auditors, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the prospective financial information, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information.

In addition to the specific assumptions set forth above, the projections also reflect numerous assumptions made by management of both companies, including assumptions with respect to general business, economic, market and financial conditions and other matters, including effective tax rates and interest rates and the anticipated amount of borrowings, all of which are difficult to predict and many of

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which are beyond the control of the preparing party. Accordingly, there can be no assurance that the assumptions made in preparing the projections will prove accurate. Actual results may be materially greater or less than those contained in the projections. The inclusion of the projections in this prospectus should not be regarded as an indication that the projections will be predictive of actual future events, and the projections should not be relied upon as such.

The projections were disclosed to the other party and its representatives as a matter of due diligence, and are included in this prospectus on that account. Each of Mariner and Forest believes that the projections prepared by it were reasonable at the time they were made; however, none of Mariner or Forest or any of their respective representatives has made or makes any representation to any stockholder regarding the ultimate performance of Mariner or the Forest Gulf of Mexico operations compared to the information contained in the projections, and none of them intends to update or otherwise revise the projections to reflect circumstances existing after the date when made or to reflect the occurrence of future events in the event that any or all of the assumptions underlying the projections are shown to be in error. In particular, these projections were prepared prior to, and do not take into account the full effects of business interruptions due to, Hurricanes Katrina and Rita in August 2005 and September 2005, respectively.

Opinion of Mariner’s Financial Advisor

Mariner engaged Lehman Brothers to act as its financial advisor in connection with the merger. On September 9, 2005, Lehman Brothers rendered its written opinion to the board of directors of Mariner, that, as of that date, based upon and subject to the matters stated in its opinion letter, from a financial point of view, the exchange ratio of 1.0 share of Mariner common stock for each share of Forest Energy Resources common stock in the merger was fair to Mariner.

The Mariner board of directors determined that the process leading up to the execution of the merger agreement was procedurally fair to all stockholders, including unaffiliated stockholders. The board did not obtain an independent advisor’s opinion with respect to procedural fairness, because numerous factors supported the conclusion that sufficient procedural safeguards existed to protect the interests of all stockholders, including the following:


	•	the fact that Mariner’s board of directors unanimously approved the merger, including all directors with no interest in the merger other than their interests as stockholders of Mariner;

	•	the fact that the stockholders of Mariner will be given the opportunity to vote on the merger, and that the merger agreement would not be adopted without the affirmative vote of at least a majority of Mariner’s common stock;

	•	the fact that Mariner does not have a controlling stockholder, and that directors and officers of Mariner own less than 11% of the outstanding stock of Mariner;

	•	the fact that independent financial and legal advisors were retained to assist in the negotiation of the terms of the merger agreement, the distribution agreement and the other ancillary agreements; and

	•	the fact that Mariner received a written opinion from its independent financial advisor as to the fairness, from a financial point of view, of the merger consideration.

The full text of Lehman Brothers’ opinion dated September 9, 2005, which sets forth assumptions made, procedures followed, matters considered and limitations upon the review undertaken in connection with the opinion, is included as Annex B to the joint proxy statement/prospectus-information statement issued by Mariner in connection with the annual meeting of stockholders.

Lehman Brothers’ advisory services and opinion were provided for the information and assistance of the board of directors of Mariner in connection with its consideration of the merger. Lehman Brothers’ opinion is not intended to be and does not constitute a recommendation to any stockholder of Mariner as to how such stockholder should vote in connection with the merger. Lehman Brothers was not

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requested to opine as to, and Lehman Brothers’ opinion does not in any manner address, Mariner’s underlying business decision to proceed with or effect the merger.

In arriving at its opinion, Lehman Brothers reviewed, among other things:


	•	the merger agreement, the distribution agreement, the other transaction agreements and the specific terms of the merger;

	•	publicly available information concerning Mariner that Lehman Brothers believed to be relevant to its analysis, including, without limitation, the Amendment No. 1 to the Registration Statement on Form S-1 filed on July 26, 2005 by Mariner;

	•	publicly available information concerning Forest that Lehman Brothers believed to be relevant to its analysis, including, without limitation, the Annual Report on Form 10-K for the year ended December 31, 2004 and the Quarterly Reports on Form 10-Q for the periods ended March 31, 2005 and June 30, 2005;

	•	financial and operating information with respect to the business, operations and prospects of Mariner as furnished to Lehman Brothers by Mariner, including financial projections and oil and gas reserve estimates as of June 30, 2005 for Mariner as prepared by the management of Mariner;

	•	financial and operating information with respect to the Forest Gulf of Mexico operations as furnished to Lehman Brothers by Forest, including financial projections and oil and gas reserve estimates as of June 30, 2005 for the Forest Gulf of Mexico operations as prepared by the management of Forest;

	•	a comparison of the historical financial results and present financial condition of Mariner and the Forest Gulf of Mexico operations with each other and with those of other companies that Lehman Brothers deemed relevant;

	•	a comparison of the financial terms of the merger with the financial terms of certain other transactions that Lehman Brothers deemed relevant;

	•	commodity prices assumptions used by the management of Mariner, commodity prices assumptions published by Lehman Brothers equity research, and commodity prices as quoted on the NYMEX on August 19, 2005 (collectively the “Commodity Price Assumptions”);

	•	estimates of certain proved reserves generated by third-party reserve engineers as of December 31, 2004 for Mariner and the Forest Gulf of Mexico operations;

	•	the potential pro forma impact of the merger on the current financial condition and future financial performance of Mariner, including the impact on Mariner’s operating metrics, including, the composition of its reserves between oil and gas; the percentage of reserves attributable to onshore, the shelf of the Gulf of Mexico and deepwater Gulf of Mexico; and the ratio of reserves as of June 30, 2005 to 2005 expected production;

	•	the relative contributions of Mariner and the Forest Gulf of Mexico operations to the current and future financial performance of the combined company on a pro forma basis;

	•	the report dated as of September 9, 2005, prepared by the management of Mariner, assessing the damage to the Gulf of Mexico assets of Mariner caused by Hurricane Katrina; and

	•	the report dated as of September 9, 2005, prepared by the management of Forest, assessing the damage to the Gulf of Mexico assets of the Forest Gulf of Mexico operations caused by Hurricane Katrina.

In addition, Lehman Brothers had discussions with the managements of Mariner and Forest concerning their respective businesses, operations, assets, financial conditions, reserves, production profiles, hedging levels, exploration programs and prospects of Mariner and the Forest Gulf of Mexico operations and undertook such other studies, analyses and investigations as Lehman Brothers deemed appropriate.

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In arriving at its opinion, Lehman Brothers assumed and relied upon the accuracy and completeness of the financial and other information used by Lehman Brothers without assuming any responsibility for independent verification of such information. Lehman Brothers further relied upon the assurances of the managements of Mariner and Forest that they were not aware of any facts or circumstances that would make such information inaccurate or misleading. With respect to the financial projections of Mariner, upon advice of Mariner, Lehman Brothers assumed that such projections were reasonably prepared on a basis reflecting the best currently available estimates and judgments of the management of Mariner as to the future financial performance of Mariner and that Mariner would perform substantially in accordance with such projections. With respect to the financial projections of the Forest Gulf of Mexico operations, upon advice of Forest, Lehman Brothers assumed that such projections were reasonably prepared on a basis reflecting the best currently available estimates and judgments of the management of Forest as to the future financial performance of the Forest Gulf of Mexico operations and that the Forest Gulf of Mexico operations would perform substantially in accordance with such projections. However, in the course of its analysis and in arriving at its opinion, Lehman Brothers also considered the various Commodity Price Assumptions, which resulted in certain adjustments to the projections of Mariner and the Forest Gulf of Mexico operations. Lehman Brothers discussed these adjusted projections with the management of Mariner and they agreed with the appropriateness of the use of such adjusted projections, as well as Forest’s management projections, in performing its analysis.

In arriving at its opinion, Lehman Brothers did not conduct a physical inspection of the properties and facilities of Mariner and the Forest Gulf of Mexico operations and did not make or obtain from third parties any evaluations or appraisals of the assets and liabilities of Mariner or the Forest Gulf of Mexico operations. Lehman Brothers’ opinion is necessarily based upon market, economic and other conditions as they existed on, and could be evaluated as of, the date of its opinion letter.

Lehman Brothers is an internationally recognized investment banking firm and, as part of its investment banking activities, is regularly engaged in the valuation of businesses and their securities in connection with mergers and acquisitions, negotiated underwritings, competitive bids, secondary distributions of listed and unlisted securities, private placements and valuations for corporate and other purposes. Mariner’s board of directors selected Lehman Brothers because of its expertise, reputation and familiarity with Mariner and the energy industry generally and because its investment banking professionals have substantial experience in transactions comparable to the merger.

Pursuant to the terms of an engagement letter dated August 9, 2005 between Lehman Brothers and Mariner, Mariner paid Lehman Brothers a fee upon delivery of Lehman Brothers’ opinion, dated September 9, 2005. Mariner has also agreed to pay Lehman Brothers an additional fee at the time of closing. Mariner also has agreed to reimburse Lehman Brothers for its reasonable expenses incurred in connection with this engagement, and to indemnify Lehman Brothers and certain related persons against certain liabilities that may arise out of its engagement by Mariner and the rendering of the Lehman Brothers’ opinion. The estimated aggregate compensation Lehman Brothers will receive in connection with the merger is $3.0 million, of which $1.0 million was contingent on the execution of a merger agreement and an additional $1.25 million is contingent on the consummation of the merger. Lehman Brothers from time to time renders investment banking services to Mariner and Forest and receives customary fees for such services. Lehman Brothers has provided no financing advisory or other financing services to Mariner during the past two years. In July 2004 Lehman Brothers participated as an underwriter in a senior note offering of Forest. Lehman Brothers’ aggregate compensation for the transaction was $72,000.

During the course of its engagement, representatives of Lehman Brothers participated in discussions with members of Mariner’s senior management regarding the rationale for, benefits of and risks and uncertainties relating to the merger. Among the benefits discussed with senior management were the economies of scale and the portfolio management opportunities provided by the increases to proved reserves and undeveloped acreage, the potential reduction in volatility related to deepwater projects, and increased visibility in the capital markets. Among the uncertainties discussed with senior management were those related to current high commodity prices and the possibility that probable and possible reserves of the acquired operations may never be converted to proved developed reserves.

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In the ordinary course of its business, Lehman Brothers may actively trade in the debt or equity securities of Mariner and Forest for its own account and for the accounts of its customers and, accordingly, may at any time hold a long or short position in such securities.

The Spin-Off

On September 12, 2005, Forest announced that Forest would spin-off to its shareholders the Forest Gulf of Mexico operations, and that the Forest Gulf of Mexico operations would immediately thereafter be acquired in a merger transaction by Mariner. Forest is carrying out the spin-off to facilitate Mariner’s acquisition of the Forest Gulf of Mexico operations and the spin-off is a condition to the merger. After the spin-off and merger, Mariner will be a separately traded public company that will own and operate the combination of Mariner’s business and the Forest Gulf of Mexico operations.

As a result of the transaction, in addition to retaining all of their shares of Forest common stock, Forest shareholders will receive approximately 0.8 shares of Mariner common stock for each share of Forest common stock owned on the record date of the transaction. Forest shareholders will receive approximately 58% of the common stock of Mariner on a pro forma basis.

Certificate of Incorporation and By-Laws

Following the merger, the certificate of incorporation and by-laws of Mariner would differ from the current certificate of incorporation and by-laws only with respect to the number of authorized shares of stock, which pursuant to the proposed amendment would be increased from 90 million to 200 million.

Material United States Federal Tax Consequences of the Merger


	*Scope of the Discussion*

The following discussion summarizes certain material U.S. tax consequences of the merger to Mariner stockholders and to stockholders of Forest Energy Resources at the effective time of the merger. It is a condition to the completion of the merger that Forest and Forest Energy Resources receive an opinion from Weil, Gotshal & Manges LLP, tax counsel to Forest and to Forest Energy Resources, and that Mariner receive an opinion from Baker Botts L.L.P., tax counsel to Mariner, in both cases dated as of the effective date of the merger, to the effect that the merger will qualify as a reorganization within the meaning of Section 368(a) of the Internal Revenue Code. The discussion below of the “Material U.S. Tax Consequences of the Merger” represents the further opinion of Baker Botts L.L.P. of the tax consequences of the merger that will follow from the merger qualifying as a reorganization under Section 368(a) of the Internal Revenue Code.

This discussion is based upon existing U.S. tax law, including legislation, regulations, administrative rulings and court decisions, as in effect on the date of this prospectus, all of which are subject to change, possibly with retroactive effect.

For purposes of this discussion:


	•	a “U.S. holder” is a beneficial owner of Forest Energy Resources or Mariner common stock that is (1) an individual citizen or resident of the U.S., (2) a corporation or any other entity taxable as a corporation created or organized in or under the laws of the U.S. or of a state of the U.S. or the District of Columbia, (3) a trust (i) in respect of which a U.S. court is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantive decisions of the trust or (ii) that was in existence on August 20, 1996 and validly elected to continue to be treated as a domestic trust, or (4) an estate that is subject to U.S. tax on its worldwide income from all sources;

	•	a “non-U.S. holder” is any holder of Forest Energy Resources or Mariner common stock other than a U.S. holder; and

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	•	the term “U.S. tax” means U.S. federal income tax under the Internal Revenue Code of 1986, as amended.

The discussion assumes that holders hold their Forest Energy Resources or Mariner common stock, as applicable, as capital assets. Other tax consequences may apply to holders who are subject to special treatment under U.S. tax or U.S. federal estate tax law, such as:


	•	tax exempt organizations;

	•	financial institutions, insurance companies and broker-dealers;

	•	holders who hold their Forest Energy Resources or Mariner common stock, as applicable, as part of a hedge, straddle, wash sale, synthetic security, conversion transaction or other integrated investment comprised of Forest Energy Resources or Mariner common stock and one or more other investments;

	•	mutual funds;

	•	holders that have a functional currency other than the U.S. dollar;

	•	traders in securities who elect to apply a mark-to-market method of accounting;

	•	holders who acquired their shares in compensatory transactions;

	•	holders who are subject to the alternative minimum tax; or

	•	non-U.S. holders who are or have previously been engaged in the conduct of a trade or business in the U.S. or who have ceased to be U.S. citizens or to be taxed as resident aliens.

In the case of a stockholder that is a partnership, determinations as to tax consequences will generally be made at the partner level, but other special considerations not described may apply. The discussion is generally limited to U.S. federal income and estate tax considerations and does not address other U.S. federal tax considerations or state, local or foreign tax considerations.

The opinions of counsel referred to above to be delivered at closing will be, and the opinions of counsel set forth herein are, based on present law, which is subject to change, possibly with retroactive effect. In providing their opinions at the closing of the merger, counsel will make customary assumptions and rely upon the accuracy of certain representations made to them by Forest, Forest Energy Resources, and Mariner, in officers’ certificates. In addition, counsel will rely upon the accuracy of the information in this prospectus and in other documents filed by Mariner and by Forest with the SEC and upon other information provided to them by Mariner and Forest. Any change in present law, or the failure of factual assumptions or representations to be true, correct and complete in all respects, could affect the continuing validity of counsels’ tax opinions. The conditions to the completion of the spin-off and merger relating to the receipt of the tax opinions may not be waived by Forest or Mariner after receipt of the Mariner shareholder approval unless further shareholder approval is obtained with appropriate disclosure. No ruling will be requested from the Internal Revenue Service on any aspect of the proposed transactions. An opinion of counsel represents counsel’s best legal judgment and is not binding on the Internal Revenue Service or any court. Accordingly, there can be no assurance that the Internal Revenue Service will agree with the conclusions set forth herein or in the opinion letters to be delivered at closing, and it is possible that the Internal Revenue Service or another tax authority could assert a position contrary to one or all of those conclusions and that a court could sustain that contrary position.

This summary is not a substitute for an individual analysis of the tax consequences of the proposed transaction to a Mariner stockholder. You are urged to consult a tax adviser as to the U.S. tax consequences of the proposed transactions, including any consequences arising from your particular facts and circumstances, and as to any estate, gift, state, local or foreign tax consequences of the proposed transaction.

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	*Material U.S. Tax Consequences of the Merger*

It is a condition to the consummation of the merger that:


	•	Mariner receive an opinion from Baker Botts L.L.P., dated as of the effective date of the merger, to the effect that the merger will qualify as a reorganization within the meaning of Section 368(a) of the Internal Revenue Code; and

	•	Forest and Forest Energy Resources receive an opinion from Weil, Gotshal & Manges LLP, tax counsel to Forest, dated as of the effective date of the merger, to the effect that the merger will qualify as a reorganization within the meaning of Section 368(a) of the Internal Revenue Code.

Baker Botts L.L.P. is of the opinion that the U.S. federal income tax consequences of such treatment will be that:


	•	a Mariner stockholder will not recognize gain or loss pursuant to the merger, and such holder’s tax basis and holding period in Mariner common stock will not be affected by the merger;

	•	a Forest Energy Resources stockholder who exchanges Forest Energy Resources common stock solely for Mariner common stock in the merger will not recognize gain or loss except, as described below, to the extent of any cash received in lieu of fractional shares of Mariner common stock;

	•	the aggregate tax basis in the Mariner common stock a Forest Energy Resources stockholder receives in the merger (including any fractional shares for which cash is received) will be the same as his or her aggregate tax basis in the Forest Energy Resources common stock surrendered in the merger;

	•	the holding period of the Mariner common stock received in the merger by a holder of Forest Energy Resources common stock (including any fractional shares for which cash is received) will include the holding period of Forest Energy Resources common stock that such stockholder surrendered in the merger; and

	•	a Forest Energy Resources stockholder who receives fractional share proceeds as a result of the sale of shares of Mariner common stock by the transfer agent will be treated as if such fractional share had been received by the shareholder as part of the merger and then sold by such stockholder. Accordingly, such stockholder will recognize capital gain or loss equal to the difference between the cash so received and the portion of the tax basis in Mariner common stock that is allocable to such fractional share. Any such capital gain or loss will be treated as a long-term or short-term capital gain or loss based on the holder’s holding period for the Mariner common stock (as determined above). Non-U.S. holders who receive fractional share proceeds may be subject to withholding tax with respect to the fractional share proceeds under special rules governing the disposition of interests in a United States real property holding corporation.

Under the Internal Revenue Code, a holder of Forest Energy Resources common stock may be subject, under certain circumstances, to backup withholding at a current rate of 28% with respect to the amount of cash, if any, received as a result of the sale of fractional share interests unless such holder provides proof of an applicable exemption or correct taxpayer identification number, and otherwise complies with applicable requirements of the backup withholding rules. Any amounts withheld under the backup withholding rules are not additional tax and may be refunded or credited against the holder’s federal income tax liability, provided the required information is timely furnished to the Internal Revenue Service.


	*Material U.S. Federal Tax Consequences to U.S. Holders of Holding and Disposing of Mariner Common Stock*


	Distributions on Common Stock

A distribution to a U.S. holder on a Mariner share will be (i) first, a dividend to the extent of Mariner’s current or accumulated earnings and profits, as determined under general U.S. tax principles,

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(ii) second, a non-taxable recovery of basis in that Mariner share, causing a reduction in the adjusted basis of the shares of Mariner common stock to the extent thereof (thereby increasing the amount of gain, or decreasing the amount of loss, to be recognized by the holder on a subsequent disposition of our common stock), and (iii) finally, an amount that is received in exchange for the Mariner share. A dividend on a Mariner share that is received by a U.S. holder generally before January 1, 2009 is subject to U.S. tax at a maximum rate of 15 percent provided that the stockholder satisfies certain holding period and other requirements with respect to that Mariner share. Any amount that is deemed to have been received in exchange for a Mariner share will be taxed as a sale or disposition of a Mariner share, discussed below.


	Sales or Dispositions of Common Stock

Upon a sale or other disposition of a Mariner share, a U.S. holder generally will recognize gain or loss in an amount that is equal to the difference between (i) the sum of any cash and the fair market value of any other property received and (ii) such U.S. holder’s adjusted basis in such Mariner share. Any such gain or loss will generally be a capital gain or loss if the Mariner share that is surrendered was held as a capital asset and will be a long-term capital gain or loss if the Mariner share had been held more than one year when the sale or other disposition occurs. Deduction of capital losses is subject to certain limitations under the Internal Revenue Code.


	Information Reporting and Backup Withholding

Payments of dividends and the proceeds of a disposition of a Mariner share that are made within the U.S. or through certain U.S. related financial intermediaries may be required to be reported to the Internal Revenue Service and may be subject to backup withholding unless (i) the U.S. holder is a corporation or other exempt recipient, or (ii) such person provides a taxpayer identification number or complies with applicable certification requirements. Amounts withheld under the backup withholding rules will be allowed as a refund or credit against a person’s U.S. tax liability if the required information is timely furnished to the Internal Revenue Service.


	U.S. Federal Estate Tax

Common stock owned or treated as owned by an individual who is a U.S. holder for U.S. federal estate tax purposes at the time of death will be included in the individual’s gross estate for U.S. federal estate tax purposes, and therefore may be subject to U.S. federal estate tax.


	*Material U.S. Federal Tax Consequences to Non-U.S. Holders of Holding and Disposing of Mariner Common Stock*


	Distributions on Common Stock

A distribution to a non-U.S. holder on a Mariner share will be (i) first, a dividend to the extent of Mariner’s current or accumulated earnings and profits, as determined under general U.S. tax principles, (ii) second, a non-taxable recovery of basis in that Mariner share, causing a reduction in the adjusted basis of the shares of common stock to the extent thereof (thereby increasing the amount of gain, or decreasing the amount of loss, to be recognized by the holder on a subsequent disposition of our common stock), and (iii) finally, an amount that is received in exchange for the Mariner share.

Dividends paid to non-U.S. holders that are not effectively connected with the non-U.S. holder’s conduct of a U.S. trade or business will be subject to U.S. federal withholding tax at a 30% rate, or if a tax treaty applies, a lower rate specified by the treaty. Non-U.S. holders should consult their tax advisors regarding their entitlement to benefits under a relevant income tax treaty. Dividends that are effectively connected with a non-U.S. holder’s conduct of a trade or business in the U.S. and, if an income tax treaty applies, are attributable to a permanent establishment in the U.S., are taxed on a net income basis at the regular graduated rates and in the manner applicable to U.S. persons. In that case, Mariner will not have to withhold U.S. federal withholding tax if the non-U.S. holder complies with applicable certification and

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disclosure requirements. In addition, a “branch profits tax” may be imposed at a 30% rate, or a lower rate under an applicable income tax treaty, on dividends received by a foreign corporation that are effectively connected with its conduct of a trade or business in the U.S.

A non-U.S. holder that claims the benefit of an applicable income tax treaty generally will be required to satisfy applicable certification and other requirements. However,


	•	in the case of Mariner common stock held by a foreign partnership, the certification requirement will generally be applied to the partners of the partnership and the partnership will be required to provide certain information;

	•	in the case of Mariner common stock held by a foreign trust, the certification requirement will generally be applied to the trust or the beneficial owners of the trust depending on whether the trust is a “foreign complex trust,” “foreign simple trust” or “foreign grantor trust” as defined in the U.S. Treasury Regulations; and

	•	look-through rules will apply for tiered partnerships, foreign simple trusts and foreign grantor trusts.

A non-U.S. holder that is a foreign partnership or a foreign trust is urged to consult its own tax advisor regarding its status under these U.S. Treasury Regulations and the certification requirements applicable to it.

A non-U.S. holder that is eligible for a reduced rate of U.S. federal withholding tax under an income tax treaty may obtain a refund or credit of any excess amounts withheld by timely filing an appropriate claim for refund with the Internal Revenue Service.


	Sales or Dispositions of Common Stock

A non-U.S. holder generally will not be subject to U.S. tax on gain recognized on a disposition of a share of Mariner common stock unless:


	•	the gain is effectively connected with the non-U.S. holder’s conduct of a trade or business in the U.S. and, if an income tax treaty applies, is attributable to a permanent establishment maintained by the non-U.S. holder in the U.S.; in these cases, the gain will be taxed on a net income basis at the rates and in the manner applicable to U.S. persons, and if the non-U.S. holder is a foreign corporation, the branch profits tax described above may also apply;

	•	the non-U.S. holder is an individual who is present in the U.S. for 183 days or more in the taxable year of the disposition and meets other requirements; or

	•	Mariner is or has been a “United States real property holding corporation” for U.S. tax purposes at any time during the shorter of the five-year period ending on the date of disposition or the period that the non-U.S. holder held such Mariner common stock.

