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Filed pursuant to Rule 424(b)(3)
Registration No. 333-137441
PROSPECTUS
 
(MARINER ENERGY LOGO)
$300,000,000
71/2% Senior Notes due 2013
 
The Offer to Exchange
$300,000,000 71/2% Senior Notes due 2013
that have been registered under the Securities Act of 1933
for any and all
$300,000,000 71/2% Senior Notes due 2013
expired at 5:00 P.M.,
New York City time, on November 9, 2006.
 
We offered to exchange an aggregate principal amount of $300,000,000 of registered 71/2% Senior Notes due 2013, which we refer to as the new notes, for any and all of our original unregistered 71/2% Senior Notes due 2013 that were issued in a private offering on April 24, 2006, which we refer to as the old notes. The exchange offer expired at 5:00 p.m., New York City time, on November 9, 2006, which we refer to as the exchange date. Each broker-dealer (other than an affiliate of ours) that receives new notes for its own account in the exchange offer in exchange for securities that were acquired by such broker-dealer as a result of market-making or other trading activities must deliver a prospectus meeting the requirements of the Securities Act of 1933 in connection with any resale of new notes. We have agreed that, for a period of 90 days after the exchange date, we will make the prospectus available to any broker-dealer for use in connection with any such resale.
 
Terms of the exchange offer:
 
  •  We exchanged all outstanding old notes that were validly tendered and not withdrawn prior to the expiration of the exchange offer for an equal principal amount of new notes.
 
  •  The terms of the new notes are substantially identical to those of the old notes, except that the transfer restrictions, registration rights and special interest provisions relating to the old notes do not apply to the new notes.
 
  •  The ability to withdraw tenders of old notes ceased upon expiration of the exchange offer.
 
  •  The exchange of new notes for old notes is not a taxable transaction for U.S. federal income tax purposes.
 
  •  We did not receive any proceeds from the exchange offer.
 
  •  The new notes are eligible for trading in the Private Offering, Resales and Trading Automatic Linkage (PORTAL) Market. SM We do not intend to apply for a listing of the new notes on any securities exchange or for their inclusion on any automated dealer quotation system.
 
See “Risk Factors” beginning on page 18 for a discussion of risks you should consider in connection with the notes.
 
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
 
We may amend or supplement this prospectus from time to time by filing amendments or supplements as required. You should read this entire prospectus and related documents and any amendments or supplements to this prospectus carefully before making your investment decision.
 
The date of this prospectus is November 22, 2006.


 

 
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  F-1
 
THIS PROSPECTUS IS PART OF A REGISTRATION STATEMENT WE FILED WITH THE SECURITIES AND EXCHANGE COMMISSION, OR SEC. IN MAKING YOUR INVESTMENT DECISION, YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN THIS PROSPECTUS, IN THE ACCOMPANYING LETTER OF TRANSMITTAL OR THE INFORMATION TO WHICH WE HAVE REFERRED YOU. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH ANY OTHER INFORMATION. IF YOU RECEIVE ANY UNAUTHORIZED INFORMATION, YOU MUST NOT RELY ON IT. THIS PROSPECTUS MAY ONLY BE USED WHERE IT IS LEGAL TO EXCHANGE THE OLD NOTES. YOU SHOULD NOT ASSUME THAT THE INFORMATION CONTAINED IN THIS PROSPECTUS IS ACCURATE AS OF ANY DATE OTHER THAN THE DATE ON THE FRONT COVER OF THIS PROSPECTUS.
 
Until January 8, 2007, all dealers that effect transactions in these securities, whether or not participating in this exchange offer, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.


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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 “may,” “will,” “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. The forward-looking statements in this prospectus speak only as of the date of this prospectus; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this prospectus. These risks, contingencies and uncertainties relate to, among other matters, the following:
 
  •  the volatility of oil and natural gas prices;
 
  •  discovery, estimation, development and replacement of oil and natural gas reserves;
 
  •  cash flow, 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;
 
  •  risks arising out of our hedging transactions;
 
  •  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 hurricanes, fires, floods and other catastrophic events and natural disasters;
 
  •  governmental regulation of the oil and natural gas industry;
 
  •  environmental liabilities;
 
  •  developments in oil-producing and natural gas-producing countries;
 
  •  uninsured or underinsured losses in our oil and natural gas operations;
 
  •  risks related to our level of indebtedness;
 
  •  our merger with Forest Energy Resources, including strategic plans, expectations and objectives for future operations, and the realization of expected benefits from the transaction; and
 
  •  disruption from the merger with Forest Energy Resources making it more difficult to manage Mariner’s business.


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WHERE YOU CAN FIND MORE INFORMATION
 
We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available to the public over the Internet at the SEC’s web site at www.sec.gov. You also may read and copy any document we file at the SEC’s public reference room in Washington, D.C. Please call the SEC at 1-800-SEC-0330 for further information about the public reference room. Reports and other information concerning us can also be inspected at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005. Our common stock is listed and traded on the New York Stock Exchange under the trading symbol “ME.”
 
You may request a copy of these filings, which we will provide to you at no cost, by writing or telephoning us at the following address: Mariner Energy, Inc., One Briar Lake Plaza, Suite 2000, 2000 West Sam Houston Parkway South, Houston, Texas 77004. Our phone number is (713) 954-5555. Our website address is www.mariner-energy.com. The information on our website is not a part of this prospectus.
 
We filed a registration statement on Form S-4 to register with the SEC the new notes issued in exchange for the old notes and guarantees thereof. This prospectus is part of that registration statement. As allowed by the SEC’s rules, this prospectus does not contain all of the information you can find in the registration statement or the exhibits to the registration statement. You should note that where we summarize in the prospectus the material terms of any contract, agreement or other document filed as an exhibit to the registration statement, the summary information provided in the prospectus is less complete than the actual contract, agreement or document. You should refer to the exhibits filed to the registration statement for copies of the actual contract, agreement or document.


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PROSPECTUS SUMMARY
 
This summary highlights information appearing in other sections of this prospectus. It does not contain all of the information you may wish to consider before participating in the exchange offer. We urge you to read this entire prospectus to understand fully the terms of the notes and other considerations that may be important to you in making your decision regarding the exchange offer, including the “Risk Factors” section beginning on page 18 of this prospectus. As used in this prospectus, unless the context otherwise requires or indicates, references to “Mariner,” “we,” “our,” “ours,” and “us” refer to Mariner Energy, Inc. and its subsidiaries collectively. Certain oil and natural gas industry terms used in this prospectus are defined in the “Glossary of Oil and Natural Gas Terms” beginning on page 165. References to “pro forma” and “on a pro forma basis” mean on a pro forma basis, giving effect to our merger with Forest Energy Resources, Inc. which was completed on March 2, 2006, as if this merger had occurred on the applicable date of determination or on the first day of the applicable period. The unaudited pro forma information contained in this prospectus 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. The pro forma 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 pro forma financial information as being 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.
 
Our Company
 
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 in West Texas. Our management has significant expertise and a successful operating track record in these areas. In the three-year period ended December 31, 2005, we added approximately 280 Bcfe of proved reserves and produced approximately 100 Bcfe, while deploying approximately $475 million of capital on acquisitions, exploration and development.
 
Our primary operating strategy is to generate high-quality exploration and development projects, which enables us to add value through the drill bit. Our expertise in project generation also facilitates our participation in high-quality projects generated by other operators. We will also pursue acquisitions of producing assets that have the potential to provide acceptable risk-adjusted rates of return and further reserve additions through exploration, exploitation, and development opportunities. We target a balanced exposure to development, exploitation and exploration opportunities, both offshore and onshore and seek to maintain a moderate risk profile.
 
On March 2, 2006, we completed a merger transaction with Forest Energy Resources, Inc., which we refer to as Forest Energy Resources. As a result of this merger, we acquired the Gulf of Mexico operations of Forest Oil Corporation (NYSE: FST), which we refer to as the Forest Gulf of Mexico operations. We refer to Forest Oil Corporation as Forest.
 
As of December 31, 2005, we had 338 Bcfe of estimated proved reserves, of which approximately 62% were natural gas and 38% were oil and condensate, and 50% of which was proved developed. Pro forma for the merger transaction, as of December 31, 2005, we had 644 Bcfe of estimated proved reserves, of which approximately 68% were natural gas and 32% were oil and condensate, and 56% of which was proved developed. Our pro forma production for 2005 was approximately 95 Bcfe, or 260 MMcfe per day on average. During the year ended December 31, 2005, our pro forma EBITDA was approximately $438.6 million, including $25.7 million of non-cash compensation expense related to restricted stock and stock options granted in 2005, but excluding general and administrative expenses of the Forest Gulf of Mexico operations. Our production for the nine months ended September 30, 2006 was approximately 55 Bcfe, or 200 MMcfe per day on average, and pro forma for the merger, 62 Bcfe, or 229 MMcfe per day on average. During the nine months ended September 30, 2006, our EBITDA was approximately $340.7 million, and pro forma for the


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merger, approximately $391.7 million, in each case, including $9.0 million of non-cash compensation expense related to restricted stock and stock options. We believe the overhead costs associated with the Forest Gulf of Mexico operations in 2006 will be approximately $6.4 million, net of capitalized amounts. See footnote 1 on page 13 for our definition of EBITDA and a reconciliation of net income to EBITDA.
 
The following table sets forth certain information with respect to our estimated proved reserves, production and acreage by geographic area on a pro forma basis for our merger with Forest Energy Resources as of December 31, 2005. 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. Proved reserve estimates do not include any value for probable or possible reserves which may exist, nor do they include any value for undeveloped acreage. The proved reserve estimates represent our net revenue interest in our properties. The reserve information for Mariner as of December 31, 2005 is based on estimates made in a reserve report prepared by Ryder Scott Company, L.P., independent petroleum engineers (“Ryder Scott”). The reserve information as of December 31, 2005 for the Forest Gulf of Mexico operations is based on estimates made by internal staff engineers of Forest, which estimates were audited by Ryder Scott. Accordingly, the pro forma reserve information presented below includes both reserves that were estimated by Ryder Scott and reserves that were estimated by internal staff engineers of Forest and audited by Ryder Scott. This information is presented on a pro forma basis, giving effect to our merger with Forest Energy Resources as though it had been consummated on December 31, 2005. We consummated the merger on March 2, 2006.
 
                                         
                            Pro Forma
 
                            Production for
 
                            Year Ended
 
    Pro Forma
          December 31,
 
    Estimated Proved
          2005  
    Reserve Quantities     Pro Forma
    (Natural
 
    Oil
    Natural
    Total
    Total Net
    Gas
 
Geographic Area
  (MMbbls)     Gas (Bcf)     (Bcfe)     Acreage     Equivalent (Bcfe))  
 
West Texas
    16.7       105.5       205.5       31,199       6.6  
Gulf of Mexico Deepwater(1)
    4.8       95.7       124.5       241,320       14.0  
Gulf of Mexico Shelf(2)
    12.7       237.6       313.7       652,086       74.3  
                                         
Total
    34.2       438.8       643.7       924,605       94.9  
Proved Developed Reserves
    18.4       252.1       362.3                  
 
 
(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.
 
Our Strategy and Our Competitive Strengths
 
Our Strategy
 
The principal elements of our operating strategy include:
 
Generating and pursuing high-quality prospects.  We expect to continue our strategy of growth through the drill bit by continuing to identify and develop high-impact shelf, deep shelf and deepwater projects in the Gulf of Mexico. Our technical team has significant expertise in, and a successful track record of achieving growth by, generating prospects internally and selectively participating in prospects generated by other operators. We believe the Gulf of Mexico is an area that offers substantial growth opportunities, and our acquisition of the Forest Gulf of Mexico operations has more than doubled our existing undeveloped acreage position in the Gulf, providing numerous additional exploration, exploitation and development opportunities.
 
Maintaining a moderate risk profile.  We seek to manage our risk profile by targeting a balanced exposure to development, exploitation and exploration opportunities. For example, we intend to continue


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to develop and seek to expand our West Texas asset base, which contributes stable cash flows and long-lived reserves to our portfolio as a counterbalance to our high-impact, high-production Gulf of Mexico assets. We also seek to mitigate and diversify our risk in drilling projects by selling partial or entire interests in projects to industry partners or by entering into arrangements with industry partners in which they agree to pay a disproportionate share of drilling costs and compensate us for expenses incurred in prospect generation. We also enter into trades or farm-in transactions whereby we acquire interests in third-party generated prospects, thereby gaining exposure to a greater number of prospects. We expect more opportunities to participate in these prospects in the future as a result of our larger scale and increased cash flow from the Forest Gulf of Mexico operations.
 
Pursuing opportunistic acquisitions.  Until 2005, we grew our reserves primarily through the drill bit. In 2005 we added significant proved reserves primarily through acquisitions in West Texas and subsequently in March 2006, through the acquisition of the Forest Gulf of Mexico operations. As part of our growth strategy, we will seek to continue to acquire producing assets that have the potential to provide acceptable risk-adjusted rates of return and further reserve additions through exploration, exploitation and development opportunities.
 
Our Competitive Strengths
 
We believe our core resources and strengths include:
 
Our high-quality assets with geographic and geological diversity.  Our assets and operations are diversified among the Gulf of Mexico shelf, deep shelf and deepwater, and West Texas. Our asset portfolio provides a balanced exposure to long-lived West Texas reserves, Gulf of Mexico shelf growth opportunities and high-impact deepwater prospects.
 
Our large inventory of prospects.  We believe we have significant potential for growth through the development of our existing asset base. The acquisition of the Forest Gulf of Mexico operations more than doubled our existing undeveloped acreage position in the Gulf of Mexico to approximately 450,000 net acres and increased our total net leasehold acreage offshore to nearly one million acres, providing numerous exploration, exploitation and development opportunities. As of September 30, 2006, we have an inventory of approximately 890 drilling locations in West Texas, which we believe would require approximately six years to drill at our current rate. These include approximately 430 locations pertaining to 98 Bcfe of estimated net proved undeveloped reserves and approximately 460 other locations.
 
Our successful track record of finding and developing oil and gas reserves.  We have demonstrated our expertise in finding and developing additional proved reserves. In the three-year period ended December 31, 2005, we deployed approximately $475 million of capital on acquisitions, exploration and development, while adding approximately 280 Bcfe of proved reserves and producing approximately 100 Bcfe.
 
Our depth of operating experience.  Our team of 41 geoscientists, engineers, geologists and other technical professionals and landmen as of September 30, 2006 average more than 22 years of experience in the exploration and production business (including extensive experience in the Gulf of Mexico), much of it with major oil companies. The addition of experienced Forest personnel to Mariner’s team of technical professionals has further enhanced our ability to generate and maintain an inventory of high-quality drillable prospects and to further develop and exploit our assets. Mariner’s technical team has also proven to be an effective and efficient operator in West Texas, as evidenced by our successful production and reserve growth there in recent years.
 
Our technology and production techniques.  Our team of geoscientists currently has access to seismic data from multiple, recent vintage 3-D seismic databases covering more than 7,000 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. We also have extensive experience and a successful track record in the use of subsea tieback technology to connect


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offshore wells to existing production facilities. This technology facilitates production from offshore properties without the necessity of fabrication and installation of platforms and top-side facilities that typically are more costly and 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, 2005, we were directly involved in 14 projects (five of which we operated) utilizing subsea tieback systems in water depths ranging from 475 feet to more than 6,700 feet. As of September 30, 2006, we had 18 subsea wells in water depths ranging from 450 feet to more than 4,700 feet. These wells were tied back to 13 host production facilities for production processing. An additional nine wells in water depths ranging from 465 feet to more than 6,800 feet were then under development for tieback to five additional host production facilities.
 
Recent Developments
 
Forest Gulf of Mexico Merger
 
On March 2, 2006, we completed a merger transaction with Forest Energy Resources. Prior to the consummation of the merger, Forest transferred and contributed the assets and certain liabilities associated with its Gulf of Mexico operations to Forest Energy Resources. Immediately prior to the merger, Forest distributed all of the outstanding shares of Forest Energy Resources to Forest shareholders on a pro rata basis. Forest Energy Resources then merged with a newly-formed subsidiary of Mariner, became a new wholly-owned subsidiary of Mariner and changed its name to Mariner Energy Resources, Inc. Immediately following the merger, approximately 59% of Mariner common stock was held by shareholders of Forest and approximately 41% of Mariner common stock was held by the pre-merger stockholders of Mariner.
 
Forest Energy Resources had approximately 306 Bcfe of estimated proved reserves as of December 31, 2005, of which approximately 76% were natural gas, and 24% were oil and condensate. The reserves and operations acquired from Forest are concentrated in the shelf and deep shelf of the Gulf of Mexico and represent a significant addition to Mariner’s asset portfolio in those areas of operation.
 
We believe our acquisition of the Forest Gulf of Mexico operations and the scale they bring to our business has further moderated our risk profile, provided many exploration, exploitation and development opportunities, enhanced our ability to participate in prospects generated by other operators, and added a significant cash flow generating resource that has improved our ability to compete effectively in the Gulf of Mexico and fund exploration activities and acquisitions. We believe we are well-positioned to optimize the Forest Energy Resources assets through aggressive and timely exploitation.
 
West Cameron Acquisition
 
In August 2006, we acquired the interest of BP Exploration and Production Inc., which we refer to as “BP”, in West Cameron Block 110 and the southeast quarter of West Cameron Block 111 in the Gulf of Mexico. The interest was acquired by our subsidiary, Mariner Energy Resources, Inc., exercising its preferential right to purchase. BP retained its interest in depths below 15,000 feet. In the Forest merger, we acquired Forest Energy Resources’ 37.5% interest in the properties. As a result of the August 2006 acquisition, Mariner Energy Resources, Inc. now owns 100% of the working interest, exclusive of the deep rights retained by BP, and Mariner Energy, Inc. became operator of the interests owned by its subsidiary. The acquisition cost, net of preliminary purchase price adjustments, was approximately $70.9 million, which was financed by borrowing under our senior secured credit facility. A $10.4 million letter of credit under our senior secured credit facility also was issued in favor of BP to secure plugging and abandonment obligations. The acquisition adds proved reserves estimated by us to be 20 Bcfe as of August 1, 2006. Production associated with the acquired interest was approximately 11 MMcfe/day during July 2006.


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Material Gulf of Mexico Discovery
 
In October 2006, we announced that we made a material conventional shelf discovery in the High Island 116 #5ST1 well, drilled to a total measured depth of 14,683 feet / 13,150 feet true vertical depth. The well encountered approximately 540 feet of net true vertical depth pay in thirteen sands. We anticipate completion and initial production in the fourth quarter of 2006. High Island 116 is part of the Forest Gulf of Mexico operations we acquired in March 2006. We have a 100% working interest and an approximate 72% net revenue interest in the well.
 
Effects of the 2005 Hurricane Season
 
In 2005, our operations were adversely affected by one of the most active and severe hurricane seasons in recorded history, resulting in shut-in production and startup delays. We estimate that as of September 30, 2006, approximately 12 MMcfe per day of production remained shut-in and approximately 33 MMcfe per day of production had recommenced since June 30, 2006. The four deepwater projects that experienced startup delays have recommenced production. As a result of ongoing repairs to pipelines, facilities, terminals and host facilities, we expect most of the remaining shut-in production to recommence by the end of 2006 and the balance in 2007, except that an immaterial amount of production is not expected to recommence.
 
We estimate the costs to repair damage caused by the hurricanes to our platforms and facilities will be approximately $85 million. However, until we are able to complete all the repair work this estimate is subject to significant variance. For the insurance period covering the 2005 hurricane activity, we carried a $3 million annual deductible and a $0.5 million single occurrence deductible for the Mariner assets. Insurance covering the Forest Gulf of Mexico properties carried a $5 million deductible for each occurrence. Until the repairs are completed and we submit costs to our insurance underwriters for review, the full extent of our insurance recoveries and the resulting net cost to us for Hurricanes Katrina and Rita will be unknown. However, we expect the total costs not covered by the combined insurance policies to be less than $15 million.
 
Corporate Information
 
We were incorporated in August 1983 as a Delaware corporation. We have three subsidiaries, Mariner Energy Resources, Inc., a Delaware corporation, Mariner LP LLC, a Delaware limited liability company, and Mariner Energy Texas LP, a Delaware limited partnership. 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.


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The Exchange Offer
 
On April 24, 2006, we completed an unregistered offering of the old notes. As part of that offering, we entered into a registration rights agreement with the initial purchasers of the old notes in which we agreed, among other things, to use commercially reasonable efforts to complete the exchange offer which expired on November 9, 2006. Each broker-dealer (other than an affiliate of ours) that receives new notes for its own account in the exchange offer in exchange for securities that were acquired by such broker-dealer as a result of market-making or other trading activities must deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of new notes. In the registration rights agreement, we also agreed that for a period of 90 days after the exchange date, we will make this prospectus available to any broker-dealer for use in connection with any such resale. We refer to the old notes and the new notes (separately or collectively, as the context indicates) as the “notes.” The following is a brief summary of the exchange offer that expired on November 9, 2006. Please also see “Exchange Offer.”
 
Old Notes 71/2% Senior Notes due April 15, 2013, which were issued on April 24, 2006.
 
New Notes 71/2% Senior Notes due April 15, 2013. The terms of the new notes are substantially identical to those terms of the old notes, except that the transfer restrictions, registration rights and special interest provisions relating to the old notes do not apply to the new notes.
 
Exchange Offer We offered to exchange $300.0 million principal amount of our new notes that have been registered under the Securities Act for an equal amount of our old notes to satisfy our obligations under the registration rights agreement.
 
The new notes evidence the same debt as the old notes and are issued under and entitled to the benefits of the same indenture that governs the old notes. Holders of the old notes do not have any appraisal or dissenter’s rights in connection with the exchange offer. Because the new notes are registered, the new notes will not be subject to transfer restrictions, and holders of old notes that have tendered and had their old notes accepted in the exchange offer have no registration rights.
 
Expiration Date The exchange offer expired at 5:00 P.M., New York City time, on November 9, 2006. The ability to withdraw tenders of old notes pursuant to the exchange offer ceased upon expiration of the exchange offer.


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Description of Senior Notes
 
The terms of the new notes and those of the outstanding old notes are substantially identical, except that the transfer restrictions and registration rights relating to the old notes do not apply to the new notes. As a result, the new notes will not bear legends restricting their transfer and will not have the benefit of the registration rights and related special interest provisions contained in the old notes. The new notes represent the same debt as the old notes for which they are being exchanged. Both the old notes and the new notes are governed by the same indenture.
 
Issuer Mariner Energy, Inc.
 
Notes Offered $300,000,000 principal amount of its 71/2% Senior Notes due 2013.
 
Maturity Date April 15, 2013.
 
Interest Rate 71/2% per year (calculated using a 360-day year).
 
Interest Payment Dates Each April 15 and October 15, beginning October 15, 2006.
 
Ranking The notes are our general unsecured senior obligations. Accordingly, they rank:
 
• effectively subordinate to all of our existing and future secured indebtedness, including indebtedness under our credit facility, to the extent of the collateral securing such indebtedness;
 
• effectively subordinate to all existing and future indebtedness and other liabilities of any non-guarantor subsidiaries (other than indebtedness and liabilities owed to us);
 
• pari passu in right of payment to all of our existing and future senior unsecured indebtedness; and
 
• senior in right of payment to any future subordinated indebtedness.
 
As of September 30, 2006, we had total indebtedness of approximately $614 million, $300 million of which was the notes, and approximately $314 million of which was secured indebtedness to which the notes effectively were subordinated as to the value of the collateral. We also then had three letters of credit outstanding for $40.0 million, $10.4 million and $4.2 million, each of which effectively was senior to the notes to the extent of the collateral securing such indebtedness.
 
Subsidiary Guarantees The notes are jointly and severally guaranteed on a senior unsecured basis by our existing and future domestic subsidiaries. In the future, the guarantees may be released or terminated under certain circumstances. Each subsidiary guarantee ranks:
 
• effectively subordinate to all existing and future secured indebtedness of the guarantor subsidiary, including its guarantee of indebtedness under our credit facility, to the extent of the collateral securing such indebtedness;
 
• pari passu in right of payment to all existing and future senior unsecured indebtedness of the guarantor subsidiary; and
 
• senior in right of payment to any future subordinated indebtedness of the guarantor subsidiary.


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As of September 30, 2006, the guarantor subsidiary Mariner Energy Resources, Inc. had approximately $176.2 million of unsecured indebtedness outstanding under an intercompany note payable to us. The other two guarantor subsidiaries were guarantors but not indebted under our senior secured credit facility and had no other indebtedness outstanding.
 
Optional Redemption At any time prior to April 15, 2009, we may redeem up to 35% of each of the notes with the net cash proceeds of certain equity offerings at the redemption prices set forth under “Description of Senior Notes — Optional Redemption,” if at least 65% of the aggregate principal amount of the notes issued under the indenture remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering.
 
At any time prior to April 15, 2010, we may redeem the notes, in whole or in part, at a “make whole” redemption price set forth under “Description of Senior Notes — Optional Redemption.” On and after April 15, 2010, we may redeem the notes, in whole or in part, at the redemption prices set forth under “Description of Senior Notes — Optional Redemption.”
 
Change of Control Triggering Event If a Change of Control Triggering Event occurs, we must offer to repurchase the notes at the redemption price set forth under “Description of Senior Notes — Repurchase at the Option of Holders — Change of Control.”
 
Certain Covenants The indenture governing the notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to:
 
• make investments;
 
• incur additional indebtedness or issue preferred stock;
 
• create certain liens;
 
• sell assets;
 
• enter into agreements that restrict dividends or other payments from our subsidiaries to us;
 
• consolidate, merge or transfer all or substantially all of the assets of our company;
 
• engage in transactions with affiliates;
 
• pay dividends or make other distributions on capital stock or subordinated indebtedness; and
 
• create unrestricted subsidiaries.


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These covenants are subject to important exceptions and qualifications. In addition, substantially all of the covenants will terminate before the notes mature if one of two specified ratings agencies assigns the notes an investment grade rating in the future and no events of default exist under the indentures. Any covenants that cease to apply to us as a result of achieving an investment grade rating will not be restored, even if the credit rating assigned to the notes later falls below an investment grade rating. See “Description of Senior Notes — Certain Covenants.”
 
Absence of Established Market for the Notes The new notes are generally freely transferable but are also new securities for which there will not initially be a market. Accordingly, we cannot assure you as to the development or liquidity of any market for the new notes. The notes will be eligible for trading in the PORTALsm Market. We do not intend to apply for a listing of the new notes on any securities exchange or for the inclusion on any automated dealer quotation system.
 
Use of Proceeds We will not receive any proceeds from the exchange offer.


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Summary Historical Financial Information
 
The following table shows Mariner’s summary historical consolidated financial data as of and for the nine months ended September 30, 2006 and September 30, 2005, the year ended December 31, 2005, the period from January 1, 2004 through March 2, 2004, the period from March 3, 2004 through December 31, 2004, and each of the three years ended December 31, 2003. The summary historical consolidated financial data for the year ended December 31, 2005, the period from January 1, 2004 through March 2, 2004, the period from March 3, 2004 through December 31, 2004, and each of the three years ended December 31, 2003 are derived from Mariner’s audited financial statements included herein, and the historical consolidated financial data as of and for the two years ended December 31, 2002 are derived from Mariner’s audited financial statements that are not included herein. The summary historical consolidated financial data for the nine months ended September 30, 2006 and the nine months ended September 30, 2005 has been derived from Mariner’s unaudited financial statements. 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 with Forest Energy Resources. Mariner’s historical results are not necessarily indicative of results to be expected in future periods.
 
The merger between a subsidiary of Mariner and Forest Energy Resources was consummated on March 2, 2006. Accordingly, the financial information as of September 30, 2006 below includes the Forest Gulf of Mexico operations as of and after March 2, 2006.
 
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 Post-2004 Merger activity (for the March 3, 2004 through December 31, 2004 period, the year ended December 31, 2005 and the nine months ended September 30, 2006 and September 30, 2005) and Pre-2004 Merger activity (for all periods prior to March  2, 2004) 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.
 


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    Post-2004 Merger       Pre-2004 Merger  
                      Period from
      Period from
                   
                      March 3,
      January 1,
                   
                      2004
      2004
                   
    Nine Months Ended
    Year Ended
    through
      through
                   
    September 30,     December 31,
    December 31,
      March 2,
    Year Ended December 31,  
    2006     2005     2005     2004       2004     2003     2002     2001  
    (In millions, except per share data)  
 
                                                                 
Statement of Operations Data:
                                                                 
Total revenues(1)
  $ 438.4     $ 151.2     $ 199.7     $ 174.4       $ 39.8     $ 142.5     $ 158.2     $ 155.0  
Lease operating expenses
    62.9       17.7       24.9       19.3         3.5       23.2       25.2       19.2  
Severance and ad valorem taxes
    5.7       2.5       5.0       2.1         0.6       1.5       0.9       0.9  
Transportation expenses
    4.0       1.7       2.3       1.9         1.1       6.3       10.5       12.0  
Depreciation, depletion and amortization
    192.2       43.4       59.4       54.3         10.6       48.3       70.8       63.5  
Impairment of production equipment held for use
          0.5       1.8       1.0                            
Derivative settlement
                                    3.2              
Impairment of Enron related receivables
                                          3.2       29.5  
General and administrative expenses
    25.1       26.7       37.1       7.6         1.1       8.1       7.7       9.3  
                                                                   
Operating income
    148.5       58.7       69.2       88.2         22.9       51.9       39.9       20.6  
Interest income
    0.5       0.7       0.8       0.2         0.1       0.8       0.4       0.7  
Interest expense
    (26.4 )     (5.4 )     (8.2 )     (6.0 )             (7.0 )     (10.3 )     (8.9 )
                                                                   
Income before income taxes
    122.6       54.0       61.8       82.4         23.0       45.7       30.0       12.4  
Provision for income taxes
    (44.4 )     (18.4 )     (21.3 )     (28.8 )       (8.1 )     (9.4 )            
                                                                   
Income before cumulative effect of change in accounting method net of tax effects
  $ 78.2     $ 35.6       40.5       53.6         14.9       36.3       30.0       12.4  
                                                                   
Income before cumulative effect per common share
                                                                 
Basic
  $ 1.07     $ 1.10       1.24       1.80         0.50       1.22       1.01       0.42  
Diluted
    1.06       1.07       1.20       1.80         0.50       1.22       1.01       0.42  
Cumulative effect of changes in accounting method
                                    1.9              
Net income
  $ 78.2     $ 35.6     $ 40.5     $ 53.6       $ 14.9     $ 38.2     $ 30.0     $ 12.4  
Net income per common share
                                                                 
Basic
  $ 1.07     $ 1.10     $ 1.24     $ 1.80       $ 0.50     $ 1.29     $ 1.01     $ 0.42  
Diluted
    1.06       1.07       1.20       1.80         0.50       1.29       1.01       0.42  
Capital Expenditure and Disposal Data:
                                                                 
Exploration, including leasehold/seismic
    169.1       23.6     $ 60.9     $ 40.4       $ 7.5     $ 31.6     $ 40.4     $ 66.3  
Development and other
    347.9       106.8       191.8       93.2         7.8       51.7       65.7       98.2  
Proceeds from property conveyances
    (2.0 )                               (121.6 )     (52.3 )     (90.5 )
Total capital expenditures net of proceeds from property conveyances
    515.0       130.4     $ 252.7     $ 133.6       $ 15.3     $ (38.3 )   $ 53.8     $ 74.0  

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(1) Includes effects of hedging.
 
                                                           
    Post-2004 Merger       Pre-2004 Merger  
    September 30,     December 31,
    December 31,
      December 31,  
    2006     2005     2005     2004       2003     2002     2001  
    (In millions)  
Balance Sheet Data(1)
                                                         
Property and equipment, net, full cost method
  $ 2,061.9     $ 393.3     $ 515.9     $ 303.8       $ 207.9     $ 287.6     $ 290.6  
Total assets
    2,700.7       502.2       665.5       376.0         312.1       360.2       363.9  
Long-term debt, less current maturities
    614.0       79.0       156.0       115.0               99.8       99.8  
Stockholders’ equity
    1,267.1       178.6       213.3       133.9         218.2       170.1       180.1  
Working capital (deficit)(2)
    (75.3 )     (30.2 )     (46.4 )     (18.7 )       38.3       (24.4 )     (19.6 )
Other Financial Data
                                                         
Ratio of earnings to fixed charges(3)
    5.43       10.23       7.88       17.17         6.83       3.56       1.82  
 
                                                         
 
 
(1) Balance sheet data as of September 30, 2006 reflects consolidation of the assets of the Forest Gulf of Mexico operations effective March 2, 2006. Balance sheet data as of December 31, 2004 reflects purchase accounting adjustments to oil and gas properties, total assets and stockholders’ 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.
 
(3) For the purposes of determining the ratio of earnings to fixed charges, earnings consist of income before taxes, plus fixed charges, less capitalized interest, and fixed charges consist of interest expense (net of capitalized interest), plus capitalized interest, plus amortized discounts related to indebtedness.
 


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    Post-2004 Merger       Pre-2004 Merger  
                      Period from
      Period from
                   
                      March 3,
      January 1,
                   
                      2004
      2004
                   
    Nine Months Ended
    Year Ended
    through
      through
                   
    September 30,     December 31,
    December 31,
      March 2,
    Year Ended December 31,  
    2006     2005     2005     2004       2004     2003     2002     2001  
    (In millions)  
Other Financial Data:
                                                                 
EBITDA(1)
  $ 340.7     $ 102.7     $ 130.4     $ 143.5       $ 33.4     $ 100.3     $ 113.9     $ 113.6  
Net cash provided by operating activities
    172.8       135.4       165.4       135.2         20.3       88.9       60.3       113.5  
Net cash (used) provided by investing activities
    (423.5 )     (142.1 )     (247.8 )     (133.0 )       (15.3 )     52.9       (53.8 )     (74.0 )
Net cash (used) provided by financing activities
    251.0       8.7       84.4       64.9               (100.0 )           (30.0 )
Reconciliation of Non-GAAP Measures:
                                                                 
EBITDA(1)
  $ 340.7     $ 102.7     $ 130.4     $ 143.5       $ 33.4     $ 100.3     $ 113.9     $ 113.6  
Changes in working capital
    (158.9 )     25.1       20.0       6.2         (13.2 )     7.2       (20.4 )     7.5  
Non-cash hedge gain/(loss)(2)
    8.2       (3.6 )     (4.5 )     (7.9 )             (2.0 )     (23.2 )      
Amortization/other
    (0.3 )     0.9       1.2       0.8                     (0.1 )     0.6  
Stock compensation expense
    9.0       17.6       25.7                                  
Net interest expense
    (25.9 )     (4.7 )     (7.4 )     (5.8 )       0.1       (6.2 )     (9.9 )     (8.2 )
Income tax expense
          (2.6 )           (1.6 )             (10.4 )            
                                                                   
Net cash provided by operating activities
  $ 172.8     $ 135.4     $ 165.4     $ 135.2       $ 20.3     $ 88.9     $ 60.3     $ 113.5  
                                                                   
 
                                                                 
 
 
(1) EBITDA means earnings before interest, income taxes, depreciation, depletion and amortization and impairments. For the nine months ended September 30, 2006 and 2005, EBITDA includes $9.0 million and $17.6 million, respectively, in non-cash compensation expense related to restricted stock and stock options. For the year ended December 31, 2005, EBITDA includes $25.7 million in non-cash 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 dedesignation 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. 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. The value at the time of the merger and included in AOCI has reversed out of AOCI and into earnings as the original corresponding production, as hedged by the contracts, is produced. We have designated subsequent hedge contracts as cash flow hedges with gains and losses resulting from the transactions recorded at market value in AOCI, as appropriate, until recognized as operating income in our Statement of Operations as the physical production hedged by the contracts is delivered.

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Summary Selected Unaudited Pro Forma Combined Condensed Financial Information
 
The merger between a subsidiary of Mariner and Forest Energy Resources was consummated on March 2, 2006. Accordingly, actual balance sheet information of the combined company as of September 30, 2006 is included elsewhere in this prospectus.
 
The following unaudited pro forma combined condensed operating results for the nine months ended September 30, 2006 and the year ended December 31, 2005 give effect to the merger as if it had occurred on January 1, 2005. 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 36.
 
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.
 
                 
    Nine Months
    Year Ended
 
    Ended
    December 31,
 
    September 30, 2006     2005  
    (In millions, except earnings per share and share data)  
 
OPERATING RESULTS:
               
Revenues
  $ 505.9     $ 592.0  
Net income
    92.6       58.0  
Earnings per share
               
Basic
  $ 1.09     $ 0.70  
Diluted
  $ 1.09     $ 0.69  
Weighted average shares outstanding
               
Basic
    84,770,289       83,304,592  
Diluted
    85,245,547       84,454,427  


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Summary Reserve and Operating Data
 
The following tables present certain information with respect to our estimated proved oil and natural gas reserves at year end and operating data for the periods presented. The 2005 information is also presented on a pro forma basis, giving effect to our merger with Forest Energy Resources as though it had been consummated on January 1, 2005. We consummated the merger on March  2, 2006.
 
Estimated Proved Reserves
 
The reserve information in the table below for Mariner is based on estimates made in reserve reports prepared by Ryder Scott. The reserve information as of December 31, 2005 for the Forest Gulf of Mexico operations is based on estimates made by internal staff engineers at Forest, which estimates were audited by Ryder Scott. Accordingly, the pro forma reserve information presented below includes both reserves that were estimated by Ryder Scott and reserves that were estimated by internal staff engineers at Forest and audited by Ryder Scott.
 
                                 
    Pro Forma
    As of the Year Ended
 
    Year Ended     December 31,  
    December 31, 2005     2005     2004     2003  
 
Estimated proved oil and natural gas reserves:
                               
Natural gas reserves (Bcf)
    438.8       207.7       151.9       127.6  
Oil (MMbbls)
    34.1       21.6       14.3       13.1  
Total proved oil and natural gas reserves (Bcfe)
    643.7       337.6       237.5       206.1  
Total proved developed reserves (Bcfe)
    362.3       167.4       109.4       96.6  
PV10 value ($ in millions):
                               
Proved developed reserves
  $ 2,023.4     $ 849.6     $ 335.4     $ 314.6  
Proved undeveloped reserves
    1,028.4       432.2       332.6       218.9  
Total PV10 value
    3,051.8       1,281.8       668.0       533.5  
Standardized measure
    2,201.7       906.6       494.4       418.2  
Prices used in calculating end of period proved reserve measures (excluding effects of hedging)(1):
                               
Natural gas ($/MMBtu)
  $ 10.05     $ 10.05     $ 6.15     $ 5.96  
Oil ($/bbl)
    61.04       61.04       43.45       32.52  
 
 
(1) Our PV10 values have been calculated using NYMEX prices at the end of the relevant period, as adjusted for our price differentials. Please read Note 11 to the audited Mariner financial statements contained in this prospectus.


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Operating Data
 
The following table presents certain information with respect to our production and operating data for the periods presented. Information for the nine months ended September 30, 2006 and the year ended December 31, 2005 also is presented on a pro forma basis, giving effect to our merger with Forest Energy Resources as though it had been consummated on January 1, 2005. The merger was consummated on March 2, 2006.
 
                                                 
    Pro Forma     Nine Months
                   
    Nine Months
    Year Ended
    Ended
                   
    Ended
    December 31,
    September 30,
    Year Ended December 31,  
    September 30, 2006     2005     2006     2005     2004     2003  
 
Production:
                                               
Natural gas (Bcf)
    45.6       67.5       39.3       18.4       23.8       23.8  
Oil (Mbbls)
    2.8       4.6       2.5       1.8       2.3       1.6  
Total natural gas equivalent (Bcfe)
    62.4       94.9       54.5       29.1       37.6       33.4  
Average daily natural gas equivalent (MMcfe)
    228.5       260.0       200.0       79.7       103.0       91.5  
Average realized sales price per unit (excluding the effects of hedging):
                                               
Natural gas ($/Mcf)
  $ 7.25     $ 8.04     $ 7.05     $ 8.33     $ 6.12     $ 5.43  
Oil ($/bbl)
    61.23       48.86       62.13       51.66       38.52       26.85  
Total natural gas equivalent ($/Mcfe)
    8.05       8.07       7.94       8.43       6.23       5.15  
Average realized sales price per unit (including the effects of hedging):
                                               
Natural gas ($/Mcf)
  $ 7.42     $ 6.40     $ 7.25     $ 6.66     $ 5.80     $ 4.40  
Oil ($/bbl)
    58.95       34.18       59.58       41.23       33.17       23.74  
Total natural gas equivalent ($/Mcfe)
    8.07       6.20       8.00       6.74       5.70       4.27  
Expenses ($/Mcfe):
                                               
Lease operating expenses
  $ 1.26     $ 1.04     $ 1.15     $ 0.86     $ 0.61     $ 0.69  
Severance and ad valorem taxes
    0.10       0.13       0.10       0.17       0.07       0.05  
Transportation
    0.07       0.06       0.07       0.08       0.08       0.19  
General and administrative, net(1)
                0.46       1.27       0.23       0.24  
Depreciation, depletion and amortization (excluding impairments)(2)
    3.51       3.47       3.53       2.04       1.73       1.45  
 
 
(1) Net of overhead reimbursements received from other working interest owners and amounts capitalized under the full cost accounting method. Includes non-cash stock compensation expense of $9.0 million for the nine months ended September 30, 2006 and $17.6 million in 2005. General and administrative expenses, net of capitalized amounts, are not included in pro forma 2005 because accounts of such costs were not historically maintained for the Forest Gulf of Mexico operations as a separate business unit. We


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believe the overhead costs associated with the Forest Gulf of Mexico operations in 2006 will approximate $6.4 million, net of capitalized amounts.
 
(2) Pro forma depreciation, depletion and amortization gives effect to the acquisition of the Forest Gulf of Mexico operations and a preliminary estimate of their step-up in value basis the unit of production method under the full cost method of accounting.


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RISK FACTORS
 
You should consider carefully the following risks, as well as the other information set forth in this prospectus, before deciding to participate in the exchange offer. Any of the following risks could materially adversely affect our business, financial condition or results of operations, which in turn could adversely affect our ability to pay the notes. In such case, you may lose all or part of your original investment.
 
Risks Related to the Exchange Offer
 
If you do not properly tender your old notes, you will continue to hold unregistered outstanding notes and your ability to transfer those notes will be adversely affected.
 
If you do not exchange your old notes for new notes in the exchange offer, you will continue to be subject to the restrictions on transfer of your old notes described in the legend on the certificates representing your old notes. In general, you may only offer or sell the old notes if they are registered under the Securities Act and applicable state securities laws or offered and sold under an exemption from those requirements. We do not plan to register any sale of the old notes under the Securities Act unless required to do so under the limited circumstances set forth in the registration rights agreement. In addition, the issuance of the new notes may adversely affect the trading market for untendered, or tendered but unaccepted, old notes. For further information regarding the consequences of not tendering your old notes in the exchange offer, see “The Exchange Offer — Consequences of Failure to Exchange” and “Material United States Federal Income Tax Considerations.”
 
We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes and you should carefully follow the instructions on how to tender your old notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of old notes. See “The Exchange Offer — Procedures for Tendering Old Notes” and “Description of Senior Notes.”
 
You may find it difficult to sell your new notes.
 
Because there is no public market for the new notes, you may not be able to resell them. The new notes will be registered under the Securities Act but will constitute a new issue of securities with no established trading market. An active market may not develop for the new notes and any trading market that does develop may not be liquid. We do not intend to apply to list the new notes for trading on any securities exchange or to arrange for quotation on any automated dealer quotation system. The trading market for the new notes may be adversely affected by:
 
  •  changes in the overall market for non-investment grade securities;
 
  •  changes in our financial performance or prospects;
 
  •  the prospects for companies in our industry generally;
 
  •  the number of holders of the new notes;
 
  •  the interest of securities dealers in making a market for the new notes; and
 
  •  prevailing interest rates and general economic conditions.
 
Historically, the market for non-investment grade debt has been subject to substantial volatility in prices. The market for the new notes, if any, may be subject to similar volatility. Prospective investors in the new notes should be aware that they may be required to bear the financial risks of such investment for an indefinite period of time.
 
Some holders who exchange their old notes may be deemed to be underwriters.
 
If you exchange your old notes in the exchange offer for the purpose of participating in a distribution of the new notes, you may be deemed to have received restricted securities and, if so, will be required to comply


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with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction. See “The Exchange Offer — Resale of the New Notes; Plan of Distribution.”
 
Risks Relating to the Oil and Natural Gas Industry and to Our Business
 
Oil and natural gas prices are volatile, and a decline in oil and natural gas prices would reduce our revenues, profitability and cash flow and impede our growth.
 
Our revenues, profitability and cash flow depend substantially upon the prices and demand for oil and natural gas. The markets for these commodities are volatile and even relatively modest drops in prices can affect significantly our financial results and impede our growth. 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 62% of our estimated proved reserves (68% on a pro forma basis) as of December 31, 2005 were natural gas reserves, our financial results are more sensitive to movements in natural gas prices. Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations.
 
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will affect materially the quantities and present value of our reserves, which may lower our bank borrowing base and reduce our access to capital.
 
Estimating oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing estimates we project production rates and timing of development expenditures. We also analyze the available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates, perhaps significantly. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and


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other factors, many of which are beyond our control. At December 31, 2005, 50% of our estimated proved reserves were proved undeveloped (44% on a pro forma basis).
 
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.
 
In estimating future net revenues from proved reserves, we assume that future prices and costs are fixed and apply a fixed discount factor. If any such assumption or the discount factor is 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 referred to in this prospectus is not necessarily the actual current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on fixed prices and costs as of the date of the estimate. Actual future prices and costs fluctuate over time and may differ materially from those used in the present value estimate. In addition, discounted future net cash flows are estimated assuming that royalties to the Minerals Management Service, or 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,” and “Business — Legal Proceedings.” Since actual future prices fluctuate over time, royalties may be required to be paid for various portions of the life of the properties and suspended for other portions of the life of the properties.
 
The timing of both the production and expenses from the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In addition, the 10% discount factor that we use to calculate the net present value of future net cash flows for reporting purposes in accordance with the SEC’s rules may not necessarily be the most appropriate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor in arriving at an accurate net present value of future net cash flows.
 
If oil and natural gas prices decrease, we may be required to write-down the carrying value and/or the estimates of total reserves of our oil and natural gas properties.
 
Accounting rules applicable to us require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur non-cash charges in the future, which could have a material adverse effect on our results of operations in the period taken. We may also reduce our estimates of the reserves that may be economically recovered, which could have the effect of reducing the value of our reserves.
 
We need to replace our reserves at a faster rate than companies whose reserves have longer production periods. Our failure to replace our reserves would result in decreasing reserves and production over time.
 
Unless we conduct successful exploration and development activities or acquire properties containing proven reserves, our proved reserves will decline as reserves are depleted. Producing oil and natural gas reserves are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. High production rates generally result in recovery of a relatively higher percentage of reserves from properties during the initial few years of production. A significant portion of our current operations are conducted in the Gulf of Mexico, especially since our merger with Forest Energy Resources. Production from reserves in the Gulf of Mexico generally declines more rapidly than reserves from reservoirs in other producing regions. As a result, our need to replace reserves from new investments is relatively greater than those of producers who produce their reserves over a longer time period, such as those


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producers whose reserves are located in areas where the rate of reserve production is lower. If we are not able to find, develop or acquire additional reserves to replace our current and future production, our production rates will decline even if we drill the undeveloped locations that were included in our proved reserves. Our future oil and natural gas reserves and production, and therefore our cash flow and income, are dependent on our success in economically finding or acquiring new reserves and efficiently developing our existing reserves.
 
Approximately 65% of our total estimated proved reserves are either developed non-producing or undeveloped (71% on a pro forma basis), and those reserves may not ultimately be produced or developed.
 
As of December 31, 2005, approximately 15% of our total estimated proved reserves were developed non-producing (27% on a pro forma basis) and approximately 50% were undeveloped (44% on a pro forma basis). These reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced during the time periods we have planned, at the costs we have budgeted, or at all, which in turn may have in a material adverse effect on our results of operations.
 
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 is 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


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techniques only assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators. 3-D seismic data does not enable an interpreter to conclusively determine whether hydrocarbons are present or producible economically. In addition, the use of 3-D seismic and other advanced technologies require greater predrilling expenditures than other 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, such as hurricanes and other adverse weather conditions;
 
  •  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 our operations, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments.”
 
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 utilize subsea completion and tieback technology. As of September 30, 2006, we had 18 subsea wells. These wells were tied back to 13 host production facilities for production processing. An additional nine wells were then under development for tieback to five additional host production facilities. The installation of subsea production systems to tieback and operate subsea wells requires substantial time and the use of advanced and very sophisticated installation equipment supported by remotely operated vehicles. These operations may encounter mechanical difficulties and equipment failures that could result in significant cost overruns. Furthermore, the deepwater operations generally lack the physical


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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, our hedging arrangements reduced the benefit we received from increases in the prices for oil and natural gas by approximately $49 million for the calendar year 2005 and increased the benefit we received by $1.5 million for the nine months ended September 30, 2006. 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, exploration arrangements with other parties, the issuance of debt securities, 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 we acquired in March 2006) 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


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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 in availability 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 adversely affect our ability to timely complete the exploration and development of our prospects.
 
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


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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 timing or scope of drilling and development activities on properties we do not operate, and therefore we may not be in a position to control 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, or 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.
 
Compliance with MMS regulations could significantly delay or curtail our operations or require us to make material expenditures, all of which could have a material adverse effect on our financial condition or results of operations.
 
A significant portion of our operations are located on federal oil and natural gas leases that are administered by the MMS. As an offshore operator, we must obtain MMS approval for our exploration, development and production plans prior to commencing such operations. The MMS has promulgated regulations that, among other things, require us to meet stringent engineering and construction specifications, restrict the flaring or venting of natural gas, govern the plug and abandonment of wells located offshore and


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the installation and removal of all production facilities, and govern the calculation of royalties and the valuation of crude oil produced from federal leases.
 
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 which 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. In addition, we have not yet been able to determine the full extent of our insurance recovery and the net cost to us resulting from the hurricanes. See “Business — Insurance Matters” for more information.
 
Risks Relating to Our Merger with Forest Energy Resources
 
The integration of the Forest Gulf of Mexico operations 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 prior to the merger;
 
  •  the possibility of 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 our 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, our results of operations may be lower than we 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


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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, our results of operations may be adversely affected.
 
We expect to incur significant charges relating to the integration plan that could materially and adversely affect our period-to-period results of operations.
 
We anticipate that from time to time we will incur charges to our earnings in connection with the integration of the Forest Gulf of Mexico operations into our business. 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 are not yet able to quantify the costs or timing of the integration. Some factors affecting the cost of the integration include 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 were provided by Forest. During the nine months ended September 30, 2006, we incurred approximately $2.6 million of such costs.
 
In order to preserve the tax-free treatment of the spin-off of Forest Energy Resources, we are 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.
 
In connection with the merger we entered into a tax sharing agreement, which imposes ongoing restrictions on Forest and on us to ensure that applicable statutory requirements under the Internal Revenue Code of 1986, as amended, or the Code, and applicable Treasury regulations continue to be met so that the spin-off of Forest Energy Resources 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 could have a negative impact on our business.
 
Risks Relating to the Notes
 
We may not be able to generate enough cash flow to meet our debt obligations.
 
We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments, including the notes. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt, including the notes. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.


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If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:
 
  •  refinancing or restructuring our debt;
 
  •  selling assets;
 
  •  reducing or delaying capital investments; or
 
  •  seeking to raise additional capital.
 
However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under the notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.
 
The notes and the guarantees will be unsecured and effectively subordinated to our and our subsidiary guarantors’ existing and future secured indebtedness.
 
The notes and the guarantees are general unsecured senior obligations ranking effectively junior in right of payment to all existing and future secured debt of ours and that of each subsidiary guarantor, respectively, including obligations under our credit facility, to the extent of the value of the collateral securing the debt. As of September 30, 2006, after giving effect to borrowings under our amended and restated credit facility and to the offering of the old notes and the application of the proceeds therefrom, our total indebtedness was $614.0 million, $300.0 million of which was the old notes and $314.0 million of which effectively was senior in right of payment to the notes to the extent of the value of the collateral securing that indebtedness. We also then had three letters of credit outstanding for $40.0 million, $10.4 million and $4.2 million, each of which effectively is senior to the notes to the extent of the collateral securing such indebtedness. Further, we then had $121.4 million in additional borrowing capacity under our credit facility which if borrowed would have been secured debt effectively senior in right of payment to the notes to the extent of the value of the collateral securing that indebtedness.
 
If we or a subsidiary guarantor are declared bankrupt, become insolvent or are liquidated or reorganized, any secured debt of ours or that subsidiary guarantor will be entitled to be paid in full from our assets or the assets of the guarantor, as applicable, securing that debt before any payment may be made with respect to the notes or the affected guarantees. Holders of the notes participate ratably with all holders of our unsecured indebtedness that does not rank junior to the notes, including all of our other general creditors, based upon the respective amounts owed to each holder or creditor, in our remaining assets. In any of the foregoing events, we cannot assure you that there will be sufficient assets to pay amounts due on the notes. As a result, holders of the notes would likely receive less, ratably, than holders of secured indebtedness.
 
Our debt level and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations and business prospects and prevent us from fulfilling our obligations under the notes.
 
Our level of indebtedness, and the covenants contained in the agreements governing our debt, could have important consequences for our operations, including by:
 
  •  making it more difficult for us to satisfy our obligations under the notes or other debt and increasing the risk that we may default on our debt obligations;
 
  •  requiring us to dedicate a substantial portion of our cash flow from operations to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;
 
  •  limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities;
 
  •  limiting management’s discretion in operating our business;


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  •  limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
 
  •  detracting from our ability to withstand successfully a downturn in our business or the economy generally;
 
  •  placing us at a competitive disadvantage against less leveraged competitors; and
 
  •  making us vulnerable to increases in interest rates, because debt under our credit facility will in some cases vary with prevailing interest rates.
 
We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the consequent acceleration of our obligation to repay outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions.
 
In addition, under the terms of our credit facility and the indenture, we must comply with certain financial covenants, including current asset and total debt ratio requirements. Our ability to comply with these covenants in future periods will depend on our ongoing financial and operating performance, which in turn will be subject to general economic conditions and financial, market and competitive factors, in particular the selling prices for our products and our ability to successfully implement our overall business strategy.
 
The breach of any of the covenants in the indenture or the credit facility could result in a default under the applicable agreement which would permit the applicable lenders or noteholders, as the case may be, to declare all amounts outstanding thereunder to be due and payable, together with accrued and unpaid interest. We may not have sufficient funds to make such payments. If we are unable to repay our debt out of cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to generate sufficient cash flow to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt. The terms of our debt, including our credit facility, may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions, restrictions in our tax sharing agreement with Forest and the value of our assets and operating performance at the time of such offering or other financing. We cannot assure you that any such offering, refinancing or sale of assets could be successfully completed.
 
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
 
Borrowings under our credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.
 
Despite our and our subsidiaries’ current level of indebtedness, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial indebtedness.
 
We and our subsidiaries may be able to incur substantial additional indebtedness in the future, subject to certain limitations. The terms of our indenture will not prohibit us or our subsidiaries from doing so. For example, as of September 30, 2006, we were able to borrow up to $362.5 million on a revolving basis under our credit facility that was increased to $450 million in October 2006. If new debt is added to our current debt levels, the related risks that we and our subsidiaries now face could intensify. Our level of indebtedness could, for instance, prevent us from engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional


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indebtedness could make it more difficult to satisfy our existing financial obligations, including those relating to the notes.
 
We may not be able to repurchase the notes upon a change of control.
 
Upon the occurrence of certain change of control events, we are required to offer to repurchase all or any part of the notes then outstanding for cash at 101% of the principal amount. The source of funds for any repurchase required as a result of any change of control will be our available cash or cash generated from our operations or other sources, including:
 
  •  borrowings under our credit facilities or other sources;
 
  •  sales of assets; or
 
  •  sales of equity.
 
We cannot assure you that sufficient funds would be available at the time of any change of control to repurchase your notes. In addition, our credit facility prohibits, and any future credit facilities may prohibit, such repurchases. Additionally, a “change of control” (as defined in the indenture for the notes) will be an event of default under our credit facility that would permit the lenders to accelerate the debt outstanding under the credit facility. Finally, using available cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future, which could negatively impact our ability to conduct our business operations.
 
A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S. bankruptcy or similar state law, which would prevent the holders of the notes from relying on that subsidiary to satisfy claims.
 
Under U.S. bankruptcy law and comparable provisions of state fraudulent transfer laws, our subsidiary guarantees can be voided, or claims under the subsidiary guarantees may be subordinated to all other debts of that subsidiary guarantor if, among other things, the subsidiary guarantor, at the time it incurred the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee, received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and:
 
  •  was insolvent or rendered insolvent by reason of such incurrence;
 
  •  was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or
 
  •  intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.
 
Our subsidiary guarantees may also be voided, without regard to the above factors, if a court found that the subsidiary guarantor entered into the guarantee with the actual intent to hinder, delay or defraud its creditors.
 
A court would likely find that a subsidiary guarantor did not receive reasonably equivalent value or fair consideration for its guarantee if the subsidiary guarantor did not substantially benefit directly or indirectly from the issuance of the guarantees. If a court were to void a subsidiary guarantee, you would no longer have a claim against the subsidiary guarantor. Sufficient funds to repay the notes may not be available from other sources, including the remaining subsidiary guarantors, if any. In addition, the court might direct you to repay any amounts that you already received from the subsidiary guarantor.
 
The measures of insolvency for purposes of fraudulent transfer laws vary depending upon the governing law. Generally, a guarantor would be considered insolvent if:
 
  •  the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all its assets;


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  •  the present fair saleable value of its assets is less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or
 
  •  it could not pay its debts as they become due.
 
Each subsidiary guarantee contains a provision intended to limit the subsidiary guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its subsidiary guarantee to be a fraudulent transfer. Such provision may not be effective to protect the subsidiary guarantees from being voided under fraudulent transfer law.
 
A financial failure by us or our subsidiaries may result in the assets of any or all of those entities becoming subject to the claims of all creditors of those entities.
 
A financial failure by us or our subsidiaries could affect payment of the notes if a bankruptcy court were to substantively consolidate us and our subsidiaries. If a bankruptcy court substantively consolidated us and our subsidiaries, the assets of each entity would become subject to the claims of creditors of all entities. This would expose holders of notes not only to the usual impairments arising from bankruptcy, but also to potential dilution of the amount ultimately recoverable because of the larger creditor base. Furthermore, forced restructuring of the notes could occur through the “cram-down” provisions of the bankruptcy code. Under these provisions, the notes could be restructured over your objections as to their general terms, primarily interest rate and maturity.


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THE EXCHANGE OFFER
 
This section of the prospectus describes certain aspects of the exchange offer which expired on November 9, 2006. Each broker-dealer (other than an affiliate of ours) that receives new notes for its own account in the exchange offer in exchange for securities that were acquired by such broker-dealer as a result of market-making or other trading activities must deliver a prospectus meeting the requirements of the Securities Act of 1933 in connection with any resale of new notes. We have agreed that, for a period of 90 days after the exchange date, we will make the prospectus available to any broker-dealer for use in connection with any such resale. While we believe that this description covers the material terms of the exchange offer that may remain relevant notwithstanding expiration or the exchange offer, this summary may not contain all of the information that is important to you. You should carefully read this entire document.
 
Purpose and Effects of the Exchange Offer
 
We initially issued $300.0 million principal amount of old notes on April 24, 2006 in a private offering. The initial purchasers subsequently offered and sold a portion of the old notes only to “qualified institutional buyers” as defined in and in compliance with Rule 144A and outside the United States in compliance with Regulation S of the Securities Act.
 
In connection with the sale of the old notes, we entered into an exchange and registration rights agreement, which requires us
 
  •  to cause the old notes to be registered under the Securities Act, or
 
  •  to file with the SEC a registration statement under the Securities Act with respect to an issue of new notes identical in all material respects to the old notes, and
 
  •  use our commercially reasonable efforts to cause such registration statement to become effective under the Securities Act, and
 
  •  upon the effectiveness of that registration statement, to offer to the holders of the old notes the opportunity to exchange their old notes for a like principal amount of new notes, which will be issued without a restrictive legend and which may be reoffered and resold by the holder without restrictions or limitations under the Securities Act.
 
We made the exchange offer to satisfy our obligations under the exchange and registration rights agreement. The term “holder” with respect to the exchange offer means any person in whose name old notes are registered on our or the Depository Trust Company’s (“DTC”) books or any other person who has obtained a properly completed bond power from the registered holder, or any person whose old notes are held of record by DTC who desires to deliver such old notes by book-entry transfer at DTC.
 
We have not requested, and do not intend to request, an interpretation by the staff of the SEC with respect to whether the new notes issued in the exchange offer in exchange for the old notes may be offered for sale, resold or otherwise transferred by any holder without compliance with the registration and prospectus delivery provisions of the Securities Act. Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe the new notes issued in exchange for old notes may be offered for resale, resold and otherwise transferred by any holder without compliance with the registration and prospectus delivery provisions of the Securities Act provided that:
 
  •  you are not a broker-dealer who purchased old notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act,
 
  •  you are not our or any subsidiary guarantor’s “affiliate”, or
 
  •  you acquire the new notes in the ordinary course of your business and that you have no arrangement or understanding with any person to participate in the distribution of the new notes.
 
Any holder who tenders in the exchange offer with the intention to participate, or for the purpose of participating, in a distribution of the new notes or who is our affiliate may not rely upon such interpretations by the staff of the SEC and, in the absence of an exemption, must comply with the registration and prospectus


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delivery requirements of the Securities Act in connection with any secondary resale transaction. Any holder to comply with such requirements may incur liabilities under the Securities Act for which the holder is not indemnified by us.
 
Resale of the New Notes; Plan of Distribution
 
Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. In addition, until January 8, 2007, all dealers effecting transactions in the new notes, whether or not participating in this distribution, may be required to deliver a prospectus. This requirement is in addition to the obligation of dealers to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
 
We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions:
 
  •  in the over-the-counter market,
 
  •  in negotiated transactions,
 
  •  through the writing of options on the new notes or a combination of such methods of resale,
 
  •  at market prices prevailing at the time of resale,
 
  •  at prices related to such prevailing market prices, or
 
  •  at negotiated prices.
 
Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes.
 
Any broker-dealer that resells new notes received for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such new notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of new notes and any commission on concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver a prospectus and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.


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USE OF PROCEEDS
 
The exchange offer was intended to satisfy our obligations under the registration rights agreement. We will not receive any proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated in this prospectus, we will receive, in exchange, outstanding old notes in like principal amount. We will cancel all old notes surrendered in exchange for new notes in the exchange offer. As a result, the issuance of the new notes will not result in any increase or decrease in our indebtedness.
 
The net proceeds from the offering of the sale of the old notes in the initial private placement were approximately $287.9 million. We used those proceeds, together with cash on hand, to repay borrowings under our amended and restated credit facility. The borrowings under the credit facility were used to:
 
  •  refinance indebtedness incurred by Forest Energy Resources in connection its acquisition by us.
 
  •  pay transaction expenses associated with the merger; and
 
  •  repay $165.0 million under our prior credit facility with Union Bank of California.


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CAPITALIZATION
 
The following table sets forth our consolidated capitalization as of September 30, 2006.
 
This table should be read together with our financial statements and the related notes included in this prospectus.
 
         
    As of September 30,
 
    2006  
    (In thousands)  
 
Long-term debt:
       
Credit facility — revolving note(1)
  $ 314,000  
Senior Notes
    300,000  
Total long-term debt
    614,000  
Stockholders’ Equity
  $ 1,267,062  
Total capitalization
  $ 1,881,062  
 
 
(1) In connection with our merger with Forest Energy Resources on March 2, 2006, we amended and restated our existing secured credit facility to, among other things, increase maximum credit availability to $500 million for revolving loans, including up to $50 million in letters of credit, with a $400 million borrowing base as of that date; add an additional dedicated $40 million letter of credit facility that does not affect the borrowing base; and add Mariner Energy Resources, Inc. as a co-borrower. Our credit facility was further amended in April 2006 to increase the borrowing base to $430 million which subsequently automatically reduced to $362.5 million upon closing of the offering of the old notes and then was increased to $450 million in October 2006, subject to redetermination or adjustment. The revolving credit facility matures on March 2, 2010. At September 30, 2006, approximately $328.6 million was outstanding under the revolving credit facility, including two letters of credit for $4.2 million and $10.4 million. The $40 million letter of credit outstanding as of September 30, 2006 under the dedicated letter of credit facility matures on March 2, 2009. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Credit Facility” for more information.


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UNAUDITED PRO FORMA COMBINED CONDENSED FINANCIAL INFORMATION
 
The merger between a subsidiary of Mariner and Forest Energy Resources was consummated on March 2, 2006. Accordingly, actual balance sheet information of the combined company as of September 30, 2006 is included elsewhere in this prospectus.
 
The following unaudited pro forma combined statements of operations and explanatory notes present how the combined statements of Mariner and the Forest Gulf of Mexico operations may have appeared had the businesses actually been combined as of January 1, 2005.
 
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 elsewhere in this prospectus. 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.
 
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.


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MARINER ENERGY, INC.
 
UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENT OF OPERATIONS
For the Nine Months Ended September 30, 2006
 
                                 
          Forest Energy
          Mariner
 
    Mariner
    Resources, Inc.
    Merger
    Pro Forma
 
    Historical(1)     Historical(2)     Adjustments(3)     Combined  
    (In thousands, except share data)  
 
Revenues:
                               
Oil & gas sales
  $ 211,587     $ 291,885           $ 503,472  
Other revenues
    2,401                   2,401  
                                 
Total revenues
    213,988       291,885             505,873  
Costs and Expenses:
                               
Lease operating expenses
    27,089       51,765             78,854  
Severance and ad valorem taxes
    5,205       1,203             6,408  
Transportation expenses
    2,728       1,458             4,186  
General and administrative expenses
    23,872       809       (4)     24,681  
Depreciation, depletion and amortization
    82,194             136,797 (5)     218,991  
                                 
Total costs and expenses
    141,088       55,235       136,797       333,120  
                                 
OPERATING INCOME
    72,900       236,650       (136,797 )     172,753  
Interest:
                               
Income
    487                   487  
Expense, net of amounts capitalized
    (17,693 )           (10,786 )(6)     (28,479 )
                                 
Income before taxes
    55,694       236,650       (147,583 )     144,761  
Provision for income taxes
    (20,966 )           (31,173 )(7)     (52,139 )
                                 
NET INCOME
  $ 34,728     $ 236,650     $ (178,756 )   $ 92,622  
                                 
Earnings per share:
                               
Net Income per share — basic
  $ 1.02                     $ 1.09  
                                 
Net Income per share — diluted
  $ 1.00                     $ 1.09  
                                 
Weighted average shares outstanding — basic
    34,133,279             50,637,010       84,770,289  
Weighted average shares outstanding — diluted
    34,557,697             50,687,850       85,245,547  


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MARINER ENERGY, INC.
 