Generally, a corporation is a United States real property holding corporation if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. The tax relating to stock in a United States real property holding corporation generally will not apply to a non-U.S. holder whose holdings, direct and indirect, at all times during the applicable period, constituted 5% or less of Mariner common stock, provided that Mariner common stock was regularly traded on an established securities market. Mariner believes that it currently is, and after the merger will continue to be, a United States real property holding corporation for U.S. tax purposes. Mariner also expects its common stock to be regularly traded on an established securities market immediately after the completion of the merger.

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	Information Reporting and Backup Withholding

Dividends paid to a non-U.S. holder may be subject to information reporting and U.S. backup withholding. A non-U.S. holder will be exempt from this backup withholding tax if such non-U.S. holder properly provides a Form W-8BEN certifying that such stockholder is a non-U.S. holder or otherwise meets documentary evidence requirements for establishing that such stockholder is a non-U.S. holder or otherwise qualifies for an exemption.

The gross proceeds from the disposition of Mariner common stock may be subject to information reporting and backup withholding. If a non-U.S. holder sells its common stock outside the U.S. through a non-U.S. office of a non-U.S. broker and the sales proceeds are paid to such stockholder outside the U.S., then the U.S. backup withholding and information reporting requirements generally will not apply to that payment. However, U.S. information reporting will generally apply to a payment of sale proceeds, even if that payment is made outside the U.S., if a non-U.S. holder sells Mariner common stock through a non-U.S. office of a broker that:


	•	is a U.S. person for U.S. tax purposes;

	•	derives 50% or more of its gross income in specific periods from the conduct of a trade or business in the U.S.;

	•	is a “controlled foreign corporation” for U.S. tax purposes; or

	•	is a foreign partnership, if at any time during its tax year:


	•	one or more of its partners are U.S. persons who in the aggregate hold more than 50% of the income or capital interests in the partnership; or

	•	the foreign partnership is engaged in a U.S. trade or business,

unless the broker has documentary evidence in its files that the non-U.S. holder is a non-U.S. person and certain other conditions are met, or the non-U.S. holder otherwise establishes an exemption. In such circumstances, backup withholding will not apply unless the broker has actual knowledge that the seller is not a non-U.S. holder.

If a non-U.S. holder receives payments of the proceeds of a sale of Mariner common stock to or through a U.S. office of a broker, the payment is subject to both U.S. backup withholding and information reporting unless such non-U.S. holder properly provides a Form W-8BEN certifying that such stockholder is a non-U.S. person or otherwise establishes an exemption.

A non-U.S. holder generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed such stockholder’s U.S. tax liability by timely filing a properly completed claim for refund with the U.S. Internal Revenue Service.


	U.S. Federal Estate Tax

Mariner common stock owned or treated as owned by an individual who is a non-U.S. holder for U.S. federal estate tax purposes at the time of death will be included in the individual’s gross estate for U.S. federal estate tax purposes, unless an applicable estate tax or other treaty provides otherwise, and therefore may be subject to U.S. federal estate tax.

You are urged to consult your own tax advisor as to the specific tax consequences to you of the merger, including tax return reporting requirements, the applicability and effect of federal, state, local, and other applicable tax laws and the effect of any proposed changes in the tax laws.

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Accounting Treatment

If the merger is consummated, the acquisition of Forest Energy Resources by Mariner will be accounted for under the purchase method of accounting under U.S. generally accepted accounting principles, with Mariner treated as the acquiror. As a result, the assets and liabilities of the Forest Gulf of Mexico operations will be recorded at their estimated fair values at the date of merger with any excess of the purchase price over the net amount of such fair values recorded as goodwill.

Regulatory Matters

None of the parties is aware of any other material governmental or regulatory approval required for the completion of the merger, other than the effectiveness of the registration statement of which this prospectus is a part and the registration statement on Form S-4 relating to the issuance of Mariner common stock to Forest shareholders, and compliance with applicable antitrust law (including the Hart-Scott-Rodino Act) and the corporate law of the State of Delaware. On November 14, 2005, the waiting period under the Hart-Scott-Rodino Act with respect to the merger expired.

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THE MERGER AGREEMENT

The Merger


	*Structure of the Merger*

At the effective time of the merger, MEI Sub, a newly formed, wholly owned subsidiary of Mariner, will merge with and into Forest Energy Resources. Forest Energy Resources will remain as the surviving corporation and immediately after the merger will become a wholly owned subsidiary of Mariner.


	*Effective Time of the Merger*

The closing of the merger will occur within two business days after the fulfillment or waiver of the conditions described under “—Conditions to the Completion of the Merger” below, unless Forest Energy Resources and Mariner agree in writing upon another time or date. Unless Mariner consents otherwise, the closing will not occur earlier than five business days following the record date for the spin-off. The merger will become effective upon the filing of a certificate of merger with the Secretary of State of the State of Delaware or at such later time as the parties to the merger agreement may agree and as is provided in the certificate of merger. The filing of the certificate of merger will take place as soon as practicable at or after the time of the closing of the merger.


	*Merger Consideration*

The merger agreement provides that each share of Forest Energy Resources common stock (other than certain shares described under “—Cancellation of Certain Shares” below) that is outstanding immediately prior to the effective time of the merger will, at the effective time of the merger, be converted into the right to receive one share of Mariner common stock as adjusted for any stock split, reverse stock split, stock dividend, subdivision, reclassification, combination, exchange, recapitalization or other similar transaction, except that shareholders will receive cash in lieu of any fractional share of Mariner common stock.


	*Cancellation of Certain Shares*

Each share of Forest Energy Resources common stock held by Forest Energy Resources as treasury stock, and each share of Forest Energy Resources common stock owned by Mariner or MEI Sub, in each case immediately prior to the effective time of the merger, will automatically be canceled and no stock or consideration will be delivered in exchange therefor. Neither Mariner nor MEI Sub currently owns any shares of Forest Energy Resources common stock.


	*Procedure for Surrender of Certificates*

Shares of Forest Energy Resources common stock to be issued in the spin-off will be issued in book-entry form, meaning that, although Forest shareholders will own the shares, they will not be issued physical share certificates. Prior to the effective time of the merger, an exchange agent will be appointed to handle the exchange of Forest Energy Resources stock certificates for Mariner stock certificates. As promptly as practicable after the effective time of the merger, Mariner will cause the exchange agent to effect the exchange, via book-entry procedures, of Forest Energy Resources shares for Mariner shares. Mariner will not issue physical certificates for the shares of common stock issued in the merger. After the merger becomes effective, Forest Energy Resources will not register any further transfers of shares of Forest Energy Resources common stock.


	*Treatment of Certain Forest Stock Options*

At the effective time of the merger, the portion of each outstanding option to acquire Forest common stock that is unexercisable as of the effective time and which is held by a Forest Energy Resources employee who remains employed by Forest Energy Resources, Mariner or their subsidiaries after the

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effective time of the merger will be converted into an option to acquire from Mariner a number of shares of Mariner common stock determined by multiplying:


	•	the number of shares of Forest common stock subject to the portion of such option that is unexercisable immediately before the effective time, by

	•	the “option exchange ratio” described below,

and rounding to the nearest whole number. The purchase price per share of Mariner common stock under the converted option will be the exercise price per share under the original Forest stock option divided by the option exchange ratio, with the resulting price rounded to the nearest whole cent.

The “option exchange ratio” means the quotient, rounded to the third decimal place, determined by dividing:


	•	the average of the daily closing prices per share of Forest common stock for the last five trading days immediately preceding the effective time of the merger, by

	•	the average of the daily closing prices per share of Mariner common stock for the first five trading days following the effective time of the merger,

subject to appropriate adjustment in the event of any stock split, stock dividend or recapitalization after the date of the merger agreement applicable to shares of Forest common stock or Mariner common stock.

Mariner will take all actions necessary to reserve for issuance, from and after the effective time of the merger, a sufficient number of shares of Mariner common stock for delivery under the Forest stock options that are deemed to constitute options to purchase shares of Mariner common stock in accordance with the preceding paragraphs, and, on or as soon as practicable after the effective time of the merger, Mariner will file with the SEC a registration statement with respect to such Mariner common stock and cause such shares to be listed on the NYSE.


	*Board of Directors and Officers of Mariner*

The board of directors of Mariner immediately after the effective time of the merger will consist of seven directors, five of whom will be the directors of Mariner immediately before the effective time of the merger and two of whom will be mutually agreed upon by Mariner and Forest prior to the effective time of the merger. The board of directors of Mariner will also appoint committees as appropriate, including an audit committee, a compensation committee and a nominating committee. The officers of Mariner immediately prior to the effective time of the merger will continue as the officers of Mariner immediately after the effective time of the merger.

Representations and Warranties

The merger agreement contains certain representations and warranties made by Forest and Forest Energy Resources jointly, and by Mariner. These representations and warranties, which are generally reciprocal unless otherwise stated below, relate to:


	•	corporate existence, qualifications to conduct business and corporate standing and power;

	•	corporate authorization, enforceability and actions by the board of directors;

	•	capitalization;

	•	financial statements and undisclosed liabilities;

	•	absence of certain material changes or events since June 30, 2005;

	•	governmental investigations and litigation;

	•	licenses and compliance with laws;

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	•	the registration statements to be filed with the SEC and the proxy statement/ prospectus-information statement related to the Mariner annual meeting of stockholders;

	•	information supplied to governmental authorities;

	•	compliance with environmental laws;

	•	tax matters;

	•	benefit plans;

	•	labor matters;

	•	intellectual property matters;

	•	material contracts;

	•	financial advisor opinion (given only by Mariner);

	•	payment of broker’s and finder’s fees in connection with the merger agreement and other transaction agreements;

	•	takeover statutes (given only by Mariner);

	•	certain findings of the board of directors to approve the merger;

	•	stockholder votes necessary to complete the merger;

	•	absence of requirement for Forest stockholder approval (given only by Forest);

	•	Forest Energy Resources stockholder approval (given only by Forest Energy Resources);

	•	payments to certain affiliated individuals or entities;

	•	title to, and sufficiency of, assets;

	•	loans made to third parties;

	•	oil and gas reserves; and

	•	derivative transactions.

Forest, on behalf of itself only, also makes representations and warranties to Mariner with respect to its:


	•	due organization and good standing;

	•	corporate power, authorization and validity of agreements;

	•	information supplied to governmental authorities;

	•	payment of broker’s and finder’s fees in connection with the merger agreement and other transaction agreements; and

	•	rights plan.

The parties acknowledge that the other parties to the merger agreement do not make any express or implied representations or warranties except as set forth in the merger agreement, the distribution agreement or the ancillary agreements. The representations and warranties contained in the merger agreement do not survive the effective time of the merger.

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Covenants

Forest Energy Resources, Forest and Mariner have each undertaken certain covenants in the merger agreement. The following summarizes the material covenants:


	*No Solicitation*

The merger agreement provides that Mariner will not, and will not permit its directors and officers, and will use all reasonable efforts to cause its employees, agents and representatives not to:


	•	solicit, initiate, encourage, facilitate or induce any inquiry, proposal or offer with respect to an acquisition proposal;

	•	participate in any discussions or negotiations regarding, provide nonpublic information with respect to, or otherwise facilitate any acquisition proposal;

	•	engage in discussions with respect to an acquisition proposal;

	•	approve, endorse or recommend an acquisition proposal, except as provided in the merger agreement; or

	•	enter into any agreement related to any acquisition proposal, except as provided by the merger agreement.

When we refer to an “acquisition proposal,” we mean any inquiry, offer or proposal for a transaction or series of related transactions involving any of the following:


	•	any purchase by any person, entity or group, as defined in Section 13(d) of the Exchange Act, of more than 15% of the total outstanding voting securities of Mariner;

	•	any tender or exchange offer that would result in any person, entity or group, as defined in Section 13(d) of the Exchange Act, owning 15% or more of the total outstanding voting securities of Mariner;

	•	any merger, consolidation, business combination or similar transaction involving Mariner;

	•	any sale, exchange, transfer, acquisition or disposition, or any lease or license outside of the ordinary course of business, of more than 15% of Mariner’s assets; or

	•	any liquidation of dissolution of Mariner.

As of the date the merger agreement was executed, Mariner agreed to immediately cease and terminate any existing discussions or negotiations with respect to any acquisition proposal.

In the event that Mariner receives an acquisition proposal or any request for nonpublic information or inquiry that it reasonably believes could lead to an acquisition proposal, Mariner agrees to:


	•	notify Forest and Forest Energy Resources orally and in writing of the material terms of the acquisition proposal, request or inquiry;

	•	identify to Forest and Forest Energy Resources the person making the acquisition proposal, request or inquiry;

	•	furnish to Forest and Forest Energy Resources copies of all written materials provided in connection with the acquisition proposal or inquiry;

	•	provide to Forest and Forest Energy Resources as promptly as practicable, both orally and in writing, all information reasonably necessary to keep Forest and Forest Energy Resources informed in all material respects of the status and details of the acquisition proposal, request or inquiry, including providing copies of written materials received from and provided to the third party making the acquisition proposal, request or inquiry; and

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	•	provide Forest and Forest Energy Resources 48 hours’ prior notice (or such lesser notice as is provided to Mariner’s directors) of any meeting of Mariner’s board of directors at which it will consider an acquisition proposal, unless shorter notice is provided to the board of directors, in which case Forest and Forest Energy Resources are to be provided the same notice.

Notwithstanding the foregoing, Mariner’s board of directors may provide nonpublic information to, and engage in negotiations with, a third party in response to an unsolicited, bona fide acquisition proposal with respect to Mariner, if:


	•	Mariner has complied with all of its non-solicitation and notification obligations in the merger agreement;

	•	in the good faith judgment of Mariner’s board of directors (after receiving the advice of its legal counsel and financial advisor), the acquisition proposal is a superior offer or is reasonably likely to result in a superior offer;

	•	concurrently with furnishing any nonpublic information, Mariner notifies Forest and Forest Energy Resources in writing of its intention to furnish nonpublic information and furnishes the same nonpublic information to Forest and Forest Energy Resources;

	•	concurrently with engaging in negotiations with the third party, Mariner notifies Forest and Forest Energy Resources in writing of its intent to enter into negotiations with the third party; and

	•	Mariner executes a customary confidentiality agreement with the third party with terms at least as restrictive as the confidentiality agreement between Forest and Mariner.

When we refer to a “superior offer,” we mean an unsolicited bona fide written proposal made by a third party to acquire, directly or indirectly, pursuant to a tender or exchange offer, merger, consolidation or other business combination, all or substantially all of the assets of Mariner or substantially all of the total outstanding voting securities of Mariner. The superior offer must be on terms that the Mariner board of directors has in good faith concluded, after receiving the advice of its legal counsel and financial adviser and taking into account all legal, financial, regulatory and other aspects of the offer and the third party offeror, to be more favorable, from a financial point of view, to Mariner’s stockholders than the terms of the merger and to be reasonably capable of being consummated.

If Mariner receives a superior offer and that superior offer has not been withdrawn, Mariner’s board of directors is permitted to change its recommendation that the Mariner stockholders approve the merger if:


	•	Mariner stockholders have not already approved the merger and the merger agreement;

	•	Mariner notifies Forest and Forest Energy Resources in writing:


	•	that it has received a superior offer;

	•	of the terms and conditions of the superior offer;

	•	of the identity of the third party making the superior offer; and

	•	that it intends to change its recommendation that Mariner stockholders approve the merger and the manner in which it intends to do so;


	•	Mariner provides Forest and Forest Energy Resources with copies of all written materials delivered by Mariner to the third party making the superior offer that have not previously been provided to Forest and Forest Energy Resources, and Mariner has otherwise made available to Forest and Forest Energy Resources all materials and information made available to the third party; and

	•	Mariner has not breached any of the provisions of the merger agreement relating to acquisition proposals and superior offers.

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Subject to complying with its fiduciary duties under applicable law, Mariner’s obligation to call, give notice of, convene and hold its stockholders’ meeting regarding approval of the merger agreement will not be limited or otherwise affected by the commencement, disclosure, announcement or submission to it of any acquisition proposal unless the merger agreement is terminated. Prior to termination of the merger agreement, Mariner will not submit to the vote of its stockholders any acquisition proposal other than the merger or enter into any agreement, agreement in principle or letter of intent with respect to, or accept any acquisition proposal other than, the merger.

In addition, notwithstanding the foregoing, Mariner and its board of directors may take a position, and disclose to its stockholders that position, with respect to a tender or exchange offer by a third party in compliance with Rule 14d-9 or Rule 14e-2(a) of the Exchange Act to the extent required by applicable law. The content of any document disclosing the position of the Mariner board of directors to Mariner stockholders will be governed by the provisions of the merger agreement. The Mariner board of directors may not recommend that Mariner stockholders tender or exchange their Mariner common stock unless the Mariner board of directors determines in good faith, after receiving advice of its legal counsel and financial adviser, that the acquisition proposal is a superior offer.


	*Board of Directors Covenant to Call Stockholders’ Meeting and to Recommend the Merger*

As promptly as practicable following the date of the merger agreement and the effectiveness of the registration statements, Mariner has agreed to call a meeting of its stockholders to be held as promptly as practicable for the purpose of voting upon the adoption of the merger agreement and any related matters, and to submit the merger agreement for adoption to the stockholders of Mariner at such Mariner meeting. Mariner has agreed to cause the Mariner meeting to be held and the vote taken within 60 days following the effectiveness of Mariner’s registration statement on Form S-4. Mariner will deliver to its stockholders the proxy statement/ prospectus-information statement in definitive form in connection with the Mariner meeting, at the time and in the manner provided by, and will conduct the Mariner meeting and the solicitation of proxies in connection with the Mariner meeting in accordance with, the applicable provisions of the law of the State of Delaware, the Exchange Act and Mariner’s certificate of incorporation and by-laws. Subject to the provisions described in “—No Solicitation” above, Mariner’s board of directors has agreed to recommend that the stockholders of Mariner adopt the merger agreement.


	*Operations of Forest (in respect of the Forest Gulf of Mexico operations), Forest Energy Resources and Mariner Pending Closing*

Forest (in respect of the Forest Gulf of Mexico operations), Forest Energy Resources and Mariner have each undertaken that, until the earlier of the effective time of the merger and the termination of the merger agreement, each will conduct its business in the ordinary course consistent with past practice and use all commercially reasonable efforts to preserve intact its business organization, maintain its material rights and franchises, keep available the services of its current officers and key employees and preserve its relationships with material third parties. Each has further agreed that it will not, except as permitted by the distribution agreement or any ancillary agreement or with the prior written consent of the other parties (such consent not to be unreasonably withheld or delayed), do any of the following:


	•	in the case of Mariner, declare or pay any dividends on or make other distributions in respect of its capital stock;

	•	split, combine or reclassify any of its capital stock or issue or authorize or propose the issuance of any other securities in respect of, in lieu of, or in substitution for, shares of its capital stock;

	•	redeem, repurchase or otherwise acquire (or permit any subsidiary to redeem, repurchase or otherwise acquire) any shares of its capital stock;

	•	issue, deliver or sell any shares of, or securities convertible into, its capital stock of any class, except, in the case of Mariner, the issuance of stock options with three-year vesting or restricted stock for up to 300,000 shares of Mariner common stock;

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	•	amend its governing documents;

	•	other than purchases from vendors or suppliers in the ordinary course of business consistent with past practice, exercises of preferential rights and, in the case of Mariner, certain specified transactions, engage in acquisitions valued at more than $25 million in the aggregate;

	•	other than product sales and other dispositions in connection with normal equipment maintenance or salvage in the ordinary course of business and consistent with past practice and permitted liens, dispose of assets valued at more than $10 million in the aggregate, except, in the case of Mariner, transactions permitted as described under “—No Solicitation” above, and except, in the case of Forest, dispositions of property to Forest and any of its wholly owned subsidiaries;

	•	incur or guarantee indebtedness, other than, in the case of Forest Energy Resources, indebtedness incurred or guaranteed in connection with the spin-off, or, in the case of Mariner, up to $185 million pursuant to a new or amended credit agreement;

	•	fail to continue its capital expenditure program for exploration and development or fail to perform, to the extent reasonably practicable, all capital expenditures at an aggregate cost not exceeding 120% of the aggregate costs set forth in the capital expenditure program;

	•	make material changes to employment arrangements;

	•	fail to comply with any laws, ordinances or regulations or permit to expire or terminate without renewal any license that is necessary to the operation of the business, to the extent the same would result in a material adverse effect;

	•	adopt a plan of complete or partial liquidation or dissolution;

	•	change its fiscal year or make any material change in its methods of accounting except as required by the Financial Accounting Standards Board or changes in generally accepted accounting principles, or in response to comments made by the SEC with respect to any registration statement;

	•	amend any agreement or arrangement with any affiliates (including employees of Mariner and Forest Energy Resources) on terms materially less favorable than could be reasonably expected to have been obtained with an unaffiliated third party on an arm’s-length basis;

	•	except in the ordinary course of business consistent with past practice, modify, amend, terminate or renew any material contract or waive, release or assign any material rights or claims, in each case if the action would have a material adverse effect or impair in any material respect the party’s ability to perform its obligations under the merger agreement and other transaction agreements;

	•	waive any preferential rights;

	•	enter into any contract not in the ordinary course of business involving total consideration of $2 million or more with a term longer than one year, unless it can be terminated by it without penalty upon no more than 30 days’ prior notice;

	•	fail to maintain insurance in amounts and against risks and losses as are customary for companies engaged in their respective businesses, except, in the case of Mariner, self-insurance with respect to operators’ extra expense insurance, physical damage to wellsite real and personal property insurance and business interruption insurance;

	•	make or rescind any material express or deemed election relating to taxes unless the action will not materially and adversely affect that party on a going-forward basis;

	•	settle or compromise any material claim or controversy relating to taxes, except where the settlement or compromise will not result in a material adverse effect on that party;

	•	amend any material tax returns;

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	•	change in any material respect any of its methods of reporting income or deductions for federal income tax purposes, except as may be required by applicable law or except for changes that are reasonably expected not to result in a material adverse effect on that party;

	•	pay, discharge or satisfy any material claims, liabilities or obligations, other than the payment, discharge or satisfaction, in the ordinary course of business or, in the case of Mariner, in accordance with their terms, of liabilities reflected or reserved against in, or contemplated by, the most recent consolidated financial statements or incurred in the ordinary course of business;

	•	take or cause or permit to be taken any action that would disqualify the spin-off under the distribution agreement from constituting a tax-free spin-off or that would disqualify either the merger or the contribution of assets from Forest to Forest Energy Resources from constituting a tax-free reorganization;

	•	intentionally take or agree or commit to take any action that would result in any of the conditions set forth in the merger agreement not being satisfied at the effective time of the merger;

	•	enter into any derivative transaction or any fixed price commodity sales agreement with a term of more than 60 days; and

	•	agree or otherwise take any action inconsistent with the foregoing.

Mariner has also undertaken that it will cause MEI Sub not to conduct any business operations, enter into any contract, acquire any assets or incur any liabilities, and will use reasonable commercial efforts to obtain the lender consent and to enter into a new credit facility. Forest and Forest Energy Resources have also undertaken not to form or propose to form a new subsidiary of Forest Energy Resources.

Also, the parties agree to promptly advise the other parties orally and in writing of any change or event having, or that, insofar as can reasonably be foreseen, could have, either individually or together with other changes or events, a material adverse effect.


	*Commercially Reasonable Efforts, Further Assurances*

Forest, Forest Energy Resources, Mariner and MEI Sub have agreed to use all commercially reasonable efforts to take, or cause to be taken, all actions and to do, or cause to be done, all things necessary under applicable laws and regulations to consummate the transactions contemplated by the merger agreement and the other transaction agreements. These actions include providing information and obtaining all necessary exemptions, rulings, consents, authorizations, approvals and waivers to effect all necessary registrations and filings and to lift any injunction or other legal bar to the merger and the other transactions contemplated by the merger agreement and the other transaction agreements as promptly as practicable, and taking all other actions necessary to consummate the transactions contemplated by the merger agreement and the other transaction agreements in a manner consistent with applicable law. Forest, Forest Energy Resources, Mariner and MEI Sub also agreed to cooperate and to use their respective commercially reasonable efforts to obtain any government clearances required to consummate the merger and to respond to any government requests for information.