UNAUDITED PRO FORMA COMBINED CONDENSED STATEMENT OF OPERATIONS
For the Year Ended December 31, 2005
 
                                 
          Forest Energy
          Mariner
 
    Mariner
    Resources, Inc.
    Merger
    Pro Forma
 
    Historical(1)     Historical(2)     Adjustments(3)     Combined  
    (In thousands, except share data)  
 
Revenues:
                               
Oil & gas sales
  $ 196,122     $ 392,272     $     $ 588,394  
Other revenues
    3,588                   3,588  
                                 
Total revenues
    199,710       392,272             591,982  
Costs and Expenses:
                               
Lease operating expenses
    24,882       78,001             102,883  
Severance and ad valorem taxes
    5,000       2,738             7,738  
Transportation expenses
    2,336       3,383             5,719  
General and administrative expenses
    37,053             (4)     37,053  
Depreciation, depletion and amortization
    59,426             270,390 (5)     329,816  
Impairment of production equipment held for use
    1,845                   1,845  
                                 
Total costs and expenses
    130,542       84,122       270,390       485,054  
                                 
OPERATING INCOME
    69,168       308,150       (270,390 )     106,928  
Interest:
                               
Income
    779                   779  
Expense, net of amounts capitalized
    (8,172 )           (10,378 )(8)     (18,550 )
                                 
Income before taxes
    61,775       308,150       (280,768 )     89,157  
Provision for income taxes
    (21,294 )           (9,911 )(7)     (31,205 )
                                 
NET INCOME
  $ 40,481     $ 308,150     $ (290,679 )   $ 57,952  
                                 
Earnings per share:
                               
Net Income per share — basic
  $ 1.24                     $ 0.70  
                                 
Net Income per share — diluted
  $ 1.20                     $ 0.69  
                                 
Weighted average shares outstanding — basic
    32,667,582               50,637,010       83,304,592  
Weighted average shares outstanding — diluted
    33,766,577               50,687,850       84,454,427  
 
 
(1) The historical Mariner information presented excludes activity related to the Forest Gulf of Mexico operations as Mariner acquired them in the merger consummated on March 2, 2006.
 
(2) 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 nine months ended September 30, 2006 and for the year ended December 31, 2005.
 
(3) Transaction costs consisting of accounting, consulting and legal fees are anticipated to be approximately $10.3 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.


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(4) The pro forma general and administrative expenses do not include costs associated with the Forest Gulf of Mexico assets. Mariner believes the overhead costs associated with these operations in 2006 will be approximately $6.4 million, net of capitalized amounts.
 
(5) 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.
 
(6) To adjust interest expense to give effect to the financing activities in connection with the organization of Forest Energy Resources assuming an interest rate of 6.375% based on the terms of the senior bank credit facility obtained by Forest Energy Resources. The interest rates used are 30-day LIBOR plus 1.50%, or 6.375%, as of September 30, 2006. A change in interest rates of approximately 10% would result in a change in pro forma combined interest of approximately $0.9 million for the nine months ended September 30, 2006.
 
(7) To record income tax expense on the combined company results of operations based on a statutory federal tax rate of 35.0%.
 
(8) To adjust interest expense to give effect to the financing activities in connection with the organization of Forest Energy Resources assuming an interest rate of 5.89% for the year ended December 31, 2005 based on the terms of the senior term loan facility obtained by Forest Energy Resources. The interest rates used are 30-day LIBOR plus 1.50%, or 5.89% as of December 31, 2005. A change in interest rates of approximately 10% would result in a change in pro forma combined interest expense of approximately $1.0 million for the year ended December 31, 2005.
 
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 January 1, 2005. The combination of the Forest Gulf of Mexico operations with Mariner’s operations 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 December 31, 2005 were 306.1 Bcfe and production for the year ended December 31, 2005 was approximately 65.8 Bcfe, a reserve life on an annualized basis of 4.7. 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 corresponding higher rate of depreciation, depletion, and amortization. As of December 31, 2005, Mariner’s proved reserves totaled 337.6 Bcfe and production for the year ended December 31, 2005 was approximately 29.1 Bcfe, a reserve life on an annualized basis of 11.6. For the combined operations, as of December 31, 2005, proved reserves would have totaled approximately 643.7 Bcfe and production for the year ended December 31, 2005 would have totaled 94.9 Bcfe, a reserve life on an annualized basis of 6.8. 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 on page F-56 and footnote 3 in Forest’s Gulf of Mexico Operations Notes to Statements of Revenues and Direct Operating Expenses for additional information presented in accordance with the requirements of Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Gas Producing Activities.


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ESTIMATED PRO FORMA COMBINED QUANTITIES OF PROVED RESERVES
 
                                                                         
          Forest Energy Resources, Inc.
       
    Mariner Historical     Historical     Mariner Pro Forma Combined  
                Natural
                Natural
                Natural
 
          Natural
    Gas
          Natural
    Gas
          Natural
    Gas
 
    Oil     Gas     Equivalent     Liquids     Gas     Equivalent     Liquids     Gas     Equivalent  
    (Mbbl)     (MMcf)     (MMcfe)     (Mbbl)     (MMcf)     (MMcfe)     (Mbbl)     (MMcf)     (MMcfe)  
 
December 31, 2004
    14,255       151,933       237,465       11,650       269,808       339,708       25,905       421,741       577,173  
Revisions of previous estimates
    835       963       5,971       3,123       4,815       23,553       3,958       5,778       29,524  
Extensions, discoveries and other additions
    1,167       22,307       29,309       504       5,639       8,663       1,671       27,946       37,972  
Production
    (1,791 )     (18,354 )     (29,100 )     (2,783 )     (49,120 )     (65,818 )     (4,574 )     (67,474 )     (94,918 )
Purchases of reserves in place
    7,181       50,837       93,923                         7,181       50,837       93,923  
                                                                         
December 31, 2005
    21,647       207,686       337,568       12,494 (1)     231,142       306,106 (1)     34,141       438,828       643,674  
                                                                         
 
 
(1) Includes 3,223 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
          Natural
          Natural
        Natural
  Gas
      Natural
  Gas
      Natural
  Gas
    Oil   Gas   Equivalent   Liquids   Gas   Equivalent   Liquids   Gas   Equivalent
    (Mbbl)   (MMcf)   (MMcfe)   (Mbbl)   (MMcf)   (MMcfe)   (Mbbl)   (MMcf)   (MMcfe)
 
December 31, 2005
    9,564       110,011       167,395       8,792       142,143       194,895       18,356       252,154       362,290  
                                                                         


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PRO FORMA COMBINED STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS
 
                         
    For the Year Ending December 31, 2005  
          Forest Energy
    Mariner
 
    Mariner
    Resources, Inc.
    Pro Forma
 
    Historical     Historical     Combined  
 
Future cash inflows
  $ 3,451,321     $ 2,849,998     $ 6,301,319  
Future production costs
    (687,583 )     (226,248 )     (913,831 )
Future development costs
    (386,497 )     (386,855 )     (773,352 )
Future income taxes
    (695,921 )     (649,002 )     (1,344,923 )
                         
Future net cash flows
    1,681,320       1,587,893       3,269,213  
Discount of future net cash flows at 10% per annum
    (774,755 )     (292,730 )     (1,067,485 )
                         
Standardized measure of discounted future net cash flows
  $ 906,565     $ 1,295,163     $ 2,201,728  
                         
Balance, beginning of period
  $ 494,382     $ 925,837     $ 1,420,219  
Increase (decrease) in discounted future net cash flows:
                       
Sales and transfers of oil and gas produced, net of production costs
    (213,189 )     (436,385 )     (649,574 )
Net changes in prices and production costs
    425,317       692,164       1,117,481  
Extensions and discoveries, net of future development and production costs
    119,501       53,744       173,245  
Purchases of reserves in place
    189,782             189,782  
Development costs during period and net change in development costs
    46,632       7,022       53,654  
Revision of previous quantity estimates
    16,323       109,207       125,530  
Net change in income taxes
    (201,647 )     (178,643 )     (380,290 )
Accretion of discount before income taxes
    49,438       122,217       171,655  
Changes in production rates (timing) and other
    (19,974 )           (19,974 )
                         
Balance, end of period
  $ 906,565     $ 1,295,163     $ 2,201,728  
                         


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SELECTED HISTORICAL FINANCIAL INFORMATION FOR MARINER
 
The following table shows Mariner’s summary historical consolidated financial data as of and for the nine months ended September 30, 2006 and September 30, 2005, the year ended December 31, 2005, the period from January 1, 2004 through March 2, 2004, the period from March 3, 2004 through December 31, 2004, and each of the three years ended December 31, 2003. The summary historical consolidated financial data for the year ended December 31, 2005, the period from January 1, 2004 through March 2, 2004, the period from March 3, 2004 through December 31, 2004, and the year ended December 31, 2003 are derived from Mariner’s audited financial statements included herein, and the historical consolidated financial data as of and for the two years ended December 31, 2002 are derived from Mariner’s audited financial statements that are not included herein. The summary historical consolidated financial data for the nine months ended September 30, 2006 and the nine months ended September 30, 2005 has been derived from Mariner’s unaudited financial statements. 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 with Forest Energy Resources. Mariner’s historical results are not necessarily indicative of results to be expected in future periods.
 
The merger between a subsidiary of Mariner and Forest Energy Resources was consummated on March 2, 2006. Accordingly, the financial information as of September 30, 2006 below includes the Forest Gulf of Mexico operations as of and after March 2, 2006.
 
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 Post-2004 Merger activity (for the March 3, 2004 through December 31, 2004 period, the year ended December 31, 2005 and the nine months ended September 30, 2006 and September 30, 2005) and Pre-2004 Merger activity (for all periods prior to March 2, 2004) 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
                   
                      March 3,
      January 1,
                   
                      2004
      2004
                   
    Nine Months
    Year Ended
    through
      through
                   
    Ended September 30,     December 31,
    December 31,
      March 2,
    Year Ended December 31,  
    2006     2005     2005     2004       2004     2003     2002     2001  
    (In millions, except per share data)  
 
                                                                 
Statement of Operations Data:
                                                                 
Total revenues(1)
  $ 438.4     $ 151.2     $ 199.7     $ 174.4       $ 39.8     $ 142.5     $ 158.2     $ 155.0  
Lease operating expenses
    62.9       17.7       24.9       19.3         3.5       23.2       25.2       19.2  
Severance and ad valorem taxes
    5.7       2.5       5.0       2.1         0.6       1.5       0.9       0.9  
Transportation expenses
    4.0       1.7       2.3       1.9         1.1       6.3       10.5       12.0  
Depreciation, depletion and amortization
    192.2       43.4       59.4       54.3         10.6       48.3       70.8       63.5  
Impairment of production equipment held for use
          0.5       1.8       1.0                            
Derivative settlement
                                    3.2              
Impairment of Enron related receivables
                                          3.2       29.5  
General and administrative expenses
    25.1       26.7       37.1       7.6         1.1       8.1       7.7       9.3  
                                                                   
Operating income
    148.5       58.7       69.2       88.2         22.9       51.9       39.9       20.6  
Interest income
    0.5       0.7       0.8       0.2         0.1       0.8       0.4       0.7  
Interest expense
    (26.4 )     (5.4 )     (8.2 )     (6.0 )             (7.0 )     (10.3 )     (8.9 )
                                                                   
Income before income taxes
    122.6       54.0       61.8       82.4         23.0       45.7       30.0       12.4  
Provision for income taxes
    (44.4 )     (18.4 )     (21.3 )     (28.8 )       (8.1 )     (9.4 )           —   
                                                                   


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    Post-2004 Merger       Pre-2004 Merger  
                      Period from
      Period from
                   
                      March 3,
      January 1,
                   
                      2004
      2004
                   
    Nine Months
    Year Ended
    through
      through
                   
    Ended September 30,     December 31,
    December 31,
      March 2,
    Year Ended December 31,  
    2006     2005     2005     2004       2004     2003     2002     2001  
    (In millions, except per share data)  
Income before cumulative effect of change in accounting method net of tax effects
  $ 78.2     $ 35.6     $ 40.5     $ 53.6       $ 14.9     $ 36.3     $ 30.0     $ 12.4  
Income before cumulative effect per common unit
                                                                 
Basic
    1.07       1.10     $ 1.24     $ 1.80       $ 0.50     $ 1.22     $ 1.01     $ 0.42  
Diluted
    1.06       1.07       1.20       1.80         0.50       1.22       1.01       0.42  
Cumulative effect of changes in accounting method
                                    1.9              
                                                                   
Net income
  $ 78.2     $ 35.6     $ 40.5     $ 53.6       $ 14.9     $ 38.2     $ 30.0     $ 12.4  
                                                                   
Net income per common share
                                                                 
Basic
  $ 1.07     $ 1.10     $ 1.24     $ 1.80       $ 0.50     $ 1.29     $ 1.01     $ 0.42  
Diluted
    1.06       1.07       1.20       1.80         0.50       1.29       1.01       0.42  
Capital Expenditure and Disposal Data:
                                                                 
Exploration, including leasehold/seismic
    169.1       23.6     $ 60.9     $ 40.4       $ 7.5     $ 31.6     $ 40.4     $ 66.3  
Development and other
    347.9       106.8       191.8       93.2         7.8       51.7       65.7       98.2  
Proceeds from property conveyances
    (2.0 )                               (121.6 )     (52.3 )     (90.5 )
                                                                   
Total capital expenditures net of proceeds from property conveyances
  $ 515.0     $ 130.4     $ 252.7     $ 133.6       $ 15.3     $ (38.3 )   $ 53.8     $ 74.0  
                                                                   
 
 
(1) Includes effects of hedging.
 
                                                           
    Post-2004 Merger       Pre-2004 Merger  
    September 30,     December 31,
    December 31,
      December 31,  
    2006     2005     2005     2004       2004     2003     2001  
    (In millions)  
 
                                                         
Balance Sheet Data(1)
                                                         
Property and equipment, net, full cost method
  $ 2,061.9     $ 393.3     $ 515.9     $ 303.8       $ 207.9     $ 287.6     $ 290.6  
Total assets
    2,700.7       502.2       665.5       376.0         312.1       360.2       363.9  
Long-term debt, less current maturities
    614.0       79.0       156.0       115.0               99.8       99.8  
Stockholders’ equity
    1,267.1       178.6       213.3       133.9         218.2       170.1       180.1  
Working capital (deficit)(2)
    (75.3 )     (30.2 )     (46.4 )     (18.7 )       38.3       (24.4 )     (19.6 )
Other Financial Data
                                                         
Ratio of Earnings to Fixed Charges(3)
    5.43       10.23       7.88       17.17         6.83       3.56       1.82  
 
 
(1) Balance sheet data as of September 30, 2006 reflects consolidation of the assets of the Forest Gulf of Mexico operations as of March 2, 2006. Balance sheet data as of December 31, 2004 reflects purchase accounting adjustments to oil and gas properties, total assets and stockholders’ equity resulting from the acquisition of our former indirect parent on March 2, 2004.


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(2) Working capital (deficit) excludes current derivative assets and liabilities, deferred tax assets and restricted cash.
 
(3) For the purposes of determining the ratio of earnings to fixed charges, earnings consist of the sum of income before taxes, plus fixed charges, less capitalized interest, and fixed charges consist of interest expense (net of capitalized interest), plus capitalized interest, plus amortized discounts related to indebtedness.
 
                                                                   
    Post-2004 Merger       Pre-2004 Merger  
                      Period from
      Period from
                   
                      March 3,
      January 1,
                   
                      2004
      2004
                   
    Nine Months
    Year Ended
    through
      through
                   
    Ended September 30,     December 31,
    December 31,
      March 2,
    Year Ended December 31,  
    2006     2005     2005     2004       2004     2003     2002     2001  
    (In millions, except per share data)  
 
                                                                 
Other Financial Data:
                                                                 
EBITDA(1)
  $ 340.7     $ 102.7     $ 130.4     $ 143.5       $ 33.4     $ 100.3     $ 113.9     $ 113.6  
Net cash provided by operating activities
    172.8       135.4       165.4       135.2         20.3       88.9       60.3       113.5  
Net cash (used) provided by investing activities
    (423.5 )     (142.1 )     (247.8 )     (133.0 )       (15.3 )     52.9       (53.8 )     (74.0 )
Net cash (used) provided by financing activities
    251.0       8.7       84.4       64.9               (100.0 )           (30.0 )
Reconciliation of Non-GAAP Measures:
                                                                 
EBITDA(1)
  $ 340.7     $ 102.7     $ 130.4     $ 143.5       $ 33.4     $ 100.3     $ 113.9     $ 113.6  
Changes in working capital
    (158.9 )     25.1       20.0       6.2         (13.2 )     7.2       (20.4 )     7.5  
Non-cash hedge gain/(loss)(2)
    8.2       (3.6 )     (4.5 )     (7.9 )             (2.0 )     (23.2 )      
Amortization/other
    (0.3 )     0.9       1.2       0.8                     (0.1 )     0.6  
Stock compensation expense
    9.0       17.6       25.7                                  
Net interest expense
    (25.9 )     (4.7 )     (7.4 )     (5.8 )       0.1       (6.2 )     (9.9 )     (8.2 )
Income tax expense
          (2.6 )           (1.6 )             (10.4 )            
                                                                   
Net cash provided by operating activities
  $ 172.8     $ 135.4     $ 165.4     $ 135.2       $ 20.3     $ 88.9     $ 60.3     $ 113.5  
                                                                   
 
 
(1) EBITDA means earnings before interest, income taxes, depreciation, depletion and amortization and impairments. For the nine months ended September 30, 2006 and 2005, EBITDA includes $9.0 million and $17.6 million, respectively, in non-cash compensation expense related to restricted stock and stock options. For the year ended December 31, 2005, EBITDA includes $25.7 million in non-cash 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 dedesignation 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. 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. The value at the time of the merger and included in AOCI has reversed out of AOCI and into earnings as the original corresponding production, as hedged by the contracts, is produced. We have designated subsequent hedge contracts as cash flow hedges with gains and losses resulting from the transactions recorded at market value in AOCI, as appropriate, until recognized as operating income in our Statement of Operations as the physical production hedged by the contracts is delivered.


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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Overview
 
We are an independent oil and natural gas exploration, development and production company with principal operations in the Gulf of Mexico and 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. As a result of increased drilling of shelf prospects, the acquisition of Forest’s Gulf of Mexico assets located primarily on the shelf, and development activities in West Texas, 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 West Texas properties. As of December 31, 2005 (after giving effect to the merger transaction with Forest Energy Resources), approximately 56% of our proved reserves were classified as proved developed, with approximately 32% of the reserves located in West Texas, 19% in the Gulf of Mexico deepwater and 49% on the Gulf of Mexico shelf.
 
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 “— 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) and Combined (for the full period from January 1 through December 31, 2004). The combined presentation does not reflect the adjustments to our statement of operations that would be reflected in a pro forma presentation. However, because such adjustments are not material, we believe that our combined presentation presents a fair presentation and facilitates an understanding of our results of operations.
 
In March 2005, we completed a private placement of 16,350,000 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors, which generated approximately $229 million of gross proceeds, or approximately $211 million net of initial purchaser’s discount, placement fee and offering expenses. Our former sole stockholder, MEI Acquisitions Holdings, LLC, also sold 15,102,500 shares of our common stock in the private placement. We used $166 million of the net proceeds from the sale of 12,750,000 shares of common stock to purchase and retire an equal number of shares of our common stock from our former sole stockholder. We used $38 million of the remaining net proceeds of approximately $44 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 “— 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.
 
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 significantly in the future. Although we attempt to mitigate the impact of price declines and provide for more predictable cash flows through our hedging strategy, a substantial or extended decline in oil and natural gas prices or poor drilling results could have a


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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. Conversely, the use of derivative instruments also can prevent us from realizing the full benefit of upward price movements.
 
Recent Developments
 
Forest Gulf of Mexico Merger.  On March 2, 2006, a subsidiary of Mariner completed a merger transaction with Forest Energy Resources. Prior to the consummation of the merger, Forest transferred and contributed the assets and certain liabilities associated with its Gulf of Mexico operations to Forest Energy Resources. Immediately prior to the merger, Forest distributed all of the outstanding shares of Forest Energy Resources to Forest shareholders on a pro rata basis. Forest Energy Resources then merged with a newly-formed subsidiary of Mariner, became a new wholly-owned subsidiary of Mariner, and changed its name to Mariner Energy Resources, Inc. Immediately following the merger, approximately 59% of Mariner common stock was held by shareholders of Forest and approximately 41% of Mariner common stock was held by the pre-merger stockholders of Mariner. In the merger, Mariner issued 50,637,010 shares of common stock to Forest shareholders. Our acquisition of Forest Energy Resources added approximately 306 Bcfe of estimated proved reserves as of December 31, 2005, of which 76% were natural gas and 24% were oil and condensate.
 
West Cameron Acquisition.  In August 2006, we acquired the interest of BP Exploration and Production Inc., which we refer to as “BP”, in West Cameron Block 110 and the southeast quarter of West Cameron Block 111 in the Gulf of Mexico. The interest was acquired by our subsidiary, Mariner Energy Resources, Inc., exercising its preferential right to purchase. BP retained its interest in depths below 15,000 feet. In the Forest merger, we acquired Forest Energy Resources’ 37.5% interest in the properties. As a result of the August 2006 acquisition, Mariner Energy Resources, Inc. now owns 100% of the working interest, exclusive of the deep rights retained by BP, and Mariner Energy, Inc. became operator of the interests owned by its subsidiary. The acquisition cost, net of preliminary purchase price adjustments, was approximately $70.9 million, which was financed by borrowing under our senior secured credit facility. A $10.4 million letter of credit under our senior secured credit facility also was issued in favor of BP to secure plugging and abandonment obligations. The acquisition adds proved reserves estimated by us to be 20 Bcfe as of August 1, 2006. Production associated with the acquired interest was approximately 11 MMcfe/day during July 2006.
 
Material Gulf of Mexico Discovery.  In October 2006, we announced that we made a material conventional shelf discovery in the High Island 116 #5ST1 well, drilled to a total measured depth of 14,683 feet / 13,150 feet true vertical depth. The well encountered approximately 540 feet of net true vertical depth pay in thirteen sands. We anticipate completion and initial production in the fourth quarter of 2006. High Island 116 is part of the Forest Gulf of Mexico operations we acquired in March 2006. We have a 100% working interest and an approximate 72% net revenue interest in the well.
 
Effects of the 2005 Hurricane Season.  In 2005, our operations were adversely affected by one of the most active and severe hurricane seasons in recorded history, resulting in shut-in production and startup delays. We estimate that as of September 30, 2006, approximately 12 MMcfe per day of production remained shut-in and approximately 33 MMcfe per day of production had recommenced since June 30, 2006. The four deepwater projects that experienced startup delays have recommenced production. As a result of ongoing repairs to pipelines, facilities, terminals and host facilities, we expect most of the remaining shut-in production to recommence by the end of 2006 and the balance in 2007, except that an immaterial amount of production is not expected to recommence.
 
We estimate that the costs to repair damage caused by the hurricanes to our platforms and facilities will be approximately $85 million. However, until we are able to complete all of the repair work, this estimate is subject to significant variance. For the insurance period covering the 2005 hurricane activity, we carried a $3 million annual deductible and a $0.5 million single occurrence deductible for the Mariner assets. Insurance covering the Forest Gulf of Mexico properties carried a $5 million deductible for each occurrence. Until the repairs are completed and we submit costs to our insurance underwriters for their review, the full extent of our insurance recoveries and the resulting net costs to us for Hurricanes Katrina and Rita will be unknown. See


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“Business — Insurance Matters.” However, we expect the total costs not covered by the combined insurance policies to be less than $15 million.
 
2006 Highlights
 
For the nine months ended September 30, 2006, we recognized net income of $78.2 million on total revenues of $438.4 million compared to net income of $35.6 million on total revenues of $151.2 million for the nine months ended September 30, 2005. Production, revenues and net income increased significantly from results reported a year ago primarily as a result of consolidation as of March 2, 2006 of assets acquired in the merger transaction with Forest Energy Resources. Production for the first nine months of 2006 averaged 200 MMcfe per day (54.5 Bcfe total for the period), compared to average daily production of 82 MMcfe per day for the first nine months of 2005 (22.5 Bcfe total for the period). Production for the first nine months of 2006 continued to be adversely effected by the 2005 hurricane season.
 
2005 Highlights
 
During the year ended December 31, 2005, we recognized net income of $40.5 million on total revenues of $199.7 million compared to net income of $68.4 million on total revenues of $214.2 million in 2004. Net income decreased 41% compared to 2004, primarily due to recognizing $25.7 million of stock compensation expense in 2005, and a 23% decrease in production, partially offset by a 35% improvement in net commodity prices realized by us (before the effects of hedging.) Our 2005 results were also negatively impacted by increased hedging losses of $49.3 million in 2005 compared to a $19.8 million loss in 2004. We produced approximately 29.1 Bcfe during 2005 and our average daily production rate was 80 MMcfe compared to 37.6 Bcfe, or 103 MMcfe per day, for 2004. Production during the last two quarters of 2005 was negatively impacted by the effects of the 2005 hurricane season. We invested approximately $252.7 million in total capital in 2005 compared to $148.9 million in 2004.
 
Our 2005 results reflect the private placement of an additional 3.6 million shares of stock in March 2005. The net proceeds of approximately $44 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 2005 and recorded compensation expense of $25.7 million in 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 invested approximately $148.9 million in total capital in 2004 compared to $83.3 million in 2003.
 
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
 
For the first nine months of 2006, our production averaged 144 MMcf of natural gas per day and approximately 9,300 barrels of oil per day, or a total of approximately 200 MMcfe per day. Natural gas production comprised approximately 72% of total production for the nine months ended September 30, 2006 compared to approximately 64% for the comparable period in 2005. This increase in the gas to oil ratio


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primarily resulted from the acquisition of the Forest Gulf of Mexico operations. Production continued to be adversely affected by the 2005 hurricane season, resulting in shut-in production and startup delays. We estimate that as of September 30, 2006, approximately 12 MMcfe per day of production remained shut-in and approximately 33 MMcfe per day of production had recommenced since June 30, 2006. The four deepwater projects that experienced startup delays have recommenced production. As a result of ongoing repairs to pipelines, facilities, terminals and host facilities, we expect most of the remaining shut-in production to recommence by the end of 2006 and the balance in 2007, except that an immaterial amount of production is not expected to recommence.
 
Our production for 2005 averaged approximately 50 MMcf of natural gas per day and approximately 4,900 barrels of oil per day, or a total of approximately 80 MMcfe per day. Natural gas production comprised approximately 63% of total production in 2005 and 2004.
 
In the last two quarters of 2005 our production was negatively impacted by Hurricanes Katrina and Rita. Production shut-in and deferred because of the hurricanes’ impact totaled approximately 6-8 Bcfe during the last two quarters of 2005. As of December 31, 2005 approximately 5 MMcfe per day of production remained shut-in awaiting repairs, primarily associated with our Baccarat property, which was brought back on-line in January 2006. 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 until the fourth quarter of 2005. 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). Our Rigel project recommenced production in the first quarter of 2006, and our Pluto and Ochre projects recommenced production in the third quarter of 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. 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. It subsequently has been shut-in since Hurricane Katrina, with production expected to recommence in the first quarter of 2007 after completion of host platform repairs. Production from Mississippi Canyon 66 (Ochre) recommenced in the third quarter of 2006, producing at about the same net rate of approximately 6.5 MMcfe per day as it was immediately prior to Hurricane Ivan.
 
Historically, a majority of our total production has been comprised of natural gas. We anticipate that our acquisition of the Forest Gulf of Mexico operations will increase our concentration in natural gas production. 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 recommenced in January 2006. We recommenced production at our Swordfish project in the fourth quarter of 2005, at our Rigel project in the first quarter of 2006 and at our Pluto project in the third quarter of 2006. Production recommenced in October 2006 at our Ewing Banks 921 (North Black Widow) project. Uncertainties, including scheduling, weather, and construction lead times, could cause further delays in the start-up of any one of the projects.


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Oil and Gas Property Costs
 
Of the total $517.0 million of capital expenditures incurred in the first nine months of 2006, approximately $264.9 million or 51% related to development activities (of which about $39.5 million was onshore), $169.1 million or 33% related to exploration activities, including the acquisition of leasehold and seismic, and the balance of approximately $83.0 million or 16% related to the West Cameron 110/111 acquisition, capitalized expenses and minor corporate items.
 
In 2005, we incurred approximately $242.6 million in capital costs related to property acquisitions, exploration, and development activities and approximately $10.1 million for capital costs associated with the installation of our Aldwell unit gathering system and other minor corporate items. Of the total $252.7 million of capital expenditures incurred in 2005, approximately 51% related to development activities and capitalized overhead and interest, 24% for exploration activities, including the acquisition of leasehold and seismic, 21% for property acquisitions, and the balance was associated with the Aldwell Unit gathering system and minor corporate items. Of the $121.7 million incurred on development activities and capitalized overhead and interest, approximately 27% were for onshore operations, 69% for deep water operations, and 4% for shelf Gulf of Mexico operations. Expenditures for property acquisitions included $46.1 million for assets located in West Texas and $7.9 million to acquire additional interests in offshore Gulf of Mexico projects.
 
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. We incurred approximately $47.9 million of exploration capital expenditures in 2004.
 
Oil and Gas Reserves
 
We have maintained our reserve base through exploration and exploitation activities despite selling 44.4 Bcfe of our reserves in 2002. Historically, we have not acquired significant reserves through acquisition activities; however, in 2005, we acquired 93.9 Bcfe of estimated proved reserves primarily in West Texas. In March 2006, we acquired estimated proved reserves of 306.1 Bcfe as a result of the merger with Forest Energy Resources. As of December 31, 2005, Ryder Scott estimated our net proved reserves at approximately 337.6 Bcfe, with a PV10 of approximately $1.3 billion and a standardized measure of discounted future net cash flows attributable to our estimated proved reserves of approximately $906.6 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 and for more information concerning our reserve estimates.
 
Development activities and acquisitions in West Texas and Gulf of Mexico deepwater divestitures have significantly changed our reserve profile since 2002. Proved reserves as of December 31, 2005 were comprised of 61% West Texas, 6% Gulf of Mexico shelf and 33% Gulf of Mexico deepwater compared to 33% West Texas, 19% Gulf of Mexico shelf and 48% Gulf of Mexico deepwater as of December 31, 2002. Proved undeveloped reserves were approximately 50% of total proved reserves as of December 31, 2005. Approximately 25% of proved undeveloped reserves were related to our West Texas Aldwell Unit, where we had 100% development drilling success on 170 wells from 2002 through 2005. Pro forma for the merger transaction, as of December 31, 2005, we had approximately 644 Bcfe of proved reserves, of which 32% were in West Texas, 49% in the Gulf of Mexico shelf and 19% in the Gulf of Mexico deepwater. Proved undeveloped reserves were approximately 44% of total proved reserves as of December 31, 2005 on a pro forma basis.


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Since December 31, 1997, we have added proved undeveloped reserves attributable to 13 deepwater projects. As of December 31, 2005, ten of those projects 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, 2005, 8.9 Bcfe of our net proved reserves attributable to this project were classified as proved behind pipe reserves. Production from Pluto recommenced in the third quarter of 2006.
 
The proved undeveloped reserves attributable to the remaining two deepwater projects were added as follows:
 
                         
    Net Proved
          Year Expected
 
    Undeveloped
          to Convert
 
    Reserves
    Year
    to Proved
 
Property
  (Bcfe)(1)     Added     Developed Status  
 
Green Canyon 646 (Daniel Boone)
    16.4       2003       2008  
Atwater Valley 380/381/382/425/426 (Bass Lite)
    32.3       2005       2008  
Ewing Bank 921 (North Black Widow)
    3.7       2005       2006  
 
 
(1) Net proved undeveloped reserves attributable to the project as of December 31, 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.


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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, the cash losses on contracts settled for natural gas and oil produced during the nine-month period ended September 30, 2006 was $8.3 million. An $8.3 million non-cash gain was also recorded for the nine-month period ended September 30, 2006 relating to the hedges acquired through the Forest transaction. Additionally, an unrealized gain of $1.4 million was recognized for the nine-month period ended September 30, 2006 related to the ineffective portion of open contracts that were not eligible for deferral under SFAS 133 due primarily to the basis differentials between the contract price, which is NYMEX-based for oil and Henry Hub-based for gas, and the indexed price at the point of sale. We incurred cash hedging losses of $53.8 million in 2005, of which $4.5 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 September 30, 2006, December 31, 2005 or December 31, 2004.
 
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. Additionally, in accordance with purchase price accounting implemented at the time of the Forest transaction, we recorded the mark-to-market liability of Forest Energy Resources hedge contracts as of March 2, 2006 totaling $17.5 million. As of December 31, 2005, the amount of our mark-to-market hedge liabilities totaled $63.8 million and at September 30, 2006 our mark to market assets totaled $73.9 million. See “— Liquidity and Capital Resources — Commodity Prices and Related Hedging Activities.”
 
For the nine months ended September 30, 2006, assuming a totally unhedged position, our price sensitivity for year-to-date revenues for a 10% change in average oil prices and average gas prices received is approximately $15.7 million and $27.7 million, respectively. For the year ended December 31, 2005, assuming a totally unhedged position, our price sensitivity for 2005 net revenues for a 10% change in average oil prices and average gas prices received is approximately $9.3 million and $15.3 million, respectively. 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.
 
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 deepwater fields. Lease operating expenses


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also include indirect costs such as oil and gas property insurance and overhead allocations in accordance with joint operating agreements.
 
Severance and ad valorem taxes are comprised of severance, production and ad valorem taxes and are generally variable costs based on production, except for ad valorem taxes.
 
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.
 
Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues (which excludes future cash outflows associated with settlement of asset retirement obligations), 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, “Accounting for Derivative Instruments and Hedging Activities” 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. At September 30, 2006, the effects of the cash flow hedges impacted the ceiling test by $209.0 million. Without the hedges, a write-down of the carrying value of the full cost pool of $125.3 million on a pre-tax basis would have been indicated. On an after-tax basis, the write-down would have been $81.5 million.


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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.
 
Compensation Expense
 
As a result of the adoption of SFAS Statement No. 123(R), we record compensation expense for the fair value of restricted stock and stock options that are granted. 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 then will be amortized to compensation expense over the applicable vesting periods.
 
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.
 
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. In May 2006, the State of Texas enacted substantial changes to its tax structure beginning in 2007 by implementing a new margin tax of 1% to be imposed on revenues less certain costs, as specified in the legislation. During the second quarter of 2006, we increased our provision by an additional $1.3 million to provide for deferred taxes to the State of Texas under the newly enacted margin tax.
 
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.


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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 Accumulated Other Comprehensive Income (“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 the consolidated 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 dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Our most significant financial estimates are based on remaining proved natural gas and oil reserves. Estimates of proved reserves are key components of our depletion rate for natural gas and oil properties, our unevaluated properties and our full cost ceiling test. In addition, estimates are used in computing taxes, preparing accruals of operating costs and production revenues, asset retirement obligations, fair value and effectiveness of derivative instruments and fair value of stock options and the related compensation expense. Because of the inherent nature of the estimation process, actual results could differ materially 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, see “— Production.”


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Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005
 
Operating and Financial Results for the Nine Months Ended September 30, 2006
Compared to the Nine Months Ended September 30, 2005
 
                 
    For the Nine-Month Period
 
    Ended September 30,  
Summary Operating Information:
  2006     2005  
 
Net Production:
               
Oil (MBbls)
    2,534       1,336  
Natural Gas (MMcf)
    39,298       14,508  
Total (MMcfe)
    54,503       22,521  
Average daily production (MMcfe/d)
    200       82  
Average sales prices:
               
Oil (per Bbl)(1)
  $ 59.58     $ 40.12  
Natural gas (per Mcf)(1)
    7.25       6.54  
Total natural gas equivalent ($/Mcfe)(1)
    8.00       6.59  
Oil and gas revenues:
               
Oil sales(1)
  $ 150,982     $ 53,579  
Gas sales(1)
    285,008       94,913  
Total oil and gas revenues(1)
    435,990       148,492  
Other revenues
    2,401       2,753  
Lease operating expenses
    62,863       17,678  
Severance and ad valorem taxes
    5,710       2,492  
Transportation expenses
    4,031       1,697  
Depreciation, depletion and amortization
    192,222       43,457  
General and administrative expenses
    25,050       26,726  
Impairment of production equipment held for use
          498  
Net interest expense
    25,906       4,720  
Income before taxes
    122,609       53,977  
Provision for income taxes
    44,385       18,414  
Net income
    78,224       35,563  
 
 
(1) Includes the effects of hedging
 
Production:  Production for the first nine months of 2006 averaged 200 MMcfe per day (54.5 Bcfe total for the period) compared to average daily production of 82 MMcfe per day for the first nine months of 2005 (22.5 Bcfe total for the period). The increased production levels for the nine months ended September 30, 2006 resulted primarily from the acquisition of the Forest Gulf of Mexico operations. The first nine months of 2006 continued to be adversely effected by the 2005 hurricane season, resulting in shut-in production and startup delays. We estimate that as of September 30, 2006, approximately 12 MMcfe per day of production remained shut-in and approximately 33 MMcfe per day of production had recommenced since June 30, 2006. The four deepwater projects that experienced startup delays have recommenced production. As a result of ongoing repairs to pipelines, facilities, terminals and host facilities, we expect most of the remaining shut-in production to recommence by the end of 2006 and the balance in 2007, except that an immaterial amount of production is not expected to recommence.
 
Production in the Gulf of Mexico increased 167% to 47.7 Bcfe from 17.9 Bcfe for the nine-month periods ended September 30, 2006 and 2005, respectively, while onshore production increased 46% to 6.8 Bcfe from 4.7 Bcfe for the nine-month periods ended September 30, 2006 and 2005, respectively. Natural gas production comprised 72% of our total production for the first nine months of 2006 compared to 65% for the


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first nine months of 2005. The increase in the gas-to-oil ratio was primarily the result of the acquisition of the Forest Gulf of Mexico operations.
 
Oil and gas revenues:  Total oil and gas revenues increased 194% to $436.0 million for the nine-month period ended September 30, 2006 compared to $148.5 million for the nine-month period ended September 30, 2005. Natural gas revenues were $285.0 million and $94.9 million for the nine-month periods ended September 30, 2006 and 2005, respectively. Total oil revenues for the nine-month period ended September 30, 2006 were $151.0 million, compared to $53.6 million for the nine-month period ended September 30, 2005.
 
Natural gas prices (excluding the effects of hedging) for the first nine months of 2006 averaged $7.05/Mcf compared to $7.23/Mcf for the comparable period of 2005. Oil prices (excluding the effects of hedging) for the first nine months of 2006 averaged $62.13/Bbl compared to $50.17/Bbl for the comparable period of 2005. For the first nine months of 2006, hedges increased average natural gas pricing by $0.20/Mcf to $7.25/Mcf and reduced average oil pricing by $2.55/Bbl to $59.58/Bbl, resulting in a net recognized hedging gain of $1.5 million.
 
The cash activity on contracts settled for natural gas and oil produced during the nine-month period ended September 30, 2006 was an $8.3 million loss. An $8.3 million non-cash gain was also recorded for the nine-month period ended September 30, 2006 relating to the hedges acquired through the Forest Energy Resources merger. Additionally, an unrealized gain of $1.4 million was recognized for the nine-month period ended September 30, 2006 related to the ineffective portion of open contracts that were not eligible for deferral under SFAS 133 due primarily to the basis differentials between the contract price, which is NYMEX-based for oil and Henry Hub-based for gas, and the indexed price at the point of sale.
 
Lease operating expenses (including workover expenses) were $62.9 million for the nine-month period ended September 30, 2006 compared to $17.7 million for the nine-month period ended September 30, 2005. The increase primarily was attributable to the consolidation of the Forest Gulf of Mexico operations and increased costs attributable to the addition of new productive wells onshore. Lease operating costs rose to $1.15 per Mcfe for the nine-month period ended September 30, 2006 compared to $0.78 per Mcfe for the nine-month period ended September 30, 2005. Continued shut-in production from the impact of the 2005 hurricanes contributed to the increased per-unit operating costs.
 
Severance and ad valorem taxes were $5.7 million and $2.5 million for the nine-month periods ended September 30, 2006 and 2005, respectively. The increase was primarily attributable to the consolidation of the Forest Gulf of Mexico operations and the resulting increased production. For the nine-month periods ended September 30, 2006 and 2005, severance and ad valorem taxes were $0.10 and $0.11 per Mcfe, respectively.
 
Transportation expenses for the nine-month period ended September 30, 2006 were $4.0 million, or $0.07 Mcfe, compared to $1.7 million, or $0.08 per Mcfe, for the nine-month period ended September 30, 2005. The nine-month transportation expenses per Mcfe remained comparable.
 
Depreciation, depletion, and amortization (“DD&A”) expense increased 342% to $192.2 million from $43.5 million for the nine-month periods ended September 30, 2006 and 2005, respectively. The increase was a result of increased production due to the consolidation of the Forest Gulf of Mexico operations, as well as an increase in the unit-of-production depreciation, depletion and amortization rate. The rate increased to $3.53 per Mcfe from $1.93 per Mcfe for the nine-month periods ended September 30, 2006 and 2005, respectively. The per unit increase primarily resulted from the increase of offshore production to 88% of total production at September 30, 2006 as compared to 79% at September 30, 2005 because offshore assets have shorter estimated lives. Another factor for the rate increase was increased accretion of asset retirement obligations due to the consolidation of the Forest Gulf of Mexico operations.
 
General and administrative (“G&A”) expenses totaled $25.1 million for the first nine months of 2006, compared to $26.7 million for the first nine months of 2005. G&A expense includes charges for stock compensation expense of $9.0 million for the first nine months of 2006 compared to $17.6 million in the first nine months of 2005. For the first nine months of 2006, $6.6 million of compensation expense resulted from amortization of the cost of restricted stock granted at the closing of Mariner’s private equity placement in March 2005 and the remaining related to the amortization of new grants issued in 2006 with vesting periods


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of three to four years. The restricted stock related to Mariner’s private equity placement was fully vested in May 2006 and there will be no future charges related to those stock grants. The 2005 compensation expense relates solely to the amortization of the restricted stock granted under Mariner’s private equity placement. Included in the 2006 G&A expenses are severance, retention, relocation and transition costs related to the acquisition of the Forest Gulf of Mexico operations of $2.6 million for the first nine months of 2006. Salaries and wages in the first nine months of 2006 increased by $11.8 million compared to the same year-earlier period. The increase was primarily the result of staffing additions related to the acquisition of the Forest Gulf of Mexico operations. In addition, the first nine months of 2005 included $2.3 million in payments to our former stockholders to terminate a services agreement. Reported G&A expenses in the first nine months of 2006 are net of $12.2 million of overhead reimbursements billed or received from other working interest owners, compared to $3.1 million for the comparable period of 2005.
 
Net interest expense increased 449% to $25.9 million from $4.7 million for the nine-month period ended September 30, 2006 and 2005, respectively. This increase was primarily due to an increase in average debt levels to $420.2 million for the nine-month period ended September 30, 2006 from $81.3 million for the nine-month period ended September 30, 2005. The increased debt was primarily the result of the issuance of $300 million of notes, the assumption of debt in the Forest Energy Resources merger and the use of our bank facility to finance capital expenditures in excess of cash flows. Additionally, the amendment and restatement of the credit facility on March 2, 2006 was treated as an extinguishment of debt for accounting purposes, and resulted in a charge of $1.2 million to interest expense.
 
Income before income taxes increased to $122.6 million from $54.0 million for the nine-month periods ended September 30, 2006 and 2005, respectively. This increase was primarily the result of higher operating income attributed to the Forest Gulf of Mexico operations.
 
Provision for income taxes had an effective tax rate of 36.2% for the nine months ended September 30, 2006 as compared to an effective tax rate of 34.1% for the comparable period of 2005. The increase in the effective tax rate for the nine months ended September 30, 2006 is primarily a result of the Texas Margins tax, which was enacted during the second quarter of 2006 for all properties residing in Texas. Excluding the effects of the Texas Margins tax, the effective rate would have been 35% for the nine months ended September 30, 2006.


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Year Ended December 31, 2005 compared to Year Ended December 31, 2004
 
Operating and Financial Results for the Year Ended December 31, 2005
Compared to the Year Ended December 31, 2004
 
                                 
                Post-Merger     Pre-Merger  
          Non-GAAP
    Period from
    Period from
 
          Combined     March 3,
    January 1,
 
    Year Ended
    2004 through
    2004 through
 
    December 31,     December 31,
    March 2,
 
Summary Operating Information:
  2005     2004     2004     2004  
    (In thousands, except average sales price)  
 
Net production:
                               
Oil (MBbls)
    1,791       2,298       1,885       413  
Natural gas (MMcf)
    18,354       23,782       19,549       4,233  
Total (MMcfe)
    29,100       37,569       30,856       6,713  
Average daily production (MMcfe/d)
    80       103       101       112  
Hedging activities:
                               
Oil revenues (loss)
  $ (18,671 )   $ (12,300 )   $ (11,614 )   $ (686 )
Gas revenues (loss)
    (30,613 )     (7,498 )     (8,929 )     1,431  
                                 
Total hedging revenues (loss)
  $ (49,284 )   $ (19,798 )   $ (20,543 )   $ 745  
Average sales prices:
                               
Oil (per Bbl) realized(1)
  $ 41.23     $ 33.17     $ 33.69     $ 30.75  
Oil (per Bbl) unhedged
    51.66       38.52       39.86       32.41  
Natural gas (per Mcf) realized(1)
    6.66       5.80       5.67       6.39  
Natural gas (per Mcf) unhedged
    8.33       6.12       6.13       6.05  
Total natural gas equivalent ($/Mcfe) realized(1)
    6.74       5.70       5.65       5.92  
Total natural gas equivalent ($/Mcfe) unhedged
    8.43       6.23       6.32       5.81  
Oil and gas revenues:
                               
Oil sales
  $ 73,831     $ 76,207     $ 63,498     $ 12,709  
Gas sales
    122,291       137,980       110,925       27,055  
                                 
Total oil and gas revenues
  $ 196,122     $ 214,187     $ 174,423     $ 39,764  
Other revenues
    3,588                    
Lease operating expenses
    29,882       25,484       21,363       4,121  
Transportation expenses
    2,336       3,029       1,959       1,070  
Depreciation, depletion and amortization
    59,426       64,911       54,281       10,630  
General and administrative expenses
    37,053       8,772       7,641       1,131  
Impairment of production equipment held for use
    1,845       957       957        
Net interest expense (income)
    7,393       5,734       5,820       (86 )
Income before taxes
    61,775       105,300       82,402       22,898  
Provision for income taxes
    21,294       36,855       28,783       8,072  
Net income
    40,481       68,445       53,619       14,826  
 
 
(1) Average realized prices include the effects of hedges.
 
Net production during 2005 decreased approximately 23% to 29.1 Bcfe from 37.6 Bcfe in 2004 primarily due to decreased Gulf of Mexico production, partially offset by increased onshore production. Mariner’s production was negatively impacted during the third and fourth quarters of 2005 due to hurricane activity, primarily Katrina and Rita. Production shut-in and deferred because of the hurricanes’ impact totaled approximately 6-8 Bcfe during the third and fourth quarters of 2005. As of December 31, 2005, approximately


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5 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 2005 at our Swordfish, Ochre, Pluto, and Rigel development projects was delayed awaiting repairs to host facilities. Swordfish recommenced production in the fourth quarter of 2005, Rigel recommenced production in the first quarter of 2006, and Ochre and Pluto recommenced production in the third quarter of 2006.
 
Increased development drilling at our Aldwell unit in West Texas contributed to a 60% increase in onshore production to an average of approximately 18.1 MMcfe per day in 2005 from an average of approximately 11.3 MMcfe per day in 2004.
 
In the deepwater Gulf of Mexico, production decreased approximately 32% to an average of approximately 32.3 MMcfe per day in 2005 compared to an average of approximately 47.2 MMcfe per day in 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 was negatively impacted by hurricane activity as well as by expected declines. As previously discussed, hurricane-related delays in commencement of production at our Swordfish, Pluto and Rigel development projects also contributed to the production decline.
 
In the Gulf of Mexico shelf, production decreased by approximately 34% to an average of approximately 29.2 MMcfe per day in 2005 from an average of approximately 44.1 MMcfe per day in 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 and Hurricanes Katrina and Rita in 2005. 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 and the impact of the 2005 hurricane season.
 
Hedging activities in 2005 decreased our average realized natural gas price received by $1.67 per Mcf and revenues by $30.6 million, compared with a decrease of $0.32 per Mcf and revenues of $7.5 million in 2004. Our hedging activities with respect to crude oil during 2005 decreased the average sales price received by $10.43 per barrel and revenues by $18.7 million compared with a decrease of $5.35 per barrel and revenues of $12.3 million for 2004.
 
Oil and gas revenues decreased 8% to $196.1 million in 2005 when compared to 2004 oil and gas revenues of $214.2 million, due to the aforementioned 23% decrease in production, partially offset by an 18% increase in realized prices (including the effects of hedging) to $6.74 per Mcfe in 2005 from $5.70 per Mcfe in 2004.
 
Other revenues of $3.6 million in 2005 represent an indemnity payment of $1.9 million received from our former stockholder related to the 2004 merger and $1.7 million generated by our West Texas Aldwell unit gathering system.
 
Lease operating expenses increased 17% to $29.9 million in 2005 from $25.5 million in 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 deepwater fields. On a per unit basis, lease operating expenses were $1.03 per Mcfe in 2005 compared to $0.68 per Mcfe in 2004. The increased per unit costs also reflect lower production rates in 2005, including hurricane-related disruptions.
 
Transportation expenses were $2.3 million or $0.08 per Mcfe in 2005, compared to $3.0 million or $0.08 per Mcfe in 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 (“DD&A”) expense decreased 8% to $59.4 million during 2005 from $64.9 million for 2004 as a result of decreased production of 8.5 Bcfe in 2005 compared to 2004, partially offset by an increase in the unit-of-production depreciation, depletion and amortization rate to


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$2.04 per Mcfe for 2005 from $1.73 per Mcfe for 2004. The per unit increase was primarily the result of an increase in future development costs on our deepwater development fields.
 
General and administrative (“G&A”) expenses, which are net of $6.9 million and $4.4 million of overhead reimbursements billed or received from other working interest owners in 2005 and 2004, respectively, increased 322% to $37.1 million during 2005 compared to $8.8 million in 2004. The increase was primarily due to recognizing $25.7 million in stock compensation expense related to restricted stock and options granted in 2005. We also paid $2.3 million to our former stockholders to terminate a services agreement in 2005, compared to $1.0 million under the same agreement in 2004. In addition, G&A expenses increased by $1.6 million due to a reduction in the amount of G&A capitalized in 2005 compared to 2004.
 
Impairment of production equipment held for use reflects the reduction of the carrying cost of our inventory by $1.8 million and $1.0 million as of December 31, 2005 and December 31, 2004, respectively. In 2005, the reduction in estimated value primarily related to subsea trees and wellhead equipment held in inventory.
 
Net interest expense for 2005 increased 25% to $7.4 million from $5.7 million in 2004, primarily due to higher average debt levels in 2005 compared to 2004. 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 ten months of interest related to such borrowings is reflected in 2004 compared to twelve months of interest in 2005.
 
Income before income taxes decreased to $61.8 million for 2005 compared to $105.3 million for 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 $21.3 million for 2005 from $36.9 million for 2004 as a result of decreased operating income for 2005 compared to 2004.
 
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
 
                                 
                Post-Merger     Pre-Merger  
                Period from
    Period from
 
          Non-GAAP
    March 3,
    January 1,
 
          Combined     2004 through
    2004 through
 
    Year Ended December 31,     December 31,
    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  


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                Post-Merger     Pre-Merger  
                Period from
    Period from
 
          Non-GAAP
    March 3,
    January 1,
 
          Combined     2004 through
    2004 through
 
    Year Ended December 31,     December 31,
    March 2,
 
Summary Operating Information:
  2003     2004     2004     2004  
    (In thousands, except average sales price)  
 
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  
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 revenue
  $ 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  
Net income
    38,244       68,445       53,619       14,826  
 
 
(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.

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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.
 
DD&A 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 expenses, which are 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.
 
Liquidity and Capital Resources
 
Cash Flows and Liquidity
 
Secured Bank Credit Facility.  At December 31, 2005, we had $152 million in advances outstanding under our secured revolving credit facility with a borrowing base as of that date of $170 million. In January 2006, the borrowing base was increased to $185 million. In connection with the merger with Forest Energy Resources on March 2, 2006, we amended and restated our existing credit facility to increase maximum credit availability to $500 million for revolving loans, including up to $50 million in letters of credit, with a $400 million borrowing base as of that date. On March 2, 2006, after giving effect to funds required at closing to refinance $176.2 million of debt assumed in the merger and other merger-related costs, our total debt drawn under the facility was approximately $350 million, including a $4.2 million letter of credit required for plugging and abandonment obligations at one of our offshore fields. On April 7, 2006, the borrowing base under the secured credit facility was increased to $430 million, subject to redetermination or adjustment. On April 24, 2006, the borrowing base was reduced to $362.5 million in accordance with an amendment to the credit facility related to our offering of $300 million of senior notes. For subsequent qualifying bond issuances, the amendment provides that the borrowing base in effect on the closing date of such a bond issuance will automatically reduce by 25% of the aggregate principal amount of such bond issuance to the extent that it does not refinance the principal amount of an existing bond issuance. The secured credit facility permits Mariner’s issuance of certain unsecured bonds of up to $350 million in aggregate principal amount that have a non-default interest rate of 10% or less per annum and a scheduled maturity date after March 1, 2012. Mariner’s sale and issuance of $300 million of senior notes in April 2006 constituted such a qualifying bond issuance. At September 30, 2006, approximately $328.6 million was outstanding under our revolving secured credit facility, including the $4.2 million letter of credit and a $10.4 million letter of credit issued in August 2006 to BP to secure certain assumed offshore plugging and abandonment obligations. The borrowing


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base was increased to $450 million in October 2006, subject to redetermination or adjustment. This credit facility matures on March 2, 2010.
 
The amendment and restatement of our secured credit facility on March 2, 2006 also provided for an additional $40 million letter of credit that is not included as a use of the borrowing base and matures on March 2, 2009. The $40 million letter of credit was issued in favor of Forest to secure Mariner’s performance of its obligations to drill and complete 150 wells under an existing drill-to-earn program. This letter of credit will reduce periodically by an amount equal to the product of $0.5 million times the number of wells exceeding 75 that are drilled and completed. The first reduction of approximately $4.3 million occurred in October 2006 based upon the 83 wells drilled and completed as of September 30, 2006. We expect additional reductions based upon quarterly drilling activity, with the next reduction anticipated in January 2007.
 
Private Placement of Senior Unsecured Notes due 2013.  On April 24, 2006, Mariner sold and issued to eligible purchasers $300 million aggregate principal amount of its 71/2% senior notes due 2013 pursuant to Rule 144A under the Securities Act. The notes were priced to yield 7.75% to maturity. Net proceeds, after deducting initial purchasers’ discounts and commissions and offering expenses, were approximately $287.9 million. Mariner used the net proceeds to repay borrowings under its secured credit facility. The issuance of the notes was a qualifying bond issuance under Mariner’s secured credit facility and resulted in an automatic reduction of its borrowing base to $362.5 million as of April 24, 2006. For a description of the terms of the notes, see “Description of Senior Notes.” Costs associated with the notes offering were approximately $8.3 million, excluding discounts of $3.8 million.
 
JEDI Term Promissory Note.  As part of the 2004 merger consideration payable to JEDI, we issued a term promissory note to JEDI in the amount of $10 million. The note bore 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 remained 10% per annum. We chose to pay the interest in cash rather than in kind. The JEDI note was secured by a lien on three of our Gulf of Mexico properties with no proved reserves. We could offset against the note the amount of certain claims for indemnification that could be asserted against JEDI under the terms of the merger agreement. The JEDI note contained 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 2005 private equity placement to repay a portion of the JEDI note. As of December 31, 2005, $4 million was still outstanding under the JEDI note. This note was repaid in full on its maturity date of March 2, 2006.
 
Working Capital.  Working capital at September 30, 2006 was a negative $75.3 million, excluding current derivative liabilities and deferred taxes. This was a result of increased accrued capital obligations for drilling and development projects in progress. Working capital at December 31, 2005 was negative $46.4 million, excluding current derivative liabilities and deferred taxes. Accrued liabilities (including accounts payable) and accrued receivables (including accounts receivable) at December 31, 2005 increased by approximately 91% and 68%, respectively, over levels at December 31, 2004 primarily due to increased accrued obligations for drilling and development projects in progress at year end 2005 and related accruals of amounts owed by partners. 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 2003 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.
 
Capital Expenditures.  In the first nine months of 2006, our capital expenditures were approximately $517.0 million, of which approximately 51% related to development activities; 46% related to the acquisition of BP’s interest in West Cameron 110/111 and exploration activities, including the acquisition of leasehold and


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seismic; and the balance related to capitalized expenses and minor corporate items. Our 2005 capital expenditures were $252.7 million. Approximately 48% of our capital expenditures were incurred for development projects, 24% for exploration activities, 21% for acquisitions of developed properties, and the remainder for other items (primarily expenditures for our Aldwell gathering system, capitalized overhead and interest). The following table presents major components of our capital expenditures for the nine months ended September 30, 2006 and for each of the three years in the period ended December 31, 2005.
 
                                                 
                      Post-Merger     Pre-Merger  
                Combined     Period from
    Period from
       
    Nine Months
          Year
    March 3,
    January 1,
       
    Ended
    Year Ended
    Ended
    2004 to
    2004 to
    Year Ended
 
    September 30,
    December 31,
    December 31,
    December 31,
    March 2,
    December 31,
 
    2006     2005     2004     2004     2004     2003  
    (In millions)  
 
Capital expenditures:
                                               
Leasehold acquisition
  $ 15.5     $ 11.5     $ 4.8     $ 4.4     $ 0.4     $ 4.8  
Oil and natural gas exploration
    154.3       50.0       43.0       35.9       7.1       26.8  
Oil and natural gas development
    264.2       121.7       88.6       82.0       6.6       44.3  
Proceeds from property conveyances
    (2.0 )                             (121.6 )
Acquisitions
    70.9       53.4       4.9       4.9              
Other items (primarily gathering system, capitalized overhead and interest)
    12.1       16.1       7.6       6.4       1.2       7.4  
                                                 
Total capital expenditures, net of proceeds from property conveyances
  $ 515.0     $ 252.7     $ 148.9     $ 133.6     $ 15.3     $ (38.3 )
                                                 
 
Our net capital expenditures for 2005 increased by $103.8 million as compared to 2004, primarily as a result of increased acquisitions, primarily in West Texas, and increased expenditures on development activities. 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.
 
We had no long-term debt outstanding as of December 31, 2003. As of December 31, 2005 and 2004, long-term debt was $156 million and $115 million, respectively. As of September 30, 2006, long-term debt was $614 million.
 
We anticipate that total capital expenditures for 2006 will approximate $690.0 million (of which approximately $70.9 million is attributable to the West Cameron acquisition described under “—Recent Developments”), with approximately 57% allocated to development activities, 41% to exploration activities, and the remainder to other items (primarily capitalized overhead and interest). The 2006 budget is an increase of approximately 83% over our 2005 expenditures. The increase is primarily driven by the addition of the Forest Gulf of Mexico operations, continuation of our deepwater development activities, and expansion of our exploration activities, including increasing our acquisition of leasehold and seismic data. In addition, we expect to incur approximately $85 million for repairs of damage caused by Hurricanes Katrina and Rita. While this will be a cash outflow in 2006, we expect to recover these costs through insurance reimbursements beginning in early 2007, although complete insurance settlement of all hurricane-related claims may take several additional quarters. See “Business — Insurance Matters.” Since we believe these costs to be reimbursable, they will not be reflected in reported 2006 capital expenditures.
 
Cash Flows.  During the first nine months of 2006, we utilized our secured credit facility to fund amounts for capital expenditures incurred in excess of cash flows. Although we expect to fund exploration and


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development capital expenditures during the remainder of 2006 from internally generated cash flows, the credit facility may be utilized for such expenditures exceeding current projections and for acquisitions.
 
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. 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 reduced. If our cash flows are less than anticipated or amounts available for borrowing under our revolving credit facility are reduced or we can not access the high yield or other debt markets, 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 year ended December 31, 2005, our Gulf of Mexico properties comprised about 77% of our total production or 93% on a pro forma basis. We plan to maintain an active drilling program for 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 and we begin to exploit our newly acquired offshore assets. 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 that subsequently was amended and restated. The new credit facility was fully drawn at inception for $135 million. In addition, we issued a $10 million promissory note to JEDI as part of the merger consideration. See “— Enron Related Matters” and “— JEDI Term Promissory Note.” Net proceeds from a private equity placement were approximately $44 million, of which $6 million was used to pay down the JEDI promissory note with the remainder used to pay down the credit facility. The JEDI note was fully repaid at its maturity date of March 2, 2006.
 
For the years ended December 31, 2005 and 2004, our interest rate sensitivity for a change in interest rates of 1/8 percent on average outstanding debt under our credit facility is approximately $0.1 million and $0.1 million, respectively. The LIBOR rate on which our bank borrowings are primarily based was 4.69% as of March 2, 2006.
 
We had net cash inflows of $0.3 million and $2.0 million for the nine-month periods ended September 30, 2006 and 2005, respectively, and a net cash inflow of $2.0 million in 2005 compared to a net cash outflow of $57.6 million in 2004 and a net cash inflow of $41.8 million in 2003. A discussion of the major components of cash flows for these periods follows.
 


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                    Post-Merger   Pre-Merger
                Non-GAAP
  Period from
  Period from
   
                Combined   March 3,
  January 1,
   
    Nine Months
  Year Ended
  Year Ended
  2004 to
  2004 to
  Year Ended
    Ended September 30,   December 31,
  December 31,
  December 31,
  March 2,
  December 31,
    2006   2005   2005   2004   2004   2004   2003
    (In millions)
 
Cash flows provided by operating activities
  $ 172.8     $ 135.4     $ 165.4     $ 155.5     $ 135.2     $ 20.3     $ 88.9  
 
Net cash flows from operations increased by $37.4 million to $172.8 million from $135.4 million for the nine-month periods ended September 30, 2006 and 2005, respectively. The increase was primarily due to increased operating revenues attributable to the Forest Gulf of Mexico operations acquired.
 
Cash flows provided by operating activities in 2005 increased by $9.9 million compared to 2004. The increase was primarily due to negative changes in working capital offset by lowered operating revenues. Cash flows provided by operating activities in 2004 increased by $66.6 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.
 
                                                         
                    Post-Merger   Pre-Merger
                Non-GAAP
  Period from
  Period from
   
                Combined   March 3,
  January 1,
   
    Nine Months
  Year Ended
  Year Ended
  2004 to
  2004 to
  Year Ended
    Ended September 30,   December 31,
  December 31,
  December 31,
  March 2,
  December 31,
    2006   2005   2005   2004   2004   2004   2003
    (In millions)
 
Cash flows (used in) provided by investing activities
  $ (423.5 )   $ (142.1 )   $ (247.8 )   $ (148.3 )   $ (133.0 )   $ (15.3 )   $ 52.9  
 
Net cash flows used for investing activities increased to $423.5 million from $142.1 million for the nine-month periods ended September 30, 2006 and 2005, respectively, due to increased capital expenditures of $117.4 million primarily related to our King Kong and Pluto deepwater projects as well as development drilling in our West Texas fields, and the $70.9 million acquisition of BP’s interests in West Cameron 110/111.
 
Cash flows used in investing activities in 2005 increased by $99.5 million compared to 2004 due to increased capital expenditures in 2005. Cash flows used in investing activities in 2004 increased by $201.2 million compared to 2003 due to increased capital expenditures in 2004 and the sale of assets in prior years.
 
                                                         
                    Post-Merger   Pre-Merger
                Non-GAAP
  Period from
  Period from
   
                Combined   March 3,
  January 1,
   
    Nine Months
  Year Ended
  Year Ended
  2004 to
  2004 to
  Year Ended
    Ended September 30,   December 31,
  December 31,
  December 31,
  March 2,
  December 31,
    2006   2005   2005   2004   2004   2004   2003
    (In millions)
 
Cash flows (used in) provided by financing activities
  $ 251.0     $ 8.7     $ 84.4     $ (64.9 )   $ (64.9 )         $ (100.0 )
 
Net cash provided by financing activities was $251.0 million for the nine-month period ended September 30, 2006 compared to net cash provided by financing activities of $8.7 million for the same period in 2005. Financings in 2006 were primarily used to fund the Forest transaction and capital expenditures in excess of current cash flows. Mariner also paid the remaining balance of the JEDI term note on March 2, 2006.
 
Cash flows provided by financing activities in 2005 were primarily the result of proceeds from a private equity offering in March 2005 ($44 million) and net borrowings under our revolving credit facility ($47 million). 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.

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Commodity Prices and Related Hedging Activities
 
The energy markets have historically been very volatile, and we can reasonably expect that oil and gas prices will be subject to wide fluctuations in the future. If 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. In addition, forward price curves and estimates of future volatility are used to assess and measure the ineffectiveness of our open contracts at the end of each period. If open contracts cease to qualify for hedge accounting, the mark to market change in fair value is recognized in the income statement. Loss of hedge accounting and cash flow designation will cause volatility in earnings. The fair values we report in our financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.
 