	*Employee Benefit Plans*

Forest Energy Resources and Mariner agreed in the merger agreement that Forest Energy Resources employees who remain employed by Forest Energy Resources, Mariner or their subsidiaries from and after the effective time of the merger:


	•	will participate in Mariner benefit plans as of the effective time of the merger on a basis no less favorable than that applicable to similarly situated Mariner employees, and be granted full credit for all purposes under such plans for prior service with Forest and Forest Energy Resources and their affiliates before the effective time of the merger (except to the extent necessary to avoid duplication of benefits);

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	•	will, if the effective time of the merger occurs in 2006, receive vacation benefits for 2006 that are equal to the employee’s accrued and unused vacation under Forest’s vacation policy as of the effective time of the merger plus any additional vacation entitlement the employee would have earned under the terms of Mariner’s vacation policy; and

	•	will receive specified relocation benefits if, from the effective time of the merger to the later of June 30, 2006 or six months after the effective time of the merger, Mariner or a subsidiary of Mariner relocates the principal place of employment of the employee by 50 miles or more from the location of his or her principal place of employment immediately prior to the effective time of the merger.

In addition, Forest Energy Resources employees will, in lieu of the payment of any annual bonuses for 2005 under annual incentive and bonus plans maintained by Forest, be eligible to receive potential retention benefits, paid in installments commencing in October 2005 and ending in June 2006, in an aggregate amount equal to 250% of the employee’s target annual bonus for 2005 under the annual incentive or bonus plan maintained by Forest and applicable to the employee.

If, during the period beginning on the effective time of the merger and ending on the later of June 30, 2006, or the date that is six months after the effective time of the merger, a Forest Energy Resources employee (a) voluntarily terminates his employment within 30 days after a reduction in his base salary or base wages from that in effect immediately prior to the effective time of the merger, (b) voluntarily terminates his employment after being notified that the principal place of his employment is changing to a location 50 miles or more from the location of his principal place of employment immediately prior to the effective time of the merger, or (c) is involuntarily terminated from employment other than for cause, then Mariner shall pay specified severance benefits to such employee, reduced, however, by the amount of any retention benefits previously paid to such employee, and provided that such employee executes a release and is not subsequently re-hired by Forest or any subsidiary of Forest during the six-month period after the effective time of the merger.

Mariner will reimburse Forest for severance amounts paid to employees of the Forest Gulf of Mexico operations who are terminated by Forest with Mariner’s consent prior to the effective time of the merger, provided that any such employee is not subsequently rehired by Forest or any Forest subsidiary during the six month period following the effective time of the merger.

After the effective time of the merger, Forest will transfer the aggregate account balances of the Forest Gulf of Mexico operations employees under Forest’s retirement savings plan to Mariner’s comparable plan. Any loans under the plan will be transferred as part of the balance transfers. All savings plan investments in shares of Forest or Mariner common stock will be converted to cash prior to transfer.


	*Directors’ and Officers’ Indemnification*

From and after the effective time of the merger, Forest Energy Resources will indemnify any persons who are or were officers or directors of Mariner prior to the effective time of the merger for losses in connection with any action arising out of or pertaining to acts or omissions, or alleged acts or omissions, by them in their capacities as such, whether commenced, asserted or claimed before or after the effective time of the merger. Forest Energy Resources will maintain existing, or provide comparable, directors’ and officers’ liability insurance policies for a period of six years following the effective time of the merger.

Additional Covenants


	*Litigation Defense*

Each of Forest, Forest Energy Resources, Mariner and MEI Sub will use all commercially reasonable efforts to defend against all actions in which such party is named as a defendant that challenge or otherwise seek to enjoin, restrain or prohibit the transactions contemplated by the merger agreement or seek damages with respect to such transactions.

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	*Accounting Matters*

Each party to the merger agreement will use its commercially reasonable efforts to ensure that, following the effective time of the merger, Mariner will establish a fiscal year ending on December 31.


	*Reorganization Treatment*

Forest, Forest Energy Resources, Mariner and MEI Sub intend that the merger will qualify as a reorganization within the meaning of Section 368(a) of the Internal Revenue Code and the parties have agreed to take the position for all tax purposes that the merger so qualifies unless a contrary position is required by a final determination within the meaning of Section 1313 of the Internal Revenue Code. Forest, Forest Energy Resources, Mariner and MEI Sub will each use their respective commercially reasonable efforts to cause the merger to qualify as a reorganization within the meaning of Section 368(a) of the Internal Revenue Code, and will not take actions, cause actions to be taken or fail to take actions that are reasonably likely to prevent such result.


	*Letter of Credit*

Mariner will obtain and maintain a letter of credit in favor of Forest with an aggregate principal amount of $40.0 million to secure Mariner’s performance of its obligations under an existing drill-to-earn program. The principal amount of the letter of credit will decrease over time as Mariner drills more wells under the program.

Conditions to the Completion of the Merger

The respective obligations of Forest, Mariner, MEI Sub and Forest Energy Resources to complete the merger are subject to the fulfillment, or the waiver by Forest and Mariner, of various conditions which include, in addition other customary closing conditions, the following:


	•	completion of the spin-off in accordance with the distribution agreement;

	•	obtaining all material consents, approvals and authorizations of any governmental authority legally required for the consummation of the transactions contemplated by the merger agreement and the other transaction agreements;

	•	the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Act;

	•	the SEC having declared effective the registration statements of Mariner relating to the shares of Mariner common stock to be issued in connection with the merger and the shares held by its existing stockholders;

	•	the approval for listing on the New York Stock Exchange or Nasdaq of the shares of Mariner common stock and such other shares required to be reserved for issuance in connection with the merger, subject to official notice of issuance;

	•	adoption of the merger agreement by the Mariner stockholders at the meeting;

	•	the absence of a final and non-appealable injunction or other prohibition issued by a court or other governmental entity that restrains, enjoins or prohibits the spin-off or the merger;

	•	there being no action by a governmental authority pending to restrain, enjoin, prohibit or delay consummation of the transactions contemplated by the merger agreement, or to impose any material restrictions or requirements on the transactions contemplated by the merger agreement or on Forest Energy Resources or Mariner with respect to the transactions;

	•	there being no action taken and no statute, rule, regulation or executive order enacted, entered, promulgated or enforced by any governmental authority with respect to the merger that, individually or in the aggregate, would restrain, prohibit or delay the consummation of the merger

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		or impose material restrictions or requirements on consummation of the merger or on Forest Energy Resources or Mariner with respect to the transactions;

	•	the performance by Forest, Forest Energy Resources and Mariner in all material respects of their respective covenants and agreements contained in the merger agreement and the truthfulness and correctness of the representations and warranties in the merger agreement in all respects, except in each case where the failure to be true and correct, individually or in the aggregate, would not have a material adverse effect or to the extent specifically contemplated or permitted by the merger agreement; and

	•	Forest, Forest Energy Resources and Mariner having received an opinion from their respective counsel to the effect that the merger will be treated for federal income tax purposes as a reorganization.

Additionally, the obligation of Forest and Forest Energy Resources to complete the merger is subject to the fulfillment or waiver by Forest of the following additional conditions:


	•	Forest having received any consents required from its bondholders; and

	•	Forest having received the consents required pursuant to its credit facility.

Additionally, the obligation of Mariner and MEI Sub to complete the merger is subject to the fulfillment or waiver by Mariner of the following additional conditions:


	•	Mariner having received the consents required pursuant to its credit facility; and

	•	Forest Energy Resources and/or Mariner having entered into a new or amended credit facility with available borrowing capacity sufficient to operate the Forest Gulf of Mexico operations and Mariner’s business after the closing of the merger transaction consistent with past practice.

None of Forest, Forest Energy Resources or Mariner may rely on the failure of any condition set forth in the merger agreement to be satisfied if such failure was caused by such party’s failure to act in good faith or to use its commercially reasonable efforts to consummate the merger and the other transactions contemplated by the merger agreement and the other transaction agreements.

A “material adverse effect” is, with respect to any person, any circumstance, change or effect that is or is reasonably likely to be materially adverse to (i) the business, operations, assets, liabilities, results of operations or condition (financial or otherwise) of such person and its subsidiaries, taken as a whole (which may include damage attributable, both directly and indirectly, to Hurricane Katrina), except for such effects on or changes in general economic or capital market conditions and effects and changes that generally affect the U.S. domestic oil and gas exploration and production business, or (ii) the ability of such person to perform its obligations under the merger agreement or under the other transaction agreements, in each case other than any such circumstance, change or effect that relates to or results primarily from (x) the announcement, pendency or consummation of the transactions contemplated by the merger agreement or the other transaction agreements or (y) acts of war, insurrection, sabotage or terrorism. Damages attributable to Hurricane Katrina disclosed in the damage reports of Mariner and Forest will not be taken into account in determining whether a material adverse effect exists or has occurred.

On November 14, 2005, the waiting period under the Hart-Scott-Rodino Act expired. On October 19, 2005, Forest received the consent required pursuant to its credit facility. On February 7, 2006, Mariner’s common stock was approved for listing on the New York Stock Exchange upon the completion of the merger. As of February 7, 2006, no other conditions to closing have been satisfied. Mariner is currently negotiating the definitive documents for its new credit facility, which documents also will grant the consent required pursuant to its existing facility. Mariner and Forest are actively working to obtain necessary consents, approvals and authorizations from governmental authorities, including the Minerals Management Service.

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Neither Mariner nor Forest currently believes that any other condition to closing is likely to be waived.

Termination of the Merger Agreement


	*Right to Terminate*

The merger agreement may be terminated and the transactions contemplated by the merger agreement may be abandoned at any time prior to the effective time of the merger as follows:


	•	by mutual written consent of the parties;

	•	by any party:


	•	if the effective time of the merger has not occurred on or before March 31, 2006, except that a party may not terminate the merger agreement if the cause of the merger not being completed on or before such date resulted from the party’s failure to fulfill its obligations;

	•	if a court or other governmental entity issues a final and non-appealable injunction or otherwise prohibits the merger and the terminating party has used all commercially reasonable efforts to remove such injunction or prohibition; or

	•	if the adoption of the merger agreement and the approval of the transactions contemplated by the merger agreement by the Mariner stockholders is not obtained, except that Mariner may not terminate the merger agreement if the cause of the approval not being obtained resulted from the action or failure to act of Mariner and such action or failure to act constitutes a breach by Mariner of the provisions of the merger agreement relating to non-solicitation in any respect or a material breach by Mariner of any of the other covenants or agreements contained in the merger agreement;


	•	by Mariner:


	•	if either Forest or Forest Energy Resources fails to perform in any material respect any of its respective covenants or agreements contained in the merger agreement required to be performed at or prior to the effective time of the merger, or the respective representations and warranties of Forest or Forest Energy Resources in the merger agreement are or will become untrue in any respect at any time prior to the effective time of the merger and the failure to be true and correct, individually or in the aggregate, would have a material adverse effect on the Forest Gulf of Mexico operations, Forest Energy Resources or Mariner and has not been cured within 30 days after written notice was given to Forest and Forest Energy Resources of such failure or untruth; or

	•	if the board of directors of Mariner changes its recommendation that Mariner stockholders approve the merger in order to accept a superior offer, provided that:


	•	Mariner is not in breach of the provisions of the merger agreement relating to non-solicitation or in material breach of any other covenant or agreement contained in the merger agreement, and has not breached any of its representations and warranties contained in the merger agreement in any material respect;

	•	Forest has not made an offer that is at least favorable as the superior offer within three business days after Forest receives written notice of the superior offer;

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	•	the Mariner board of directors authorizes Mariner to enter into a binding written agreement with respect to the superior offer and notifies Forest and Forest Energy Resources of its intent to do so and provides a copy of the most current version of the agreement; and

	•	Mariner pays the termination fee and expense reimbursement;


	•	by Forest:


	•	if Mariner fails to perform in any material respect any of its covenants or agreements contained in the merger agreement required to be performed at or prior to the effective time of the merger, or the representations and warranties of Mariner in the merger agreement are or will become untrue in any respect at any time prior to the effective time of the merger and the failure to be true and correct, individually or in the aggregate, would have a material adverse effect on Mariner, the Forest Gulf of Mexico operations or Forest Energy Resources and has not been cured within 30 days after written notice was given to Mariner of such failure or untruth; or

	•	if the board of directors of Mariner (i) fails to reaffirm publicly its approval of the merger, as soon as reasonably practicable, and in no event within three business days after Forest’s request, or resolves not to reaffirm the merger, (ii) fails to include in this proxy statement/ prospectus-information statement its recommendation, without modification or qualification, that Mariner stockholders approve the merger, (iii) withholds, withdraws, amends or modifies its recommendation that Mariner stockholders approve the merger, (iv) changes its recommendation that Mariner stockholders approve the merger or (v) within ten business days after commencement, fails to recommend against acceptance of any tender or exchange offer for shares of Mariner common stock or takes no position with respect to any tender or exchange offer.


	*Termination Fees and Expenses*

If either Forest or Mariner terminates the merger agreement as a result of:


	•	the other party’s failure to perform in any material respect any of its covenants or agreements contained in the merger agreement; or

	•	the representations and warranties of such other party in the merger agreement being or becoming untrue; and

	•	the failure to be true and correct, individually or in the aggregate, would have a material adverse effect on Forest Energy Resources, the Mariner business or Mariner and has not been cured within 30 days after written notice was given to such party of such failure or untruth,

the terminating party will be entitled to reimbursement of all of its documented out-of-pocket expenses and fees incurred by such terminating party up to $5 million in the aggregate.

In addition to the reimbursement of out-of-pocket expenses and fees, Mariner has agreed to pay Forest a termination fee of $25 million, together with the expense reimbursement described above, if:


	•	(i) either Forest or Mariner terminates the merger agreement as a result of the failure to obtain the requisite stockholder approval from Mariner stockholders, (ii) either Forest or Mariner terminates the merger agreement as a result of the effective time of the merger not occurring on or before March 31, 2006 or (iii) Forest terminates the merger agreement as a result of the failure of Mariner to perform in any material respect any of its covenants and agreements contained in the merger agreement, plus an acquisition proposal had been publicly announced prior to the termination and, within twelve months of the date of termination, Mariner either completes an acquisition proposal with a third party or enters into an agreement or recommends approval of any acquisition proposal that is subsequently completed (whether or not within the twelve-month period);

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	•	Forest terminates the merger agreement as a result of the board of directors of Mariner (i) having failed to reaffirm publicly its approval of the merger, as soon as reasonably practicable, and in no event later than three business days, after request by Forest, or having resolved not to reaffirm the merger, (ii) having failed to include in this proxy statement/ prospectus-information statement its recommendation, without modification or qualification, that Mariner stockholders approve the merger, (iii) having withheld, withdrawn, amended or modified its recommendation that Mariner stockholders approve the merger, (iv) having changed its recommendation that Mariner stockholders approve the merger or (v) within ten business days after commencement, having failed to recommend against acceptance of any tender or exchange offer for shares of Mariner common stock or takes no position with respect to any such tender or exchange offer; or

	•	Mariner terminates the merger agreement as a result of the board of directors of Mariner changing its recommendation that Mariner stockholders approve the merger in order to permit Mariner to accept a superior offer.

Amendments and Waiver

Any provision of the merger agreement may, to the extent legally allowed, be amended or waived at any time prior to the effective time of the merger. However, if a provision of the merger agreement is amended or waived after the Mariner stockholders adopt the merger agreement, such amendment or waiver will be subject to any necessary stockholder approval. Forest, Forest Energy Resources, Mariner and MEI Sub must sign any amendments. Any waiver must be signed by the party against whom the waiver is to be effective. Mariner and Forest will recirculate revised proxy materials and resolicit proxies if there are any material changes in the terms of the merger, including those that result from amendments or waivers.

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THE DISTRIBUTION AGREEMENT

Summary of the Transactions

In connection with the merger, Forest has contributed the Forest Gulf of Mexico operations to Forest Energy Resources pursuant to the terms and conditions of the distribution agreement summarized below. Prior to the merger, Forest will spin-off Forest Energy Resources by distributing all of the shares of Forest Energy Resources common stock to Forest shareholders on a pro rata basis.

Contribution of the Forest Gulf of Mexico Assets and Assumption of Liabilities

Under the distribution agreement, Forest has taken or caused to be taken all actions necessary to cause the transfer to Forest Energy Resources of all of the ownership interest of Forest and its subsidiaries in:


	•	all real property interests, overriding royalty interests, reversionary interests, real or immovable property (including use and occupation rights, rights to pooled, communitized or unitized acreage, and platforms, pipelines and improvements), easements, inventory, hydrocarbons, equipment, personal or movable property, spare parts, contracts, books and records, proceeds, refunds, settlements, claims and current assets to the extent comprising a part of the Forest Gulf of Mexico operations;

	•	other assets of Forest and the subsidiaries of Forest to the extent specifically assigned by Forest or any subsidiaries pursuant to the distribution agreement; and

	•	all rights of Forest Energy Resources under the distribution agreement and the other agreements entered into in connection with the merger and the spin-off.

Forest Energy Resources has assumed certain liabilities, including:


	•	all of the liabilities of the Forest Gulf of Mexico operations to the extent arising after June 30, 2005 and attributable to the conduct of the business after that date;

	•	legal obligations to plug, abandon, remove or retire platforms, pipelines, improvements, equipment, personal or movable property, fixtures and improvements comprising part of the Forest Gulf of Mexico assets, to the extent the obligation was previously disclosed to Mariner, arose after June 30, 2005 or was not known to Forest after due inquiry on the date of the distribution agreement;

	•	environmental liabilities arising from the conduct of the Forest Gulf of Mexico operations (subject to a monetary cap with respect to specified conditions), unless such liability was required to have been disclosed to Mariner prior to the execution of the merger agreement and was not so disclosed; and

	•	liabilities under specified derivatives contracts with an estimated fair value of $50.8 million as of June 30, 2005.

In connection with the spin-off, Forest Energy Resources will also transfer a cash amount to Forest, which Forest will use to reduce its indebtedness. The cash amount will equal $200 million, plus or minus the following amounts:


	•	minus revenue derived from the Forest Gulf of Mexico operations from June 30, 2005 through the date of the spin-off (which period is referred to as the “measurement period”);

	•	minus cash consideration from any sale of property, plant and equipment related to the Forest Gulf of Mexico assets during the measurement period;

	•	plus certain net assets and liabilities specified on the date of the distribution agreement;

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	•	plus or minus the net gas balancing assets or liabilities of the Forest Gulf of Mexico operations as of June 30, 2005;

	•	plus or minus the net settlement amounts in respect of settlements of gas imbalances effected during the measurement period;

	•	plus capital and operating expenditures attributable to the Forest Gulf of Mexico operations during the measurement period;

	•	plus an amount equal to hypothetical income taxes attributable to the Forest Gulf of Mexico operations during the measurement period;

	•	plus interest expense attributable to the Forest Gulf of Mexico operations during the measurement period;

	•	plus $1.6 million per month during the measurement period in respect of general and administrative expenses;

	•	plus an amount, not to exceed $7 million, in respect of the fees and expenses of Forest and Forest Energy Resources in connection with the merger and related transactions;

	•	plus or minus an amount equal to the change in working capital accounts (other than cash) of the Forest Gulf of Mexico operations during the measurement period;

	•	plus or minus an amount to adjust for the above items to the extent they are settled through intercompany accounts prior to the closing.

To the extent that any transfers are not completed before the spin-off, the parties will use their commercially reasonable efforts to effect any remaining transfers as promptly as practicable following the spin-off.

Spin-off

Before the merger, Forest will distribute 50,637,010 shares, which will represent all of the then-outstanding shares of Forest Energy Resources common stock, to Forest’s shareholders. As a result of the spin-off, Forest Energy Resources will be a separate company that will own and operate the Forest Gulf of Mexico operations.

Representations and Warranties

In the distribution agreement Forest represents to Mariner and Forest Energy Resources that, at the time of the spin-off and on June 30, 2005, the Forest Gulf of Mexico assets to be contributed to Forest Energy Resources in connection with the spin-off constitute all of Forest’s business and assets in the offshore Gulf of Mexico, and that all such assets are owned free and clear of all liens other than liens permitted under the agreement.

Indemnification

Forest Energy Resources has agreed to indemnify, defend and hold Forest and each of its affiliates and their representatives harmless from and against all losses or liabilities arising out of or related to any liabilities assumed by Forest Energy Resources or from Forest Energy Resources’ failure to perform its obligations under the distribution agreement.

Forest has agreed to indemnify, defend and hold Forest Energy Resources and each of its affiliates and their representatives harmless from and against all losses or liabilities arising out of or related to the failure of Forest or any of its subsidiaries:


	•	to pay, among other things, any losses or liabilities of Forest or its subsidiaries (including liabilities under the agreements entered into in connection with the merger and the spin-off);

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	•	to transfer to Forest Energy Resources or any of its subsidiaries all of the assets to be transferred to Forest Energy Resources; and

	•	to perform any of its obligations under the distribution agreement.

Forest has agreed that it will use commercially reasonable efforts to assist Forest Energy Resources in asserting claims relating to the assets transferred to Forest Energy Resources or liabilities assumed by Forest Energy Resources under Forest’s insurance policies, to the extent such claims are based on events prior to the spin-off date or were commenced prior to the spin-off date.

Conditions to the Spin-off

The obligations of Forest under the distribution agreement are subject to the fulfillment (or waiver by Forest) at or prior to the spin-off of a number of conditions, including the following:


	•	obtaining all material consents, approvals and authorizations of any governmental authority that are legally required for the spin-off and other transactions contemplated by the other agreements entered into in connection with the spin-off and the merger;

	•	the absence of an injunction or other prohibition issued by a court or other governmental entity that restrains, enjoins or prohibits or otherwise imposes material restrictions on the spin-off or the merger;

	•	the SEC having declared effective the registration statement on Form S-4 of Mariner relating to the shares of Mariner common stock to be issued into which shares of Forest Energy Resources common stock will be converted pursuant to the merger.

	•	the approval for listing on the New York Stock Exchange or Nasdaq of the Mariner common stock and the other shares required to be reserved for issuance in connection with the merger, subject to official notice of issuance;

	•	the adoption of the merger agreement by the Mariner stockholders at the meeting;

	•	Forest having received an opinion from its tax counsel to the effect that the contribution will constitute a reorganization under Section 368(a) of the Internal Revenue Code and the distribution will qualify under Section 355 of the Internal Revenue Code;

	•	Forest having received the consents required from its bondholders;

	•	the performance by Mariner in all material respects of its covenants and agreements contained in the merger agreement required to be performed at or prior to the date of the spin-off; and

	•	the truthfulness and correctness of the representations and warranties of Mariner in the merger agreement in all respects, except as permitted by the merger agreement or where the failure to be true and correct would not have a material adverse effect.

Based on its current valuation of the Forest Gulf of Mexico operations and the current amount of distributions permitted by the covenants contained in the indentures governing Forest’s outstanding bonds, Forest believes that no consents of bondholders will be required for the spin-off and the merger. If Forest’s belief that bondholder consents are not necessary remains unchanged as the merger closing approaches, it intends to waive conditions in the merger agreement and distribution agreement related to such consents.

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ANCILLARY AGREEMENTS

Forest and Forest Energy Resources have entered into agreements that will govern the ongoing relationships among Mariner, Forest Energy Resources and Forest and provide for an orderly transition after the spin-off and the merger. These agreements are summarized below.

Tax Sharing Agreement

In order to allocate the responsibilities for payment of taxes and certain other tax matters, Forest, Mariner and Forest Energy Resources have entered into a tax sharing agreement. The following is a summary of the material terms of the tax sharing agreement.


	*Preparation and Filing of Tax Returns*

Forest will prepare and file all tax returns (including any tax returns reporting the results of Forest Energy Resources) for periods ending on or prior to the date of the distribution of Forest Energy Resources to the shareholders of Forest, as well as any consolidated or combined returns of Forest that include Forest Energy Resources or the Forest Gulf of Mexico operations. Mariner and Forest Energy Resources will be responsible for filing all tax returns with respect to Forest Energy Resources’ operations for all other periods.