As of September 30, 2006, Mariner had the following hedge contracts outstanding:
 
                         
                September 30,
 
                2006 Fair Value
 
Fixed Price Swaps
  Quantity     Fixed Price     Gain/(Loss)  
                (In millions)  
 
Crude Oil (Bbls)
                       
October 1 — December 31, 2006
    644,920     $ 72.24     $ 5.1  
Natural Gas (MMbtus)
                       
October 1 — December 31, 2006
    9,315,000       7.97       20.9  
January 1 — December 31, 2007
    15,846,323       9.68       31.7  
January 1 — September 30, 2008
    3,059,689       9.58       4.3  
                         
Total
                  $ 62.0  
                         
 
                                 
                      September 30,
 
                      2006 Fair Value
 
Costless Collars
  Quantity     Floor     Cap     Gain/(Loss)  
                      (In millions)  
 
Crude Oil (Bbls)
                               
October 1 — December 31, 2006
    63,480     $ 32.65     $ 41.52     $ (1.4 )
January 1 — December 31, 2007
    2,032,689       59.84       84.21       (1.0 )
January 1 — December 31, 2008
    1,195,495       61.66       86.80       2.7  
Natural Gas (MMbtus)
                               
October 1 — December 31, 2006
    1,851,960       5.78       7.85       0.9  
January 1 — December 31, 2007
    14,106,750       6.87       11.82       1.7  
January 1 — December 31, 2008
    12,347,000       7.83       14.60       9.1  
                                 
Total
                          $ 12.0  
                                 
 
As of December 31, 2005, Mariner had the following hedge contracts outstanding:
 
                         
                December 31,
 
                2005 Fair Value
 
Fixed Price Swaps
  Quantity     Fixed Price     Gain/(Loss)  
                (In millions)  
 
Crude Oil (Bbls)
                       
January 1 — December 31, 2006
    140,160     $ 29.56       (4.7 )
Natural Gas (MMBtus)
                       
January 1 — December 31, 2006
    1,827,547       5.53       (9.9 )
                         
Total
                  $ (14.6 )
                         


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                      December 31,
 
                      2005 Fair Value
 
Costless Collars
  Quantity     Floor     Cap     Gain/(Loss)  
                      (In millions)  
 
Crude Oil (Bbls)
                               
January 1 — December 31, 2006
    251,850     $ 32.65     $ 41.52       (5.3 )
January 1 — December 31, 2007
    202,575       31.27       39.83       (4.7 )
Natural Gas (MMBtus)
                               
January 1 — December 31, 2006
    7,347,450       5.78       7.85       (22.3 )
January 1 — December 31, 2007
    5,310,750       5.49       7.22       (16.9 )
                                 
Total
                          $ (49.2 )
                                 
 
As of December 31, 2004, Mariner had the following hedge contracts outstanding:
 
                         
                December 31,
 
                2004 Fair Value
 
Fixed Price Swaps
  Quantity     Fixed 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 )
                                 
 
As of November 3, 2006, there were no hedging transactions entered into subsequent to September 30, 2006.
 
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 September 30, 2006, December 31, 2005 and December 31, 2004, we had no deposits for collateral with our counterparties.


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The following table sets forth the results of third party hedging transactions during the periods indicated:
 
                                 
    Nine Months Ended
    Year Ended December 31,  
    September 30, 2006     2005     2004     2003  
    (Dollars in millions)  
 
Natural Gas
                               
Quantity settled (MMBtus)
    19,378,000       15,917,159       18,823,063       25,520,000  
Increase/(Decrease) in Natural Gas Sales
  $ 5.0     $ (33.0 )   $ (10.8 )   $ (27.1 )
Crude Oil
                               
Quantity settled (Mbbls)
    937       836       1,554       730  
Decrease in Crude Oil Sales
  $ (6.5 )   $ (20.8 )   $ (16.9 )   $ (5.0 )
 
The cash losses on contracts settled for natural gas and oil produced during the nine-month period ended September 30, 2006 was $8.3 million. An $8.3 million non-cash gain was recorded for the nine-month period ended September 30, 2006 relating to the hedges acquired through the Forest transaction. Additionally, an unrealized gain of $1.4 million was recognized for the nine-month period ended September 30, 2006 related to the ineffective portion of open contracts that were not eligible for deferral under SFAS 133 due primarily to the basis differentials between the contract price, which is NYMEX-based for oil and Henry Hub-based for gas, and the indexed price at the point of sale. 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 years ended December 31, 2005 and 2004, $4.5 million and $7.9 million, respectively, of the $53.8 million and $27.7 million total decrease in natural gas and oil sales, respectively, of cash hedge losses relate to the liability recorded at the time of the merger.
 
Interest Rate Hedges
 
Borrowings under our revolving credit facility, discussed above, mature on March 2, 2010, 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. For the nine-month period ended September 30, 2006, the interest rate on our outstanding bank debt averaged 7.16%. If the balance of our bank debt at September 30, 2006 were to remain constant, a 10% change in market interest rates would impact our cash flow by approximately $0.4 million per quarter or $1.1 million for the nine-month period ended September 30, 2006.
 
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 September 30, 2006:
 
                                         
          Less Than
    1-3
    3-5
    More Than
 
    Total     One Year     Years     Years     5 Years  
    (In millions)  
 
Debt obligations(1)
  $ 614.0     $     $     $ 314.0     $ 300.0  
Interest obligations(2)
    155.1       28.1       45.0       45.0       37.0  
Operating leases
    7.6       1.5       2.4       1.3       2.4  
Abandonment liabilities
    222.5       52.0       41.1       43.8       85.6  
Derivative financial instruments
    (74.0 )     (55.3 )     (18.7 )            
Other liabilities
    243.1       237.1       6.0              
                                         
Total contractual cash commitments
  $ 1,168.3     $ 263.4     $ 75.8     $ 404.1     $ 425.0  
                                         


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(1) As of September 30, 2006, we had incurred debt obligations under our secured credit facility and the senior unsecured notes that are due on March 2, 2010 and April 15, 2013, respectively.
 
(2) Interest obligations represent interest due on the senior unsecured notes at 7.5%. Future interest obligations under our credit facility are uncertain, due to the variable interest rate on fluctuating balances. Based on a 8.0% weighted average interest rate on amounts outstanding under our amended and restated credit facility as of September 30, 2006, $25.1 million, $50.2 million and $13.6 million would be due under the credit facility in less than one year, 1-3 years and 3-5 years, respectively.
 
Certain MMS Leases.  Each of Mariner and its subsidiary, Mariner Energy Resources, Inc., owns numerous properties in the Gulf of Mexico. Certain of these 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 leases until a designated volume is produced. Two of these leases held by Mariner and one held by its subsidiary contained language that limited royalty relief if commodity prices exceeded predetermined levels. Since 2000, commodity prices have exceeded the predetermined levels, except in 2002. Mariner and its subsidiary believe the MMS did not have the authority to set pricing limits in these leases and have withheld payment of royalties on the leases while disputing the MMS’ authority in two pending proceedings. Mariner has recorded a liability for 100% of the exposure on its two leases, which at September 30, 2006 was $19.9 million. Various legal proceedings are pending concerning this potential liability and further proceedings may be initiated with respect to years not covered by the pending proceedings. In April 2005, the MMS denied Mariner’s administrative appeal of the MMS’ April 2001 order asserting royalties were due because price limits had been exceeded. In October 2005, Mariner filed suit in the U.S. District Court for the Southern District of Texas seeking judicial review of the dismissal. Upon motion of the MMS, Mariner’s lawsuit was dismissed on procedural grounds. In August 2006, Mariner filed an appeal of such dismissal. Mariner had also filed an administrative appeal of a December 2005 order of the MMS demanding royalties for calendar year 2004 under the same leases at issue in the April 2001 MMS order. However, the MMS withdrew such order, rendering the appeal moot. Thereafter, in May 2006, the MMS issued an order asserting price limits were exceeded in calendar years 2001, 2003 and 2004 and, accordingly, that royalties were due under such leases on oil and gas produced in those years. Mariner has filed and is pursuing an administrative appeal of that order.
 
The potential liability of Mariner Energy Resources, Inc. under its lease subject to the RRA containing such commodity price threshold language is approximately $2.2 million as of September 30, 2006. This potential liability relates to production from the lease commencing July 1, 2005, the effective date of Mariner’s acquisition of Mariner Energy Resources, Inc. A reserve for this possible liability will be made when deemed appropriate. The MMS has not yet made demand for non-payment of royalties alleged to be due for calendar years subsequent to 2004 on the basis of price thresholds being exceeded.
 
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, this no longer is an off-balance sheet arrangement.


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Letters of Credit — On March 2, 2006, Mariner obtained a $40 million letter of credit under its senior secured letter of credit facility. The letter of credit was issued in favor of Forest to secure performance of our obligation to drill and complete 150 wells under an existing drill-to-earn program and is not included as a use of the borrowing base of the senior secured credit facility. This letter of credit will reduce periodically by an amount equal to the product of $0.5 million times the number of wells exceeding 75 that are drilled and completed. The first reduction of approximately $4.3 million occurred in October 2006 based upon the 83 wells drilled and completed as of September 30, 2006. Mariner expects additional reductions based upon quarterly drilling activity, with the next reduction anticipated in January 2007.
 
Mariner’s senior secured credit facility also has a letter of credit facility of up to $50 million that is included as a use of the borrowing base. As of September 30, 2006, two such letters of credit for $4.2 million and $10.4 million were outstanding. These two letters of credit are required for plugging and abandonment obligations at certain of Mariner’s offshore fields.
 
Recent Accounting Pronouncements
 
In September 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF Issue 04-13 requires that purchases and sales of inventory with the same counterparty in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. The consensus is effective for inventory arrangements entered into, modified or renewed in interim or annual reporting periods beginning after March 15, 2006. We do not expect the adoption of this EITF Issue to have a material impact on our consolidated financial position, results of operations or cash flows.
 
In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes.  FIN No. 48 clarifies SFAS No. 109, Accounting for Income Taxes, and requires us to evaluate our tax positions for all jurisdictions and all years where the statute of limitations has not expired. FIN No. 48 requires companies to meet a “more-likely-than-not” threshold (i.e. greater than a 50 percent likelihood of being sustained under examination) prior to recording a benefit for their tax positions. Additionally, for tax positions meeting this “more-likely-than-not” threshold, the amount of benefit is limited to the largest benefit that has a greater than 50 percent probability of being realized upon ultimate settlement. The cumulative effect of applying the provisions of the new interpretation will be recorded as an adjustment to the beginning balance of retained earnings, or other components of stockholders’ equity, as appropriate, in the period of adoption. We will adopt the provisions of this interpretation effective January 1, 2007, and are currently evaluating the impact, if any, that this interpretation will have on our financial statements.
 
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. SFAS No. 157 does not require any new fair value measurements but rather it eliminates inconsistencies in the guidance found in various prior accounting pronouncements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. Earlier adoption is encouraged, provided the company has not yet issued financial statements, including for interim periods, for that fiscal year. Although we are still evaluating the potential effects of this standard, we do not expect the adoption of SFAS No. 157 to have a material impact on our consolidated financial position, results of operation, or cash flows.
 
In September 2006, the Securities and Exchange Commission released Staff Accounting Bulletin No. 108, “Quantifying Financial Statement Misstatements” (“SAB 108”). SAB 108 gives guidance on how errors, built up over time in the balance sheet, should be considered from a materiality perspective and corrected. SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. SAB 108 represents the SEC Staff’s views on the proper interpretation of existing rules and as such has no effective date. We do not expect the adoption of SAB 108 to have a material impact on our consolidated financial position, results of operation, or cash flows.
 
In June 2006, the Emerging Issues Task Force (“EITF”) reached a consensus on Issue No. 06-03, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That Is, Gross versus Net Presentation)”. EITF 06-03 requires that companies disclose the


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gross amounts of taxes reported. The consensus is effective for interim or annual reporting periods beginning after December 15, 2006. We do not expect the adoption of this EITF issue to have a material impact on our consolidated financial position, results of operations or cash flows.
 
BUSINESS
 
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 in West Texas. Our management has significant expertise and a successful operating track record in these areas. In the three-year period ended December 31, 2005, we added approximately 280 Bcfe of proved reserves and produced approximately 100 Bcfe, while deploying approximately $475 million of capital on acquisitions, exploration and development.
 
Our primary operating strategy is to generate high-quality exploration and development projects, which enables us to add value through the drill bit. Our expertise in project generation also facilitates our participation in high-quality projects generated by other operators. We will also pursue acquisitions of producing assets that have the potential to provide acceptable risk-adjusted rates of return and further reserve additions through exploration, exploitation, and development opportunities. We target a balanced exposure to development, exploitation and exploration opportunities, both offshore and onshore and seek to maintain a moderate risk profile.
 
On March 2, 2006, we completed a merger transaction with Forest Energy Resources, Inc., which we refer to as Forest Energy Resources. As a result of this merger, we acquired the Gulf of Mexico operations of Forest Oil Corporation (NYSE: FST), which we refer to as the Forest Gulf of Mexico operations. As of December 31, 2005, we had 338 Bcfe of estimated proved reserves, of which approximately 62% were natural gas, and 38% were oil and condensate, and 50% of which was proved developed. Pro forma for the merger transaction, as of December 31, 2005, we had 644 Bcfe of estimated proved reserves, of which approximately 68% were natural gas and 32% were oil and condensate, and 56% of which was proved developed.
 
Our production for 2005 was approximately 29 Bcfe, or 80 MMcfe per day on average, and 95 Bcfe, or 260 MMcfe per day on average, pro forma for the merger. During the year ended December 31, 2005, our pro forma EBITDA was approximately $438.6 million, including $25.7 million of non-cash compensation expense related to restricted stock and stock options granted in 2005, but excluding general and administrative expenses of the Forest Gulf of Mexico operations. Our production for the nine months ended September 30, 2006 was approximately 55 Bcfe, or 200 MMcfe per day on average, and pro forma for the merger, 62 Bcfe, or 229 MMcfe per day on average. During the nine months ended September 30, 2006, our EBITDA was approximately $340.7 million, and pro forma for the merger, approximately $391.7 million, in each case, including a $9.0 million reduction for non-cash compensation expense related to restricted stock and stock options. We believe the overhead costs associated with the Forest Gulf of Mexico operations in 2006 will be approximately $6.4 million, net of capitalized amounts. See footnote 1 on page 13 for our definition of EBITDA and a reconciliation of net income to EBITDA.


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The following table sets forth certain information with respect to our estimated proved reserves, production and acreage by geographic area as of December 31, 2005. 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. Proved reserve estimates do not include any value for probable or possible reserves which may exist, nor do they include any value for undeveloped acreage. The proved reserve estimates represent our net revenue interest in our properties. The reserve information for Mariner as of December 31, 2005 is based on estimates made in a reserve report prepared by Ryder Scott.
 
                                         
                Production for
 
                Year Ended
 
    Estimated Proved
          December 31
 
    Reserve Quantities           2005  
    Oil
    Natural Gas
    Total
    Total Net
    (Natural Gas
 
    (MMbbls)     (Bcf)     (Bcfe)     Acreage     Equivalent (Bcfe))  
 
West Texas
    16.7       105.5       205.5       31,199       6.6  
Gulf of Mexico Deepwater(1)
    4.7       83.2       111.1       185,271       11.8  
Gulf of Mexico Shelf(2)
    0.3       19.0       21.0       124,180       10.7  
                                         
Total
    21.7       207.7       337.6       340,650       29.1  
Proved Developed Reserves
    9.6       110.0       167.4                  
 
 
(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.
 
The following table sets forth certain information with respect to our estimated proved reserves, production and acreage by geographic area on a pro forma basis for our merger with Forest Energy Resources as of December 31, 2005. The reserve information as of December 31, 2005 for the Forest Gulf of Mexico operations is based on estimates made by internal staff engineers of Forest, which estimates were audited by Ryder Scott. This information is presented on a pro forma basis, giving effect to our merger with Forest Energy Resources as though it had been consummated on December 31, 2005. We consummated the merger on March 2, 2006.
 
                                         
                Pro Forma
 
                            Production for
 
    Pro Forma
          Year Ended
 
    Estimated Proved
          December 31
 
    Reserve Quantities     Total
    2005  
    Oil
    Natural Gas
    Total
    Net
    (Natural Gas
 
    (MMbbls)     (Bcf)     (Bcfe)     Acreage     Equivalent (Bcfe))  
 
West Texas
    16.7       105.5       205.5       31,199       6.6  
Gulf of Mexico Deepwater(1)
    4.8       95.7       124.5       241,320       14.0  
Gulf of Mexico Shelf(2)
    12.7       237.6       313.7       652,086       74.3  
                                         
Total
    34.2       438.8       643.7       924,605       94.9  
Proved Developed Reserves
    18.4       252.1       362.3                  
 
 
(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.
 
Forest Gulf of Mexico Merger
 
On March 2, 2006, we completed a merger transaction with Forest Energy Resources. Prior to the consummation of the merger, Forest transferred and contributed the assets and certain liabilities associated with its Gulf of Mexico operations to Forest Energy Resources. Immediately prior to the merger, Forest


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distributed all of the outstanding shares of Forest Energy Resources to Forest shareholders on a pro rata basis. Forest Energy Resources then merged with a newly-formed subsidiary of Mariner, became a new wholly-owned subsidiary of Mariner, and changed its name to Mariner Energy Resources, Inc. Immediately following the merger, approximately 59% of Mariner common stock was held by shareholders of Forest and approximately 41% of Mariner common stock was held by the pre-merger stockholders of Mariner.
 
Forest Energy Resources had approximately 306 Bcfe of estimated proved reserves as of December 31, 2005, of which approximately 76% were natural gas, and 24% were oil and condensate. The reserves and operations acquired from Forest are concentrated in the shelf and deep shelf of the Gulf of Mexico and represent a significant addition to Mariner’s asset portfolio in those areas of operation.
 
We believe our acquisition of the Forest Gulf of Mexico operations and the scale they bring to our business has further moderated our risk profile, provided many exploration, exploitation and development opportunities, enhanced our ability to participate in prospects generated by other operators, and added a significant cash flow generating resource that has improved our ability to compete effectively in the Gulf of Mexico and fund exploration activities and acquisitions. We believe we are well-positioned to optimize the Forest Energy Resources assets through aggressive and timely exploitation.
 
Our Strategy and Our Competitive Strengths
 
Our Strategy
 
The principal elements of our operating strategy include:
 
Generating and pursuing high-quality prospects.  We expect to continue our strategy of growth through the drill bit by continuing to identify and develop high-impact shelf, deep shelf and deepwater projects in the Gulf of Mexico. Our technical team has significant expertise in, and a successful track record of achieving growth by, generating prospects internally and selectively participating in prospects generated by other operators. We believe the Gulf of Mexico is an area that offers substantial growth opportunities, and our acquisition of the Forest Gulf of Mexico operations has more than doubled our existing undeveloped acreage position in the Gulf, providing numerous additional exploration, exploitation and development opportunities.
 
Maintaining a moderate risk profile.  We seek to manage our risk profile by targeting a balanced exposure to development, exploitation and exploration opportunities. For example, we intend to continue to develop and seek to expand our West Texas asset base, which contributes stable cash flows and long-lived reserves to our portfolio as a counterbalance to our high-impact, high-production Gulf of Mexico assets. We also seek to mitigate and diversify our risk in drilling projects by selling partial or entire interests in projects to industry partners or by entering into arrangements with industry partners in which they agree to pay a disproportionate share of drilling costs and compensate us for expenses incurred in prospect generation. We also enter into trades or farm-in transactions whereby we acquire interests in third-party generated prospects, thereby gaining exposure to a greater number of prospects. We expect more opportunities to participate in these prospects in the future as a result of our larger scale and increased cash flow from the Forest Gulf of Mexico operations.
 
Pursuing opportunistic acquisitions.  Until 2005, we grew our reserves primarily through the drill bit. In 2005 we added significant proved reserves primarily through acquisitions in West Texas and subsequently in March 2006, through the acquisition of the Forest Gulf of Mexico operations. As part of our growth strategy, we will seek to continue to acquire producing assets that have the potential to provide acceptable risk-adjusted rates of return and further reserve additions through exploration, exploitation and development opportunities.


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Our Competitive Strengths
 
We believe our core resources and strengths include:
 
Our high-quality assets with geographic and geological diversity.  Our assets and operations are diversified among the Gulf of Mexico shelf, deep shelf and deepwater, and West Texas. Our asset portfolio provides a balanced exposure to long-lived West Texas reserves, Gulf of Mexico shelf growth opportunities and high-impact deepwater prospects.
 
Our large inventory of prospects.  We believe we have significant potential for growth through the development of our existing asset base. The acquisition of the Forest Gulf of Mexico operations more than doubled our existing undeveloped acreage position in the Gulf of Mexico to approximately 450,000 net acres and increased our total net leasehold acreage offshore to nearly one million acres, providing numerous exploration, exploitation and development opportunities. As of September 30, 2006, we have an inventory of approximately 890 drilling locations in West Texas, which we believe would require approximately six years to drill at our current rate. These include approximately 430 locations pertaining to 98 Bcfe of estimated net proved undeveloped reserves and approximately 460 other locations.
 
Our successful track record of finding and developing oil and gas reserves.  We have demonstrated our expertise in finding and developing additional proved reserves. In the three-year period ended December 31, 2005, we deployed approximately $475 million of capital on acquisitions, exploration and development, while adding approximately 280 Bcfe of proved reserves and producing approximately 100 Bcfe.
 
Our depth of operating experience.  Our team of 41 geoscientists, engineers, geologists and other technical professionals and landmen as of September 30, 2006 average more than 22 years of experience in the exploration and production business (including extensive experience in the Gulf of Mexico), much of it with major oil companies. The addition of experienced Forest personnel to Mariner’s team of technical professionals has further enhanced our ability to generate and maintain an inventory of high-quality drillable prospects and to further develop and exploit our assets. Mariner’s technical team has also proven to be an effective and efficient operator in West Texas, as evidenced by our successful production and reserve growth there in recent years.
 
Our technology and production techniques.  Our team of geoscientists currently has access to seismic data from multiple, recent vintage 3-D seismic databases covering more than 7,000 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. We also 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 platforms and top-side facilities that typically are more costly and 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, 2005, we were directly involved in 14 projects (five of which we operated) utilizing subsea tieback systems in water depths ranging from 475 feet to more than 6,700 feet. As of September 30, 2006, we had 18 subsea wells in water depths ranging from 450 feet to more than 4,700 feet. These wells were tied back to 13 host production facilities for production processing. An additional nine wells in water depths ranging from 465 feet to more than 6,800 feet were then under development for tieback to five additional host production facilities.


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Properties
 
We currently 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 (including the largest properties we acquired in our merger with Forest Energy Resources), based on the present value of estimated future net proved reserves as of December 31, 2005, are shown in the following table.
 
                                                             
                          Date
    Estimated
             
        Mariner
    Approximate
    Gross
    Production
    Proved
             
        Working
    Water Depth
    Producing
    Commenced/
    Reserves
          Standardized
 
   
Operator
  Interest (%)     (Feet)     Wells(1)     Expected     (Bcfe)     PV10 Value     Measure  
                                      ($ In millions)(2)     ($ In millions)  
 
West Texas:
                                                           
Aldwell Unit
  Mariner     66.5 (3)     Onshore       246       *       120.7     $ 367.0          
Tamarack/Spraberry Properties
  Tamarack     35.0 (4)     Onshore       187       *       67.8       103.2          
Gulf of Mexico Deepwater:
                                                           
Mississippi Canyon 296/252
                                First Quarter                          
(Rigel)
  Dominion     22.5       5,200       0 (5)     2006       22.5       161.4          
Atwater Valley 426 (Bass Lite)
  Mariner     38.75 (6)     6,800       0       2008       32.3       137.9          
Viosca Knoll 917/961/962
                                Fourth Quarter                          
(Swordfish)
  Mariner(7)     15.0       4,700       2       2005       12.9       101.7          
Mississippi Canyon 718 (Pluto)(8)
  Mariner     51.0       2,830       0       1999       9.0       69.3          
Green Canyon 646 (Daniel Boone)
  W&T Offshore     40.0       4,300       0       2008       16.4       61.8          
Green Canyon 516 (Yosemite)
  ENI     44.0       3,900       1       2002       7.8       53.9          
East Breaks 420**
  Noble     50.0       2,560       1       2002       13.4       75.8          
Gulf of Mexico Shelf:
                                                           
East Cameron 14**
  Mariner     50.0       25       2       *       15.2       91.5          
Eugene Island 292**
  Mariner     45.0       195       8       *       8.2       54.7          
Eugene Island 53**
  Mariner     50.0 (9)     40       4       *       10.4       78.1          
High Island 116**
  Mariner     98.9 (10)     45       2       *       9.7       52.7          
Ship Shoal 26**
  Mariner     100.0       10       1       *       7.2       41.5          
South Marsh Island 18**
  Mariner     100.0       75       1       1993       9.5       50.6          
South Pass 24-NCOC**
  Mariner     100.0       10       15       *       23.5       103.8          
Vermilion 14**
  Mariner     100.0       20       16       *       32.8       177.7          
Vermilion 380**
  Mariner     55.0-100.0       320       5       *       11.4       59.2          
West Cameron 110/SE/4 111**
  BP/Amoco(11)     37.5 (11)     40.5       5       *       9.0       51.9          
West Cameron 111/112**
  Mariner     55.0-100.0       43.1       1       2004       6.5       49.8          
West Cameron 205**
  Mariner     100.0       50       1       *       5.7       41.9          
Other Properties
                        93               48.2       225.6          
Other Properties (Forest pro forma)**
                        344               143.6       840.8          
                                                             
Total:
                        935               643.7     $ 3,051.8     $ 2,201.7  
                                                             
 
 
Production commenced twenty or more years ago.
 
**  Pro forma properties from Forest Gulf of Mexico operations.
 
(1) Wells producing or capable of producing as of December 31, 2005.


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(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) Mariner operates the field and owns working interests in individual wells ranging from approximately 33% to 84%.
 
(4) Mariner owns an approximate average 35% working interest in producing wells. Upon drilling and completing 150 additional wells, Mariner will obtain an approximate 35% working interest in the entire committed acreage. As of September 30, 2006, 83 of such wells had been drilled and completed.
 
(5) The Rigel Prospect commenced production with one well in the first quarter of 2006.
 
(6) Since December 31, 2005, Mariner has exercised a preferential right with respect to the property, thereby increasing its working interest to 42.19%.
 
(7) 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.
 
(8) 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, 2005, 8.9 Bcfe of our net proved reserves attributable to this project were classified as proved behind pipe reserves. Production from Pluto recommenced in the third quarter of 2006.
 
(9) Mariner operates the field and owns working interests in individual wells ranging from approximately 50% to 100%.
 
(10) Mariner operates the field and owns working interests in individual wells ranging from approximately 98.9% to 100%.
 
(11) In August 2006, Mariner Energy Resources, Inc. exercised a preferential right with respect to the West Cameron 110 and the southeast quarter of West Cameron 111, thereby increasing its working interest in these properties to 100%, exclusive of retained interests in depths below 15,000 feet. In addition, Mariner Energy, Inc. became operator of the interests its subsidiary owns.
 
West Texas
 
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, 54 wells in 2004 and 65 wells in 2005. As of December 31, 2005, there were a total of 249 wells producing or capable of producing in the field, and as of September 30, 2006, an additional 27 wells were capable of production.
 
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 contracts with third parties to provide processing of our natural gas and transportation of our oil produced in the unit. The 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. These arrangements have improved the economics of production from the Aldwell Unit.
 
Tamarack/Spraberry Properties.  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 and complete an additional 150 wells within a four-year period, while 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. As of September 30, 2006, we have drilled and completed 83 wells under this agreement.
 
Other Projects and Activity.  In December 2004, we acquired an approximate 50% working interest in two Permian Basin fields containing approximately 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


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opportunities. We have commenced drilling operations in one of the fields and as of September 30, 2006, have drilled and completed 23 wells, all of which are productive.
 
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.
 
In September 2005, we acquired a 100% working interest and 75% net revenue interest in three producing wells and approximately 3,300 leasehold acres that are held by production in the Canyon Sawyer Field in Sutton and Schleicher Counties, Texas. The purchase price was $700,000. Since acquiring the property, we have refracted two of the three producing wells acquired, and drilled and completed six new wells as Canyon Sand gas producers. We expect to complete two additional Canyon Sand wells in the fourth quarter of 2006. We have approximately 20 additional potential drilling locations on the property.
 
In December 2005, we acquired an interest in approximately 5,500 acres with an average 84% working interest and 64% net revenue interest in the Spraberry trend area 5-10 miles southwest of our Aldwell Unit. The purchase price was $5.5 million with an effective date of August 1, 2005 and included 34 producing wells with the potential to drill an additional 68 wells on 40-acre spacing. During the third quarter of 2006, we drilled and completed five new wells, all of which are productive.
 
During 2005, our aggregate net capital expenditures for West Texas were approximately $86 million, and we added 97.2 Bcfe of proved reserves, while producing 6.6 Bcfe. Average daily net production from our West Texas operations increased from 10.8 MMcfe per day in 2004 to 17.8 MMcfe per day in 2005, representing an increase of 64%. As of December 31, 2005, our West Texas operations included 487 producing wells on 31,199 net acres, compared to 189 producing wells on 14,448 net acres at December 31, 2004.
 
Gulf of Mexico Deepwater
 
Mississippi Canyon 296/252 (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. Our working interest in Rigel is 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 was developed with a single subsea well tied back 12 miles to an existing subsea manifold that is connected to an existing platform. Production commenced in the first quarter of 2006.
 
Atwater Valley 426 (Bass Lite).  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 6,800 feet of water. We have a 42.19% working interest and have been designated operator of this project. Our working interest partners have approved development plans. The process of selecting suppliers of major equipment and services is substantially complete. Drilling operations are expected to begin in the fourth quarter of 2006, with drilling and completion of two wells anticipated by the second quarter of 2007 and initial production expected in 2008.
 
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 commencement of initial production and own a 15% working interest. The project 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 and production commenced in the fourth quarter of 2005 on two wells and in October 2006 on the third well.
 
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


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pending the drilling of a new well and completion of the installation of an infield 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 complete and production recommenced in the third quarter of 2006, following completion of the platform operator’s repairs to the host facilities necessitated by damage inflicted by Hurricane Katrina.
 
Green Canyon 646 (Daniel Boone).  Mariner generated the Daniel Boone prospect and acquired a 100% working interest in Daniel Boone at a Gulf of Mexico federal offshore lease sale in July 1998. The project is located in approximately 4,300 feet of water approximately 165 miles south 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 2003. The project will be developed as a subsea tieback to existing infrastructure and is expected to commence production in 2008.
 
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, Louisiana. In 2001, we drilled an exploratory well on the prospect, and in February 2002 commenced production via a 16-mile subsea tieback to an existing platform which also handles production from the King Kong field in Green Canyon 472/473, in which we own a 50% interest.
 
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. A successful well was drilled in 2001. The project was completed with a subsea tieback to existing infrastructure. Production commenced in June 2002. The property was acquired by Mariner on March 2, 2006 as part of its merger with Forest Energy Resources. In the second quarter of 2006, additional compression was added to the host platform which resulted in an approximate 50% increase in production.
 
Other Projects 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, Louisiana 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 it commenced production in October 2006.
 
In June 2005, we increased our working interest in the LaSalle project (East Breaks 513, 514 and 558) 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. We have 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 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 feet and 3,300 feet, respectively. Mariner and Kerr McGee committed to drill four wells, three on East Breaks 602 and one on East Breaks 558. The four wells have been drilled and were successful. First production is expected in 2008, with related completion and facility capital being spent in 2006 and 2007. As of December 31, 2005, we had not recorded proved reserves to these projects.
 
At the King Kong field (Green Canyon blocks 472 and 473), a two-well drilling program to exploit potential new reserve additions has been executed. We drilled one successful development well on block 473 in the first quarter of 2006, and an unsuccessful exploration well on block 472 in the second quarter of 2006. We own a 50% working interest in the King Kong field in Green Canyon 472 and 473. The development well on Green Canyon 473 has been completed and initial production commenced in April 2006.
 
Gulf of Mexico Shelf
 
Each of the following Gulf of Mexico shelf properties was acquired by Mariner on March 2, 2006 as part of its merger with Forest Energy Resources.


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East Cameron 14.  Forest acquired a 50% working interest in this property through Forest’s acquisition of Forcenergy Inc in 2000. Since March 2, 2006, Mariner has operated the property and owns a 50% working interest. This property is located in approximately 25 feet of water, approximately 30 miles southeast of Cameron, Louisiana.
 
Eugene Island 292.  This property was installed in 1967, with first production commencing in 1970. Since March 2, 2006, Mariner has operated the property and 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.  The shallow rights to this property were acquired in 1993 from Sandefer Offshore Operating. Subsequently, the deep rights were acquired from Pennzoil in 1995 and 1997. Since March 2, 2006, Mariner has operated the property and 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.  This property was acquired in 1993 from Arco. In 2000 Forest purchased the remaining working interests in this property and, since March 2, 2006, Mariner has operated the property and owns a 100% working interest as a result of our acquisition of the Forest Gulf of Mexico operations. The property is located in approximately 45 feet of water, approximately 49 miles southwest of Cameron, Louisiana. In October 2006, we announced that we made a material conventional shelf discovery in the High Island 116 #5ST1 well, drilled to a total measured depth of 14,683 feet / 13,150 feet true vertical depth. The well encountered approximately 540 feet of net true vertical depth pay in thirteen sands. We anticipate completion and initial production in the fourth quarter of 2006. We have a 100% working interest and an approximate 72% net revenue interest in the well.
 
Ship Shoal 26.  This property was acquired through Forest’s acquisition of Forcenergy Inc in 2000. Since March 2, 2006, Mariner has operated the property and 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 18.  This property was acquired through Forest’s acquisition of Forcenergy Inc in 2000. Forest subsequently sold a 50% working interest in the property to Union Oil of California (Unocal) in 2001. As part of an acquisition of properties from Unocal in 2003, Forest repurchased Unocal’s 50% working interest, and, since March 2, 2006, Mariner has operated the property and 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.  This property was acquired through Forest’s acquisition of Forcenergy Inc in 2000. Forest acquired the remaining working interest (approximately 25%) from Pogo in 2004. Since March 2, 2006, Mariner has operated the property and currently holds a 100% working interest. The property is located approximately 82 miles south of New Orleans, Louisiana in approximately 10 feet of water.
 
Vermillion 14.  A 50% working interest in this property was acquired from Unocal in 2003. In 2004, Forest acquired BP’s 50% working interest and, since March 2, 2006, Mariner has operated the property and 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.  This property was acquired through Forest’s 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. Since March 2, 2006, Mariner has operated the property and owns working interests in the individual wells ranging from approximately 55% to 100%. The property is located in approximately 320 feet of water, approximately 135 miles southeast of Cameron, Louisiana.
 