	*Liability for Taxes*

Each party has agreed to indemnify the other in respect of all taxes for which it is responsible under the tax sharing agreement. Forest is responsible for all taxes for all periods arising from the Forest Gulf of Mexico operations prior to the time that the common stock of Forest Energy Resources is distributed to the Forest shareholders and agrees to hold Forest Energy Resources and Mariner harmless in respect of those taxes. Forest is entitled to receive all refunds of previously paid taxes arising from the Forest Gulf of Mexico operations during such time. Forest remains responsible for all taxes related to the businesses of Forest other than the Forest Gulf of Mexico operations and has agreed to indemnify Forest Energy Resources and Mariner in respect of any liability for any of such taxes.

Forest Energy Resources and Mariner are responsible for all taxes for all periods arising from the Forest Gulf of Mexico operations subsequent to the time that Forest Energy Resources is distributed to the Forest shareholders and agree to hold Forest harmless in respect of those taxes.


	*Transaction Taxes*

If the spin-off fails to qualify as a tax-free transaction because of an action by Mariner (or one of its affiliates) that was not contemplated or permitted by the transaction agreements, Mariner and Forest Energy Resources agree to indemnify and hold Forest harmless for any resulting tax liability (or for the utilization of any tax attributes used to absorb any resulting taxable gain). In all other circumstances, Forest is liable for and agrees to indemnify and hold Forest Energy Resources and Mariner harmless for any tax liability if the spin-off fails to qualify as a tax-free transaction.


	*Continuing Covenants*

Forest, Mariner and Forest Energy Resources each agrees not to take (and each agrees to cause its respective affiliates to refrain from taking) any position on a tax return that will be inconsistent with the treatment of the spin-off and the merger as tax-free transactions under the applicable provisions of the Internal Revenue Code. In addition, Forest, Forest Energy Resources and Mariner each agrees that, during the two-year period following the spin-off, it will not take or fail to take (or permit any affiliate to take or fail to take) any action which would cause the spin-off to fail to qualify as a tax-free spin-off.

Moreover, Forest and Mariner each agrees that, during the two-year period following the spin-off, prior to entering into any agreement, or failing to take any action, that would result in a more than immaterial possibility that the spin-off would be treated as part of a plan pursuant to which one or more

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persons acquire directly or indirectly Forest Energy Resources stock or Forest stock representing a “50-percent or greater interest” within the meaning of Section 355(e)(4) of the Internal Revenue Code, it will obtain:


	•	a ruling from the Internal Revenue Service to the effect that the action contemplated would not affect the tax-free status of the spin-off,

	•	an opinion from a nationally recognized law firm both reasonably acceptable to Forest and Mariner to the effect that the action contemplated would not affect the tax-free status of the spin-off, or

	•	the agreement of both Forest and Mariner that such contemplated action would not affect the tax-free status of the spin-off.

Actions which may be restricted by these requirements include an issuance of shares of Mariner (or any instrument that is convertible or exchangeable into Mariner shares) in an acquisition or public or private offering. Under U.S. Treasury Regulations, certain safe harbors exist under which certain issuances of shares of Mariner will not be deemed part of the same plan as the spin-off and thus not restricted. Among other safe harbors, safe harbors exist for transactions if specific timing conditions are met as to when agreements or substantial negotiations relating to such transactions occur, and a safe harbor exists for certain issuances pursuant to compensatory employment-related arrangements.


	*Miscellaneous*

The tax sharing agreement also provides that Forest and Forest Energy Resources will cooperate with each other and exchange necessary information in connection with tax audits and examinations and the tax sharing agreement contains provisions entitling the appropriate party to control particular tax audits and controversies.

Employee Benefits Agreement

Forest and Forest Energy Resources have entered into an employee benefits agreement that provides for the transfer of the employees of the Forest Gulf of Mexico operations to Forest Energy Resources, effective upon completion of the spin-off.

The employee benefits agreement also allocates the assets and liabilities under certain existing Forest employee benefit plans and other employment-related liabilities to Forest and Forest Energy Resources, respectively. In general, at the time of the spin-off, Forest Energy Resources will assume the liabilities relating to the former employees of the Forest Gulf of Mexico operations arising after the date of the spin-off and other specified liabilities, and Forest will retain the pre-spin-off liabilities relating to the Forest Gulf of Mexico operations employees and all liabilities relating to its continuing employees. The employee benefits agreement also:


	•	sets forth the rights of the Forest Gulf of Mexico operations employees under certain of the Forest plans in which they previously participated, including with respect to the portion of their stock options that are exercisable at the effective time of the merger; and

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	•	provides for the assumption by Forest Energy Resources of certain liabilities of Forest relating to employees who are transferred to Forest Energy Resources, including the assumption of liabilities under Forest’s educational assistance plan and accrued vacation liabilities.

Pursuant to the employee benefits agreement, each of Forest Energy Resources and Forest has agreed that, without the prior consent of the other, it will not solicit employees of the other party for two years following the spin-off date.

Transition Services Agreement

Forest and Forest Energy Resources have entered into a transition services agreement under which Forest will provide services to Forest Energy Resources on an as-needed basis for a limited period of time after the merger.

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FINANCING ARRANGEMENTS RELATING TO THE SPIN-OFF AND THE MERGER

At the closing of the merger, Mariner and Mariner Energy Resources expect to enter into a new $500 million senior secured revolving credit facility, and Mariner also will obtain a $40 million senior secured letter of credit facility. The revolving credit facility will mature on the fourth anniversary of the closing, and the letter of credit facility will mature on the third anniversary of the closing. We may use the borrowings under the revolving credit facility to retire existing debt, to facilitate the merger and for general corporate purposes. The letter of credit facility will be used to obtain a letter of credit in favor of Forest to secure our performance of our obligations under an existing drill-to-earn program.

The outstanding principal balance of loans under the revolving credit facility may not exceed the borrowing base, which initially will be set at $400 million. The borrowing base will be redetermined semi-annually by the lenders, subject to reduction by Mariner. In addition, the agent and Mariner may request one additional redetermination during the interval between each scheduled redetermination, and the agent may require redeterminations in connection with certain material dispositions. If the borrowing base falls below the outstanding balance under the revolving credit facility, we will be required to prepay the deficit, pledge additional unencumbered collateral or some combination of such prepayment and pledge.

Interest under the revolving credit facility will be determined by reference to the following grid:


	Applicable Margin

Usage as a %	LIBOR		Reference		Unused
Borrowing Base	Loans		Rate Loans		Fee

Less than 50%		1.25%		0.00%		0.375%
51% to 75%		1.50%		0.00%		0.375%
76% to 90%		1.75%		0.25%		0.250%
Greater than 90%		2.00%		0.50%		0.250%

Interest will be payable quarterly for Union Bank of California Reference Rate loans and at the applicable maturity date for LIBOR (London interbank offered rate) loans. The fee for letters of credit issued under the revolving credit facility will be the LIBOR margin indicated in the grid, per annum. The fee for letters of credit under the letter of credit facility will be 1.50% due quarterly in advance.

The obligations under the credit facilities will be secured by first priority liens on substantially all of our real and personal property, including our existing and after-acquired oil and gas properties and related real property interests. Additionally, the obligations under the credit facilities will be guaranteed by us and each of our subsidiaries.

The credit facilities will contain various covenants that limit our ability to do the following, among other things:


	•	incur certain indebtedness;

	•	grant certain liens;

	•	merge or consolidate with another entity;

	•	sell unmortgaged property or other assets which generate proceeds in excess of 10% of the borrowing base;

	•	sell assets comprising collateral pledged to the lenders;

	•	make certain loans and investments;

	•	enter new lines of business; and

	•	permit certain trade payables to exceed 90 days.

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The credit facilities also will contain covenants, which, among other things, require us to maintain specified ratios or conditions as follows:


	•	consolidated current assets plus the unused borrowing base to consolidated current liabilities of not less than 1.0 to 1.0; and

	•	total debt to EBITDA of not more than 2.5 to 1.0.

If an event of default exists under the credit facilities, the lenders will be able to accelerate the maturity of the credit facilities and exercise other rights and remedies. Events of default will include defaults in payment or performance under the credit facilities, misrepresentations, cross-defaults to other debt or material obligations, and insolvency, material adverse judgments, change of control (including certain changes in ownership and in the event Mr. Scott D. Josey ceases to be involved in Mariner’s management, the failure to timely replace him with someone with comparable qualifications) and any material adverse change.

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SELECTED CONSOLIDATED STATEMENTS OF REVENUES AND

DIRECT OPERATING EXPENSES OF THE FOREST GULF OF MEXICO OPERATIONS

The selected consolidated statements of revenues and direct operating expenses for the Forest Gulf of Mexico operations for the nine months ended September 30, 2005 and 2004 and the years ended December 31, 2004, 2003 and 2002 were derived from the historical records of Forest. For additional information concerning this financial data, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Forest Gulf of Mexico Operations.” Complete financial and operating information related to the Forest Gulf of Mexico operations, including balance sheet and cash flow information, are not presented below because the Forest Gulf of Mexico operations were not maintained as a separate business unit, and therefore the assets, liabilities or indirect operating costs applicable to the operations were not segregated.


		Nine Months Ended				Years Ended
		September 30,				December 31,

		2005		2004		2004		2003		2002

		(dollars in thousands)
Oil and natural gas revenues(1)		$	326,722		324,426		453,139		342,019		228,896
Direct Operating Expenses:
	Lease operating expenses		57,431		63,022		80,079		45,716		52,076
	Transportation		2,484		1,424		2,175		2,652		3,855
	Production taxes		1,948		1,243		1,548		1,521		947

Total direct operating expenses			61,863		65,689		83,802		49,889		56,878

Revenues in excess of direct operating expenses		$	264,859		258,737		369,337		292,130		172,018

Production:
Natural gas (MMcf)			41,442		46,036		61,684		58,785		50,566
Oil and condensate (MBbls)			1,845		2,004		2,624		2,143		1,974
Natural gas liquids (MBbls)			628		186		606		2		6
Total (MMcfe)			56,280		59,176		81,064		71,655		62,446
Average daily production (MMcfe/d)			206		216		221		196		171
Per Mcfe:
Average realized sales price(1)		$	5.81		5.48		5.59		4.77		3.67
Lease operating expenses		$	1.02		1.06		0.99		0.64		0.83
Transportation		$	0.04		0.02		0.03		0.04		0.06
Production taxes		$	0.03		0.02		0.02		0.02		0.02


(1)	Includes effects of hedging.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS OF THE FOREST GULF OF MEXICO OPERATIONS

Overview

The accompanying historical statements of revenues and direct operating expenses are presented using accrual basis, full cost accounting and relate to Forest’s interests in certain producing oil and gas properties located offshore in the Gulf of Mexico. These historical statements may not be representative of future operations. The historical statements were prepared from the historical accounting records of Forest. The historical statements do not include Federal and state income taxes, interest expenses, depletion, depreciation and amortization, accretion, or general and administrative expenses. The historical statements include oil and natural gas revenues and direct lease operating and production expenses, including transportation and production taxes, for all the periods presented.

Complete financial statements, including a balance sheet, are not presented. The Forest Gulf of Mexico operations were not maintained as a separate business unit within Forest, and assets, liabilities or indirect operating costs applicable to the Forest Gulf of Mexico operations were not segregated. Accordingly, it was not practicable to identify all assets, liabilities or indirect operating costs applicable to the Forest Gulf of Mexico operations.

Recent Developments

Hurricane Impact

Forest’s Gulf of Mexico operations were adversely affected by one of the most active hurricane seasons in recorded history. As of December 31, 2005, Forest had approximately 70 MMcfe/d of net production shut-in relating to the Forest Gulf of Mexico operations. Forest estimates that as of January 25, 2006, approximately 51 MMcfe/d net remains shut in. The majority of the production that remains shut-in is due to repairs necessary to platforms as well as third-party processing facilities and infrastructure. The timetable for restoring full production is uncertain as it is dependent on repairs to transportation and processing facilities that are owned by others. Forest estimates that total production associated with the Forest Gulf of Mexico operations deferred for hurricanes Katrina and Rita during the fourth quarter of 2005 was approximately 9.3 Bcfe, while total production deferred in the third and fourth quarters of 2005 was approximately 13.3 Bcfe.

Forest carries property and casualty insurance to insure against property damages such as those caused by hurricanes. The insurance has a $5 million deductible for each occurrence. Forest’s estimated uninsured liability for the repair of its facilities damaged by hurricanes in the third quarter of 2005 will be $10 million, the majority of which will be incurred in the fourth quarter of 2005 as the related repairs are made. Forest’s insurance does not insure against losses or deferrals of production caused by shut-in production.

Nine Months Ended September 30, 2005 Highlights

Revenues in excess of direct operating expenses of $264.9 million for the nine months ended September 30, 2005 were 2% higher than revenues in excess of direct operating expenses of $258.7 million for the same period in 2004. The period-over-period revenues in excess of direct operating expenses were primarily driven by the following factors:


	•	Sales volumes decreased 5% to 56.3 Bcfe in the nine months ended September 30, 2005 from 59.2 Bcfe in 2004.

	•	Average realized prices increased 6% to $5.81 per Mcfe in 2005 from $5.48 per Mcfe in 2004.

	•	Higher realized prices partially offset by decreased sales volumes resulted in oil and natural gas revenues increasing 1% to $326.7 million in the nine months ended September 30, 2005 from $324.4 million in the corresponding period in 2004.

	•	Lease operating expense declined 4% from $1.06 per Mcfe for 2004 to $1.02 per Mcfe for 2005.

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	*Production*

Production from the Forest Gulf of Mexico operations for the nine months ended September 30, 2005 averaged approximately 152 MMcf of natural gas per day and approximately 9,000 barrels of oil per day or total equivalents of approximately 206 MMcfe per day. Natural gas production comprised approximately 74% of the total production.

Historically, a majority of the production from the Forest Gulf of Mexico operations has been comprised of natural gas, and the concentration of natural gas production is expected to continue. As a result, the revenues, profitability and cash flows of the Forest Gulf of Mexico operations will be more sensitive to natural gas prices than to oil and condensate prices.


	*Oil and Gas Property Costs*

In the nine months ended September 30, 2005, $104.7 million in capital expenditures were made with respect to the Forest Gulf of Mexico operations, with 55% and 45% related to development activities and exploration activities, respectively. The exploration activities consisted of drilling and completion of new wells in the Brazos, South Marsh Island, South Timbalier, Vermillion and West Cameron fields. The development activities consisted of development drilling and recompletions in the Eugene Island, South Timbalier and West Cameron fields.

During 2004, $185.5 million in capital expenditures were made with respect to the Forest Gulf of Mexico properties, including $28.3 million in exploration activities, $70.0 million in development activities, and $87.2 million in acquisitions. The exploration activities primarily were related to drilling and completion of new wells in the High Island, Main Pass and Vermillion fields. The development activities primarily were related to recompletions, drilling and completion of development wells, as well as installation of production facilities in the West Cameron field and in the Eugene Island, High Island, Ship Shoal, South Marsh Island and West Cameron fields. The $87.2 million in acquisition costs related primarily to the offshore Gulf of Mexico properties acquired in connection with Forest’s acquisition of the Wiser Oil Company in June 2004 and the acquisition of BP’s interest in the Vermillion 14 field in the fourth quarter of 2004.


	*Oil and Gas Reserves*

Estimated net proved reserves related to the Forest Gulf of Mexico operations have been maintained between approximately 330 Bcfe to 370 Bcfe from 2002 through 2004 primarily through acquisition activities. During the same time period, a total of 215 Bcfe was produced. Approximately 140 Bcfe of estimated proved reserves were acquired from 2001 to 2004 and were augmented by additions from exploration and development activities of approximately 53 Bcfe during the same period. As of December 31, 2004, estimated net proved reserves related to the Forest Gulf of Mexico operations were approximately 340 Bcfe, with a PV10 of approximately $1.2 billion and a standardized measure of discounted future net cash flows attributable to estimated proved reserves of approximately $925.8 million. Please see “The Forest Gulf of Mexico Operations—Estimated Proved Reserves” for a definition of PV10 and a reconciliation of PV10 to the standardized measure of discounted future net cash flows. See “The Forest Gulf of Mexico Operations—Estimated Proved Reserves” for more information concerning the net reserve estimates for the Forest Gulf of Mexico operations.


	*Oil and Natural Gas Prices and Hedging Activities*

Prices for oil and natural gas can fluctuate widely, thereby affecting the amount of cash flow generated from the Forest Gulf of Mexico operations which is available to cover operating costs and capital expenditures, and the amount of oil and natural gas that can be economically produced. 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.

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The revenues, profitability and future growth of the Forest Gulf of Mexico operations depend substantially on prevailing prices for oil and gas and the ability to find, exploit and develop 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 the results of operations and quantities of oil and natural gas reserves that can economically be produced.

Hedging arrangements have been utilized from time to time to reduce exposure to fluctuations in oil and natural gas prices. Historically, the hedging strategy has involved entering into commodity price swaps and costless collars with third parties. Price swaps establish a fixed price and an index-related price for the covered commodity. When the index-related price exceeds the fixed price, the third party is paid the difference, and when the fixed price exceeds the index-related prices, the third party pays 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, the third party is paid the difference, and when the index-related price is less than the fixed floor price, the third party pays the difference. While hedging arrangements provide a more predictable cash flow, they also limit the benefits of increased prices. As a result of increased oil and natural gas prices throughout 2004 and 2005, hedging losses totaling $57.1 million were incurred during the year ended December 31, 2004 and $83.8 million during the nine months ended September 30, 2005.

The following table sets forth information regarding the commodity swap agreements that will be transferred to Forest Energy Resources in the spin-off. The fair value of the commodity swaps based on the futures prices quoted on September 30, 2005 was a liability of approximately $125.2 million.


	Natural Gas (NYMEX HH)

			Weighted Average
	Bbtu per		Hedged Price per
	Day		MMBtu

Fourth Quarter 2005		55.0	$	4.88
First Quarter 2006		40.0		6.15
Second Quarter 2006		40.0		6.15
Third Quarter 2006		40.0		6.15
Fourth Quarter 2006		40.0		6.15

Results of Operations

For certain information with respect to oil and natural gas production, average sales price received and expenses per unit of production related to the Forest Gulf of Mexico operations for the nine months ended September 30, 2005 and 2004 and the three years ended December 31, 2004, see “Selected Consolidated Statements of Revenues and Direct Operating Expenses of the Forest Gulf of Mexico Operations” beginning on page 140.


	*Nine Months Ended September 30, 2005 compared to Nine Months Ended September 30, 2004*

Net production during the nine months ended September 30, 2005 decreased approximately 5% to 56.3 Bcfe from 59.2 Bcfe in the same period of 2004. The decrease in production volumes was primarily attributable to approximately 6 Bcfe of production shut-in during the third quarter of 2005 due to hurricanes in the Gulf of Mexico partially offset by offshore oil and gas properties purchased in connection with Forest’s acquisition of Wiser in June of 2004 and deep shelf discoveries in 2004.

Oil and natural gas revenues increased 1% to $326.7 million for the nine months ended September 30, 2005 from $324.4 million in the corresponding period of 2004. The increase in oil and natural gas revenues was due to a 6% increase in average sales price received per Mcfe from $5.48 in 2004 to $5.81 in 2005 partially offset by the 5% decrease in production.

Hedging activities in the first nine months of 2005 decreased the average realized natural gas price received by $1.13 per Mcf and revenues by $47.0 million, compared with a decrease of $0.45 per Mcf and

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revenues of $20.9 million for the same period in 2004. The hedging activities with respect to crude oil during the first nine months of 2005 decreased the average sales price received by $19.95 per barrel and revenues by $36.8 million, compared with a decrease of $6.61 per barrel and revenues of $13.2 million for the same period in 2004.

Lease operating expenses (“LOE”) decreased 9% from $63.0 million in the first nine months of 2004 to $57.4 million in the first nine months of 2005. On a per-Mcfe basis, LOE decreased 4% from $1.06 in 2004 to $1.02 in 2005. The reduced costs were primarily attributable to cost control efforts implemented in the third quarter of 2004, specifically focusing on helicopter, boat and crane charges, as well as catering and paramedic charges.

Transportation expenses were $2.5 million or $0.04 per Mcfe for the nine months ended September 30, 2005, compared to $1.4 million or $0.02 per Mcfe in the first nine months of 2004. The increase in transportation expenses in total and on a per unit of production basis is attributable to a large discovery which had initial production in June 2004 and had higher-than-average transportation costs. In addition, beginning in 2005, equity gas production is being used and transported to processing plants for the replacement of plant thermal reduction in lieu of buying third party gas, as had been done through 2004.

Production taxes were $1.9 million or $0.03 per Mcfe for the nine months ended September 30, 2005, compared to $1.2 million or $0.02 per Mcfe in the first quarter of 2004. The increase was primarily attributable to the increase in the average realized prices of oil and natural gas before hedging losses.


	*Year Ended December 31, 2004 compared to Year Ended December 31, 2003*

Net production for 2004 increased approximately 13% to 81.1 Bcfe from 71.7 Bcfe in 2003, primarily due the acquisition of additional offshore oil and gas properties in late 2003 and during 2004, exploration of these properties and deep shelf discoveries.

Oil and natural gas revenues increased 32% to $453.1 million for 2004 from $342.0 million in 2003. The increase in oil and natural gas revenues was due to a 17% increase in average sales price received per Mcfe, from $4.77 in 2003 to $5.59 in 2004, and a 13% increase in production.

Hedging activities in 2004 decreased the average realized natural gas price received by $0.56 per Mcf and revenues by $34.6 million, compared with a decrease of $0.63 per Mcf and revenues of $36.8 million for 2003. The hedging activities with respect to crude oil during 2004 decreased the average sales price received by $8.55 per barrel and revenues by $22.4 million, compared with a decrease of $1.90 per barrel and revenues of $4.1 million for 2003.

Lease operating expenses were $80.1 million in 2004 and $45.7 million in 2003. On a per-Mcfe basis, LOE increased 55% from $0.64 in 2003 to $0.99 in 2004. The increase was primarily attributable to properties purchased in late 2003 and during 2004. These properties had higher initial LOE due primarily to deferred maintenance of the properties at the time of acquisition.

Transportation expenses were $2.2 million or $0.03 per Mcfe for 2004, compared to $2.7 million or $0.04 per Mcfe in 2003.

Production taxes were comparable at $1.5 million or $0.02 per Mcfe for 2004 and $1.5 million or $0.02 per Mcfe in 2003, despite higher average realized oil and natural gas prices on a per Mcfe basis, due to a change in the mix of offshore production subject to production taxes.


	*Year Ended December 31, 2003 Compared to Year Ended December 31, 2002*

Net production for 2003 increased approximately 15% to 71.7 Bcfe from 62.4 Bcfe for 2002, primarily due the acquisition of offshore oil and gas properties in late 2003.

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Oil and natural gas revenues increased 49% to $342.0 million for 2003 from $228.9 million in 2002. The increase in oil and natural gas revenues was due to a 30% increase in average sales price received per Mcfe from $3.67 in 2002 to $4.77 in 2003, and a 15% increase in production.

Hedging activities in 2003 decreased the average realized natural gas price received by $0.63 per Mcf and revenues by $36.8 million, compared with an increase of $0.17 per Mcf and revenues of $8.4 million for the same period in 2002. The hedging activities with respect to crude oil during 2003 decreased the average sales price received by $1.90 per barrel and revenues by $4.1 million. There was no hedge activity with respect to crude oil during 2002.

Lease operating expenses were $45.7 million in 2003 and $52.1 million in 2002. On a per-Mcfe basis, LOE decreased 23%, from $0.83 in 2002 to $0.64 in 2003. The reduced costs were primarily attributable to less workover costs and hurricane repairs in 2003 compared to 2002.

Transportation expenses were $2.7 million or $0.04 per Mcfe for 2003, compared to $3.9 million or $0.06 per Mcfe in 2002. The change is primarily due to improvements in marketing arrangements and cost control.

Production taxes were $1.5 million and $0.9 million for 2003 and 2002, respectively. Production taxes were $0.02 per Mcfe for each period.

Capital Expenditures

Expenditures for property acquisitions, exploration, and development related to the Forest Gulf of Mexico operations were as follows:


		Nine Months Ended				Years Ended
		September 30,				December 31,

		2005		2004		2004		2003		2002

Property acquisitions		$	25		85,546		87,165		168,485		3,263
Exploration			47,418		23,261		28,331		39,683		17,503
Development			57,248		57,145		70,027		74,690		70,833

	Total Capital Expenditures	$	104,691		165,952		185,523		282,858		91,599

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THE FOREST GULF OF MEXICO OPERATIONS

As of December 1, 2005, Forest has transferred and contributed the assets and certain liabilities associated with the Forest Gulf of Mexico operations to Forest Energy Resources. The following discussion describes the Forest Gulf of Mexico operations that Forest has contributed to Forest Energy Resources, and does not reflect Mariner’s business integration plans after the merger.

As of December 31, 2004, the Forest Gulf of Mexico operations included estimated proved reserves of 339.7 Bcfe, of which approximately 79% were natural gas and 21% were oil and condensate. Approximately 76% of these estimated proved reserves were classified as proved developed as of December 31, 2004. For the year ended December 31, 2004, the Forest Gulf of Mexico operations had total net production of 81.1 Bcfe, or an average of 221 MMcfe per day. During 2004, capital expenditures for exploration and development and property acquisitions associated with the Forest Gulf of Mexico operations totaled $185.5 million.

Significant Properties

The oil and gas properties, including producing and non-producing properties, that are included in the Forest Gulf of Mexico operations are located primarily in federal waters. Based on the present value of estimated future net proved reserves as of December 31, 2004, the largest offshore Gulf of Mexico properties include the following:


								Approximate
								Water		Gross		Date Production		Estimated		PV10 Value		Standardized
					Working			Depth		Producing		Commenced/		Proved Reserves		(In $		Measure
			Operator		Interest			(Feet)		Wells(a)		Expected		(Bcfe)(b)		Millions)(b)		(In $ Millions)

					%
Gulf of Mexico Shelf:
	East Cameron 14			FOC		50.0			25		2		1969		17.2	$	81.0
	Eugene Island 273			FOC		77.7			175		7		1970		5.4		27.9
	Eugene Island 292			FOC		45.0			195		4		1970		8.5		39.0
	Eugene Island 53			FOC		50.0	(c)		40		5		1964		12.6		68.9
	High Island 116			FOC		98.9	(d)		45		2		1986		10.2		44.9
	High Island 195			Apache		23.5			50		6		1989		3.8		20.9
	Main Pass 166			FOC		100.0			125		0		2006		5.1		18.0
	Ship Shoal 26			FOC		100.0			10		1		1969		5.5		24.6
	South Marsh Isl 149			Unocal		50.0			150		4		1979		5.5		31.7
	South Marsh Isl 18			FOC		100.0			75		1		1993		9.8		32.7
	South Pass 24–NCOC			FOC		100.0			10		37		1957		22.8		73.7
	South Timbalier 72			FOC		100.0	(e)		65		4		1963		6.8		39.1
	Vermilion 14			FOC		100.0			20		21		1959		35.4		129.4
	Vermilion 380			FOC		100.0			320		3		1982		11.5		40.7
	West Cameron 110			BP/Amoco		37.5			40		1		1958		7.7		36.8
	West Cameron 112			FOC		55%			43		1		2004		3.7		22.8
	West Cameron 205			FOC		100.0			50		3		1982		5.9		30.0
	Other Properties										871				146.1		392.3
Gulf of Mexico Deepwater:
	East Breaks 420			Samedan		50.0			2,560		1		2002		16.2		67.8

		Total:									974				339.7	$	1,222.2	$	925.8

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(a)	Wells producing or capable of producing as of December 31, 2004.

(b)	As of December 31, 2004. Please see “The Forest Gulf of Mexico Operations—Estimated Proved Reserves” for a definition of PV10 and a reconciliation of PV10 to the standardized measure of discounted future net cash flows.

(c)	Forest operates the field and owns working interests in individual wells ranging from approximately 50% to 100%.

(d)	Forest operates the field and owns working interests in individual wells ranging from approximately 98.9% to 100%.

(e)	Forest operates the field and owns working interests in individual wells ranging from approximately 37.5% to 100%.


	*Gulf of Mexico Shelf Properties*

East Cameron 14. Forest acquired a 50% working interest in this property through Forest’s acquisition of Forcenergy Inc in 2000. This property is located in approximately 25 feet of water, approximately 30 miles southeast of Cameron, Louisiana.

Eugene Island 273. This is a legacy Forest property installed in 1970 in approximately 175 feet of water, approximately 142 miles southeast of Cameron, Louisiana. Forest owns a 77.7% working interest in this field. Redevelopment of this property occurred in 2004 with the installation of a new platform.

Eugene Island 292. This is a legacy Forest property installed in 1967, with first production commencing in 1970. Forest owns a 45% working interest in this field. The property consists of a hub for the complex including six platforms. The property is located in approximately 195 feet of water, approximately 140 miles southeast of Cameron, Louisiana.

Eugene Island 53. Forest acquired the shallow rights to this property in 1993 from Sandefer Offshore Operating. Subsequently, Forest acquired the deep rights from Pennzoil in 1995 and 1997. Forest owns between 50% and 100% working interests in various wells in the field. The property is located in approximately 40 feet of water, approximately 111 miles southeast of Cameron, Louisiana.

High Island 116. Forest acquired this property in 1993 from Arco. Forest farmed out a prospect to Zilkha Energy in 1996, subsequently acquiring 44% of Zilkha’s working interest and participating in the drilling of the discovery well in deeper horizons as a 44% working interest owner. In 2000 Forest purchased the remaining working interests in this property and now owns a 100% working interest. The property is located in approximately 45 feet of water, approximately 49 miles southwest of Cameron, Louisiana.

High Island 195. Forest acquired its 23.5% working interest in this property, operated by Apache, through its acquisition of Forcenergy Inc in 2000. The property is located in approximately 50 feet of water, approximately 66 miles southwest of Cameron, Louisiana.

Main Pass 166. Forest acquired this property in an Outer Continental Shelf Lease Sale in 2004. The property was acquired to drill a well to exploit bypassed pay in the 2,800-foot and 3,600-foot sands. Forest owns a 100% working in this property, which is located approximately 96 miles southeast of New Orleans, Louisiana.

Ship Shoal 26. Forest acquired this property through its acquisition of Forcenergy Inc in 2000. Forest owns a 100% working interest in the property. The property is located in approximately 10 feet of water, approximately 97 miles southwest of New Orleans, Louisiana.

South Marsh Island 149. Forest acquired this property through its acquisition of Forcenergy Inc in 2000. Forest subsequently sold a 50% working interest in the property to Unocal in 2001. This property is located in approximately 150 feet of water, approximately 130 miles southeast of Cameron, Louisiana.

South Marsh Island 18. Forest acquired this property through its acquisition of Forcenergy Inc in 2000. Forest subsequently sold a 50% working interest in the property to Unocal in 2001. As part of an

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acquisition of properties from Union Oil of California (Unocal) in 2003, Forest repurchased Unocal’s 50% working interest, and Forest currently holds a 100% working interest. The property is located in approximately 75 feet of water, approximately 101 miles southeast of Cameron, Louisiana.

South Pass 24 NCOC. Forest acquired this property through its acquisition of Forcenergy Inc in 2000. Forest acquired the remaining working interest (approximately 25%) from Pogo in 2004. The property is located approximately 82 miles south of New Orleans, Louisiana in approximately 10 feet of water.

South Timbalier 72. Forest acquired this property through its acquisition of Forcenergy Inc in 2000. Redevelopment occurred in 2003, 2004 and 2005. Forest operates the property and owns working interests in individual wells ranging from 75% to 100%. The property is located in approximately 65 feet of water, approximately 100 miles southwest of New Orleans, Louisiana.

Vermillion 14. Forest acquired a 50% working interest in this property from Unocal in 2003. In 2004, Forest acquired BP’s 50% working interest and now owns a 100% working interest. The property is located in approximately 20 feet of water, approximately 63 miles southeast of New Orleans, Louisiana.

Vermillion 380. Forest acquired this property through its acquisition of Forcenergy Inc in 2000. Forest subsequently sold a 50% working interest to Unocal in 2001. As part of the Unocal acquisition in 2003, Forest repurchased Unocal’s 50% working interest. Forest operates the property and owns working interests in the individual wells ranging from approximately 55% to 100%. The property is located in approximately 320 of water, approximately 135 miles southeast of Cameron, Louisiana.

West Cameron 110. Forest acquired a 37.5% working interest in this property through its acquisition of Forcenergy Inc in 2000. BP operates the property. The property is located in approximately 320 feet of water, approximately 21 miles south of Cameron, Louisiana.

West Cameron 112. Forest acquired this property through the acquisition of Forcenergy Inc in 2000. Forest initially held a 100% working interest in the property and sold a portion of its working interest in 2003 and, as a result, Forest owns a 55% working interest. The property is located in approximately 40 feet of water, approximately 45 miles southeast of Cameron, Louisiana.

West Cameron 205. Forest acquired this property through its acquisition of Forcenergy Inc in 2000. Forest owns a 100% working interest in the property, which is located in approximately 50 feet of water, approximately 36 miles south of Cameron, Louisiana.


	*Gulf of Mexico Deepwater Property*

East Breaks 420. Forest leased three blocks located on this property in 1996, and an additional block in 1998. Forest subsequently sold a 50% working interest to Noble. The property is located in approximately 2,560 feet of water, approximately 174 miles southwest of Cameron, Louisiana.

Estimated Proved Reserves

The following tables set forth certain information with respect to the estimated proved reserves attributable to the Forest Gulf of Mexico operations as of December 31, 2004. Reserve volumes and values were estimated using 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 reserve estimates prepared by the internal staff of engineers at Forest. A substantial portion of Forest’s reserves are audited by independent petroleum engineers engaged by Forest. These reserve audits are conducted in accordance with Forest’s reserve audit procedures that require the independent reserve engineers to prepare their own independent estimates of proved reserves for fields comprising at least 80% of Forest’s year-end PV10 value of the fields, and a minimum of 80% of the PV10 value of the reserves added during the year through discoveries, extensions, and acquisitions. Forest may also include fields that fall outside of the top 80% of the PV10 value that represent material volumes of proved reserves, have experienced material revisions to prior estimates of proved reserve volumes or value,

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or have experienced changes as a result of new operational activity. Forest’s procedures prohibit exclusions of any fields, or any part of a field, that comprises part of the top 80% of the PV10 value. The independent reserve engineers then compare their estimates to those prepared by Forest. The independent reserve audits prepared for Forest are not financial audits and are not performed in accordance with the established generally accepted financial audit procedures. Instead, a reserve audit is conducted based on rules and regulations, reserve definitions and costs, and price parameters specified by the SEC.

For the year-end 2004, Forest engaged two independent petroleum engineering firms to perform reserve audit services for the properties included in the Forest Gulf of Mexico operations. Ryder Scott Company and DeGolyer and MacNaughton audited the estimates of reserves attributable to properties included in the Forest Gulf of Mexico operations. When compared on a field-by-field basis, some of Forest’s estimates of net proved reserves are greater and some are less than the estimates prepared by Forest’s independent petroleum engineers. However, there was no material difference, in the aggregate, between Forest’s internal estimates of total net proved reserves and the estimates prepared by the independent petroleum engineers.


		Estimated Proved
		Reserve Quantities

				Natural				PV10 Value(3)
		Oil		Gas		Total								Standardized
Geographic Area		(MMbbls)		(Bcf)		(Bcfe)		Developed		Undeveloped		Total		Measure

								(millions)						(millions)
Gulf of Mexico Shelf(1)			11.7		253.6		323.5	$	907.8	$	246.6	$	1,154.4
Gulf of Mexico Deepwater(2)			—		16.2		16.2		67.8		—		67.8

	Total		11.7		269.8		339.7	$	975.6	$	246.6	$	1,222.2	$	925.8

Proved Developed Reserves			9.5		201.8		258.6


(1)	Shelf refers to water depths less than 1,300 feet.

(2)	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).

(3)	Please see below for a definition of PV10 and a reconciliation of PV10 to the standardized measure of discounted future net cash flows.

Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond the control of Forest. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and the interpretation thereof. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing, and production subsequent to the date of an estimate, as well as economic factors such as change in product prices, may require revision of such estimates. Accordingly, oil and gas quantities ultimately recovered will vary from reserve estimates.

PV10 is an 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. Forest and Forest Energy Resources believe PV10 to be an important measure for evaluating the relative significance of the natural gas and oil properties included in the Forest Gulf of Mexico operations 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. Forest and Forest Energy Resources believe that most other companies in the oil and gas industry calculate PV10 on the same basis. The management of Forest and Forest Energy Resources also use PV10 in evaluating acquisition candidates.

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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

	(millions)
PV10	$	1,222.2	$	1,217.2	$	828.1
Future income taxes, discounted at 10%		296.4		267.8		180.1

Standardized measure of discounted future net cash flows	$	925.8	$	949.4	$	648.0

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 reserves and production of the Forest Gulf of Mexico operations will decline. See “Risk Factors” 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 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 the properties included in the Forest Gulf of Mexico operations, average sales price received and expenses per unit of production during the periods indicated.


			Nine Months
			Ended			Year Ended December 31,
			September 30,
			2005			2004			2003			2002

			(unaudited)
Production:
	Natural gas (Bcf)			41.4			61.7			58.8			50.6
	Oil (MMbbls)			1.8			2.6			2.1			2.0
	Natural gas liquids (MMbbls)			.6			.6			—			—
	Total natural gas equivalent (Bcfe)			56.3			81.1			71.7			62.4
Average realized sales price per unit:
	Natural gas ($/Mcf):
		Sales price received	$	7.14		$	6.30		$	5.41		$	3.39
		Effects of hedging		(1.13	)		(0.56	)		(0.63	)		0.17

		Net sales price received		6.01			5.74			4.78			3.56

	Oil ($/bbl):
		Sales price received	$	51.97		$	40.06		$	30.19		$	24.85
		Effects of hedging		(19.95	)		(8.55	)		(1.90	)		—

		Net sales price received		32.02			31.51			28.29			24.85

	Natural gas liquids ($/bbl)
		Sales price received	$	29.54		$	27.28		$	19.00		$	12.33
Average realized sales price per Mcfe (including effects of hedging) ($/Mcfe)			$	5.81		$	5.59		$	4.77		$	3.67

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		Nine Months
		Ended		Year Ended December 31,
		September 30,
		2005		2004		2003		2002

		(unaudited)
Expenses ($/Mcfe):
	Lease operating	$	1.02	$	0.99	$	0.64	$	0.83
	Transportation		0.04		0.03		0.04		0.06
	Production taxes		0.03		0.02		0.02		0.02

Productive Wells

The following table shows the number of productive oil and gas wells included in the Forest Gulf of Mexico operations in which Forest Energy Resources will own a working interest, as of December 31, 2004.


		Total
		Productive
		Wells at

		December 31,
		2004

		Gross		Net

Oil			338		163
Gas			636		366

	Total		974		529

Acreage

The following table shows the developed and undeveloped acreage included in the Forest Gulf of Mexico operations as of December 31, 2004.


		Developed Acres(1)				Undeveloped Acres(2)

Location		Gross		Net		Gross		Net

Gulf of Mexico Shelf(3)			906,448		402,094		341,976		215,675
Gulf of Mexico Deepwater(4)			11,520		5,760		46,080		40,320

	Total		917,968		407,854		388,056		255,995


(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)	Shelf refers to water depths less than 1,300 feet.

(4)	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).

At December 31, 2004, approximately 24%, 30%, and 4.4% of the net undeveloped acreage included in the Forest Gulf of Mexico operations was subject to leases that have terms that expired in 2005 and will expire in 2006 and 2007, respectively, if not extended by exploration or production activities. All of the properties that are subject to expiration terms that have not been extended by exploration or production activities are located in the Gulf of Mexico shelf.

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Drilling Activity

The following table summarizes the drilling activity performed on the oil and gas properties included in the Forest Gulf of Mexico operations during the years ended December 31, 2002, 2003, and 2004, excluding wells in which Forest Energy Resources will not have a working interest. As of December 31, 2004, there were no wells in progress involving the Forest Gulf of Mexico operations.


			Year Ended December 31,

			2004				2003				2002

			Gross		Net		Gross		Net		Gross		Net

Exploratory wells:
	Producing			11.0		6.15		4.0		2.92		1.0		0.72
	Dry holes			3.0		2.62		2.0		2.00		2.0		0.68

		Total		14.0		8.77		6.0		4.92		3.0		1.40

Development wells:
	Producing			6.0		4.37		6.0		4.20		13.0		7.30
	Dry holes			—		—		1.0		0.50		1.0		0.17

		Total		6.0		4.37		7.0		4.70		14.0		7.47

Total wells:
	Producing			17.0		10.52		10.0		7.12		14.0		8.02
	Dry holes			3.0		2.62		3.0		2.50		3.0		0.85

		Total		20.0		13.14		13.0		9.62		17.0		8.87

Title to Properties

A portion of the oil and natural gas properties included in the Forest Gulf of Mexico operations are subject to liens securing Forest’s credit facility. As a condition to the merger, these liens will be released. In addition, Forest Energy Resources’ title to these oil and gas properties will be subject to customary royalty, overriding royalty, carried, net profits, working and similar interests and liens incident to operating agreements and customary in the oil and gas industry. These properties may also be subject to liens for current taxes not yet due and other typical burdens and encumbrances. Forest does not believe that any of the burdens or encumbrances unrelated to Forest’s credit facility materially interfere with the use of such properties.

With respect to the oil and gas properties included in the Forest Gulf of Mexico operations, Forest’s general practice has been to conduct a title examination on all material property acquisitions. Further, prior to commencing drilling operations, title examination and, if necessary, curative work is performed. Forest believes that title issues generally are not as likely to arise on offshore oil and gas properties as on onshore properties, and that the methods of title examination utilized in connection with the Forest Gulf of Mexico operations are reasonable and are designed to insure that production from these operations and properties, if obtained, will be salable for Forest Energy Resources’ account.

Employees

As of February 1, 2006, approximately 120 employees currently work directly with the Forest Gulf of Mexico operations. These employees are not currently represented by any labor unions.

Offices

The business activities of the Forest Gulf of Mexico operations are conducted out of offices located in Denver, Colorado and Lafayette and Metairie, Louisiana. Forest believes that these facilities are adequate for these operations as currently conducted.

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Legal Proceedings

Forest Energy Resources currently is not a party, claimant and/or a defendant in any pending legal proceedings.


	Insurance Matters

In August and September 2005, Forest incurred damage from Hurricanes Katrina and Rita that affected certain properties and facilities included in the Forest Gulf of Mexico operations. Hurricane Katrina did not cause significant damage to the assets of the Forest Gulf of Mexico operations, although it resulted in shut-in production that has not fully recommenced, primarily as a result of damage to third-party pipeline and plants in South Louisiana. Hurricane Rita damaged third-party pipeline and gas processing plants offshore and in Louisiana and damaged a number of Forest’s offshore platforms, thereby resulting in shut-in production for the Forest Gulf of Mexico operations. The shut-in production has not fully recommenced and Forest continues to assess the damage. Until it is able to complete all investigations and the repair work and submit the costs to Forest’s insurance underwriters for review, Forest will not be able to identify the net losses and costs of the two hurricanes, but Forest currently estimates damages of approximately $50 million net to the Forest Gulf of Mexico operations. Forest carries property and casualty insurance with a $5 million deductible for each occurrence, which would indicate that approximately $40 million of the approximately $50 million in estimated damages would be reimbursed through insurance. Forest does not have insurance for losses in revenue caused by shut-in production.

For more information on the marketing and customers, competition, and environmental and other regulatory matters which would impact the Forest Gulf of Mexico operations following the merger, see “Business—Marketing and Customers,” “Business—Competition,” “Business—Regulation” and “Business—Environmental Regulations.”

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FOREST OIL CORPORATION

Following the spin-off and merger of the Forest Gulf of Mexico operations, Forest will be a long-lived onshore resource company. Forest believes the onshore resource company resulting from the spin-off and merger will provide for enhanced strategic clarity and management focus. In order to achieve its objectives as an onshore focused resource company, Forest intends to continue to pursue a modified four-point strategy that calls for continued growth through operations, pursuit of acquisition opportunities, reduced costs, and preserving financial flexibility. Forest expects to continue to conduct its operations through five business units, including the Western Business Unit, the Alaska Business Unit, a new Southern Business Unit that will conduct operations onshore in Louisiana and South Texas, the Canadian Business Unit and the International Business Unit.

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MANAGEMENT OF MARINER

Directors and Executive Officers

The board of directors of Mariner following the merger will be composed initially of seven directors, five of whom will be the current directors of Mariner and two of whom will be mutually agreed by Mariner and Forest prior to the completion of the merger.

The following table sets forth the names, ages (as of February 1, 2006) and titles of the individuals who would be the directors and executive officers of Mariner following the effective time of the merger, other than the two additional directors to be mutually agreed by Mariner and Forest prior to the completion of the merger. All directors are elected for terms in accordance with their class, as described in “—Board of Directors” below. 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		54	Chief Operating Officer
Rick G. Lester		54	Vice President, Chief Financial Officer and Treasurer
Jesus G. Melendrez		47	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		50	Vice President— Shelf and Onshore
Cory L. Loegering		50	Vice President— Deepwater
Bernard Aronson		59	Director
Jonathan Ginns		41	Director
John F. Greene		65	Director
John L. Schwager		57	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 2002, 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.

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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 October 2001 to February 2002, Mr. Hansen was self-employed as a consultant. From 1997 until March 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 27 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. Mr. Loegering has 29 years of experience in the industry.

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.

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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.

John F. Greene— Mr. Greene was elected as a director in August 2005. He served as Executive Vice President of Worldwide Exploration, Production and Natural Gas Marketing at Louisiana Land & Exploration Company before his retirement in 1995. Prior to joining Louisiana Land & Exploration Company, Mr. Greene was the President and Chief Executive Officer of Milestone Petroleum, Inc. (today, Burlington Resources, Inc.) from 1981 to 1985. Mr. Greene served on the board of directors of Colorado-Wyoming Reserves Company from 1998 through 2004 and as a director and member of the compensation committee of Basin Exploration, Inc. from 1996 through 2001. Mr. Greene began his career at Conoco and served in the United States Navy from 1963 until 1986. He is currently a partner and director of The Shoreline Company and Leaf River Resources.

John L. Schwager— Mr. Schwager was elected as a director in August 2005. Prior to his retirement in 2004, Mr. Schwager served as Chief Executive Officer and President of Belden & Blake Corporation. Before joining Belden & Blake Corporation in 1999, Mr. Schwager was the founder and served as President of AnnaCarol Enterprises, Inc., a consulting firm that provided planning, advisory, evaluation and management services to the energy industry. From 1984 until 1997 he served in several management roles, including President and Chief Executive Officer at Alamco, Inc. From 1970 through 1984, Mr. Schwager held various engineering, operations, management and executive officer positions with Callon Petroleum Company and Shell Oil Company.

Messrs. Aronson and Ginns, both of whom served on the board of managers of our former sole stockholder, MEI Acquisitions Holdings, LLC, were elected to the board in connection with the merger in March 2004 with our former sole stockholder, MEI Acquisitions Holdings, LLC. As of February 1, 2006, MEI Acquisitions Holdings, LLC is the record holder of approximately 5.3% of the outstanding common stock and ACON Investments is the beneficial owner of an additional 4.3% of the outstanding common stock. Until February 2006, Messrs. Aronson and Ginns were managers of ACON E&P. Messrs. Aronson and Ginns are managing members of ACON Investments LLC. With respect to transactions between us and MEI Acquisitions Holdings, LLC and ACON E&P, please see “Certain Transactions with Affiliates and Management of Mariner.”

Board of Directors

Under the terms of the merger agreement, the board of directors of Mariner after completion of the merger will be composed initially of seven individuals, five of whom will be the current directors of Mariner and two of whom will be mutually agreed upon by Mariner and Forest prior to the completion of the merger.

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. The Class I director’s term will expire at the annual meeting of stockholders scheduled to occur on Thursday, March 2, 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. Greene and Schwager, and the Class III directors are Messrs. Ginns and Josey. Pursuant to provisions in our certificate of incorporation regarding vacancies on the board of directors, Messrs. Greene and Schwager (in addition to Mr. Aronson, as the Class I director) must stand for reelection at the annual stockholders meeting scheduled to occur on Thursday, March 2, 2006. 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

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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 intends to establish three committees, the audit committee, the compensation committee and the nominating and corporate governance committee.