West Cameron 110/SE/4 111.  In August 2006, Mariner Energy Resources, Inc. exercised a preferential right with respect to the West Cameron 110 and the southeast quarter of West Cameron 111, thereby increasing its working interest in these properties to 100%, exclusive of retained interests in depths below


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15,000 feet. In addition, Mariner Energy, Inc. became operator of the interests its subsidiary owns. A 37.5% working interest was acquired through Forest’s acquisition of Forcenergy Inc in 2000. The property is located in approximately 45 feet of water, approximately 21 miles south of Cameron, Louisiana.
 
West Cameron 111/112.  This property consists of the north half and southwest quarter of Block 111 and all of Block 112, and was acquired through Forest’s 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. Effective July 2005, Forest reacquired the working interests sold in the north half and southwest quarter of Block 111 and, as a result, Mariner owns a 100% working interest in the Block 111 portion of the property and a 55% working interest in Block 112. Since March 2, 2006, Mariner has operated the property. The property is located in approximately 40 feet of water, approximately 45 miles southeast of Cameron, Louisiana.
 
West Cameron 205.  This property was acquired through Forest’s acquisition of Forcenergy Inc in 2000. Since March 2, 2006, Mariner has operated the property and owns a 100% working interest in the property, which is located in approximately 50 feet of water, approximately 36 miles south of Cameron, Louisiana.
 
Other Projects and Activity.  In connection with the March 2005 Central Gulf of Mexico federal lease sale, Mariner was awarded West Cameron 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 709, East Breaks 844 and East Breaks 843).
 
In May 2005, Mariner drilled the Capricorn discovery well, which encountered over 100 net feet of pay in four zones. The Capricorn project is located on High Island A341 approximately 115 miles south southwest of Cameron, Louisiana, in approximately 240 feet of water. During 2006, the platform and facilities were installed, and a successful appraisal well was drilled. Production from two wells commenced in the third quarter of 2006.
 
In late 2002, Mariner drilled a successful exploration well on our Mississippi Canyon 66 (Ochre) 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 have entered into a production handling agreement with the operator of the nearby Amberjack (MC109) host facility, and production recommenced in the third quarter of 2006, following completion of the operator’s repairs to the host facility necessitated by damage inflicted by Hurricane Katrina.
 
In connection with the March 2006 Central Gulf of Mexico lease sale, Mariner was the high bidder on ten blocks including two deepwater blocks, at a potential aggregate cost of $18 million to Mariner. We have been awarded nine blocks, including the block on which we made our highest bid and the two deepwater blocks (Mississippi Canyon 152 and 239). Our net cost exposure for the nine blocks is approximately $16.5 million. No lease was awarded on a tenth block on which we also were the high bidder.
 
At the August 2006 Western Gulf of Mexico lease sale, Mariner was the apparent high bidder on six blocks, including High Island Blocks 233, A21, A126, A154, A155 and A480, located in water depths ranging from 39 feet to 151 feet. Mariner has been awarded all six blocks. Our cost for the approximately 25,000 net acres covered by the six blocks is approximately $4.4 million.


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Estimated Proved Reserves
 
The following table sets forth certain information with respect to our estimated proved reserves by geographic area as of December 31, 2005. 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, 2005 for Mariner is based on estimates made in a reserve report prepared by Ryder Scott.
 
                                                         
    Estimated Proved
                         
    Reserve Quantities                          
          Natural
                               
    Oil
    Gas
    Total
    PV10 Value(3)     Standardized
 
Geographic Area
  (MMbbls)     (Bcf)     (Bcfe)     Developed     Undeveloped     Total     Measure  
 
West Texas
    16.7       105.5       205.5     $ 333.7     $ 173.4     $ 507.1          
Gulf of Mexico Deepwater(1)
    4.7       83.2       111.1       383.3       257.4       640.7          
Gulf of Mexico Shelf(2)
    0.3       19.0       21.0       132.6       1.4       134.0          
                                                         
Total
    21.7       207.7       337.6     $ 849.6     $ 432.2     $ 1,281.8     $ 906.6  
                                                         
Proved Developed Reserves
    9.6       110.0       167.4                                  
                                                         
 
 
(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 below for a definition of PV10 and a reconciliation of PV10 to the standardized measure of discounted future net cash flows.
 
The following table sets forth certain information with respect to our pro forma estimated proved reserves by geographic area as of December 31, 2005. This information is presented on a pro forma basis, giving effect to our merger with Forest Energy Resources as though it had been consummated on December 31, 2005. We consummated the merger on March 2, 2006. The reserve information as of December 31, 2005 for the Forest Gulf of Mexico operations is based on estimates made by internal staff engineers at Forest, which estimates were audited by Ryder Scott. Accordingly, the pro forma reserve information presented below includes both reserves that were estimated by Ryder Scott and reserves that were estimated by internal staff engineers at Forest and audited by Ryder Scott.
 
                                                         
    Pro Forma
                         
    Estimated Proved
                         
    Reserve Quantities                          
          Natural
          Pro Forma
    Pro Forma
 
    Oil
    Gas
    Total
    PV10 Value(3)     Standardized
 
Geographic Area
  (MMbbls)     (Bcf)     (Bcfe)     Developed     Undeveloped     Total     Measure  
                            ($ millions)           ($ millions)  
 
West Texas
    16.7       105.5       205.5     $ 333.7     $ 173.4     $ 507.1          
Gulf of Mexico Deepwater(1)
    4.8       95.7       124.5       406.3       310.3       716.6          
Gulf of Mexico Shelf(2)
    12.7       237.6       313.7       1,283.4       544.7       1,828.1          
                                                         
Total
    34.2       438.8       643.7     $ 2,023.4     $ 1,028.4     $ 3,051.8     $ 2,201.7  
                                                         
Proved Developed Reserves
    18.4       252.1       362.3                                  
                                                         
 
 
(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.


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(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 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 may 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 affect 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 (and, with respect to 2005, pro forma PV10) to the standardized measure of discounted future net cash flows.
 
                                 
    Pro Forma at
                   
    December 31,
    At December 31,  
    2005     2005     2004     2003  
    (In millions)  
 
PV10
  $ 3,051.8     $ 1,281.8     $ 668.0     $ 533.5  
Future income taxes, discounted at 10%
    850.1       375.2       173.6       115.3  
Standardized measure of discounted future net cash flows
  $ 2,201.7     $ 906.6     $ 494.4     $ 418.2  
                                 
 
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 11 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, 2005 used in the proved reserve and future net revenues estimates above were calculated using NYMEX prices at December 31, 2005, of $61.04 per bbl of oil and $10.05 per MMBtu of gas, adjusted for our price differentials but excluding the effects of hedging.


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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. The information for the nine months ended September 30, 2006 and year ended December 31, 2005 also is presented on a pro forma basis, giving effect to our merger with Forest Energy Resources as though it had been consummated on January 1, 2005. We consummated the merger on March 2, 2006.
 
                                                 
    Pro Forma                          
    Nine Months
    Year
    Nine Months
                   
    Ended
    Ended
    Ended
                   
    September 30,
    December 31,
    September 30,
    Year Ended December 31,  
    2006     2005     2006     2005     2004     2003  
 
Production:
                                               
Natural gas (Bcf)
    45.6       67.5       39.3       18.4       23.8       23.8  
Oil (Mbbls)
    2.8       4.6       2.5       1.8       2.3       1.6  
Total natural gas equivalent (Bcfe)
    62.4       94.9       54.5       29.1       37.6       33.4  
Average daily natural gas equivalent (MMcfe)
    228.5       260.0       200.0       79.7       103.0       91.5  
Average realized sales price per unit (excluding the effects of hedging):
                                               
Natural gas ($/Mcf)
  $ 7.25     $ 8.04     $ 7.05     $ 8.33     $ 6.12     $ 5.43  
Oil ($/bbl)
    61.23       48.86       62.13       51.66       38.52       26.85  
Total natural gas equivalent ($/Mcfe)
    8.05       8.07       7.94       8.43       6.23       5.15  
Average realized sales price per unit (including the effects of hedging):
                                               
Natural gas ($/Mcf)
  $ 7.42     $ 6.40     $ 7.25     $ 6.66     $ 5.80     $ 4.40  
Oil ($/bbl)
    58.95       34.18       59.58       41.23       33.17       23.74  
Total natural gas equivalent ($/Mcfe)
    8.07       6.20       8.00       6.74       5.70       4.27  
Expenses ($/Mcfe):
                                               
Lease operating expenses
  $ 1.26     $ 1.04     $ 1.15     $ 0.86     $ 0.61     $ 0.69  
Severance and ad valorem taxes
    0.10       0.13       0.10       0.17       0.07       0.05  
Transportation
    0.07       0.06       0.07       0.08       0.08       0.19  
General and administrative, net(1)
                0.46       1.27       0.23       0.24  
Depreciation, depletion and amortization (excluding impairments)(2)
    3.51       3.47       3.53       2.04       1.73       1.45  
 
 
(1) Net of overhead reimbursements received from other working interest owners and amounts capitalized under the full cost accounting method. Includes non-cash stock compensation expense of $9.0 million for the nine months ended September 30, 2006 and $25.7 million in 2005. General and administrative expenses, net of capitalized amounts, are not included in pro forma 2005 because accounts of such costs were not historically maintained for the Forest Gulf of Mexico operations as a separate business unit. We believe the overhead costs associated with the Forest Gulf of Mexico operations in 2006 will approximate $6.4 million, net of capitalized amounts.
 
(2) Pro forma depreciation, depletion and amortization gives effect to the acquisition of the Forest Gulf of Mexico operations and a preliminary estimate of their step-up in value basis the unit of production method under the full cost method of accounting.


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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, 2005 and December 31, 2004, and on a pro forma basis at December 31, 2005.
 
                                                 
    Pro Forma at
    Total Productive Wells at  
    December 31,
    December 31,
    December 31,
 
    2005     2005     2004  
    Gross     Net     Gross     Net     Gross     Net  
 
Oil
    669       335.0       492       271.3       197       127.9  
Gas
    266       117.3       37       10.7       34       9.5  
                                                 
Total
    935       452.3       529       282.0       231       137.4  
 
Acreage
 
The following table sets forth certain information with respect to actual developed and undeveloped acreage as of September 30, 2006, and pro forma and actual developed and undeveloped acreage as of December 31, 2005. The pro forma information gives effect to our merger with Forest Energy Resources as though it had been consummated on December 31, 2005. We consummated the merger on March 2, 2006.
 
                                                                                                 
          Pro Forma
       
    September 30, 2006     at December 31, 2005     At December 31, 2005  
    Developed
    Undeveloped
    Developed
    Undeveloped
    Developed
    Undeveloped
 
    Acres(1)     Acres(2)     Acres(1)     Acres(2)     Acres(1)     Acres(2)  
    Gross     Net     Gross     Net     Gross     Net     Gross     Net     Gross     Net     Gross     Net  
 
West Texas(3)
    59,974       31,186                   59,974       31,199                   59,974       31,199              
Gulf of Mexico Deepwater(4)
    91,980       36,026       328,320       225,466       90,720       36,035       332,528       205,285       79,200       30,275       259,200       154,996  
Gulf of Mexico Shelf(5)
    774,758       372,658       339,053       217,805       1,007,882       399,184       399,792       251,915       136,062       40,435       137,128       82,758  
Other Onshore
    1,311       344       854       242       3,392       744       856       243       3,392       744       856       243  
                                                                                                 
Total
    928,023       440,214       668,227       443,513       1,161,968       467,162       733,176       457,443       278,628       102,653       397,184       237,997  
                                                                                                 
 
 
(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) Includes 31,933 gross and 11,883 net acres committed under the Tamarack/Spraberry drill-to-earn program. Under this program, upon drilling and completing 150 additional wells, Mariner will obtain an approximate 35% working interest in all committed acreage. As of September 30, 2006, 83 of such wells had been drilled and completed.
 
(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).
 
(5) Shelf refers to water depths less than 1,300 feet.
 
The following table sets forth Mariner’s offshore undeveloped acreage as of December 31, 2005 that is subject to expiration during the three years ended December 31, 2008. The amount of onshore undeveloped acreage subject to expiration is not material.
 
                                                 
    Undeveloped Acreage
 
    Subject to Expiration in the Year Ended December 31,  
    2006     2007     2008  
    Gross     Net     Gross     Net     Gross     Net  
 
Oil
    46,080       12,988       28,800       9,360       51,840       30,240  
Gas
    10,760       6,260       46,000       31,183       25,760       16,510  
                                                 
Total
    56,840       19,248       74,800       40,543       77,600       46,750  
                                                 


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Drilling Activity
 
Certain information with regard to our drilling activity during the nine months ended September 30, 2006 and the years ended December 31, 2005, 2004 and 2003 is set forth below.
 
                                                                 
    Nine Months
                                     
    Ended
                                     
    September 30     Year Ended December 31,  
    2006     2005     2004     2003  
    Gross     Net     Gross     Net     Gross     Net     Gross     Net  
 
Exploratory wells:
                                                               
Producing
    14       5.83       3       1.13       7       3.34       6       2.03  
Dry
    5       2.50       7       2.44       7       2.65       6       2.35  
Total
    19       8.33       10       3.57       14       5.99       12       4.38  
Development wells:
                                                               
Producing
    127       61.15       93       54.20       56       34.84       45       30.07  
Dry
                            1       0.68              
Total
    127       61.15       93       54.20       57       35.52       45       30.07  
Total wells:
                                                               
Producing
    141       66.98       96       55.33       63       38.18       51       32.10  
Dry
    5       2.50       7       2.44       8       3.33       6       2.35  
Total
    146       69.48       103       57.77       71       41.51       57       34.45  
 
As of September 30, 2006, we were in the process of drilling three gross (1.2 net) wells in the Gulf of Mexico and five gross (approximately 2.0 net) wells in West Texas.
 
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, 2005. We sold working interests totaling 50% in each of our non-producing deepwater Falcon and Harrier projects in two separate sales for $48.8 million in 2002 and $121.6 million in 2003.


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Marketing and Customers
 
We market substantially all of the oil and natural gas production from the properties we operate as well as the properties operated by others where our interest is significant. The majority of our natural gas, oil and condensate production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices. The following table lists customers accounting for more than 10% of our total revenues for the year indicated.
 
                         
    Percentage of Total
 
    Revenues for
 
    Year Ended
 
    December 31,  
Customer
  2005     2004     2003  
 
Sempra
          *       34 %
Bridgeline Gas Distributing Company(1)
    15 %     27 %     19 %
Trammo Petroleum Inc. 
    *       9 %     14 %
Duke Energy
    *       *       6 %
Genesis Crude Oil LP
          *       4 %
Chevron Texaco and affiliates(1)
    24 %     18 %      
BP Energy
    *       12 %      
Plains Marketing LP
    10 %            
 
 
Less than 1%
 
(1) Bridgeline Gas Distributing Company is an affiliate of ChevronTexaco.
 
Title to Properties
 
Substantially all of our properties currently are subject to liens securing our credit facility and obligations under hedging arrangements with members of our bank group. 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 with respect to offshore oil and gas properties as with respect to 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 primary competitors include major integrated oil and natural gas companies and major independent oil and natural gas companies. 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


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of changes in laws and regulations more easily than we can, which would adversely affect our competitive position.
 
Royalty Relief
 
The Outer Continental Shelf Deep Water Royalty Relief Act, or 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 after the RRA was enacted 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 after the RRA was enacted 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, or pre-Act leases, and on leases acquired after November 28, 2000, or 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 water depths of greater than 15,000 feet. 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, 2004 and 2005, 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 have contested the authority of the MMS 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


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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, or 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, or EP Act 2005. Among other matters, EP Act 2005 amends the Natural Gas Act, or NGA, to make it unlawful for “any entity”, including otherwise non-jurisdictional producers such as Mariner, 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


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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, or CERCLA, 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


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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 may 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, also known as 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, or 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.


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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 (on February 17, 2006, this compliance deadline was extended until October 31, 2007). 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, or 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 September 30, 2006, we had 214 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
 
Each of Mariner and its subsidiary, Mariner Energy Resources, Inc., owns numerous properties in the Gulf of Mexico. Certain of these properties were leased from the MMS subject to the RRA. The RRA relieved the obligation to pay royalties on certain leases until a designated volume is produced. Two of these leases held by Mariner and one held by its subsidiary contained language that limited royalty relief if commodity prices exceeded predetermined levels. Since 2000, commodity prices have exceeded the predetermined levels, except in 2002. Mariner and its subsidiary believe the MMS did not have the authority to set pricing limits in these leases and have withheld payment of royalties on the leases while disputing the MMS’ authority in two pending proceedings. Mariner has recorded a liability for 100% of the exposure on its two leases, which at September 30, 2006 was $19.9 million. Various legal proceedings are pending concerning this potential liability and further proceedings may be initiated with respect to years not covered by the pending proceedings. In April 2005, the MMS denied Mariner’s administrative appeal of the MMS’ April 2001 order asserting royalties were due because price limits had been exceeded. In October 2005, Mariner filed suit in the


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U.S. District Court for the Southern District of Texas seeking judicial review of the dismissal. Upon motion of the MMS, Mariner’s lawsuit was dismissed on procedural grounds. In August 2006, Mariner filed an appeal of such dismissal. Mariner had also filed an administrative appeal of a December 2005 order of the MMS demanding royalties for calendar year 2004 under the same leases at issue in the April 2001 MMS order. However, the MMS withdrew such order, rendering the appeal moot. Thereafter, in May 2006, the MMS issued an order asserting price limits were exceeded in calendar years 2001, 2003 and 2004 and, accordingly, that royalties were due under such leases on oil and gas produced in those years. Mariner has filed and is pursuing an administrative appeal of that order.
 
The potential liability of Mariner Energy Resources, Inc. under its lease subject to the RRA containing such commodity price threshold language is approximately $2.2 million as of September 30, 2006. This potential liability relates to production from the lease commencing July 1, 2005, the effective date of Mariner’s acquisition of Mariner Energy Resources, Inc. A reserve for this possible liability will be made when deemed appropriate. The MMS has not yet made demand for non-payment of royalties alleged to be due for calendar years subsequent to 2004 on the basis of price thresholds being exceeded.
 
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 and those that may involve the filing of liens against us or our assets. We do not consider our exposure in these proceedings, individually or in the aggregate, to be material.
 
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 Ochre was shut-in until September 2006, when repairs to a host platform were completed and production recommenced at about the same net rate of approximately 6.5 MMcfe per day as it was prior to Hurricane Ivan. Production from Mississippi Canyon 357 was shut-in until March 2005, when necessary repairs were completed and production recommenced. It subsequently has been shut-in since Hurricane Katrina, with production expected to recommence in the first quarter of 2007 after completion of host platform repairs. We expect to be reimbursed for costs expended in excess of our annual deductible of $1.25 million plus a single occurrence deductible of $.375 million in effect for the insurance period ended September 30, 2004. Through September 30, 2006, we recovered approximately $2.4 million in insurance proceeds.
 
In 2005, our operations were adversely affected by one of the most active and severe hurricane seasons in recorded history, resulting in shut-in production and startup delays. We estimate that as of September 30, 2006, approximately 12 MMcfe per day of production remained shut-in and approximately 33 MMcfe per day of production had recommenced since June 30, 2006. The four deepwater projects that experienced startup delays have recommenced production. As a result of ongoing repairs to pipelines, facilities, terminals and host facilities, we expect most of the remaining shut-in production to recommence by the end of 2006 and the balance in 2007, except that an immaterial amount of production is not expected to recommence. Actual commencement or recommencement of deferred or shut-in production will vary based on circumstances beyond our control, including the timing of repairs to both onshore and offshore platforms, pipelines and facilities, the actions of operators on our fields, availability of service equipment, and weather.
 
As of September 30, 2006, we had paid $72.8 million toward the repair of physical damage caused by Hurricanes Katrina and Rita and estimate that total hurricane-related repairs during 2006 and 2007 will be approximately $85.0 million. While this is our current estimate of the cost of all hurricane-related repairs, the ultimate cost cannot be ascertained until we are able to complete all of the repairs. Approximately $82.4 million of this amount relates to the Forest Gulf of Mexico operations we acquired and which were more directly affected by the path of the hurricanes than were Mariner’s historical assets. As a result of our acquisition of the Forest Gulf of Mexico operations, we are responsible for the 2005 season hurricane-related repairs to the Forest assets and entitled to the proceeds from Forest’s insurance policies applicable to such repairs. Mariner’s historical Gulf assets sustained only $2.6 million in physical damage from the hurricanes.


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Forest’s insurance coverage for the hurricane damage is subject to a $10 million deductible. Forest’s primary carrier has advised Mariner that, inasmuch as aggregate claims resulting from the hurricanes are expected to exceed the carrier’s $500 million per occurrence loss limit, Mariner’s primary claim pertaining to the Forest Gulf of Mexico operations is expected to be reduced pro rata with all other competing claims from the storms. To the extent insurance recovery under the primary policy relating to the Forest assets is reduced, Mariner believes the shortfall would be collectible under Forest’s excess insurance coverage. The insurance coverage pertaining to Mariner’s historical properties is subject to an aggregate $3.75 million deductible, which we do not expect to exceed given the limited physical damage sustained by Mariner’s historical properties.
 
Taking into account Forest’s insurance coverage in effect at the time of Hurricanes Katrina and Rita, we currently estimate our unreimbursed losses from hurricane-related repairs should not exceed $15 million. Given the magnitude and complexity of the insurance claims currently being processed by the insurance industry with respect to these two significant storms, however, the timing of our ultimate insurance recovery presently cannot be ascertained. Although we expect to begin receiving insurance proceeds early in 2007, we believe that a complete insurance settlement of all hurricane-related claims may take several additional quarters. As a result, we expect to maintain a possibly significant insurance receivable for the indefinite future while we actively pursue settlement of our claims to minimize the impact to our working capital and liquidity.
 
Effective March 2, 2006, Mariner has been accepted as a member of OIL Insurance, Ltd., an industry insurance cooperative, through which all of Mariner’s assets are insured. The coverage contains a $5 million annual per-occurrence deductible for the combined assets and a $250 million per-occurrence loss limit. However, if a single event causes losses to OIL insured assets in excess of $500 million, amounts covered for such losses will be reduced on a pro rata basis among OIL members. We maintained our commercially underwritten insurance coverage for the premerger Mariner assets, which coverage expired on September 30, 2006. This coverage contained a $3 million annual deductible and a $500,000 occurrence deductible, $150 million of aggregate loss limits, and limited business interruption coverage. While the coverage was in effect, it was primary to the OIL coverage for the pre-merger Mariner assets. We have acquired additional windstorm/physical damage insurance covering all of Mariner’s assets to supplement the existing OIL coverage. The coverage provides up to $31 million of annual loss coverage (with no additional deductible) if recoveries from OIL for insured losses are reduced by the OIL overall loss limit (i.e., if losses to OIL insured assets from a single event exceed $500 million). We also have acquired additional limited business interruption insurance on most of our deepwater producing fields which becomes effective 60 days after a field is shut-in due to a covered event. The coverage varies by field and is limited to a maximum recovery resulting from windstorm damage of approximately $43 million (assuming all covered fields are shut-in for the full insurance term of 365 days).
 
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 has not owned any direct or indirect interest in Mariner, and we have not had any affiliation 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.


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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 bore 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 remained at 10% per annum. The JEDI promissory note was secured by a lien on three of our properties located in the Outer Continental Shelf of the Gulf of Mexico. 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. The note matured on March 2, 2006 and was repaid in full.
 
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.


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MANAGEMENT
 
Directors and Executive Officers
 
The Board of Directors of Mariner is composed of seven directors.
 
The following table sets forth the names, ages (as of November 3, 2006) and titles of the individuals who are the directors and executive officers of Mariner. 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. There are no family relationships among any of our directors or executive officers.
 
             
Name
 
Age
 
Position with Company
 
Scott D. Josey
  49   Chairman of the Board, Chief Executive Officer and President
Dalton F. Polasek
  54   Chief Operating Officer
John H. Karnes
  45   Senior Vice President, Chief Financial Officer and Treasurer
Jesus G. Melendrez
  47   Senior Vice President — Corporate Development
Mike C. van den Bold
  43   Senior Vice President and Chief Exploration Officer
Teresa G. Bushman
  57   Senior Vice President, General Counsel and Secretary
Judd A. Hansen
  50   Senior Vice President — Shelf and Onshore
Cory L. Loegering
  51   Senior Vice President — Deepwater
Richard A. Molohon
  52   Vice President — Reservoir Engineering
Bernard Aronson
  60   Director
Alan R. Crain, Jr. 
  55   Director
Jonathan Ginns
  42   Director
John F. Greene
  66   Director
H. Clayton Peterson
  61   Director
John L. Schwager
  58   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 August 2003 to April 2004, he served as Senior Vice President — Shelf and Onshore. From August 2002 to August 2003, he was Senior Vice President, and from October 2001 to January 2003, he was a consultant to Mariner. Prior to joining Mariner, Mr. Polasek was self employed from February 2001 to October 2001 and served as: Vice President of Gulf Coast Engineering for Basin Exploration, Inc. from 1996 until February 2001; Vice President of Engineering for SMR Energy Income Funds 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.
 
John H. Karnes — Mr. Karnes was appointed Senior Vice President, Chief Financial Officer and Treasurer in October 2006. He served as Senior Vice President and Chief Financial Officer of The Houston Exploration Company from November 2002 through December 2005. He then served as Executive Vice


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President and Chief Financial Officer of Maxxam Inc. from April 2006 to July 2006, and Senior Vice President and Chief Financial Officer of CDX Gas, LLC from July 2006 to August 2006. Prior to joining Houston Exploration, Mr. Karnes was Vice President and General Counsel of Encore Acquisition Company, a NYSE-listed oil and gas producer, from January 2002 to November 2002, and Executive Vice President and Chief Financial Officer of CyberCash, Inc., a NASDAQ-listed internet payment software and services provider, during 2000 and 2001. He also served as Chief Operating Officer of CyberCash during the disposition of its operating divisions through a pre-packaged Chapter 11 bankruptcy proceeding in 2001. Earlier in his career, he served in senior management roles at several publicly-traded companies, including Snyder Oil Corporation and Apache Corporation, practiced law with the national law firm of Kirkland & Ellis, and was employed in various roles in the securities industry. Mr. Karnes has a J.D. from Southern Methodist University School of Law and a B.B.A. in Accounting from The University of Texas at Austin.
 
Jesus G. Melendrez — Mr. Melendrez was promoted to Senior Vice President — Corporate Development in April 2006 and served as Vice President — Corporate Development from July 2003 to April 2006. 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 promoted to Senior Vice President and Chief Exploration Officer in April 2006 and served as Vice President and Chief Exploration Officer from April 2004 to April 2006. 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 was promoted to Senior Vice President, General Counsel and Secretary in April 2006 and served as Vice President, General Counsel and Secretary from June 2003 to April 2006. 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 was promoted to Senior Vice President — Shelf and Onshore in April 2006 and served as Vice President — Shelf and Onshore from February 2002 to April 2006. 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 was promoted to Senior Vice President — Deepwater in September 2006 and served as Vice President — Deepwater from August 2002 to September 2006. 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.


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Richard A. Molohon — Mr. Molohon was appointed Vice President — Reservoir Engineering in May 2006. He joined Mariner in January 1995 as a Senior Reservoir Engineer and since then has held various positions in reservoir engineering, economics, acquisitions and dispositions, exploration, development, and planning and basin analysis, including Senior Staff Engineer from January 2000 to January 2004, and Manager, Reserves and Economics from January 2004 to May 2006. Mr. Molohon has more than 29 years of industry experience. He began his career with Amoco Production Company as a Production Engineer from 1977 until 1980. From 1980 to 1991, he was a Project Petroleum Engineer for various subsidiaries of Tenneco, Inc. From 1991 to 1995 he was a Senior Acquisition Engineer for General Atlantic Inc. Mr. Molohon has been a Registered Professional Engineer in Texas since 1983 and is a member of the Society of Petroleum Engineers.
 
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.
 
Alan R. Crain, Jr. — Mr. Crain was elected a director in April 2006. He is Vice President and General Counsel of Baker Hughes Incorporated and has served in that capacity since October 2000. He was Executive Vice President, General Counsel and Secretary of Crown, Cork & Seal Company, Inc. from 1999 to 2000. He was Vice President and General Counsel from 1996 to 1999, and Assistant General Counsel from 1988 to 1996, of Union Texas Petroleum Holdings, Inc.
 
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 and Tropigas S.A.
 
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 1968. He is currently a partner and director of The Shoreline Company and Leaf River Resources.
 
H. Clayton Peterson — Mr. Peterson was elected a director in March 2006. During his 33-year career with Arthur Andersen, he specialized in audits of oil and gas companies. Most recently, from January 2000 to September 2002, Mr. Peterson was Managing Partner of the Denver office of Arthur Andersen and Regional Managing Partner of the audit practices of Arthur Andersen in Tulsa, Oklahoma City and Dallas. Since September 2002, Mr. Peterson has been a business consultant, including to the Estate of Kim Magness from August 2003 to present. He has been a member of the board of directors of RE/MAX International, Inc. since May 2005 and is co-chair of its audit committee.
 
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


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engineering, operations, management and executive officer positions with Callon Petroleum Company and Shell Oil Company.
 
Board of Directors
 
Under the terms of the Forest Energy Resources merger agreement, as amended, the Board of Directors of Mariner after completion of the merger is to be composed initially of seven individuals, five of whom were directors of Mariner immediately prior to the merger, one of whom, Mr. Peterson, was mutually agreed upon by Mariner and Forest prior to, and became a director upon, completion of the merger, and one of whom, Mr. Crain, was mutually agreed upon by Mariner and Forest for appointment on April 1, 2006.
 
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 directors’ term will expire at the annual meeting of stockholders to be held in 2009, 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 directors are Messrs. Aronson, Crain and Peterson, the Class II directors are Messrs. Greene and Schwager, and the Class III directors are Messrs. Ginns and Josey. Effective upon completion of the merger, the directors increased the board to six and elected Mr. Peterson to fill the vacancy. On April 1, 2006, the directors increased the board to seven and elected Mr. Crain to fill the vacancy. Pursuant to provisions in our certificate of incorporation regarding vacancies on the Board of Directors, Messrs. Peterson and Crain must stand for reelection at the next annual stockholders meeting for a term expiring at the 2009 annual stockholders meeting. At each annual meeting of stockholders held after the initial classification, the successors to directors whose terms will then expire will be elected to serve from the time of election until the third annual meeting following election. The division of our Board of Directors into three classes with staggered terms may delay or prevent a change of our management or a change in control.
 
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 has established four committees, the audit committee, the compensation committee, the nominating and corporate governance committee, and the executive committee.
 
Each of Messrs. Aronson, Ginns and Peterson (Chairman) is a member of our audit committee and is “independent” under the listing standards of New York Stock Exchange and SEC rules. In addition, the Board of Directors has determined that Mr. Peterson is an “audit committee financial expert,” as defined under the rules of the SEC. The audit committee recommends to the Board of Directors the independent public accountants to audit our financial statements and oversees the annual audit. The committee also approves any other services provided by public accounting firms. The audit committee provides 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 oversees 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 is 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.
 
Each of Messrs. Aronson (Chairman), Crain and Greene serves on the nominating and corporate governance committee of our Board of Directors and is “independent” under the listing standards of the


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New York Stock Exchange and SEC rules. This committee nominates candidates to serve on our Board of Directors and approves director compensation. The committee also is 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.
 
Each of Messrs. Ginns, Greene and Schwager (Chairman) serves on the compensation committee of our Board of Directors and is “independent” under the listing standards of the New York Stock Exchange and SEC rules. The compensation committee reviews the compensation and benefits of our executive officers, establishes and reviews general policies related to our compensation and benefits, and administers our Equity Participation Plan and Amended and Restated Stock Incentive Plan. Under the compensation committee charter, the compensation committee determines the compensation of our CEO.
 
Each of Messrs. Ginns, Josey (Chairman), Peterson and Schwager serves on the executive committee of our Board of Directors. The executive committee may exercise the powers and authority of the Board in managing the business and affairs of the Company when the Board is not in session, subject to our certificate of incorporation, applicable law and any limits on authority determined from time to time by the Board.
 
Director Compensation
 
Officers and employees who also serve as directors will not receive additional compensation. For periods before August 11, 2005, Messrs. Aronson and Ginns did not receive compensation for their services as directors. For director services from August 11, 2005 through March 1, 2006, the Company paid cash compensation on an annual basis of $40,000 to each of Messrs. Aronson, Ginns, Greene and Schwager. In addition, on March 31, 2006, the Company granted each of them 1,100 shares of restricted stock under the Company’s Amended and Restated Stock Incentive Plan, as amended, with one-third of the shares to vest upon each of the first three annual meetings of Mariner’s stockholders following the date of grant. The 1,100 shares of restricted stock granted to each of Messrs. Greene and Schwager replaced an option each received upon his appointment to the Board in August 2005, exercisable for 4,500 shares of the Company’s common stock at $15.50 per share, and vesting in 1/3 increments upon each of the three successive annual meetings of Mariner’s stockholders following the date of grant. As of March 31, 2006, neither of these in the money options had been exercised.
 
Effective March 2, 2006, non-employee directors will receive annual compensation for service as a director of $50,000, and additional annual compensation of $12,500 for serving on the board’s audit committee, $20,000 for serving as chairman of the audit committee, $5,000 for serving on any board committee other than the audit committee, and $10,000 for serving as chairman of any board committee other than the audit committee. Non-employee directors also will be paid a meeting fee of $1,500 for attendance or participation by phone at board meetings and $1,000 for attendance or participation by phone at board committee meetings. All nonemployee director fees will be paid quarterly. 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.
 