Messrs. Aronson, Ginns and Schwager will be the initial members of our audit committee. Mr. Schwager is “independent” under the listing standards of New York Stock Exchange and SEC rules. In addition, the board of directors has determined that Mr. Ginns is an “audit committee financial expert,” as defined under the rules of the SEC. Within 90 days of the effectiveness of the registration statement, at least a majority of our audit committee will be independent, and within one year all audit committee members will be independent. 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 Mariner.

Messrs. Aronson and Greene will serve on the nominating and corporate governance committee of our board of directors. Mr. Greene is “independent” under the listing standards of the New York Stock Exchange and SEC rules. 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 Mariner. Within 90 days of the effectiveness of the registration statement, at least a majority of the committee will be independent, and within one year all committee members will be independent.

Messrs. Ginns, Greene and Schwager will serve on the compensation committee of our board of directors. Messrs. Greene and Schwager are “independent” under the listing standards of the New York Stock Exchange and SEC rules. 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. Within 90 days of the effectiveness of the registration statement, at least a majority of the committee will be independent, and within one year all committee members will be independent.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serves as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of our board of directors or compensation committee.

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During the fiscal year 2005, the board of directors determined executive compensation.

Director Compensation

Officers and employees who also serve as directors will not receive additional compensation. To date, Messrs. Aronson and Ginns have not received compensation for their services as directors. Messrs. Greene and Schwager have received and will receive annual cash compensation of $40,000, and received a grant of 4,500 stock options upon their appointment to the board, which options will vest in ¹/3 increments on each of the three successive annual meetings of Mariner’s stockholders following the date of grant. In addition, each director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

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 and the four other most highly compensated executive officers for the three fiscal years ended December 31, 2005.

Summary Compensation Table


				Annual Compensation				Long-Term Compensation

								Awards				Payouts

										Securities
								Restricted Stock		Underlying		LTIP		All Other
Name and Principal Position		Year		Salary($)		Bonuses(1)($)		Awards($)(2)		Options(#)		Payouts($)		Compensation($)(3)

Scott D. Josey			2005	$	375,000	$		$	—		—	$	—	$	16,210
	Chairman of the Board,		2004		350,000		550,000		9,522,534		200,000		575,000		15,133
	Chief Executive Officer		2003		300,290		850,000		—		—		—		514,895
	and President
Dalton F. Polasek			2005		250,000				—		—		—		16,626
	Chief Operating Officer		2004		215,000		300,000		4,316,886		102,000		248,400		15,236
			2003		176,698		325,000		—		—		—		280,677
Mike C. van den Bold			2005		200,000				—		—		—		15,819
	Vice President and		2004		192,500		215,000		3,174,178		74,000		322,000		14,949
	Chief Exploration Officer		2003		170,150		350,000		—		—		—		45,430
Rick G. Lester			2005		200,000				—		—		—		16,363
	Vice President,		2004		43,352		120,000		428,512		40,000		—		3,502
	Chief Financial Officer		2003		—		—		—		—		—		—
	and Treasurer
Teresa G. Bushman			2005		200,000				—		—		—		17,197
	Vice President, General		2004		190,000		215,000		1,920,380		40,000		59,800		14,834
	Counsel and Secretary		2003		97,750		200,000		—		—		—		23,270


(1)	As of January 31, 2006, bonuses for 2005 have not yet been paid.

(2)	Dollar amounts are calculated by multiplying the number of shares of common stock awarded by $14, the trading price of our common stock on the business day immediately preceding the date the award was granted. Grantees are entitled to vote, and accrue dividends on, the restricted stock prior to vesting; provided, 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. Except in specified circumstances, the

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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”, as defined in our Equity Participation Plan; but in no event later than the second anniversary of the date of grant. Notwithstanding this 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 connection with the merger, each of Mariner’s executive officers has agreed, in exchange for a cash payment of $1,000, that his or her shares of restricted stock will not vest before the later of March 11, 2006 or ninety days after the effective date of the merger. For additional information regarding these special long-term grants, please see “—Equity Participation Plan.”


	At December 31, 2005, the value of all restricted stock held by each named executive (based on the $17.75 trading price of our common stock on December 31, 2005) was as follows:


Name	No. of Shares		Value

Scott D. Josey		680,181	$	12,073,213
Dalton F. Polasek		308,349		5,473,195
Mike C. van den Bold		226,727		4,024,404
Rick G. Lester		30,608		543,292
Teresa G. Bushman		137,170		2,434,768

(3)

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. The amounts for 2005 for Messrs. Josey, Polasek, van den Bold, and Lester and Ms. Bushman include $7,000 of employer matching contributions made pursuant to our 401(k) plan and $8,400 made pursuant to the profit sharing portion of our 401(k) plan. In addition, the 2005 amount for Mr. Josey includes $810 of insurance premiums under our group term life insurance. The 2005 amount for Mr. Polasek also includes $1,226 of insurance premiums under our group term life insurance. The 2005 amount for Mr. van den Bold also includes $419 of insurance premiums under our group term life insurance. The 2005 amount for Mr. Lester also includes $963 of insurance premiums under our group term life insurance. The 2005 amount for Ms. Bushman includes $1,797 of insurance premiums under our group term life insurance.

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.

Under the employment agreements, the officers are entitled to the following 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 18 months of salary continuation (two years for Mr. Josey and Mr. Polasek) at the highest rate in effect prior to termination, (ii) health care coverage for a period of eighteen months (two years for Mr. Josey and Mr. Polasek), (iii) an amount equal to the sum of all bonuses paid to the officer in the year prior to the year in which termination occurs, (iv) 100% vesting of all restricted shares under our Equity Participation Plan, and (v) 50% vesting of all other rights under any other equity plans, including our Stock Incentive Plan.

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The executive officers of Mariner will receive cash payments of $1,000 each in exchange for the waiver of certain rights under their employment agreements, including the automatic vesting or acceleration of restricted stock and options upon the completion of the merger and the right to receive a lump sum cash payment if the officer voluntarily terminates employment without good reason within nine months following the completion of the merger.

The agreements also include confidentiality and non-solicitation provisions.

Overriding Royalty Arrangements

Mariner’s geologist and geophysicist employees are eligible to participate in Mariner’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. Certain of the Forest Gulf of Mexico leases not covering developed or undeveloped reserves may become burdened by ORRIs under the plan as determined by such committee in accordance with the terms of the plan. None of the members of the committee is eligible to participate in the plan.

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 nine 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 Mariner as officers and consultants but were not employed by Mariner. No payments were made in respect of these ORRIs until 2004, when each received less than $60,000 with respect to his ORRI.

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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 2005, 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
Dalton F. Polasek		308,349		4,316,886
Mike C. van den Bold		226,727		3,174,178
Rick G. Lester		30,608		428,512
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;

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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 connection with the merger, each of Mariner’s executive officers has agreed, in exchange for a cash payment of $1,000, that his or her shares of restricted stock will not vest before the later of March 11, 2006 or ninety days after the effective date of the merger.

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, which became effective March 11, 2005. The objectives of the Stock Incentive Plan are to encourage employees and directors to acquire or increase their equity interest with Mariner and to provide a means whereby they may develop a sense of proprietorship and personal involvement in the development and financial success of Mariner. The Stock Incentive Plan is also designed to enhance Mariner’s ability to attract and retain the services of individuals who are essential for the growth and profitability of Mariner. We have proposed to amend and restate the Stock Incentive Plan to add 4.5 million shares of common stock to the plan, to extend the plan through October 12, 2015, and to limit the number of shares subject to stock options or shares of restricted stock issuable under the plan to any individual to 2.85 million, subject to the completion of the merger.

Awards to participants under the Stock Incentive Plan may be made in the form of incentive stock options, or ISOs, non-qualified stock options or restricted stock. The participants to whom awards are granted, the type or types of awards granted to a participant, the number of shares covered by each award, the purchase price, conditions and other terms of each award are determined by the Board of Directors or the committee appointed by the Board of Directors to administer the Stock Incentive Plan (the “Committee”).


	*Shares Subject to the Stock Incentive Plan*

At the inception of the Stock Incentive Plan, a maximum of two million shares of common stock of Mariner could be issued to participants. Pursuant to the proposed addition of shares to the Stock Incentive Plan, the maximum number of shares would, if the proposal is approved, be increased to 6.5 million shares. As of September 30, 2005, approximately 1.2 million shares remained available under the Stock Incentive Plan for future issuance to participants.

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	*Administration and Eligibility*

The Committee has the authority to administer the Stock Incentive Plan and to take all actions that are specifically contemplated by the Stock Incentive Plan or are necessary or appropriate in connection with the administration of the Stock Incentive Plan. The Committee has the full power and authority to designate participants, determine the type or types of awards, the number of shares to be covered by awards, and the terms and conditions of any award. The Committee also determines whether, to what extent, and under what circumstances awards may be settled or exercised in cash, shares or other securities, other awards or other property, or canceled, forfeited or suspended and the method or methods by which awards may be settled, exercised, canceled, forfeited or suspended. The Committee has the authority to establish, amend, suspend or waive such rules and regulations, and appoint such agents as it shall deem appropriate, and make any other determination or take any other action the Committee deems necessary for the proper administration of the Stock Incentive Plan.

Any employee of Mariner (or any parent entity or subsidiary) and any non-employee director of Mariner is eligible to be designated a participant by the Committee. As of December 31, 2005, two non-employee directors and 51 employees had been granted awards under the Stock Incentive Plan.


	*Awards*

Awards may, in the discretion of the Committee, be granted either alone or in addition to, or in tandem with, any other award granted under the Stock Incentive Plan or any award granted under any other plan of Mariner or any parent entity or subsidiary. Awards granted in addition to or in tandem with other awards or awards granted under any other plan of Mariner or any parent entity or subsidiary may be granted either at the same time as or at a different time from the grant of such other awards. All or part of an award may be subject to conditions established by the Committee.

The types of awards to participants that may be made under the Stock Incentive Plan are as follows:

Options. Options are rights to purchase a specified number of shares of common stock at a specified price. The Committee will determine the participants to whom options are granted, the number of shares to be covered by each option, the purchase price and the conditions, which of the options is an ISO or a non-qualified stock option, and limitations applicable to the exercise of the option. To the extent that the aggregate fair market value, determined at the time the respective ISO is granted, of common stock with respect to which ISOs are exercisable for the first time by an individual during any calendar year under all incentive stock option plans of Mariner and its parent and subsidiary corporations exceeds $100,000, or such option fails to constitute an ISO for any reason, such purported ISOs will be treated as non-qualified stock options.

ISOs may be granted only to an individual who is an employee of Mariner or any parent or subsidiary corporation at the time the option is granted. The Committee determines the exercise price at the time each option is granted, but the exercise price shall never be less than the fair market value per share on the effective date of such grant. The Committee determines the time or times at which each option may be exercised, the method or methods by which, and the form or forms in which, payment of the exercise price may be made or deemed to have been made.

An ISO must be granted within 10 years from the date the Stock Incentive Plan was approved by the Board or the shareholders, whichever is earlier. No ISO shall be granted to an individual if, at the time the ISO is granted, such individual owns stock possessing more than 10% of the total combined voting power of all classes of stock of Mariner or of its parent or subsidiary corporation, unless


	•	at the time the ISO is granted, the option price is at least 110% of the fair market value of the common stock subject to the option and

	•	such ISO, by its terms, is not exercisable after the expiration of five years from the date of grant.

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Options are not transferable, other than by will or the laws of descent and distribution, and are exercisable during the participant’s lifetime only by the participant or the participant’s guardian or legal representative.

Restricted Stock. Restricted stock is stock that has limitations placed on it. Dividends paid on restricted stock may be paid directly to the participant, sequestered and held in a bookkeeping account, or reinvested in additional shares, which may be subject to the same restrictions as the underlying award or other restrictions, as determined by the Committee. Restricted stock is evidenced in such manner as deemed appropriate by the Committee, but any stock certificate that is issued in respect of restricted stock granted under the Stock Incentive Plan must be registered under the participant’s name and bear an appropriate legend referring to the terms, conditions and restrictions applicable to the restricted stock.

Unless otherwise determined by the Committee or provided in an award agreement, upon termination of a participant’s employment for any reason during the applicable restricted period, which is the period established by the Committee with respect to an award during which the award either remains subject to forfeiture or is not transferable by the participant, all restricted stock is forfeited without payment and reacquired by Mariner. The Committee may waive in whole or in part any or all remaining restrictions on such participant’s restricted stock, but if such award was intended to qualify as performance-based compensation, then only upon an event permitted under Section 162(m) of the Internal Revenue Code. Restricted stock is subject to such limitations on transfer as are necessary to comply with Section 83 of the Internal Revenue Code.


	*Other Provisions*

Unless sooner terminated, no award may be granted under the Stock Incentive Plan after October 12, 2015. The Board or the Committee may amend, alter, suspend, discontinue or terminate the Stock Incentive Plan without the consent of any stockholder, participant, other holder or beneficiary of an award or any other person. However, no amendment may materially adversely affect the rights of a participant under an award without the consent of such participant.

In the event of any distribution, recapitalization, reorganization, merger, spin-off, split-off, split-up, consolidation, combination, repurchase, or exchange of shares or other securities of Mariner or any other relevant corporate transaction or event or any unusual or nonrecurring transactions or events affecting Mariner, the Committee may, in its sole discretion and on such terms and conditions as it deems appropriate:


	•	provide for either the termination of any such award in exchange for cash in the amount that would have been attained upon the exercise of such award or the replacement of such award with other rights or property selected by the Committee;

	•	provide that such award be assumed by the successor or survivor corporation or its parent or be substituted for by similar options, rights or awards; or

	•	make adjustments in the number and type of shares or other property subject to outstanding awards.


	*Stock Incentive Plan Benefits*

Because the granting of awards under the Stock Incentive Plan is at the discretion of the Committee, it is not now possible to determine which persons may be granted awards. Also, it is not now possible to estimate the number of shares of common stock that may be awarded under the Stock Incentive Plan.


	*U.S. Federal Tax Consequences*

The following is a general discussion of the current Federal income tax consequences of awards under the Stock Incentive Plan to participants who are classified as U.S. residents for Federal income tax purposes. Different or additional rules may apply to participants who are subject to income tax in a foreign

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jurisdiction and/or are subject to state or local income tax in the United States. Each participant should rely on his or her own tax advisors regarding federal income tax treatment under the Stock Incentive Plan.


	*Restricted Stock*

The grant of restricted stock does not result in taxable income to the participant. At each vesting event, the participant will recognize taxable ordinary income equal to the excess of the fair market value of the shares of common stock that become vested over the purchase price (if any) paid for such common stock. However, if a participant makes a timely election under Section 83(b) of the Internal Revenue Code, the participant will recognize taxable ordinary income in the taxable year of the grant equal to the excess of the fair market value of the shares of common stock underlying the restricted stock award at the time of the grant over the purchase price (if any) paid for such common stock. Furthermore, the participant will not recognize ordinary income on such restricted stock when it subsequently vests.

In all cases, the participant’s ordinary income is subject to applicable withholding taxes. Mariner will be allowed an income tax deduction in the taxable year the participant recognizes ordinary income, in an amount equal to such ordinary income.


	*Stock Options*

The grant of a non-qualified stock option will not result in taxable income to the participant and Mariner will not be entitled to an income tax deduction. Upon the exercise of a non-qualified stock option, a participant will realize ordinary taxable income on the date of exercise. Such taxable income will equal the difference between the option price and the fair market value of the common stock purchased under option on the date of exercise. Mariner will be entitled to an income tax deduction equal to the amount included in the participant’s ordinary income.

Upon the grant or exercise of an ISO, a participant will not recognize taxable income and Mariner will not be entitled to an income tax deduction. However, the exercise of an ISO will result in an amount being included in the participant’s alternative minimum taxable income for the year in which the exercise occurs equal to the excess of the fair market value of the common stock purchased under the ISO at the time of exercise over the option price.

The optionee will recognize taxable income in the year in which the shares of common stock underlying the ISO are sold or disposed of. Dispositions are divided into two categories: qualifying and disqualifying. A qualifying disposition occurs if the sale or disposition is made more than two years from the option grant date and more than one year from the exercise date. If the participant sells or disposes of the shares of common stock in a qualifying disposition, any gain recognized by the participant on such sale or disposition will be a long-term capital gain.

If either of the two holding periods described above are not satisfied, then a disqualifying disposition will occur. If the optionee makes a disqualifying disposition of the shares of common stock that have been acquired through the exercise of the option, then the optionee will have ordinary taxable income for the taxable year in which the sale or disposition occurs equal to the lesser of:


	•	the excess of the fair market value of such shares on the option exercise date over the exercise price paid for the shares, or

	•	the amount realized on the sale or disposition over the exercise price paid for the shares.

If the optionee makes a qualifying disposition, Mariner will not be entitled to an income tax deduction. However, if the optionee makes a disqualifying disposition, Mariner will be entitled to an income tax deduction equal to the amount included in ordinary income to the participant.

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The table below includes information regarding stock options under the Stock Incentive Plan granted in our last fiscal year to our chief executive officer and our four other most highly compensated executive officers.

Option Grants in Last Fiscal Year


										Potential Realizable
										Value of Assumed
										Annual Rates of Stock
										Price Appreciation for
			% of Total Options							Option Term (a)
	No. of Securities		Granted to Employees			Exercise		Expiration
Name	Underlying Options		in Fiscal Year			Price		Date		5%($)		10%($)

Scott D. Josey		200,000		24.7	%	$	14.00		3/11/2015	$	1,760,905	$	4,462,479
Dalton F. Polasek		102,000		12.6			14.00		3/11/2015		898,062		2,275,864
Mike C. van den Bold		74,000		9.1			14.00		3/11/2015		651,535		1,651,117
Rick G. Lester		40,000		4.9			14.00		3/11/2015		352,181		892,496
Teresa G. Bushman		40,000		4.9			14.00		3/11/2015		352,181		892,496


	(a)	In accordance with SEC rules, these columns show gain that could accrue for the listed options, assuming that the market price per share of our common stock appreciates from the date of grant over a period of 10 years at an annualized rate of 5% and 10%, respectively. If the stock price does not increase above the exercise price at the time of exercise, the realized value from these options will be zero.

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SECURITY OWNERSHIP OF CERTAIN

BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth information as of February 8, 2006 with respect to the beneficial ownership of Mariner’s 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 of
Name of Beneficial Owner	Amount(1)		Class(2)

5% Stockholder:
FMR Corp.(3)		5,002,200		13.9	%
SAB Capital Advisors, L.L.C.(4)		2,255,700		6.3	%
ACON E&P, LLC(5)		1,895,630		5.3	%
Officers and Directors(6):
Scott D. Josey(7)		746,848		2.1	%
Dalton F. Polasek(8)		342,349		*
Mike C. van den Bold(9)		251,394		*
Rick G. Lester(10)		43,942		*
Teresa G. Bushman(10)		150,504		*
Bernard Aronson(11)		3,405,207		9.5	%
Jonathan Ginns(12)		3,405,207		9.5	%
John F. Greene(13)		1,500		*
John L. Schwager(13)		1,500		*
Executive officers and directors as a group (12 persons)		5,406,491		15.1	%


	*	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. Also includes shares issuable upon exercise of options held by certain of the indicated persons to the extent the options vest in the next 60 days.

	(2)	Includes shares issuable upon exercise of options held by employees and directors to the extent the options vest in the next 60 days.

	(3)	Of the amount shown, 1,847,200 shares are held by Fidelity Contrafund, 1,831,700 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, 200,000 shares are held by Fidelity Securities Fund: Fidelity Small Cap Value Fund, 75,000 shares are held by Fidelity Securities Fund: Fidelity Small Cap Growth 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.

	(4)	The address of SAB Capital Advisors, L.L.C. is 712 Fifth Avenue, 42nd Floor, New York, New York 10019. Of the amount shown, 1,098,083 shares are held by SAB Capital Partners, L.P. and 1,157,617 shares are held by SAB Overseas Master Fund, L.P.

	(5)	The address of ACON E&P, LLC is c/o ACON Investments LLC, 1133 Connecticut Avenue, N.W., Suite 700, Washington, D.C. 20036. The shares beneficially owned by ACON E&P, LLC are held of record by MEI Acquisitions Holdings, LLC.

	(6)	The address of each officer and director is c/o Mariner Energy, Inc., One BriarLake Plaza, Suite 2000, 2000 West Sam Houston Parkway South, Houston, Texas 77042.

168


	(7)	Includes 66,667 shares issuable upon exercise of an option that vests as to these shares on March 11, 2006.

	(8)	Includes 34,000 shares issuable upon exercise of an option that vests as to these shares on March 11, 2006.

	(9)	Includes 24,667 shares issuable upon exercise of an option that vests as to these shares on March 11, 2006.


(10)	Includes 13,334 shares issuable upon exercise of an option that vests as to these shares on March 11, 2006.

(11)	Mr. Aronson may be deemed to be a beneficial owner of 1,895,630 shares and 1,509,577 shares that are beneficially owned by ACON E&P, LLC and ACON Investments LLC, respectively. MEI Investment Holdings, LLC is the record holder of the shares beneficially owned by ACON Investments LLC. Mr. Aronson is a manager of ACON E&P, LLC and a managing member of ACON Investments LLC, the managing member of MEI Investment Holdings, 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 700, Washington, D.C. 20036.

(12)	Mr. Ginns may be deemed to be a beneficial owner of 1,895,630 shares and 1,509,577 shares that are beneficially owned by ACON E&P, LLC and ACON Investments LLC, respectively. MEI Investment Holdings, LLC is the record holder of the shares beneficially owned by ACON Investments LLC. Mr. Ginns is a managing member of Burns Park Investments LLC, a manager of ACON E&P, LLC. Mr. Ginns is a managing member of ACON Investments LLC, the managing member of MEI Investment Holdings, LLC. Mr. Ginns disclaims beneficial ownership of these shares except to the extent of his pecuniary interest therein. Mr. Ginn’s address is c/o ACON Investments, LLC, 1133 Connecticut Avenue, N.W., Suite 700, Washington, D.C. 20036.

(13)	Includes shares that will be issuable upon exercise of an option that will vest as to these shares upon the date of Mariner’s next annual stockholders meeting, which is scheduled to occur on March 2, 2006.

169

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 C/R Energy Partners and ACON E&P received aggregate fees in the amount of $2.5 million. 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 E&P, 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 E&P 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 2005 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 $0.8 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. Some of the shares reflected in the following table were issued as restricted stock to our employees pursuant to our Equity Participation Plan.

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 February 8, 2006. The selling stockholders identified below may have sold, transferred or

170

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	%
ACON Investments LLC(2)		1,509,577		4.24	%
Acorn Overseas Securities Co		2,600		*
Alexander, Leslie		570,000		1.62	%
Alexandra Global Master Fund, Ltd		300,000		*
Alexis A. Shehata-Personal Portfolio		1,840		*
Allied Funding, Inc.		17,000		*
America		40,000		*
Anderson, William J.(3)		22,673		*
Anima S.G.R.P.A.		112,000		*
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 ID Fund LP		875		*
Atlas Capital (Q.P.), L.P.		50,809		*
Atlas Capital Master Fund Ltd.		107,846		*
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		9,315		*
Axia Partners Qualified, LP		95,739		*
Axia Partners, LP		42,136		*
Baker-Hazel Funeral Home, Inc.-401(k) Plan		550		*
Baker-Hazel Funeral Home-Corporate Investment Fund		330		*
Banks, Michael R.(3)		7,935		*
Basso Fund Ltd.		21,100		*
Basso Multi-Strategy Holding Fund Ltd		78,700		*
Basso Private Opportunities Holding Fund Ltd.		40,800		*
BBT Fund, L.P.		505,811		1.42	%
BBVA		321,429		*

171


			Percentage of
	Number of Shares of		Common
	Common Stock That		Stock
Selling Stockholder	May Be Sold		Outstanding

Beach, Patrick & Christine JTWROS		6,666		*
Bear Stearns Sec. Corp. Cust. FBO Emerson Partners		50,000		*
Bear Stearns Sec. Corp. Cust. FBO J. Steven Emerson IRA R/O II		720,000		2.02	%
Bear Stearns Sec. Corp. Cust. FBO J. Steven Emerson Roth IRA		420,000		1.18	%
Bear Stearns Sec. Corp. Cust. FBO J. Steven Emerson		186,000		*
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		44,150		*
BLT Enterprises, LLLP-Partnership		1,100		*
Blueprint Partners, L.P.		20,000		*
Borman, Casey J.		5,000		*
Boston Partners Asset Management, LLC(4)		536,115		1.51	%
Bradley J. Hausfeld-IRA		400		*
Brady Retirement Fund L.P.		27,500		*
Brunswick Master Pension Trust		23,600		*
Calm Waters Partnership		201,500		*
Campbell, Thomas M.(3)		46,932		*
Canyon Capital Balanced Equity Master Fund, Ltd(4)		71,429		*
Canyon Value Realization Fund (Cayman) Ltd.(4)		500,000		1.40	%
Canyon Value Realization Fund L.P.(4)		121,428		*
Canyon Value Realization MAC- 18 Ltd(4)		7,143		*
Cap Fund, L.P.		185,619		*
Carmine and Wendy Guerro Living Trust-U/ A DTD 7/31/2000-C Guerro and W Guerro, TTEES		1,080		*
Carmine Guerro-IRA Rollover		2,090		*
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		*
Carter, Debra R.(3)		5,441		*
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.		6,434		*
Caxton International Limited(4)		714,200		2.01	%
Ceisel, Charles B		1,500		*
Chamberlain Investments Ltd.		18,794		*
Charles L. & Miriam L. Bechtel-Joint Personal Portfolio		450		*
Cheyne Special Situations Fund LP		757,000		2.13	%
Chimermine, Lawrence		2,000		*
Christine Hausfeld-IRA		160		*
Christopher M. Ruff-IRA Rollover		200		*
Cindu International Pension Fund		2,900		*
Citi Canyon Ltd.(4)		7,143		*
Clam Partners, LLC		70,000		*

172


			Percentage of
	Number of Shares of		Common
	Common Stock That		Stock
Selling Stockholder	May Be Sold		Outstanding

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		*
Davis, John L.(3)		17,005		*
DB AG London(4)		53,571		*
Deanne W. Joseph-IRA Rollover		370		*
Deephaven Event Trading Ltd.(4)		1,176,135		3.30	%
Deephaven Growth Opportunities Trading Ltd.(4)		481,770		1.35	%
Delaware Street Capital Master Fund, L.P.		1,210,750		3.40	%
Dickerson, Estelle E.(3)		7,935		*
Dinger, Blaine E.(3)		17,005		*
Dominguez, Melissa D.(3)		3,173		*
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, L.P.		53,929		*
Duke, James A.(3)		10,203		*
Edenworld International Ltd.		9,636		*
Edison Sources Ltd.		33,600		*
Edward W. Eppley-IRA — SEP		600		*
Edwards, Susan R.(3)		5,895		*
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	%

173


			Percentage of
	Number of Shares of		Common
	Common Stock That		Stock
Selling Stockholder	May Be Sold		Outstanding

Emerson, J. Steven Roth IRA		400,000		1.12	%
Empyrean Capital Fund		96,250		*
Empyrean Capital Overseas Benefit Plan Fund, Ltd.		18,462		*
Empyrean Capital Overseas Fund, Ltd.		160,288		*
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		*
Evan L. Julber-IRA		9,000		*
Excelsior Value and Restructuring Fund		1,500,000		4.21	%
Farallon Capital Institutional Partners II, L.P.		5,400		*
Farallon Capital Institutional Partners III, L.P.		6,400		*
Farallon Capital Institutional Partners, L.P.		65,600		*
Farallon Capital Offshore Investors, Inc.		124,006		*
Farallon Capital Offshore Investors II, L.P.		61,994		*
Farallon Capital Partners, L.P.		99,086		*
Farvane Limited		2,617		*
FBO Marjorie G. Kasch-U/ A/ D 3/21/80-Thomas A. Holton TTEE		700		*
Fidelity Contrafund(5)		1,847,200		5.19	%
Fidelity Management Trust Company on behalf of accounts managed by it(6)		4,400		*
Fidelity Puritan Trust: Fidelity Balanced Fund(5)		516,300		1.45	%
Fidelity Puritan Trust: Fidelity Low-Priced Stock Fund(5)		1,831,700		5.14	%
Fidelity Securities Fund: Fidelity Small Cap Growth Fund(5)		75,000		*
Fidelity Securities Fund: Fidelity Small Cap Value Fund(5)		200,000		*
Fisher, William F.(3)		56,682		*
Flagg Street Offshore, LP		103,538		*
Flagg Street Partners LP		34,345		*
Flagg Street Partners Qualified LP		37,117		*
Fleet Maritime, Inc.		33,139		*
Folksam		35,000		*
Fondo America		40,000		*
Fondo Attivo		17,000		*
Fondo Trading		55,000		*
Fort Mason Master, L.P.		501,829		1.41	%
Fort Mason Partners, L.P.		33,171		*
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		*
George & Carol V. Hicks Joint Personal Portfolio		30		*
Gerald Allen-IRA		420		*
Gerald E. & Deanne W. Joseph-Combined Portfolio		1,180		*
Gerald J. Allen-Personal Portfolio		3,580		*
GLG Market Neutral Fund		178,570		*
GLG North American Opportunity Fund		850,000		2.39	%

174


			Percentage of
	Number of Shares of		Common
	Common Stock That		Stock
Selling Stockholder	May Be Sold		Outstanding

Global Capital Ltd.		20,000		*
GMI Master Retirement Trust		33,395		*
Goins, Rebecca L.(3)		5,441		*
Goldman Sachs & Co., Inc.(4)		317,756		*
Goldstein, Robert B. & Candy K		4,000		*
Gracie Capital International		75,000		*
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		15,140		*
Guggenheim Portfolio Company LLC		40,000		*
Guggenheim Portfolio Company XII LLC		35,700		*
H. Joseph & Rosemary Wood-Joint Personal Portfolio		880		*
Hagan, Dawn E.(3)		5,895		*
Hancock, David H		13,300		*
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		*
Hartley, Steven C.(3)		2,267		*
HCM Energy Holdings LLC		78,571		*
HedgEnergy Master Fund LP		120,000		*
HFR HE Systematic Master Trust		28,500		*
Highbridge Event Driven/ Relative Value Fund, L.P.(4)		98,702		*
Highbridge Event Driven/ Relative Value Fund, Ltd(4)		760,441		2.14	%
Highbridge International LLC(4)		671,428		1.89	%
Highland Equity Focus Fund, LP		70,000		*
Highland Equity Fund, LP		30,000		*
HSBC Guyerzeller Trust Company		12,630		*
Hsien-Ming Meng-IRA Rollover		990		*
Idnani, Rajesh		7,500		*
Institutional Benchmarks Master Fund, Ltd(4)		7,143		*
Ironman Energy Capital, L.P.		70,000		*
James R. Goldstein-Personal Portfolio		570		*
Jan Munroe Trust(4)		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 & Betty Eubel-Combined Portfolio		5,100		*
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		*

175


			Percentage of
	Number of Shares of		Common
	Common Stock That		Stock
Selling Stockholder	May Be Sold		Outstanding

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 F. Carroll-IRA—SEP		130		*
John H. Lienesch-IRA		2,080		*
John Hancock Funds II		37,240		*
John Hancock Trust		41,800		*
John M. Walsh, Jr.-IRA Rollover		980		*
John O’Meara-IRA Rollover		400		*
John T. Dahm-IRA		1,870		*
Johnson, Richard J.		10,000		*
Johnson Revocable Living Trust		10,000		*
Jon D. and Linda W. Gruber Trust		15,100		*
Jon R. Yenor-IRA Rollover		910		*
Jon R. Yenor & Caroline L. Breckner-Joint Tenants		1,230		*
Joseph D. Maloney-Personal Portfolio		810		*
Joseph F. & Mary K. Scullion-Combined Portfolio		1,400		*
Josey, Scott D.(7)		680,181		1.91	%
Judith Keasel-IRA Rollover		340		*
Julber, Evan L		4,000		*
Kandythe J. Miller-Combined 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		*
Koehler, Anne C.(3)		14,737		*
Lagunitas Partners LP		69,760		*
Lamb Partners LP		165,600		*
Lanza III, Nick(3)		7,935		*
Larry & Marilyn Lehman-Combined Portfolio		1,600		*
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		*
Lester, Ricky G.(7)		30,608		*
Linda M. Meister-Personal Portfolio		1,000		*
LJB Inc. Savings Plan & Trust-U/ A DTD 1/1/1985 FBO T. Beach-Stephen D. Williams TTEE		490		*
Loegering, Cory L.(7)		124,700		*
Long, Annette R.(3)		7,482		*
Loyola University Employee’s Retirement Plan Trust		8,400		*
Loyola University of Chicago Endowment Fund		8,450		*

176


				Percentage of
		Number of Shares of		Common
		Common Stock That		Stock
Selling Stockholder		May Be Sold		Outstanding

MA Deep Event, Ltd.(4)			114,095		*
Magnetar Capital Master Fund, L.P.			90,000		*
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		*
McClung, Emily R.(3)			9,069		*
McCullough, Michael C.(3)			19,272		*
Melodee Ruffo-Combined 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-Combined 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		*
Molohon, Richard A.(3)			56,682		*
Monte R. Black-Personal Portfolio			5,380		*
Morgan Stanley & Co. Incorporated(4)			500,000		1.40	%
Muellenberg, Jerry L.(3)			6,802		*
Mulholland Fund, L.P.			13,800		*
Micro-Cap Equity Fund(4)			144,000		*
Neal L. & Kandythe J. Miller-Joint Personal Portfolio			560		*
Neal L. Miller-IRA Rollover			270		*
Neelam Idnani Julian			7,500		*
Nemeth, Denise A.(3)			13,604		*
Northwestern Mutual Life Insurance(4)			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, LP			224,000		*
Passport Master Fund II, LP			176,000		*

177


			Percentage of
	Number of Shares of		Common
	Common Stock That		Stock
Selling Stockholder	May Be Sold		Outstanding

Patricia A. Kremer Revocable Trust -DTD 4/29/04-Donald G. Kremer, TTEE		1,250		*
Patricia Meyer Dorn-Personal Portfolio		2,800		*
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		*
Peter & Noreen McInnes-Combined Portfolio		8,800		*
Peter D. Senkiw-Revocable Living Trust DTD 11/02/98-Peter D. Senkiw, TTEE		320		*
Peter R. Newman-IRA Rollover		2,430		*
Philip M. Haisley-IRA Rollover		330		*
Plemons, Melanie O.(3)		6,802		*
Poole, Richard A.(3)		9,069		*
Precept Capital Master Fund, G.P		20,000		*
Presidio Partners		127,500		*
Prism Partners I, L.P.		114,782		*
Prism Partners II Offshore Fund		42,857		*
Prism Partners III Leveraged L.P.		137,738		*
Prism Partners IV Leveraged Offshore Fund		160,694		*
Producers-Writers Guild of America		11,700		*
Rae, Rita-Roxanne R.(3)		9,069		*
Raymond W. Lane-Personal Portfolio		1,700		*
Raytheon Company Combined DB/ DC Master Trust		23,000		*
Raytheon Master Pension Trust		96,100		*
Rebecca A. Nelson-IRA Rollover		1,200		*
Reed, Sammy D.(3)		13,604		*
Renee D. Ciferri-IRA Rollover		410		*
Richard D. Smith-Combined Portfolio		1,300		*
Richard H. LeSourd, Jr.-IRA—SEP		1,200		*
Richard, Karen A.(3)		9,069		*
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		*
Russell, Gregory D.(3)		1,134		*
Ruth E. Kremer Revocable Living Trust-DTD 5/7/96-David R. Kremer & Ruth E. Kremer, TTEES		830		*
SAB Capital Partners, L.P.		1,098,083		2.98	%
SAB Overseas Master Fund, L.P.		1,157,617		3.25	%
Sandra E. Nischwitz-Personal Portfolio		1,240		*
Savannah International Longshoremen’s Association Employers Pension Trust		10,200		*
Seneca Capital International Ltd		446,200		1.25	%

178


			Percentage of
	Number of Shares of		Common
	Common Stock That		Stock
Selling Stockholder	May Be Sold		Outstanding

Seneca Capital LP		215,400		*
Seneca Capital II LP		1,100		*
Settegast, Cynthia L.(3)		7,482		*
SF Capital Partners Ltd(4)		224,500		*
Sharon A. Lowry-IRA-Robert W. Lowry, POA		1,560		*
Sisters of St. Joseph Carondelet		4,700		*
Slovin, Bruce		10,000		*
Sniper Fund		3,300		*
Sound Energy Capital Offshore Fund, Ltd.		41,900		*
Soundpost Partners, LP		9,000		*
Southport Energy Plus Offshore Fund, Inc.		139,300		*
Southport Energy Plus Partners L.P.		318,800		*
Sprain, Janet E.(3)		8,389		*
Spring Street Partners L.P.		40,000		*
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		*
Steven M. Rebecca A. Nelson-Combined Portfolio		1,200		*
Susan J. Gagnon-Revocable Living Trust UA 8/30/95-Susan J. Gagnon TTEE		2,100		*
Talkot Fund, L.P.		40,000		*
Tanya P. Hrinyo Pavlina-Revocable Trust DTD 11/21/95-Tanya P. Hrinyo Pavlina TTEE		1,200		*
Tetra Capital Partners, LP		8,000		*
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 Edward W. & Frances L. Eppley-Combined Portfolio		600		*
The Johnson Irrevocable Living Trust DTD May 1998		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.		1,800		*
TNM Investments LTD-Partnership		310		*
Touradji Global Resources Master Fund, Ltd.		497,000		1.40	%
Town of Darien Employee Pension		3,300		*
Town of Darien Police Pension		2,900		*
TPG-Axon Partners (Offshore), Ltd		768,783		2.16	%
TPG-Axon Partners, LP		495,017		1.39	%
Treaty Oak Ironwood		74,295		*
Treaty Oak Master Fund		59,235		*

179


			Percentage of
	Number of Shares of		Common
	Common Stock That		Stock
Selling Stockholder	May Be Sold		Outstanding

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		*
Van den Bold, Michiel C.(7)		226,727		*
Variable Insurance Products Fund II: Contrafund Portfolio(2)		527,600		1.48	%
Verizon		122,700		*
Verle McGillivray-IRA Rollover		680		*
Victoire Finance et Aestion BV		35,714		*
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		*
Wooster Capital, LP		33,500		*
Wooster Offshore Fund, Ltd.		70,000		*
York Capital Management, L.P.		119,058		*
York Credit Opportunities Fund L.P.		97,046		*
York Global Value Partners, L.P.		122,363		*
York Investment Limited		528,684		1.48	%
York Select Unit Trust		103,376		*
York Select, L.P.		124,473		*
Yvette Van de Grift-Personal Portfolio		220		*
Zelin, Leonard IRA		40,000		*

180


	*	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 shares beneficially owned by ACON Investments LLC are held of record by MEI Investment Holdings, LLC. See “Certain Transactions with Affiliates and Management.”

(3)	Employee of Mariner.

(4)	Broker-dealer or an affiliate of a broker-dealer.

(5)	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 4,997,800 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.

(6)

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.


(7)	Executive officer of Mariner.

181

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 with respect to securities sold by them pursuant to this prospectus. 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.

182

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. The maximum amount of compensation to be received by any participating NASD member will not exceed 8% of the total proceeds of the offering.

Our common stock has been approved for listing on the New York Stock Exchange, subject to the completion of the proposed merger with Forest Energy Resources, Inc. 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.

183

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. If the proposed amendment to Mariner’s certificate of incorporation is approved by the Mariner stockholders, the authorized capital stock of Mariner would consist of 180 million shares of common stock and 20 million shares of preferred stock.

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 809,000 of which have been granted to certain of our employees and directors. Pursuant to the proposed addition of shares to the Stock Incentive Plan, the maximum number of shares would, if the proposal is approved, be increased to 6.5 million shares. 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.

184

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, Mariner 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.

185


	*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.


	*Advance 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 Mariner’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 Mariner 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 Mariner 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 Mariner or prohibit Mariner 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.

186

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.

187

REGISTRATION RIGHTS

We entered into a registration rights agreement in connection with our 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,

188


		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 New York Stock Exchange, 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.

189

EXPERTS

The consolidated financial statements of Mariner Energy, Inc. as of December 31, 2004 (Post-2004 Merger), December 31, 2003 (Pre-2004 Merger) and for the period from January 1, 2004 through March 2, 2004 (Pre-2004 Merger), for the period from March 3, 2004 through December 31, 2004 (Post-2004 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 Mariner’s parent) included in this prospectus, and has been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The statements of revenues and direct operating expenses of the Forest Gulf of Mexico operations for each of the years in the three-year period ended December 31, 2004 have been included herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere in this prospectus, and upon the authority of such firm 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 Mariner 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.

LEGAL MATTERS

The validity of the shares of Mariner common stock offered pursuant to this prospectus will be passed upon by Baker Botts L.L.P.

190

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.

Deep shelf well. A well drilled on the outer continental shelf to subsurface depths greater than 15,000 feet.

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

191

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.

192

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. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the website at http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.

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. This definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the website at http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.

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. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the website at http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.

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.

193

INDEX TO FINANCIAL STATEMENTS


MARINER ENERGY, INC.
	Report of Independent Registered Public Accounting Firm	F-2
	Balance Sheets at September 30, 2005 (unaudited), December 31, 2004 and 2003	F-3
	Statements of Operations for the nine months ended September 30, 2005 (unaudited); the period from March 3, 2004 through September 30, 2004 (unaudited); the period from March 3, 2004 through December 31, 2004; the period from January 1, 2004 through March 2, 2004; and the years ended December 31, 2003 and 2002	F-4
	Statements of Stockholder’s Equity and Comprehensive Income for the nine months ended September 30, 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 nine months ended September 30, 2005 (unaudited); the period from March 3, 2004 through September 30, 2004 (unaudited); the period from March 3, 2004 through December 31, 2004; the period from January 1, 2004 through March 2, 2004; and the years ended December 31, 2003 and 2002	F-7
	Notes to the Financial Statements	F-8
FOREST GULF OF MEXICO OPERATIONS
	Report of Independent Registered Public Accounting Firm	F-37
	Statements of Revenues and Direct Operating Expenses for the nine months ended September 30, 2005 and September 30, 2004 (unaudited) and the years ended December 31, 2004, 2003 and 2002	F-38
	Notes to Statements of Revenues and Direct Operating Expenses of Forest Gulf of Mexico Operations	F-39

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

				September 30,			December 31,			December 31,
				2005			2004			2003

				(unaudited)
							(in thousands except
							share data)
Current Assets:
	Cash and cash equivalents			$	4,564		$	2,541		$	60,174
	Restricted cash				—			—			621
	Receivables				50,259			52,734			33,272
	Deferred tax asset				30,480			—			—
	Prepaid expenses and other				18,732			10,471			9,014

			Total current assets		104,035			65,746			103,081
Property and Equipment:
	Oil and gas properties, full cost method:
		Proved			446,868			319,553			599,762
		Unproved, not subject to amortization			31,126			36,245			36,619

			Total		477,994			355,798			636,381
	Other property and equipment				10,074			960			5,651
	Accumulated depreciation, depletion and amortization				(94,810	)		(52,985	)		(434,160	)

			Total property and equipment, net		393,258			303,773			207,872
Deferred Tax Asset					—			3,029			—
Other Assets, Net of Amortization					4,916			3,471			1,151

			TOTAL ASSETS	$	502,209		$	376,019		$	312,104


LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
	Accounts payable			$	14,573		$	2,526		$	28,640
	Accrued liabilities				88,993			81,831			35,486
	Accrued interest				141			79			—
	Derivative liability				76,902			16,976			2,464

			Total current liabilities		180,609			101,412			66,590
Long-Term Liabilities:
	Abandonment liability				26,314			19,268			15,027
	Taxes payable to parent company				—			—			5,664
	Deferred income tax				6,468			—			4,769
	Derivative liability				28,221			5,432			1,897
	Bank debt				75,000			105,000			—
	Note payable				4,000			10,000			—
	Other long-term liabilities				3,000			1,000			—

			Total long-term liabilities		143,003			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 September 30, 2005, December 31, 2004 and December 31, 2003, respectively				4			1			1
	Additional paid-in-capital				171,667			91,917			227,318
	Unearned compensation				(14,548	)		—			—
	Accumulated other comprehensive (loss)				(67,708	)		(11,630	)		(4,360	)
	Accumulated retained earnings (deficit)				89,182			53,619			(4,802	)

			Total stockholder’s equity		178,597			133,907			218,157

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY				$	502,209		$	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

						Period from			Period from			Period from
			Nine Months			March 3, 2004			March 3, 2004			January 1, 2004
			Ended			through			through			through			Year Ended December 31,
			September 30,			September 30,			December 31,			March 2,
			2005			2004			2004			2004			2003			2002

			(unaudited)			(unaudited)
			(in thousands except per share data)
Revenues:
	Oil sales		$	53,579		$	44,576		$	63,498		$	12,709		$	37,992		$	38,792
	Gas sales			94,913			77,950			110,925			27,055			104,551			119,436
	Other revenues			2,753			—			—			—			—			—

		Total revenues		151,245			122,526			174,423			39,764			142,543			158,228

Costs and Expenses:
	Lease operating expense			20,170			15,073			21,363			4,121			24,719			26,076
	Transportation expense			1,697			3,744			1,959			1,070			6,252			10,480
	General and administrative expense			26,726			6,174			7,641			1,131			8,098			7,716
	Depreciation, depletion and amortization			43,457			37,464			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			498			957			957			—			—			—

		Total costs and expenses		92,548			63,412			86,201			16,952			90,630			118,327

OPERATING INCOME				58,697			59,114			88,222			22,812			51,913			39,901
Interest:
	Income			696			168			225			91			756			390
	Expense, net of amounts capitalized			(5,416	)		(4,381	)		(6,045	)		(5	)		(6,981	)		(10,298	)

Income before taxes				53,977			54,901			82,402			22,898			45,688			29,993
Provision for income taxes				(18,414	)		(19,221	)		(28,783	)		(8,072	)		(9,387	)		—

Income before cumulative effect of change in accounting method, net of tax effects				35,563			35,680			53,619			14,826			36,301			29,993
Cumulative effect of change in accounting method, net of tax effects				—			—			—			—			1,943			—

NET INCOME			$	35,563			35,680		$	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		$	1.10		$	1.20		$	1.80		$	.50		$	1.22		$	1.01
	Cumulative effect of change in accounting method, net of tax effects			—			—			—			—			.07			—

	Income per share—basic		$	1.10		$	1.20		$	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		$	1.07		$	1.20		$	1.80		$	.50		$	1.22		$	1.01
	Cumulative effect of change in accounting method, net of tax effects			—			—			—			—			.07			—

	Income per share—diluted		$	1.07		$	1.20		$	1.80		$	.50		$	1.29		$	1.01

Weighted average shares outstanding—basic				32,438,240			29,748,130			29,748,130			29,748,130			29,748,130			29,748,130
Weighted average shares outstanding—diluted				33,312,831			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—net of income taxes		—		—		—			—		(32,171	)		—			(32,171	)
	Hedge settlements reclassified to income—net of income taxes		—		—		—			—		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

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)
	Common shares issued—private equity offering (unaudited)		3,600		2		44,532		—			—			—		44,534
	Common shares issued—restricted stock (unaudited)		2,267		1		31,741		(31,742	)		—			—		—
	Amortization of unearned compensation—net of income taxes (unaudited)		—		—		—		17,194			—			—		17,194
	Stock compensation expense— stock options—net of income taxes (unaudited)		—		—		420		—			—			—		420
Contributed capital—Mariner Energy, LLC and Mariner Holdings, Inc. (unaudited)			—		—		3,057		—			—			—		3,057
Comprehensive income:
	Net income (unaudited)		—		—		—		—			—			35,563		35,563
	Other comprehensive income (loss):
	Change in fair value of derivative hedging instruments—net of income taxes (unaudited)		—		—		—		—			(79,479	)		—		(79,479	)
	Hedge settlements reclassified to income—net of income taxes (unaudited)		—		—		—		—			23,401			—		23,401

	Total comprehensive income (loss) (unaudited)		—		—		—		—			—			—		(20,515	)

Balance at September 30, 2005 (unaudited)			35,615	$	4	$	171,667	$	(14,548	)	$	(67,708	)	$	89,182	$	178,597

The accompanying notes are an integral part of these financial statements

F-6

MARINER ENERGY, INC.