The Board of Directors authorized a restricted stock grant made on March 31, 2006 to each nonemployee director and on April 3, 2006 to Mr. Crain equal to that number of shares of Mariner’s common stock with a market value, determined as of the date of grant, of $50,000, with one-third of the shares to vest on each of the first three annual meetings of Mariner’s stockholders following the date of grant. Each grant of 2,438 shares on March 31, 2006, based on the closing price of $20.51 per share, and of 2,465 shares on April 3, 2006, based on a closing price of $20.28 per share, was made under Mariner’s Amended and Restated Stock Incentive Plan, as amended.
 
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. We have also entered into indemnification agreements with our executive officers and directors


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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 five other most highly compensated executive officers for the three fiscal years ended December 31, 2005.
 
Summary Compensation Table
 
                                                         
                      Long-Term Compensation  
                      Awards              
                      Restricted
    Securities
    Payouts        
          Annual Compensation     Stock
    Underlying
    LTIP
    All Other
 
Name and Principal Position
  Year     Salary ($)     Bonuses($)     Awards ($)(2)     Options (#)     Payouts ($)     Compensation ($)(3)  
 
Scott D. Josey
    2005     $ 375,000     $ 1,200,000     $           $     $ 16,210  
Chairman of the Board,
    2004       350,000       550,000       9,522,534       200,000       575,000       15,133  
Chief Executive Officer
and President
    2003       300,290       850,000                         514,895  
Dalton F. Polasek
    2005       250,000       580,000                           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       440,000                         15,819  
Senior Vice President and
    2004       192,500       215,000       3,174,178       74,000       322,000       14,949  
Chief Exploration Officer(1)
    2003       170,150       350,000                         45,430  
Judd A. Hansen
    2005       187,500       325,000                         15,983  
Senior Vice President —
    2004       180,000       185,000       2,221,926       48,000       184,000       15,059  
Shelf and Offshore(1)
                                                       
      2003       156,023       250,000                         109,272  
Rick G. Lester(2)
    2005       200,000       300,000                         16,363  
Vice President,
    2004       43,352       120,000       428,512       40,000             3,502  
Chief Financial Officer and Treasurer
    2003                                      
Teresa G. Bushman
    2005       200,000       300,000                         17,197  
Senior Vice President, General
    2004       190,000       215,000       1,920,380       40,000       59,800       14,834  
Counsel and Secretary(1)
    2003       97,750       200,000                         23,270  
 
 
(1) Mr. van den Bold was Vice President and Chief Exploration Officer in 2005 and until promoted to indicated position as of April 27, 2006. Mr. Hansen was Vice President — Shelf and Offshore in 2005 and until promoted to indicated position as of April 27, 2006. Ms. Bushman was Vice President, General Counsel and Secretary in 2005 and until promoted to indicated position as of April 27, 2006.
 
(2) On October 16, 2006, Mr. Lester resigned as Vice President, Chief Financial Officer and Treasurer and John H. Karnes was appointed Senior Vice President, Chief Financial Officer and Treasurer. See “— Employment Agreements and Other Arrangements.”
 
(3) 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. The restricted stock fully vested on May 31, 2006. For additional information regarding these grants, please see “— Equity Participation Plan.”


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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  
Judd A. Hansen
    158,709       2,817,085  
Rick G. Lester
    30,608       543,292  
Teresa G. Bushman
    137,170       2,434,768  
 
 
(4) 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, Hansen 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 includes insurance premiums under our group term life insurance of $810 for Mr. Josey, $1,226 for Mr. Polasek, $419 for Mr. van den Bold, $583 for Mr. Hansen, $963 for Mr. Lester, and $1,797 for Ms. Bushman.
 
Employment Agreements and Other Arrangements
 
We 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, officers are entitled to the following severance benefits in the event of an officer’s resignation for good reason, a termination by us without cause, upon disability or, in the case of Mr. Josey’s agreement, our non-renewal of the agreement: (i) a lump sum payment equal to 2.0 (2.5 for Messrs. Polasek, van den Bold and Hansen, and Ms. Bushman, and 2.99 for Mr. Josey) times the sum of the officer’s base salary and three year average annual bonus, (ii) health care coverage for a period of eighteen months (two years for Mr. Josey and Mr. Polasek), (iii) 100% vesting of all unvested restricted shares under our Equity Participation Plan (as discussed under “— Equity Participation Plan,” all such shares have fully vested), and (iv) 50% vesting of all other unvested rights under any other equity plans, including our Amended and Restated Stock Incentive Plan. Subsequent awards under equity plans vest in accordance with their terms.
 
The employment agreements also provide for certain change of control benefits. Upon termination by us 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 an officer’s resignation of employment for good reason or termination by us without cause, the agreements provide for the following benefits: (i) a lump sum payment equal to 2.0 (2.5 for Messrs. Polasek, van den Bold and Hansen, and Ms. Bushman, 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 unvested rights under any equity plans, including our Amended and Restated Stock Incentive Plan.
 
The executive officers of Mariner as of March 2, 2006 became entitled to 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 with Forest Energy Resources 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.


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The employment agreements provide that the officers are entitled to a full tax gross-up payment if the aggregate payments and benefits to be provided constitute a “parachute payment” subject to a Federal excise tax. The agreements also include confidentiality and non-solicitation provisions.
 
The term of Mr. Lester’s employment agreement expired upon his resignation as an employee effective August 15, 2006. He is leaving Mariner to pursue personal interests and served as an officer of Mariner until October 16, 2006 under a consulting agreement made effective August 16, 2006 while Mariner continued its search for his successor. Under the consulting agreement, Mr. Lester agreed to perform finance, accounting and other services on a consulting basis, continue to serve in his capacity as an officer of Mariner, and assist in transition upon the hiring of his successor. The consulting agreement, which we expect will terminate in December 2006, provides that Mariner pay Mr. Lester $2,300 per day for his services. In connection with Mr. Lester’s resignation as an employee, Mariner agreed to pay him a bonus in the amount of $237,500 in respect of his performance in 2006 as an employee.
 
Mariner and John H. Karnes, who became its Senior Vice President, Chief Financial Officer and Treasurer in October 2006, entered into an employment agreement, dated as of October 16, 2006. The employment agreement has an initial term ending October 15, 2007 and automatically renews each October 15 thereafter for an additional 12 months unless prior notice is given. It provides for a base salary that may be adjusted annually in the sole discretion of Mariner’s Board of Directors, a discretionary bonus, and participation in Mariner’s benefit plans and programs. The initial base salary on an annualized basis is $235,000. If Mr. Karnes remains employed by Mariner until such time in 2007 as bonuses in respect of performance in 2006 are paid to other officers of Mariner, then for his services during 2006, Mariner will pay him a guaranteed bonus of not less than $125,000 and grant him no fewer than 20,000 shares of restricted common stock of Mariner, which is expected to have a four-year vesting schedule. In connection with Mariner’s employment of Mr. Karnes, it granted him 15,000 shares of restricted common stock in October 2006 under its Amended and Restated Stock Incentive Plan, as amended, subject to four-year vesting.
 
Under the employment agreement, if Mr. Karnes terminates his employment for good reason or Mariner terminates his employment without cause, he is entitled to a severance payment of (i) $375,000 if the termination occurs before the earlier of April 16, 2007 or the occurrence of a change of control, or (ii) a lump sum payment equal to 2.99 times the sum of his base salary and three-year average annual bonus if the termination occurs on or after April 16, 2007 or the occurrence of a change of control. If Mariner terminates his employment due to disability, he is entitled to a lump sum payment equal to 2.99 times the sum of his base salary and three-year average annual bonus. Mr. Karnes also is entitled to the following severance benefits if he resigns for good reason or Mariner terminates his employment without cause or due to disability: (i) health care coverage for a period of 18 months, and (ii) 50% vesting of all unvested rights under any equity plans of Mariner. Subsequent awards under equity plans vest in accordance with their terms. In addition, upon the occurrence of a change of control that occurs during the period Mr. Karnes is employed or within nine months after he resigns for good reason or Mariner terminates his employment without cause, he will become 100% vested in all unvested rights under any of Mariner’s stock and other equity plans.
 
The employment agreement provides that Mr. Karnes is 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. It also includes 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


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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.
 
As of December 31, 2005, six employees participated 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, 2005, approximately $584,000 has been distributed to participants with respect to ORRIs granted to them under the plan, of which $332,000 was distributed in 2005.
 
In 2002, two of our current executive officers, Dalton F. Polasek, Chief Operating Officer, and Judd A. Hansen, Senior 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. No payments were made in respect of these ORRIs in 2005.
 
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 — Deepwater, and Richard A. Molohon, Vice President — Reservoir Engineering, are the only current executive officers who may be entitled to receive ORRIs from time to time under any of these agreements. Mariner made net cash payments to each of Mr. Loegering of $378,312, $368,095 and $205,245 in 2005, 2004 and 2003, respectively, and Mr. Molohon of $282,153, $274,364 and $151,482 in 2005, 2004 and 2003, respectively in respect of ORRIs assigned from time to time pursuant to a right to receive such ORRIs that was granted in 2002.
 
All ORRIs assigned to these parties are excluded from Mariner’s interests evaluated in our reserve report.
 
Equity Participation Plan
 
We adopted an Equity Participation Plan administered by our Board of Directors 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 received such a grant may be eligible for future awards of restricted stock or stock options under our Amended and Restated 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 2005 under the Equity Participation Plan to our chief executive officer, our five other most highly compensated executive officers as of the year ended 2005, and all officers as a group as of December 31, 2005.


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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  
Judd A. Hansen
    158,709       2,221,926  
Rick G. Lester
    30,608       428,512  
Teresa G. Bushman
    137,170       1,920,380  
Officers as a group (8 persons)
    1,803,614       25,250,596  
 
 
(1) Based on a price of $14.00 per share.
 
In connection with the merger with Forest Energy Resources, all shares of restricted stock granted under the Equity Participation Plan vested as follows: (i) the 463,656 shares of restricted stock held by non-executive employees vested on March 2, 2006, and (ii) the 1,803,614 shares of restricted stock held by executive officers vested on May 31, 2006 pursuant to an agreement, made in exchange for a cash payment of $1,000 to each officer, that his or her shares of restricted stock would not vest before the later of March 11, 2006 or ninety days after the effective date of the merger. The Equity Participation Plan expired upon the vesting of all shares granted thereunder.
 
Stock could 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 had 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. As a result of such participant elections, we withheld an aggregate 807,376 shares that otherwise would have remained outstanding upon vesting of the restricted stock, reducing the aggregate outstanding vested stock grants made under the Equity Participation Plan to 1,459,894 shares. The 807,376 shares withheld became treasury shares that were retired and restored to the status of authorized and unissued shares of common stock. We paid the associated withholding taxes in cash.
 
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 and Estimates — Compensation Expense” for a discussion of these charges.
 
Amended and Restated Stock Incentive Plan
 
We adopted a Stock Incentive Plan which became effective March 11, 2005 and was amended and restated on March 2, 2006. The objectives of the Amended and Restated 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 Amended and Restated 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.
 
Awards to participants under the Amended and Restated 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 Amended and Restated Stock Incentive Plan (the “Committee”).


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Shares Subject to the Amended and Restated Stock Incentive Plan
 
A total of 6.5 million shares of Mariner’s common stock is subject to the Amended and Restated Stock Incentive Plan. No more than 2.85 million shares issuable upon exercise of options or as restricted stock can be issued to any individual. As of September 30, 2006, 4,966,071 shares remained available under the Amended and Restated Stock Incentive Plan for future issuance to participants.
 
Administration and Eligibility
 
The Committee has the authority to administer the Amended and Restated Stock Incentive Plan and to take all actions that are specifically contemplated by the Amended and Restated Stock Incentive Plan or are necessary or appropriate in connection with the administration of the Amended and Restated 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 Amended and Restated 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 Amended and Restated 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 Amended and Restated 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 Amended and Restated 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 nonqualified 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 Amended and Restated 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


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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.
 
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 Amended and Restated 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 Code. Restricted stock is subject to such limitations on transfer as are necessary to comply with Section 83 of the Code.
 
Other Provisions
 
Unless sooner terminated, no award may be granted under the Amended and Restated Stock Incentive Plan after October 12, 2015. The Board of Directors 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.
 
Amended and Restated Stock Incentive Plan Benefits
 
Because the granting of awards under the Amended and Restated 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 Amended and Restated Stock Incentive Plan.


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U.S. Federal Tax Consequences
 
The following is a general discussion of the current Federal income tax consequences of awards under the Amended and Restated 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 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 Amended and Restated 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 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 fair market value of the common stock on the date of exercise and the option price. 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.


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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.
 
The table below includes information regarding stock options under the Amended and Restated Stock Incentive Plan granted in our last fiscal year to our chief executive officer and our five other most highly compensated executive officers.
 
Option Grants in Last Fiscal Year
 
                                                 
          % of Total
                         
          Options
                Potential Realizable
 
    No. of
    Granted to
                Value of Assumed
 
    Securities
    Employees
                Annual Rates of
 
    Underlying
    in Fiscal
    Exercise
    Expiration
    Stock Price Appreciation for Option Term(1)  
Name
  Options     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  
Judd A. Hansen
    48,000       5.9       14.00       3/11/2015       422,617       1,070,995  
Rick G. Lester
    40,000 (2)     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  
 
 
(1) 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.
 
(2) This option expired unexercised on August 15, 2006.


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SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
 
The following table sets forth information as of November 3, 2006 (except as otherwise indicated) with respect to the beneficial ownership of Mariner’s common stock by (i) 5% stockholders, (ii) current directors, (iii) six most highly compensated executive officers during 2005 and (iv) current 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(1)
  Amount(2)     Class  
 
5% Stockholder:
               
FMR Corp.(3)
    14,167,849       16.4 %
Officers and Directors(4):
               
Scott D. Josey(5)
    633,571       *  
Dalton F. Polasek(6)
    305,229       *  
Mike C. van den Bold(7)
    212,227       *  
Judd A. Hansen(8)
    157,051       *  
Rick G. Lester
    22,512       *  
Teresa G. Bushman(9)
    132,522       *  
Bernard Aronson(10)
    1,900,785       2.2 %
Alan R. Crain, Jr. 
    2,465       *  
Jonathan Ginns(11)
    1,899,168       2.2 %
John F. Greene
    11,775       *  
H. Clayton Peterson
    3,651       *  
John L. Schwager
    3,538       *  
Executive officers and directors as a group (15 persons)(12)
    3,706,820       4.3 %
 
 
Less than 1%.
 
(1) As of November 3, 2006, Mariner had 86,365,035 shares of common stock outstanding. As of that date, the only stockholder of record holding more than 5% of Mariner’s outstanding common stock was CEDE & CO (FAST) which held of record 80,547,907 or 93.3% of such shares. Mariner understands that CEDE & CO (FAST) does not beneficially own such shares and as of November 3, 2006, had not been able to ascertain whether any of the beneficial owners of such shares owned more than 5% of Mariner’s outstanding common stock except as indicated in footnote (3) below. CEDE & CO (FAST)’s address is PO Box 20, Bowling Green Station, New York, NY 10004.
 
(2) Includes grants of restricted stock to directors and certain executive officers under our Amended and Restated Stock Incentive Plan. These shares may be voted, but not disposed of, prior to vesting. Also includes shares issuable upon exercise of presently exercisable options held by certain of the indicated persons.
 
(3) A Schedule 13G filed with the Securities and Exchange Commission by FMR Corp. on April 10, 2006 (the “13G”) indicates that no one person’s interest in the indicated shares is more than five percent of Mariner’s outstanding common stock, that FMR Corp. beneficially owns and has sole power to dispose or to direct the disposition of 100% of the indicated shares, and that FMR Corp. has sole power to vote or direct the vote of 1,066,618 of the indicated shares. The 13G discloses that Fidelity Management & Research Company, a wholly-owned subsidiary of FMR Corp. and an investment adviser registered under the Investment Advisers Act of 1940, is the beneficial owner of 13,225,660 of the indicated shares as a result of acting as investment adviser to various investment companies registered under the Investment Company Act of 1940. The 13G further discloses that Edward C. Johnson 3d and FMR Corp., through its control of Fidelity Management & Research Company, and the funds each has sole power to dispose


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of the 13,225,660 shares owned by the funds, and that the Boards of Trustees of the funds have sole power to vote or direct the voting of the shares owned by the funds, with Fidelity Management & Trust Company carrying out the voting of the shares under written guidelines established by the funds’ Boards of Trustees. The 13G notes that Mr. Johnson is the Chairman of FMR Corp. and that members of his family may, as a result of certain security ownership in FMR Corp. and a related voting agreement, be deemed, under the Investment Company Act of 1940, to form a controlling group with respect to FMR Corp. The 13G also discloses that Fidelity Management Trust Company, a wholly-owned subsidiary of FMR Corp. and a bank as defined in Section 3(a)(6) of the Securities Exchange Act of 1934, is the beneficial owner of 942,189 of the indicated shares as a result of its serving as investment manager of institutional account(s). The 13G further discloses that Mr. Johnson and FMR Corp., through its control of Fidelity Management Trust Company, each has sole dispositive power over, and sole power to vote or to direct the voting of, the 942,189 shares owned by such institutional account(s). The 13G reports the address of each of FMR Corp., Fidelity Management & Research Company and Fidelity Management Trust Company as 82 Devonshire Street, Boston, Massachusetts 02109. This description of the 13G is qualified by reference to the 13G.
 
(4) The address of each officer and director is c/o Mariner Energy, Inc., One Briar Lake Plaza, Suite 2000, 2000 West Sam Houston Parkway South, Houston, Texas 77042.
 
(5) Includes 66,667 shares issuable upon exercise of a presently exercisable option.
 
(6) Includes 34,000 shares issuable upon exercise of a presently exercisable option.
 
(7) Includes 24,667 shares issuable upon exercise of a presently exercisable option.
 
(8) Includes 16,000 shares issuable upon exercise of a presently exercisable option.
 
(9) Includes 13,334 shares issuable upon exercise of a presently exercisable option.
 
(10) Mr. Aronson indirectly owns 1,213 shares that are directly owned by the Bolivar International Defined Benefit Pension Plan and 404 shares that are directly owned by his IRA. Mr. Aronson may be deemed to be a beneficial owner of 1,895,630 shares that are beneficially owned by ACON E&P, LLC. MEI Acquisitions Holdings, LLC is the record holder of the shares beneficially owned by ACON E&P, LLC. Mr. Aronson is a manager of ACON E&P, LLC. Mr. Aronson disclaims beneficial ownership of these shares except to the extent of his pecuniary interest therein. Mr. Aronson’s address is c/o ACON Investments, LLC, 1133 Connecticut Avenue, N.W., Suite 700, Washington, D.C. 20036.
 
(11) Mr. Ginns may be deemed to be a beneficial owner of 1,895,630 shares that are beneficially owned by ACON E&P, LLC. MEI Acquisitions Holdings, LLC is the record holder of the shares beneficially owned by ACON E&P LLC. Mr. Ginns is a managing member of Burns Park Investments LLC, a manager of ACON E&P, LLC. Mr. Ginns disclaims beneficial ownership of these shares except to the extent of his pecuniary interest therein. Mr. Ginns’ address is c/o ACON Investments, LLC, 1133 Connecticut Avenue, N.W., Suite 700, Washington, D.C. 20036.
 
(12) Includes 199,336 shares issuable upon exercise of presently exercisable options.


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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
 
In connection with Mariner’s 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 totaling $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 shares 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 March 2005 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 two other officers who may be entitled to assignments of ORRIs under previously terminated employment and consulting agreements, as described in “Management — Overriding Royalty Arrangements.”


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DESCRIPTION OF EXISTING INDEBTEDNESS
 
Secured Bank Credit Facility
 
In January 2006, the borrowing base under our revolving secured credit facility was increased to $185 million. In connection with the merger with Forest Energy Resources on March 2, 2006, we amended and restated our existing credit facility to increase maximum credit availability to $500 million for revolving loans, including up to $50 million in letters of credit, with a $400 million borrowing base as of that date. On March 2, 2006, after giving effect to funds required at closing to refinance $176.2 million of debt assumed in the merger and other merger-related costs, our total debt drawn under the facility was approximately $350 million, including a $4.2 million letter of credit required for plugging and abandonment obligations at one of our offshore fields. On April 7, 2006, the borrowing base under the secured credit facility was increased to $430 million, subject to redetermination or adjustment. On April 24, 2006, the borrowing base was reduced to $362.5 million in accordance with an amendment to the revolving credit facility related to our offering of the old notes. For subsequent qualifying bond issuances, the amendment provides that the borrowing base in effect on the closing date of such a bond issuance will automatically reduce by 25% of the aggregate principal amount of such bond issuance to the extent that it does not refinance the principal amount of an existing bond issuance. The secured credit facility permits Mariner’s issuance of certain unsecured bonds of up to $350 million in aggregate principal amount that have a non-default interest rate of 10% or less per annum and a scheduled maturity date after March 1, 2012. Mariner’s sale and issuance of the old notes and the new notes were and will be, respectively, such a qualifying bond issuance. At September 30, 2006, approximately $328.6 million was outstanding under our revolving secured credit facility, including the $4.2 million letter of credit and a $10.4 million letter of credit issued in August 2006 to BP to secure certain assumed offshore plugging and abandonment obligations. The borrowing base was increased to $450 million in October 2006, subject to redetermination or adjustment. This credit facility matures on March 2, 2010.
 
The amendment and restatement of our secured credit facility on March 2, 2006 also provided for an additional $40 million letter of credit that is not included as a use of the borrowing base and matures on March 2, 2009. The $40 million letter of credit was issued in favor of Forest to secure performance of our obligation to drill and complete 150 wells under an existing drill-to-earn program. This letter of credit will reduce periodically by an amount equal to the product of $533,333 times the number of wells exceeding 75 that are drilled and completed. The first reduction of $4,266,664 occurred in October 2006 based upon the 83 wells drilled and completed as of September 30, 2006. We expect additional reductions based upon quarterly drilling activity, with the next reduction anticipated in January 2007.
 
Interest under the revolving credit facility is determined by reference to the following grid:
 
Applicable Margin
 
                         
          Reference
       
Usage as a % of Borrowing Base
  LIBOR Loans     Rate Loans     Unused 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 is payable quarterly for Union Bank of California Reference Rate loans and at the applicable maturity date (or, if the maturity date is longer than three months, on each three-month anniversary date) for LIBOR (London interbank offered rate) loans. The fee for letters of credit issued under the revolving credit facility is the LIBOR margin indicated in the grid, per annum. The fee for letters of credit under the letter of credit facility is 1.50% due quarterly in advance.
 
The obligations under the credit facilities are 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


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interests. Additionally, the obligations under the credit facilities are guaranteed by us and each of our subsidiaries.
 
The credit facilities 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 property or other assets which generate proceeds in excess of 5% of the then current borrowing base;
 
  •  make certain loans or investments, or dividends or other payments in respect of equity;
 
  •  make optional prepayments in respect of the notes, except optional prepayments (i) of 50% or less of the then outstanding principal amount of the notes which are made promptly with the proceeds Mariner receives from an offering of its equity securities registered under the Securities Act, and (ii) to refinance the notes with the proceeds Mariner receives from the issuances of certain qualifying debt;
 
  •  enter into speculative hedging transactions; and
 
  •  enter new lines of business.
 
The credit facilities also contain covenants, which, among other things, require us to maintain specified ratios 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 consolidated EBITDA of not more than 2.5 to 1.0.
 
We were in compliance with the financial covenants under the bank credit facility as of September 30, 2006.
 
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 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.
 
As of December 31, 2005, $4 million was outstanding under the JEDI note. This note was repaid in full on its maturity date of March 2, 2006.


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DESCRIPTION OF SENIOR NOTES
 
You can find the definitions of certain terms used in this description under the subheading “Certain Definitions.” In this description, the words “Mariner,” “we,” “us” and “our” refers only to Mariner Energy, Inc. and not to any of its subsidiaries.
 
On April 24, 2006, we issued $300.0 million aggregate principal amount of 71/2% Senior Notes under the indenture dated as of April 24, 2006 among us and Wells Fargo, N.A., as trustee, and the Guarantors, in a private transaction not subject to the registration requirements of the Securities Act. The terms of the old notes and the new notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”).
 
The following description is a summary of the material provisions of the indenture and the registration rights agreement. It does not restate those agreements in their entirety. We urge you to read the indenture and the registration rights agreement because they, and not this description, define your rights as holders of the notes. Copies of the indenture and the registration rights agreement are available as set forth below under “— Additional Information.” Certain defined terms used in this description but not defined below under “— Certain Definitions” have the meanings assigned to them in the indenture.
 
The registered holder of a note will be treated as the owner of it for all purposes. Only registered holders will have rights under the indenture.
 
Brief Description of the Notes and the Note Guarantees
 
The Notes
 
The notes are:
 
  •  general unsecured obligations of Mariner;
 
  •  limited to an aggregate principal amount at maturity of $300 million, subject to our ability to issue additional notes;
 
  •  accrue interest from the date they are issued at a rate of 71/2%, which is payable semi-annually;
 
  •  mature on April 15, 2013;
 
  •  rank effectively junior in right of payment to any secured Indebtedness of Mariner, including Indebtedness under the Credit Agreement, to the extent of the value of the Collateral securing such Indebtedness;
 
  •  rank pari passu in right of payment with all existing and future unsecured senior Indebtedness of Mariner;
 
  •  rank senior in right of payment to any future subordinated Indebtedness of Mariner; and
 
  •  fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors.
 
See “Risk Factors — The notes and the guarantees are unsecured and effectively subordinated to our and our subsidiary guarantors’ existing and future secured indebtedness.”
 
The Note Guarantees
 
The notes will be guaranteed by all of Mariner’s presently existing Domestic Subsidiaries. Each guarantee of the notes is:
 
  •  a general unsecured obligation of the Guarantor;
 
  •  rank effectively junior in right of payment to any secured Indebtedness of that Guarantor, including Indebtedness under the Credit Agreement, to the extent of the value of the Collateral securing such Indebtedness;


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  •  rank pari passu in right of payment with any future unsecured senior Indebtedness of that Guarantor; and
 
  •  rank senior in right of payment to any future subordinated Indebtedness of that Guarantor.
 
Newly created or acquired Restricted Subsidiaries are required to guarantee the notes only under the circumstances described below under the caption “— Certain Covenants — Additional Note Guarantees.” In the event of a bankruptcy, liquidation or reorganization of any non-guarantor Subsidiary, the non-guarantor Subsidiary will pay the holders of its debt and its trade creditors before it will be able to distribute any of its assets to Mariner.
 
As of the date of the indenture, all of our Subsidiaries were “Restricted Subsidiaries.” However, under the circumstances described below under the caption “— Certain Covenants — Designation of Restricted and Unrestricted Subsidiaries,” we are permitted to designate certain of our Subsidiaries as “Unrestricted Subsidiaries.” Our Unrestricted Subsidiaries are not subject to many of the restrictive covenants in the indenture. Our Unrestricted Subsidiaries will not guarantee the notes.
 
Principal, Maturity and Interest
 
Mariner will issue up to $300 million in aggregate principal amount of new notes in the exchange offer in exchange for old notes. Mariner may issue additional notes under the indenture from time to time after the exchange offer. Any issuance of additional notes is subject to all of the covenants in the indenture, including the covenant described below under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock.” The notes and any additional notes subsequently issued under the indenture will be treated as a single class for all purposes under the indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase. Notes will be issued in minimum denominations of $1,000 and integral multiples of $1,000. The notes will mature on April 15, 2013.
 
Interest on the notes accrues at the rate of 71/2% per annum and is payable semi-annually in arrears on April 15 and October 15, commencing on October 15, 2006. Interest on overdue principal and interest and Special Interest, if any, accrues at a rate that is 1.0% higher than the then applicable interest rate on the notes. Mariner makes each interest payment to the holders of record on the immediately preceding April 1 and October 1.
 
Interest on the notes accrues from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest is computed on the basis of a 360-day year comprised of twelve 30-day months.
 
Methods of Receiving Payments on the Notes
 
If a holder of notes has given wire transfer instructions to Mariner, Mariner will pay all principal, interest and premium and Special Interest, if any, on that holder’s notes in accordance with those instructions. All other payments on the notes will be made at the office or agency of the paying agent and registrar within the City and State of New York unless Mariner elects to make interest payments by check mailed to the noteholders at their address set forth in the register of holders.
 
Paying Agent and Registrar for the Notes
 
The trustee will initially act as paying agent and registrar. Mariner may change the paying agent or registrar without prior notice to the holders of the notes, and Mariner or any of its Subsidiaries may act as paying agent or registrar.
 
Transfer and Exchange
 
A holder may transfer or exchange notes in accordance with the provisions of the indenture. The registrar and the trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of notes. Holders will be required to pay all taxes due on transfer.


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Mariner is not required to transfer or exchange any note selected for redemption. Also, Mariner is not required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed.
 
Note Guarantees
 
Mariner’s payment obligations with respect to the notes are jointly and severally guaranteed on a senior basis by the Guarantors. Additional Domestic Subsidiaries of Mariner will be required to become Guarantors under the circumstances described under “— Certain Covenants — Additional Subsidiary Guarantees.” These Note Guarantees are joint and several obligations of the Guarantors. The obligations of each Guarantor under its Note Guarantee are limited as necessary to prevent that Note Guarantee from constituting a fraudulent conveyance under applicable law. See “Risk Factors — Risks relating to the notes — A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S. bankruptcy or similar state law, which would prevent the holders of the notes from relying on that subsidiary to satisfy claims.”
 
A Guarantor may not sell or otherwise dispose of all or substantially all of its assets to, or consolidate with or merge with or into (whether or not such Guarantor is the surviving Person), another Person, other than Mariner or another Guarantor, unless:
 
(1) immediately after giving effect to that transaction, no Default or Event of Default exists; and
 
(2) either:
 
(a) the Person acquiring the property in any such sale or disposition or the Person formed by or surviving any such consolidation or merger (if other than Mariner or another Guarantor) unconditionally assumes, pursuant to a supplemental indenture substantially in the form specified in the indenture, all the obligations of such Guarantor under such indenture, such series of notes, its Note Guarantee and the applicable registration rights agreement on terms set forth therein; or
 
(b) the Net Proceeds of such sale or other disposition are applied in accordance with the provisions of the indenture described under the caption “— Repurchase at the Option of Holders — Asset Sales”.
 
The Note Guarantee of a Guarantor will be released:
 
(1) in connection with any sale or other disposition of all or substantially all of the assets of that Guarantor (including by way of merger or consolidation) to a Person that is not (either before or after giving effect to such transaction) Mariner or a Restricted Subsidiary of Mariner, if the sale or other disposition complies with the applicable provisions of the indenture;
 
(2) in connection with any sale or other disposition of all of the Capital Stock of that Guarantor to a Person that is not (either before or after giving effect to such transaction) Mariner or a Restricted Subsidiary of Mariner, if the sale or other disposition complies with the applicable provisions of the indenture;
 
(3) if such Guarantor is a Restricted Subsidiary and Mariner designates such Guarantor as an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture;
 
(4) upon Legal Defeasance or Covenant Defeasance as described below under the caption “— Legal Defeasance and Covenant Defeasance” or upon satisfaction and discharge of the indenture as described under the caption “— Satisfaction and Discharge”;
 
(5) upon the liquidation or dissolution of such Guarantor provided no Default or Event of Default has occurred or is continuing;
 
(6) at any time after the occurrence of an Investment Grade Rating Event, at such time as such Guarantor does not have outstanding or guarantee Indebtedness (other than Indebtedness or guarantees under the notes) in excess of $5.0 million in aggregate principal amount; or


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(7) upon such Guarantor consolidating with, merging into or transferring all of its properties or assets to Mariner or another Guarantor, and as a result of, or in connection with, such transaction such Guarantor dissolving or otherwise ceasing to exist.
 
Optional Redemption
 
Except as otherwise described below, the notes will not be redeemable at Mariner’s option prior to April 15, 2010. Mariner is not, however, prohibited from acquiring the notes by means other than a redemption, whether pursuant to a tender offer, open market purchase or otherwise, so long as the acquisition does not violate the terms of the indenture.
 
On or after April 15, 2010, the notes will be subject to redemption at the option of Mariner, in whole or in part, at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest and Special Interest, if any, thereon to, but not including, the applicable redemption date, if redeemed during the twelve-month period beginning on April 15 of the year indicated below:
 
         
    % of Principal
 
Year
  Amount  
 
2010
    103.750 %
2011
    101.875 %
2012 and thereafter
    100.000 %
 
Prior to April 15, 2009, Mariner may, at its option, on any one or more occasions, redeem up to 35% of the aggregate principal amount of the notes (including any additional notes issued after the Issue Date) at a redemption price equal to 107.50% of the principal amount thereof, plus accrued and unpaid interest and Special Interest, if any, thereon to, but not including, the redemption date, with all or a portion of the net proceeds of one or more Equity Offerings; provided that at least 65% of the aggregate principal amount of the notes issued under the indenture remains outstanding immediately after the occurrence of such redemption; and provided, further, that such redemption shall occur within 180 days of the date of the closing of any such Equity Offering.
 
In addition, at any time prior to April 15, 2010 Mariner may also redeem, in whole or in part, the notes at a redemption price equal to 100% of the principal amount of notes to be redeemed, plus the Applicable Premium (as defined below) as of, and accrued and unpaid interest and Special Interest, if any, to, but not including, the redemption date, subject to the rights of the holders on the relevant record date to receive interest and Special Interest, if any, due on the relevant interest payment date.
 