STATEMENTS OF CASH FLOWS


				Post-Merger									Pre-Merger

							Period from			Period from			Period from
				Nine Months			March 3, 2004			March 3, 2004			January 1, 2004			Year Ended
				Ended			through			through			through			December 31,
				September 30,			September 30,			December 31,			March 2,
				2005			2004			2004			2004			2003			2002

				(unaudited)			(unaudited)
				(in thousands)
Operating Activities:
	Net income			$	35,563		$	35,680		$	53,619		$	14,826		$	38,244		$	29,993
	Adjustments to reconcile net loss to net cash provided by operating activities:
	Deferred income tax				15,862			17,601			27,162			8,072			—			—
	Depreciation, depletion and amortization				44,321			37,964			55,067			10,630			48,414			70,588
	Stock compensation expense				17,614			—			—			—			—			—
	Hedge activities				—			—			—			—			(2,030	)		(23,200	)
	Impairment of Enron-related receivables				—			—			—			—			—			3,234
	Impairment of production equipment held for use				498			957			957			—			—			—
	Loss on sale of fixed assets				—			—			—			—			—			69
	Cumulative effect of changes in accounting method				—			—			—			—			(2,988	)		—
	Changes in operating assets and liabilities:
		Receivables			2,476			7,707			(10,615	)		(8,847	)		(3,599	)		4,449
		Prepaid expenses and other			418			2,100			(965	)		551			(2,257	)		3,249
		Other assets			(629	)		(636	)		321			(963	)		1,485			344
		Restricted cash			—			(7,800	)		620			1			14,574			(15,195	)
		Accounts payable and accrued liabilities			19,251			3,261			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		135,374			96,834			135,863			20,296			103,483			60,275

Investing Activities:
	Additions to oil and gas properties				(132,988	)		(85,699	)		(133,425	)		(15,264	)		(83,228	)		(105,360	)
	Proceeds from property conveyances				18			—			—			—			121,625			52,329
	Additions to other property and equipment				(9,114	)		(169	)		(172	)		(78	)		(50	)		(738	)

			Net cash (used in) provided by investing activities		(142,084	)		(85,868	)		(133,597	)		(15,342	)		38,347			(53,769	)

Financing Activities:
	Initial borrowings from revolving credit facility, net of fees				—			131,579			131,579			—			—			—
	Repayment of subordinated notes				—			—			—			—			(100,000	)		—
	Repayment of term note				(6,000	)		—			—			—			—			—
	Credit facility borrowings (repayments), net				(30,000	)		(40,000	)		(30,000	)		—			—			—
	Proceeds from private equity offering				44,534			—			—			—			—			—
	Deferred offering costs				(2,680	)		—			—			—			—			—
	Capital contribution from affiliates				2,879			—			—			—			—			—
	Dividend to Mariner Energy LLC				—			(166,431	)		(166,432	)		—			—			—

			Net cash (used in) provided by financing activities		8,733			(74,852	)		(64,853	)		—			(100,000	)		—

Increase (Decrease) in Cash and Cash Equivalents					2,023			(63,886	)		(62,587	)		4,954			41,830			6,506
Cash and Cash Equivalents at Beginning of Period					2,541			65,128			65,128			60,174			18,344			11,838

Cash and Cash Equivalents at End of Period				$	4,564		$	1,242		$	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 Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

for the Period from January 1, 2004 through March 2, 2004 (Pre-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 September 30, 2005 and for the nine months ended September 30, 2005 and the period from March 3, 2004 through September 30, 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. Quarterly results are not necessarily indicative of expected annual results because of the impact of commodity price fluctuations and other factors.

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 agreed to indemnify the Company from certain liabilities and the Company 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)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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 through March 2, 2004 is referred to as 2004 Pre-Merger and the period March 3, 2004 through December 31, 2004 is referred to as 2004 Post-Merger.

F-9

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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


(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, intercompany receivables of $0.2 million and $2.9 million in cash held by the affiliates were 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 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.

F-10

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002


	Post-Merger						Pre-Merger

			Period from		Period from		Period from
	Nine Months		March 3, 2004		March 3, 2004		January 1, 2004		Years Ended
	Ended		through		through		through		December 31,
	September 30,		September 30,		December 31,		March 2,
	2005		2004		2004		2004		2003		2002

	(unaudited)		(unaudited)
Numerator:
Income before cumulative effect of change in accounting method, net of tax effects	$	35,563	$	35,680	$	53,619	$	14,826	$	36,301	$	29,993
Cumulative effect of change in accounting method, net of tax effects		—		—		—		—		1,943		—

Net income	$	35,563	$	35,680	$	53,619	$	14,826	$	38,244	$	29,993

Denominator:
Weighted average shares outstanding		32,438		29,748		29,748		29,748		29,748		29,748
Add dilutive securities: Restricted shares		875		—		—		—		—		—

Total weighted average shares outstanding and dilutive securities		33,313		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	$	1.10	$	1.20	$	1.80	$	.50	$	1.22	$	1.01
Cumulative effect of change in accounting method, net of tax effects		—		—		—		—		.07		—

Net income per share—basic	$	1.10	$	1.20	$	1.80	$	.50	$	1.29	$	1.01

Earnings per share— diluted:
Income before cumulative effect of change in accounting method, net of tax effects	$	1.07	$	1.20	$	1.80	$	.50	$	1.22	$	1.01
Cumulative effect of change in accounting method, net of tax effects		—		—		—		—		.07		—

Net income per share— diluted	$	1.07	$	1.20	$	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 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 periods presented prior to 2005, Mariner Energy, Inc. had no outstanding stock options so the basic and diluted earnings per share were 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. During the second and third quarters of 2005, an additional 21,640 stock options were granted under the Stock Incentive Plan for a total of 809,000 stock options outstanding as of September 30, 2005. Outstanding restricted stock and unexercised stock options diluted earnings by $0.03 per share for the nine months ended September 30, 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.

F-11

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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.

Unproved Properties— The costs associated with unevaluated properties and properties under development are not initially included in the full cost 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, including 3-D seismic data costs, are included in the full cost amortization base as incurred when such costs cannot be associated with specific unevaluated properties for which we own a direct interest. Seismic data costs are associated with specific unevaluated properties if the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by us. We make this determination based on an analysis of leasehold and seismic maps and discussions with our Chief Exploration Officer. Geological and geophysical costs included in unproved properties are transferred to the full cost amortization base along with the associated leasehold costs on a specific project basis.

F-12

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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 twenty-two years.

Prepaid Expenses and Other—Prepaid expenses and other includes $3.6 million of oil and gas lease and well equipment held in inventory at December 31, 2004. In 2004 and the nine months ended September 30, 2005, we reduced the carrying cost of our inventory by $957,000 and $498,000, respectively, to account for a reduction in the estimated value, primarily related to subsea trees held in inventory.

Other Assets—Other assets as of September 30, 2005 were primarily comprised of $1.7 million of amortizable bank fees and $3.0 million of prepaid seismic costs. 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 September 30, 2005, December 31, 2004 and 2003 was $1.8 million, $0.9 million and $6.6 million, 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 directly identified with acquisition exploration and development 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.

F-13

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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 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.

F-14

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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 (unaudited)		9.4
Claims Settled (unaudited)		(1.9	)
Accretion Expense (unaudited)		1.6

Abandonment Liability as of September 30, 2005 (Post-merger) (unaudited)(2)	$	33.1


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

(2)	Includes $6.8 million classified as a current accrued liability at September 30, 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-15

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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.

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

F-16

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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 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 recorded compensation expense for the fair value of restricted stock that was granted pursuant to our Equity Participation Plan (see “Management of Mariner—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 of Mariner—Stock Incentive Plan”). We recorded 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 nine months ended September 30, 2005 includes $17.2 million of compensation expense related to restricted stock granted in 2005 and $0.4 million of compensation expense related to stock options outstanding as of September 30, 2005. For the comparable period in 2004, we recorded no stock compensation expense related to either restricted stock or stock options.

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

F-17

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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 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

F-18

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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 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.

F-19

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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)		—		—

Supplemental ENA Affiliate Data—provided below is supplemental balance sheet and income statement information for affiliate entities reflecting 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		—		—


	*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 connection with the provision of management services. Such payments have been made.

F-20

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

Mariner Energy LLC 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 nine months ended September 30, 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. On

F-21

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

August 5, 2005, the lenders agreed to increase the borrowing base to $170 million. On January 20, 2006, the lenders agreed to increase the borrowing base to $185 million.

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.

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.

F-22

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

As of September 30, 2005, $75.0 million was outstanding under the bank credit facility, and the weighted average interest rate was 5.84%. 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.

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,

F-23

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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 nine months ended September 30, 2005, we granted 2,267,270 shares of restricted stock and options to purchase 809,000 shares of stock. We also issued 3.6 million shares of common stock in March 2005 in connection with our private placement offering. We recorded compensation expense of $17.2 million in the nine months ended September 30, 2005 related to the restricted stock, and in the nine months ended September 30, 2005, we recorded $0.4 million of compensation expense related to stock options outstanding as of September 30, 2005. For the comparable period in 2004, we recorded no stock compensation expense related to either restricted stock or stock options.


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.

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 were $.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		—

F-24

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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 September 30, 2005, the Company had the following fixed price swaps outstanding:


						September 30,
						2005
				Fixed		Fair Value
Fixed Price Swaps		Quantity		Price		Gain/(Loss)

						(in millions)
Crude Oil (Bbls)
	October 1—December 31, 2005		138,000	$	25.22	$	(5.7	)
	January 1—December 31, 2006		140,160		29.56		(5.2	)
Natural Gas (MMbtus)
	October 1—December 31, 2005		1,352,400,		5.00		(12.3	)
	January 1—December 31, 2006		1,827,547		5.53		(13.6	)

	Total					$	(36.8	)

As of September 30, 2005, the Company had the following costless collars outstanding:


								September 30,
								2005
								Fair Value
Costless Collars		Quantity		Floor		Cap		Gain/(Loss)

								(in millions)
Crude Oil (Bbls)
	October 1—December 31, 2005		57,960	$	35.60	$	44.77	$	(1.2	)
	January 1—December 31, 2006		251,850		32.65		41.52		(6.2	)
	January 1—December 31, 2007		202,575		31.27		39.83		(4.8	)
Natural Gas (MMbtus)
	October 1—December 31, 2005		2,189,600		6.01		8.02		(12.3	)
	January 1—December 31, 2006		7,347,450		5.78		7.85		(29.1	)
	January 1—December 31, 2007		5,310,750		5.49		7.22		(14.7	)

	Total							$	(68.3	)

F-25

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

The Company has not entered into any hedge transactions subsequent to September 30, 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-26

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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 September 30, 2005 was $14.6 million. In April 2005, the MMS denied the administrative appeal. On

F-27

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

October 3, 2005, we filed suit in the U.S. District Court for the Southern District of Texas seeking judicial review of the dismissal of our appeal by the Board of Land Appeals.

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’s 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 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 in the first quarter of 2006. 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.

In August 2005 and September 2005, Mariner incurred damage from Hurricanes Katrina and Rita that affected several of its offshore fields. Hurricane Katrina caused minor damage to our owned platforms and facilities. Production that was shut-in by the hurricane was recommenced within three weeks of the hurricane, with the exception of two minor non-operated fields. However, Hurricane Katrina inflicted damage to host facilities for our Pluto, Rigel and Ochre projects that is expected to delay start-up of these projects until 2006. Hurricane Rita caused minor damage to our owned platforms and some damage to certain host facilities of our development projects. Production shut-in as a result of Hurricane Rita fully recommenced within three weeks of the hurricane, with the exception of one minor field. We cannot estimate a range of loss arising from the hurricanes until we are able to more completely assess the impacts on our properties and the properties of our operational partners. Until we are able to complete all the repair work and submit costs to our insurance underwriters for review, the full extent of our insurance recovery and the resulting net cost to us for Hurricanes Katrina and Rita will be unknown. For the insurance period ending September 30, 2005, we carried a $3.0 million annual deductible and a $.375 million single occurrence deductible.

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.

F-28

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002


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 December 31, 2003 and 2002. An 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

F-29

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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-30

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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.

F-31

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002


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 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.

F-32

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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

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

F-33

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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 cash 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-34

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002

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-35

MARINER ENERGY, INC.

NOTES TO THE FINANCIAL STATEMENTS — (Continued)

For the Nine Month Period Ended September 30, 2005 (Unaudited),

for the Period from March 3, 2004 through September 30, 2004 (Unaudited),

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

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

and For the Years Ended December 31, 2003 and 2002


11.	Unaudited Quarterly Financial Information

The following table presents Mariner’s unaudited quarterly financial information for 2004 and 2003:


		Post-Merger								Pre-Merger

								Period from		Period from
		2004 Quarter Ended						March 3, 2004		January 1, 2004		2003 Quarter Ended
								through		through
		December 31		September 30		June 30		March 31, 2004		March 2, 2004		December 31		September 30			June 30		March 31

		(in thousands, except per share data)
Total revenues		$	51,897	$	50,202	$	51,086	$	21,238	$	39,764	$	33,231	$	29,002		$	35,099	$	45,211
Operating income		$	29,108	$	24,403	$	25,045	$	9,666	$	22,812	$	14,474	$	4,428		$	9,681	$	23,330
Income before income taxes		$	27,501	$	22,804	$	23,071	$	9,026	$	22,898	$	14,453	$	2,758		$	7,583	$	20,894
Provision for income taxes			9,562		8,498		7,630		3,093		8,072		10,432		(1,045	)		—		—

Income before cumulative effect of change in accounting method, net of tax effects			17,939		14,306		15,441		5,933		14,826		4,021		3,803			7,583		20,894
Cumulative effect of change in accounting method, net of tax effects			—		—		—		—		—		—		(1,045	)		—		2,988

Net Income		$	17,939	$	14,306	$	15,441	$	5,933	$	14,826	$	4,021	$	2,758		$	7,583	$	23,882

Earnings per share:
Net income per share—basic
	Income before cumulative effect of change in accounting method, net of tax effects	$	0.60	$	0.48	$	0.52	$	0.20	$	0.50	$	0.14	$	0.13		$	0.25	$	0.70
	Cumulative effect of change in accounting method, net of tax effects		—		—		—		—		—		—		(0.04	)		—		0.10

	Income per share—basic	$	0.60	$	0.48	$	0.52	$	0.20	$	0.50	$	0.14	$	0.09		$	0.25	$	0.80

Net income per share—diluted
	Income before cumulative effect of change in accounting method, net of tax effects	$	0.60	$	0.48	$	0.52	$	0.20	$	0.50	$	0.14	$	0.13		$	0.25	$	0.70
	Cumulative effect of change in accounting method, net of tax effects		—		—		—		—		—		—		(0.04	)		—		0.10

	Income per share—diluted	$	0.60	$	0.48	$	0.52	$	0.20	$	0.50	$	0.14	$	0.09		$	0.25	$	0.80

Weighted average shares outstanding—basic			29,748,130		29,748,130		29,748,130		29,748,130		29,748,130		29,748,130		29,748,130			29,748,130		29,748,130
Weighted average shares outstanding—diluted			29,748,130		29,748,130		29,748,130		29,748,130		29,748,130		29,748,130		29,748,130			29,748,130		29,748,130

F-36

Report of Independent Registered Public Accounting Firm

The Board of Directors

Forest Oil Corporation:

We have audited the statements of revenues and direct operating expenses of the Forest Gulf of Mexico operations (as defined in note 1) for each of the years in the three-year period ended December 31, 2004 (Historical Statements). These Historical Statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Historical Statements are free of material misstatement. Our audits include 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the Historical Statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the Historical Statements. We believe that our audits provide a reasonable basis for our opinion.

The accompanying statements were prepared for purposes of complying with the rules and regulations of the Securities and Exchange Commission and for inclusion in the registration statement on Form S-4 of Mariner Energy, Inc. The presentation is not intended to be a complete presentation of the revenues and expenses of the Forest Gulf of Mexico operations.

In our opinion, the Historical Statements referred to above present fairly, in all material respects, the revenues and direct operating expenses described in note 1 of the Forest Gulf of Mexico operations for each of the years in the three-year period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.


	KPMG LLP

Denver, Colorado

October 12, 2005

F-37

FOREST GULF OF MEXICO OPERATIONS

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES


		Nine Months Ended
		September 30,				Years Ended December 31,

		2005		2004		2004		2003		2002

		(unaudited)
		(in thousands)
Oil and natural gas revenues		$	326,722	$	324,426	$	453,139	$	342,019	$	228,896

Direct Operating Expenses:
	Lease operating expenses		57,431		63,022		80,079		45,716		52,076
	Transportation		2,484		1,424		2,175		2,652		3,855
	Production taxes		1,948		1,243		1,548		1,521		947

Total direct operating expenses			61,863		65,689		83,802		49,889		56,878

Revenues in excess of direct operating expenses		$	264,859	$	258,737	$	369,337	$	292,130	$	172,018

See accompanying notes to statements of revenues and direct operating expenses.

F-38

FOREST GULF OF MEXICO OPERATIONS

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

For the Years Ended December 31, 2004, 2003 and 2002

and for the Nine Months Ended September 30, 2005 and 2004

(Information as of and for the nine months ended September 30, 2005 and 2004 is unaudited)


1.	BASIS OF PRESENTATION

The accompanying historical statements of revenues and direct operating expenses (the “historical statements”) are presented using accrual basis, and represent the revenues and direct operating expenses attributable to Forest Oil Corporation’s (“Forest Oil”) interests in certain producing oil and gas properties located offshore in the Gulf of Mexico (the “Forest Gulf of Mexico operations”). The historical statements were prepared from the historical accounting records of Forest Oil. The historical statements include only oil and natural gas revenues and direct lease operating and production expenses, including transportation and production taxes. The historical statements do not include Federal and state income taxes, interest expenses, depletion, depreciation and amortization, accretion, or general and administrative expenses. Oil and gas revenues include gains or losses on derivative instruments designated as hedges of oil and gas production from these properties.

Complete financial statements, including a balance sheet, are not presented as the oil and gas properties were not operated as a separate business unit within Forest Oil. Accordingly, it is not practicable to identify all assets and liabilities, or the indirect operating costs applicable to these oil and gas properties. As such, the historical statements of oil and gas revenues and direct operating expenses have been presented in lieu of the financial statements prescribed by Rule 3-05 of Securities and Exchange Commission Regulation S-X.


2.	DERIVATIVE INSTRUMENTS

In order to reduce the impact of fluctuations in oil and gas prices, or to protect the economics of property acquisitions, from time to time Forest Oil entered into derivative instruments designed to hedge future production from its oil and gas properties, including future production from the properties constituting the Forest Gulf of Mexico operations. Forest Oil entered into derivative instruments, including commodity swaps, collars, and other financial instruments with counterparties who, in general, are participants in Forest Oil’s credit facilities. These arrangements, which are based on prices available in the financial markets at the time the contracts are entered into, are settled in cash and do not require physical deliveries.

Net losses related to hedging activities of $57.1 million and $40.9 million were recognized for the years ended December 31, 2004 and 2003, respectively, and net gains of $8.4 million were recognized for the year ended December 31, 2002. Net losses related to hedging activities of $83.8 million and $34.1 million were recognized for the nine months ended September 30, 2005 and 2004, respectively. Gains and losses recognized on hedging activities are included in oil and natural gas revenues in the statements of revenues and direct operating expenses.


3.	SUPPLEMENTAL INFORMATION REGARDING PROVED OIL AND GAS RESERVES (UNAUDITED)

Supplemental oil and natural gas reserve information related to the Forest Gulf of Mexico operations is presented in accordance with the requirements of Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities (“FAS 69”). There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures.

F-39

FOREST GULF OF MEXICO OPERATIONS

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

For the Years Ended December 31, 2004, 2003 and 2002

and for the Nine Months Ended September 30, 2005 and 2004

(Information as of and for the nine months ended September 30, 2005 and 2004 is unaudited)


	*Estimated Proved Reserves*

Proved oil and gas reserves are 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; 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 arrangement, but not on escalations based on future conditions. Purchases of reserves in place represent volumes recorded on the closing dates of the acquisitions for financial accounting purposes.

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 are 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.

An analysis of the estimated changes in quantities of proved natural gas reserves attributed to the Forest Gulf of Mexico operations for the years ended December 31, 2004, 2003 and 2002 is shown below:


	Liquids			Gas			Total
	(MBbls)			(MMcf)			(MMcfe)

Balance at January 1, 2002		12,767			296,497			373,099
Revisions of previous estimates		(280	)		12,671			10,991
Extensions and discoveries		481			5,557			8,443
Production		(1,980	)		(50,566	)		(62,446	)
Purchases of reserves in place		—			2,009			2,009

Balance at December 31, 2002		10,988			266,168			332,096
Revisions of previous estimates		(2,492	)		(14,565	)		(29,517	)
Extensions and discoveries		357			23,714			25,856
Production		(2,145	)		(58,785	)		(71,655	)
Purchases of reserves in place		4,649			78,815			106,709

Balance at December 31, 2003		11,357			295,347			363,489
Revisions of previous estimates		1,693			(2,860	)		7,298
Extensions and discoveries		630			14,449			18,229
Production		(3,230	)		(61,684	)		(81,064	)
Purchases of reserves in place		1,200			24,556			31,756

Balance at December 31, 2004		11,650			269,808			339,708

Proved developed reserves at:
December 31, 2002		7,644			208,904			254,768
December 31, 2003		7,920			205,334			252,854
December 31, 2004		9,471			201,759			258,585

F-40

FOREST GULF OF MEXICO OPERATIONS

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

For the Years Ended December 31, 2004, 2003 and 2002

and for the Nine Months Ended September 30, 2005 and 2004

(Information as of and for the nine months ended September 30, 2005 and 2004 is unaudited)


	*Standardized Measure of Discounted Future Net Cash Flows*

Future oil and gas sales and production and development costs have been estimated using prices and costs in effect at the end of the years indicated. The weighted average prices used for the December 31, 2004, 2003 and 2002 calculations were $43.45, $32.55 and $31.23 per barrel of oil and $6.15, $5.97 and $4.60 per Mcf of gas, respectively. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs. Future income tax expenses are estimated using the statutory federal rate of 35%. No deductions were made for general overhead, depletion, depreciation, and amortization, or any indirect costs. All cash flow amounts are discounted at 10%.

Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of the company’s proved reserves.

The estimated standardized measure of discounted future net cash flows relating to proved reserves at December 31, 2004, 2003 and 2002 is shown below.


	December 31,

	2004			2003			2002

	(in thousands)
Future cash inflows	$	2,155,217			2,105,447			1,539,033
Future production costs		(272,020	)		(272,335	)		(237,876	)
Future development costs		(357,592	)		(372,139	)		(213,020	)
Future income taxes		(412,477	)		(360,707	)		(257,647	)

Future net cash flows		1,113,128			1,100,266			830,490
10% annual discount		(187,291	)		(150,845	)		(182,450	)

Standardized measure of discounted future net cash flows relating to proved reserves	$	925,837			949,421			648,040

F-41

FOREST GULF OF MEXICO OPERATIONS

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)

For the Years Ended December 31, 2004, 2003 and 2002

and for the Nine Months Ended September 30, 2005 and 2004

(Information as of and for the nine months ended September 30, 2005 and 2004 is unaudited)

An analysis of the sources of changes in the standardized measure of discounted future net cash flows relating to proved reserves on the pricing basis described above for the years ended December 31, 2004, 2003 and 2002 is shown below.


		December 31,

		2004			2003			2002

		(in thousands)
Balance, beginning of period		$	949,421			648,040			434,955
Increase (decrease) in discounted future net cash flows:
	Sales of oil and gas, net of production costs		(426,405	)		(333,029	)		(163,604	)
	Net changes in prices and future production costs		11,628			345,947			373,243
	Net changes in future development costs		9,615			(82,874	)		(43,636	)
	Extensions, discoveries and improved recovery		88,999			98,561			24,292
	Previously estimated development costs incurred during the period		70,027			74,690			70,833
	Revisions of previous quantity estimates		28,701			(104,674	)		31,446
	Purchases of reserves in place		100,681			307,686			3,741
	Accretion of discount		121,720			82,808			48,343
Net change in income taxes			(28,550	)		(87,734	)		(131,573	)

Balance, end of period		$	925,837			949,421			648,040

F-42

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.

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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

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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

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PETROLEUM RESERVES DEFINITIONS

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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)

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

February 10, 2006

Until March 7, 2006 (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.