“Applicable Premium” means, with respect to any note on any redemption date, the excess of:
 
(1) the present value at such redemption date of (i) the redemption price of the note on April 15, 2010 (such redemption price being set forth in the table appearing above under the caption “— Optional redemption”), plus (ii) all required interest payments and Special Interest, if applicable, payments due on the note through April 15, 2010 (excluding accrued but unpaid interest and Special Interest, if any, to the redemption date) discounted back to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at a rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over
 
(2) the principal amount of the note.
 
“Treasury Rate” means, as of any redemption date, the yield to maturity as of such redemption date of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two Business Days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the redemption date to April 15, 2010; provided, however, that if the period from the redemption date to April 15, 2010 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year will be used.


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All redemptions of the notes will be made upon not less than 30 days’ nor more than 60 days’ prior notice, except that a redemption notice may be made more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the indenture. Unless Mariner defaults in the payment of the redemption price, interest and Special Interest, if applicable, will cease to accrue on the notes or portions thereof called for redemption on the applicable redemption date.
 
Notice of any redemption including, without limitation, upon an Equity Offering may, at Mariner’s discretion, be subject to one or more conditions precedent, including, but not limited to, completion of the related Equity Offering.
 
Mandatory Redemption
 
Except as set forth below under “Repurchase at the Option of Holders,” Mariner is not required to make mandatory redemption or sinking fund payments with respect to the notes.
 
Repurchase at the Option of Holders
 
Change of Control
 
If a Change of Control Triggering Event occurs, each holder of notes will have the right to require Mariner to repurchase all or any part (equal to $1,000 or an integral multiple of $1,000) of that holder’s notes pursuant to an offer (“Change of Control Offer”) on the terms set forth in the indenture. In the Change of Control Offer, Mariner will offer a payment in cash (the “Change of Control Payment”) equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest and Special Interest, if any, on the notes repurchased to the date of purchase (the “Change of Control Payment Date”), subject to the rights of holders of notes on the relevant record date to receive interest and Special Interest, if applicable, due on the relevant interest payment date. Within 30 days following any Change of Control Triggering Event, Mariner will mail a notice to each holder describing the transaction or transactions that constitute the Change of Control Triggering Event and offering to repurchase notes on the Change of Control Payment Date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed, pursuant to the procedures required by the indenture and described in such notice. Mariner will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control Triggering Event. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control Triggering Event provisions of the indenture, Mariner will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control Triggering Event provisions of the indenture by virtue of such compliance.
 
On the Change of Control Payment Date, Mariner will, to the extent lawful:
 
(1) accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer;
 
(2) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and
 
(3) deliver or cause to be delivered to the trustee the notes properly accepted together with an officers’ certificate stating the aggregate principal amount of notes or portions of notes being purchased by Mariner.
 
The paying agent will promptly mail to each holder of notes properly tendered the Change of Control Payment for such notes (or, if all the notes are then in global form, make such payment through the facilities of DTC), and the trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any; provided that each such new note will be in a principal amount of $1,000 or an integral multiple thereof. Any note so accepted for payment will cease to accrue interest and Special Interest, if applicable, on and after the


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Change of Control Payment Date unless Mariner defaults in making the Change of Control Payment. Mariner will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date.
 
The provisions described herein that require Mariner to make a Change of Control Offer following a Change of Control Triggering Event will be applicable whether or not any other provisions of the indenture are applicable. Except as described above with respect to a Change of Control Triggering Event, the indenture does not contain provisions that permit the holders of the notes to require that Mariner repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.
 
Mariner will not be required to make a Change of Control Offer upon a Change of Control Triggering Event if (1) a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by Mariner and purchases all notes properly tendered and not withdrawn under the Change of Control Offer, or (2) notice of redemption has been given pursuant to the indenture as described above under the caption “— Optional Redemption,” unless and until there is a default in payment of the applicable redemption price.
 
A Change of Control Offer may be made in advance of a Change of Control Triggering Event, and conditioned upon the occurrence of such Change of Control Triggering Event, if a definitive agreement is in place for the Change of Control Triggering Event at the time of making the Change of Control Offer. Notes repurchased by Mariner pursuant to a Change of Control Offer will have the status of notes issued but not outstanding or will be retired and cancelled, at Mariner’s option. Notes purchased by a third party pursuant to the preceding paragraph will have the status of notes issued and outstanding.
 
The Credit Agreement will prohibit Mariner from repurchasing any notes pursuant to a Change of Control Offer prior to the repayment in full of the Indebtedness under the Credit Agreement. Moreover, the occurrence of certain change of control events identified in the Credit Agreement constitutes a default under the Credit Agreement. Any future Credit Facilities or other agreements relating to the Indebtedness to which Mariner becomes a party may contain similar restrictions and provisions. If a Change of Control Triggering Event were to occur, Mariner may not have sufficient available funds to pay the Change of Control Payment for all notes that might be delivered by holders of notes seeking to accept the Change of Control Offer after first satisfying its obligations under the Credit Agreement or other agreements relating to Indebtedness, if accelerated. The failure of Mariner to make or consummate the Change of Control Offer or pay the Change of Control Payment when due will constitute a Default under the indenture and will otherwise give the trustee and the holders of notes the rights described under “— Events of default and remedies.” See “Risk Factors — Risks Relating to the notes — We may not be able to repurchase the notes upon a change of control.”
 
The definition of Change of Control Triggering Event includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of Mariner and its Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require Mariner to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of Mariner and its Subsidiaries taken as a whole to another Person or group may be uncertain.
 
In the event that holders of not less than 90% of the aggregate principal amount of the outstanding notes accept a Change of Control Offer and Mariner purchases all of the notes held by such holders, Mariner will have the right, upon not less than 30 nor more than 60 days’ prior notice, given not more than 30 days following the purchase pursuant to the Change of Control Offer described above, to redeem all of the notes that remain outstanding following such purchase at a purchase price equal to the Change of Control Payment plus, to the extent not included in the Change of Control Payment, accrued and unpaid interest and Special Interest, if any, on the notes that remain outstanding, to the date of redemption (subject to the right of holders on the relevant record date to receive interest due on the relevant interest payment date).


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Asset Sales
 
Mariner will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:
 
(1) Mariner (or the Restricted Subsidiary, as the case may be) receives consideration at the time of the Asset Sale at least equal to the Fair Market Value of the assets or Equity Interests issued or sold or otherwise disposed of; and
 
(2) (a) at least 75% of the consideration received in the Asset Sale by Mariner or such Restricted Subsidiary is in the form of cash or (b) the Fair Market Value of all forms of consideration other than cash received for all Asset Sales since the Issue Date does not exceed in the aggregate 10% of the Adjusted Consolidated Net Tangible Assets of Mariner at the time each determination is made. For purposes of this provision, each of the following will be deemed to be cash:
 
(a) any liabilities, as shown on Mariner’s most recent consolidated balance sheet, of Mariner or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the notes or any Note Guarantee) that are assumed by the transferee of any such assets pursuant to a customary novation agreement that releases Mariner or such Restricted Subsidiary from further liability;
 
(b) any securities, notes or other obligations received by Mariner or any such Restricted Subsidiary from such transferee that are converted by Mariner or such Restricted Subsidiary into cash within 180 days after the date of the Asset Sale, to the extent of the cash received in that conversion;
 
(c) any stock or assets of the kind referred to in clauses (2) or (4) of the next paragraph of this covenant; and
 
(d) accounts receivable of a business retained by Mariner or any Restricted Subsidiary, as the case may be, following the sale of such business, provided, that such accounts receivable are not (a) past due more than 90 days and (b) do not have a payment date greater than 120 days from the date of the invoice creating such accounts receivable.
 
Within 360 days after the receipt of any Net Proceeds from an Asset Sale, Mariner (or the applicable Restricted Subsidiary, as the case may be) may apply such Net Proceeds:
 
(1) to repay Senior Debt;
 
(2) to invest in Additional Assets;
 
(3) to make capital expenditures in respect of Mariner’s or its Restricted Subsidiaries’ Oil and Gas Business; or
 
(4) enter into a bona fide binding contract with a Person other than an Affiliate of Mariner to apply the Net Proceeds pursuant to clauses (2) or (3) above, provided that such binding contract shall be treated as a permitted application of the Net Proceeds from the date of such contract until the earlier of (a) the date on which such acquisition or expenditure is consummated, and (b) the 180th day following the expiration of the aforementioned 360-day period.
 
Pending the final application of any Net Proceeds, Mariner or any Restricted Subsidiary may temporarily reduce revolving credit borrowings or otherwise invest the Net Proceeds in any manner that is not prohibited by the indenture. Any Net Proceeds from Asset Sales that are not applied or invested as provided in the second paragraph of this covenant will constitute “Excess Proceeds.”
 
On the 361st day after the Asset Sale (or, at Mariner’s option, any earlier date), if the aggregate amount of Excess Proceeds then exceeds $20.0 million, Mariner will make an offer (the “Asset Sale Offer”) to all holders of notes and all holders of other Indebtedness that is pari passu with the notes containing provisions similar to those set forth in the indenture with respect to offers to purchase or redeem with the proceeds of sales of assets, to purchase the maximum principal amount of notes and such other pari passu Indebtedness


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that may be purchased out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of the principal amount plus accrued and unpaid interest and Special Interest, if any, to the date of purchase, and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, Mariner may use those Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of notes and other pari passu Indebtedness tendered into such Asset Sale Offer exceeds the amount of Excess Proceeds, the trustee will select the notes to be purchased on a pro rata basis. Upon completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset at zero.
 
Mariner will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the Asset Sale provisions of the indenture, Mariner will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the indenture by virtue of such compliance.
 
The Credit Agreement and certain other agreements governing Mariner’s other Indebtedness contain, and future agreements may contain, prohibitions of certain events, including events that would constitute a Change of Control Triggering Event or an Asset Sale and including repurchases of or other prepayments in respect of the notes. The exercise by the holders of notes of their right to require Mariner to repurchase the notes upon a Change of Control Triggering Event or an Asset Sale could cause a default under these other agreements, even if the Change of Control Triggering Event or Asset Sale itself does not due to the financial effect of such repurchases on Mariner or otherwise. In the event a Change of Control or Asset Sale occurs at a time when Mariner is prohibited from purchasing notes, Mariner could seek the consent of the applicable lenders to the purchase of notes or could attempt to refinance the Indebtedness that contain such prohibitions. If Mariner does not obtain a consent or repay that Indebtedness, Mariner will remain prohibited from purchasing notes. In that case, Mariner’s failure to purchase tendered notes would constitute an Event of Default under the indenture which could, in turn, constitute a default under other Indebtedness. Finally, Mariner’s ability to pay cash to the holders of notes upon a repurchase may be limited by Mariner’s then existing financial resources. See “Risk Factors — Risks Relating to the Notes — We may not be able to repurchase the notes upon a change of control.”
 
Selection and Notice
 
If less than all of the notes are to be redeemed at any time, the trustee will select notes for redemption on a pro rata basis unless otherwise required by law or applicable stock exchange requirements.
 
No notes of $1,000 or less can be redeemed in part. Notices of redemption will be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each holder of notes to be redeemed at its registered address, except that redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the indenture.
 
If any note is to be redeemed in part only, the notice of redemption that relates to that note will state the portion of the principal amount of that note that is to be redeemed. A new note in principal amount equal to the unredeemed portion of the original note will be issued in the name of the holder of notes upon cancellation of the original note. notes called for redemption become due on the date fixed for redemption. Notes called for redemption become due on the date fixed for redemption except as described in “— Optional Redemption.” On and after the redemption date, interest and Special Interest, if any, cease to accrue on notes or portions of notes called for redemption, unless Mariner defaults in making the payment of funds for such a redemption.


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Certain Covenants
 
Restricted Payments
 
Mariner will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:
 
(1) declare or pay any dividend or make any other payment or distribution on account of Mariner’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any such payment or distribution made in connection with any merger or consolidation involving Mariner or any of its Restricted Subsidiaries) or to the direct or indirect holders of Mariner’s or any of its Restricted Subsidiaries’ Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of Mariner and other than dividends or distributions payable to Mariner or a Restricted Subsidiary of Mariner);
 
(2) purchase, redeem or otherwise acquire or retire for value (including, without limitation, any such purchase, redemption, acquisition or retirement made in connection with any merger or consolidation involving Mariner) any Equity Interests of Mariner or any direct or indirect parent or other Affiliate of Mariner that is not a Restricted Subsidiary of Mariner;
 
(3) make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value, prior to the Stated Maturity thereof, any Indebtedness of Mariner or any Guarantor that is contractually subordinated to the notes or to any Note Guarantee (excluding (a) any intercompany Indebtedness between or among Mariner and any of its Restricted Subsidiaries or (b) the purchase, repurchase or other acquisition of Indebtedness that is subordinated to the notes or the Note Guarantees purchased in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of purchase, repurchase or acquisition); or
 
(4) make any Restricted Investment;
 
(all such payments and other actions set forth in clauses (1) through (4) above being collectively referred to as “Restricted Payments”),
 
unless, at the time of and after giving effect to such Restricted Payment:
 
(1) no Default or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment;
 
(2) Mariner would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period, have been permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described below under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock;” and
 
(3) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by Mariner and its Restricted Subsidiaries since the date of the indenture (excluding Restricted Payments permitted by clauses (2), (3), (4), (5), (6), (7), (8) and (10) of the next succeeding paragraph), is equal to or less than the sum, without duplication, of:
 
(a) 50% of the Consolidated Net Income of Mariner for the period (taken as one accounting period) from the beginning of the first fiscal quarter commencing after the Issue Date to the end of Mariner’s most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit); plus
 
(b) 100% of the aggregate net cash proceeds received, and the Fair Market Value of property received from a non-Affiliate used or useful in an Oil and Gas Business, by Mariner since the Issue Date as a contribution to its common capital or from the issue or sale of Equity Interests of Mariner (other than Disqualified Stock) or from the issue or sale of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities of Mariner that have been converted into or


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exchanged for such Equity Interests (other than Equity Interests (or Disqualified Stock or debt securities) sold to a Subsidiary of Mariner or an employee stock ownership plan, option plan or similar trust to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or guaranteed by Mariner or any of its Restricted Subsidiaries unless such loans have been repaid with cash on or prior to the date of determination); plus
 
(c) the amount equal to the net reduction in Restricted Investments made by Mariner or any of its Restricted Subsidiaries in any Person resulting from:
 
(i) repurchases or redemptions of such Restricted Investments by such Person, proceeds realized upon the sale of such Restricted Investment to a purchaser other than Mariner or a Subsidiary or Mariner, repayments of loans or advances or other transfers of assets (including by way of dividend or distribution) by such Person to Mariner or any Restricted Subsidiary of Mariner; or
 
(ii) the redesignation of Unrestricted Subsidiaries as Restricted Subsidiaries (valued in each case as provided in the definition of “Investment”) not to exceed, in the case of any Unrestricted Subsidiary, the amount of Investments previously made by Mariner or any Restricted Subsidiary of Mariner in such Unrestricted Subsidiary, which amount in each case under this clause (c) was included in the calculation of the amount of Restricted Payments; provided, however, that no amount will be included under this clause (c) to the extent it is already included in Consolidated Net Income; plus
 
(d) 50% of any dividends received by Mariner or a Restricted Subsidiary of Mariner that is a Guarantor after the Issue Date from an Unrestricted Subsidiary of Mariner, to the extent that such dividends were not otherwise included in the Consolidated Net Income of Mariner for such period.
 
So long as no Default has occurred and is continuing or would be caused thereby, the preceding provisions will not prohibit:
 
(1) the payment of any dividend or the consummation of any irrevocable redemption within 60 days after the date of declaration of the dividend or giving of the redemption notice, as the case may be, if at the date of declaration or notice, the dividend or redemption payment would have complied with the provisions of the indenture;
 
(2) the making of any Restricted Payment in exchange for, or out of the net cash proceeds of the substantially concurrent sale (other than to a Subsidiary of Mariner) of, Equity Interests of Mariner (other than Disqualified Stock and other than Equity Interests issued or sold to an employee stock ownership plan, option plan or similar trust to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or guaranteed by Mariner or any of its Restricted Subsidiaries unless such loans have been repaid with cash on or prior to the date of determination) or from the substantially concurrent contribution of common equity capital to Mariner; provided that the amount of any such net cash proceeds that are utilized for any such Restricted Payment will be excluded from clause (3)(b) of the preceding paragraph;
 
(3) the repurchase, redemption, defeasance or other acquisition or retirement for value of Indebtedness of Mariner or any Guarantor that is contractually subordinated to the notes or to any Note Guarantee with the net cash proceeds from a substantially concurrent incurrence of Permitted Refinancing Indebtedness;
 
(4) the payment of any dividend (or, in the case of any partnership or limited liability company, any similar distribution) by a Restricted Subsidiary of Mariner to the holders of its Equity Interests on a pro rata basis;
 
(5) the defeasance, repurchase, redemption or other acquisition or retirement for value of any Equity Interests of Mariner or any Restricted Subsidiary of Mariner held by any of Mariner’s (or any of its Restricted Subsidiaries’) current or former directors or employees pursuant to any director or employee equity subscription agreement, stock option agreement or restricted stock agreement; provided that the


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aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests may not exceed $3.0 million in any twelve-month period (with unused amounts in any 12-month period being permitted to be carried over into succeeding 12-month periods); provided, further, that the amounts in any 12-month period may be increased by an amount not to exceed (A) the cash proceeds received by Mariner or any of its Restricted Subsidiaries from the sale of Mariner’s Equity Interests (other than Disqualified Stock) to any such directors or employees that occurs after the Issue Date (provided that the amount of such cash proceeds utilized for any such repurchase, retirement or other acquisition or retirement will not increase the amount available for Restricted Payments under clause (3) of the immediately preceding paragraph and to the extent such proceeds have not otherwise been applied to the payment of Restricted Payments) plus (B) the cash proceeds of key man life insurance policies received by Mariner and its Restricted Subsidiaries after the Issue Date;
 
(6) the defeasance, repurchase, redemption or other acquisition or retirement for value of any Equity Interests of Mariner or any Restricted Subsidiary of Mariner held by any of Mariner’s (or any of its Restricted Subsidiaries’) current or former directors or employees in connection with the exercise or vesting of any equity compensation (including, without limitation, stock options, restricted stock and phantom stock) in order to satisfy Mariner’s or such Restricted Subsidiary’s tax withholding obligation with respect to such exercise or vesting;
 
(7) any payments made in connection with the consummation of the transaction closing contemporaneously with the closing of the offering of old notes;
 
(8) so long as no Default has occurred and is continuing or would be caused thereby, repurchases of Indebtedness that is subordinated to the notes or a Note Guarantee at a purchase price not greater than (i) 101% of the principal amount of such subordinated Indebtedness and accrued and unpaid interest thereon in the event of a Change of Control Triggering Event or (ii) 100% of the principal amount of such subordinated Indebtedness and accrued and unpaid interest thereon in the event of an Asset Sale, in each case plus accrued interest, in connection with any change of control offer or asset sale offer required by the terms of such Indebtedness, but only if:
 
(a) in the case of a Change of Control Triggering Event, Mariner has first complied with and fully satisfied its obligations under the provisions described under “— Repurchase at the Option of Holders — Change of Control Triggering Event”; or
 
(b) in the case of an Asset Sale, Mariner has complied with and fully satisfied its obligations in accordance with the covenant under the heading, “— Repurchase at the Option of Holders — Asset Sales”;
 
(9) the repurchase, redemption or other acquisition for value of Capital Stock of Mariner representing fractional shares of such Capital Stock in connection with a merger, consolidation, amalgamation or other combination involving Mariner or any other transaction permitted by the indenture;
 
(10) repurchases of Capital Stock deemed to occur upon the exercise of stock options if such Capital Stock represents a portion of the exercise price thereof;
 
(11) the declaration and payment of regularly scheduled or accrued dividends to holders of any class or series of Disqualified Stock of Mariner or any Restricted Subsidiary of Mariner issued on or after the Issue Date in accordance with the Fixed Charge Coverage Ratio test described below under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock;” and
 
(12) other Restricted Payments in an aggregate amount not to exceed $25.0 million since the Issue Date.
 
The amount of all Restricted Payments (other than cash) will be the Fair Market Value on the date of the Restricted Payment of the asset(s) or securities proposed to be transferred or issued by Mariner or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. The Fair Market Value of any assets or securities that are required to be valued by this covenant will be determined by the Board of


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Directors of Mariner whose resolution with respect thereto will be delivered to the trustee. For purposes of determining compliance with this covenant, in the event that a Restricted Payment meets the criteria of more than one of the exceptions described in (1) through (12) above or is entitled to be made pursuant to the first paragraph of this covenant, Mariner shall, in its sole discretion, classify such Restricted Payment, or later classify, reclassify or re-divide all or a portion of such Restricted Payment, in any manner that complies with this covenant.
 
Incurrence of Indebtedness and Issuance of Preferred Stock
 
Mariner will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, “incur”) any Indebtedness (including Acquired Debt), and Mariner will not issue any Disqualified Stock and will not permit any of its Restricted Subsidiaries to issue any shares of preferred stock; provided, however, that Mariner and the Restricted Subsidiaries may incur Indebtedness (including Acquired Debt) or issue Disqualified Stock, if the Fixed Charge Coverage Ratio for Mariner’s most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock is issued, as the case may be, would have been at least 2.25 to 1.0, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or the Disqualified Stock had been issued, as the case may be, at the beginning of such four-quarter period.
 
The first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness (collectively, “Permitted Debt”):
 
(1) the incurrence by Mariner and any Restricted Subsidiary of additional Indebtedness and letters of credit under Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) (with letters of credit being deemed to have a principal amount equal to the maximum potential liability of Mariner and its Restricted Subsidiaries thereunder) not to exceed the greater of (a) $600.0 million and (b) an amount equal to the sum of (A) $300.0 million plus (B) 10% of Adjusted Consolidated Net Tangible Assets determined as of the date of the incurrence of such Indebtedness after giving pro forma effect to such incurrence and the application of the proceeds therefrom;
 
(2) the incurrence by Mariner and its Restricted Subsidiaries of the Existing Indebtedness;
 
(3) the incurrence by Mariner and the Guarantors of Indebtedness represented by the notes and the related Note Guarantees to be issued on the date of the indenture and the notes and the related Note Guarantees to be issued pursuant to the registration rights agreement;
 
(4) the incurrence by Mariner or any of its Restricted Subsidiaries of Indebtedness represented by Capital Lease Obligations, mortgage financings or purchase money obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of design, construction, installation or improvement of property, plant or equipment used in the business of Mariner or any of its Restricted Subsidiaries, in an aggregate principal amount, including all Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (4), not to exceed $50.0 million at any time outstanding;
 
(5) the incurrence by Mariner or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge any Indebtedness (other than intercompany Indebtedness) that was permitted by the indenture to be incurred under the first paragraph of this covenant or clauses (2), (3), (4) or (11) of this paragraph or this clause (5);
 
(6) the incurrence by Mariner or any of its Restricted Subsidiaries of intercompany Indebtedness between or among Mariner and any of its Restricted Subsidiaries; provided, however, that:
 
(a) if Mariner or any Guarantor is the obligor on such Indebtedness and the payee is not Mariner or a Guarantor, such Indebtedness must be expressly subordinated to the prior payment in


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full in cash of all Obligations then due with respect to the notes, in the case of Mariner, or the Note Guarantee, in the case of a Guarantor; and
 
(b) (i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than Mariner or a Restricted Subsidiary of Mariner and (ii) any sale or other transfer of any such Indebtedness to a Person that is not either Mariner or a Restricted Subsidiary of Mariner will be deemed, in each case, to constitute an incurrence of such Indebtedness by Mariner or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);
 
(7) the issuance by any of Mariner’s Restricted Subsidiaries to Mariner or to any of its Restricted Subsidiaries of shares of preferred stock; provided, however, that:
 
(a) any subsequent issuance or transfer of Equity Interests that results in any such preferred stock being held by a Person other than Mariner or a Restricted Subsidiary of Mariner; and
 
(b) any sale or other transfer of any such preferred stock to a Person that is not either Mariner or a Restricted Subsidiary of Mariner, will be deemed, in each case, to constitute an issuance of such preferred stock by such Restricted Subsidiary that was not permitted by this clause (7);
 
(8) the incurrence by Mariner or any of its Restricted Subsidiaries of Hedging Obligations in the ordinary course of business;
 
(9) the incurrence by Mariner of any of its Restricted Subsidiaries of obligations relating to net gas balancing positions arising in the ordinary course of business and consistent with past practice;
 
(10) the guarantee by Mariner or any of the Guarantors of Indebtedness of Mariner or a Restricted Subsidiary of Mariner that was permitted to be incurred by another provision of this covenant; provided that if the Indebtedness being guaranteed is subordinated to or pari passu with the notes, then the guarantee shall be subordinated or pari passu, as applicable, to the same extent as the Indebtedness guaranteed;
 
(11) Permitted Acquisition Indebtedness;
 
(12) the incurrence by Mariner or any of its Restricted Subsidiaries of Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument inadvertently drawn against insufficient funds, so long as such Indebtedness is covered within five Business Days;
 
(13) Indebtedness consisting of the financing of insurance premiums in customary amounts consistent with the operations and business of Mariner and its Restricted Subsidiaries;
 
(14) the incurrence by Mariner or any of its Restricted Subsidiaries of Indebtedness arising from agreements of Mariner or any of its Restricted Subsidiaries providing for indemnification, adjustment of purchase price or similar obligations, in each case, incurred or assumed in connection with the disposition of any business, assets or Capital Stock of a Subsidiary, provided that the maximum aggregate liability in respect of all such Indebtedness shall at no time exceed the gross proceeds actually received by Mariner and its Restricted Subsidiaries in connection with such disposition;
 
(15) the incurrence by Mariner or any of its Restricted Subsidiaries of Indebtedness in respect of bid, performance, surety and similar bonds issued for the account of Mariner and any of its Restricted Subsidiaries in the ordinary course of business, including guarantees and obligations of Mariner or any of its Restricted Subsidiaries with respect to letters of credit supporting such obligations (in each case, other than an obligation for money borrowed);
 
(16) the incurrence by Mariner or any of its Restricted Subsidiaries of Indebtedness arising from guarantees of Indebtedness of joint ventures at any time outstanding not to exceed the greater of $10.0 million and 1.00% of the Adjusted Consolidated Net Tangible Assets determined as of the date of the incurrence of such Indebtedness after giving pro forma effect to such incurrence and the application of proceeds therefrom; and


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(17) the incurrence by Mariner or any of its Restricted Subsidiaries of additional Indebtedness in an aggregate principal amount (or accreted value, as applicable) at any time outstanding not to exceed the greater of $50.0 million and 2.50% of the Adjusted Consolidated Net Tangible Assets determined as of the date of the incurrence of such Indebtedness after giving pro forma effect to such incurrence and the application of proceeds therefrom.
 
Mariner will not incur, and will not permit any Guarantor to incur, any Indebtedness (including Permitted Debt) that is contractually subordinated in right of payment to any other Indebtedness of Mariner or such Guarantor unless such Indebtedness is also contractually subordinated in right of payment to the notes and the applicable Note Guarantee on substantially identical terms; provided, however, that no Indebtedness will be deemed to be contractually subordinated in right of payment to any other Indebtedness of Mariner solely by virtue of being unsecured or by virtue of being secured on a first or junior Lien basis.
 
For purposes of determining compliance with this “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant, in the event that an item of proposed Indebtedness meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (17) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, Mariner will be permitted to classify such item of Indebtedness on the date of its incurrence, or later reclassify all or a portion of such item of Indebtedness, in any manner that complies with this covenant. The accrual of interest, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness in the form of additional Indebtedness with the same terms, the reclassification of preferred stock as Indebtedness due to a change in accounting principles, and the payment of dividends on Disqualified Stock in the form of additional shares of the same class of Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of Disqualified Stock for purposes of this covenant; provided, in each such case, that the amount of any such accrual, accretion or payment is included in Fixed Charges of Mariner as accrued. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that Mariner or any Restricted Subsidiary may incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in exchange rates or currency values.
 
Liens
 
Mariner will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, assume or suffer to exist any Lien of any kind (other than Permitted Liens) upon any of its property or assets (whether now owned or hereafter acquired), securing any Subordinated Obligations or Indebtedness, unless:
 
(1) in the case of any Lien securing Subordinated Obligations of Mariner or a Guarantor, the notes or Note Guarantee, as applicable, are secured by a Lien on such property or assets on a senior basis to the Subordinated Obligations so secured until such time as such Subordinated Obligations are no longer so secured by that Lien; and
 
(2) in the case of any other Lien (other than a Permitted Lien) securing Indebtedness, the notes or note Guarantees, as applicable, are secured by a Lien on such property or assets on an equal and ratable basis with the Senior Debt so secured until such time as such Senior Debt is no longer so secured by that Lien.
 
Dividend and Other Payment Restrictions Affecting Subsidiaries
 
Mariner will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:
 
(1) pay dividends or make any other distributions on its Capital Stock to Mariner or any of its Restricted Subsidiaries, or with respect to any other interest or participation in, or measured by, its profits, or pay any indebtedness owed to Mariner or any of its Restricted Subsidiaries;
 
(2) make loans or advances to Mariner or any of its Restricted Subsidiaries; or


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(3) sell, lease or transfer any of its properties or assets to Mariner or any of its Restricted Subsidiaries.
 
However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:
 
(1) agreements governing Existing Indebtedness and Credit Facilities as in effect on the Issue Date and any amendments, restatements, modifications, renewals, supplements, increases, refundings, replacements or refinancings of those agreements; provided that the amendments, restatements, modifications, renewals, supplements, increases, refundings, replacements or refinancings are no more restrictive, taken as a whole, with respect to such dividend and other payment restrictions than those contained in those agreements on the Issue Date;
 
(2) the indenture, the notes and the Note Guarantees;
 
(3) applicable law, rule, regulation, order, approval, permit or similar restriction;
 
(4) any instrument governing Indebtedness or Capital Stock of a Person acquired by Mariner or any of its Restricted Subsidiaries as in effect at the time of such acquisition (except to the extent such Indebtedness or Capital Stock was incurred in connection with or in contemplation of such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired; provided that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the indenture to be incurred;
 
(5) customary non-assignment provisions in contracts, leases and licenses (including, without limitation, licenses of intellectual property) entered into in the ordinary course of business;
 
(6) purchase money obligations for property (including Capital Stock) acquired in the ordinary course of business, Capital Lease Obligations and mortgage financings that impose restrictions on the property purchased or leased of the nature described in clause (3) of the preceding paragraph;
 
(7) any agreement for the sale or other disposition of assets, including without limitation an agreement for the sale or other disposition of the Capital Stock or assets of a Restricted Subsidiary, that restricts distributions by the applicable Restricted Subsidiary pending the sale or other disposition;
 
(8) Permitted Refinancing Indebtedness; provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced;
 
(9) Liens permitted to be incurred under the provisions of the covenant described above under the caption “— Liens” that limit the right of the debtor to dispose of the assets subject to such Liens;
 
(10) provisions limiting the disposition or distribution of assets or property in, or transfer of Capital Stock of, joint venture agreements, asset sale agreements, sale-leaseback agreements, stock sale agreements and other similar agreements entered into (a) in the ordinary course of business, consistent with past practice or (b) with the approval of Mariner’s Board of Directors, which limitations are applicable only to the assets, property or Capital Stock that are the subject of such agreements;
 
(11) other Indebtedness of Mariner or any of its Restricted Subsidiaries permitted to be incurred pursuant to an agreement entered into subsequent to the Issue Date in accordance with the covenant described under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock”; provided that the provisions relating to such encumbrance or restriction contained in such Indebtedness are not materially less favorable to Mariner taken as a whole, as determined by the Board of Directors of Mariner in good faith, than the provisions contained in the Credit Agreement and in the indenture as in effect on the Issue Date;
 
(12) the issuance of preferred stock by a Restricted Subsidiary or the payment of dividends thereon in accordance with the terms thereof; provided that issuance of such preferred stock is permitted pursuant to the covenant described under the caption “— Incurrence of Indebtedness and Issuance of Preferred


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Stock” and the terms of such preferred stock do not expressly restrict the ability of a Restricted Subsidiary to pay dividends or make any other distributions on its Capital Stock (other than requirements to pay dividends or liquidation preferences on such preferred stock prior to paying any dividends or making any other distributions on such other Capital Stock);
 
(13) supermajority voting requirements existing under corporate charters, bylaws, stockholders agreements and similar documents and agreements;
 
(14) customary provisions restricting subletting or assignment of any lease governing a leasehold interest;
 
(15) encumbrances or restrictions contained in Hedging Obligations permitted from time to time under the indenture; and
 
(16) restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business.
 
Merger, Consolidation or Sale of Assets
 
Mariner will not, directly or indirectly, consolidate, amalgamate or merge with or into another Person (whether or not Mariner is the surviving corporation), convert into another form of entity or continue in another jurisdiction; or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets, in one or more related transactions, to another Person, unless:
 
(1) either: (a) Mariner is the surviving corporation; or (b) the Person formed by or surviving any such consolidation, amalgamation or merger or resulting from such conversion (if other than Mariner) or to which such sale, assignment, transfer, conveyance or other disposition has been made is a corporation, limited liability company or limited partnership organized or existing under the laws of the United States, any state of the United States or the District of Columbia;
 
(2) the Person formed by or surviving any such conversion, consolidation, amalgamation or merger (if other than Mariner) or the Person to which such sale, assignment, transfer, conveyance or other disposition has been made assumes all the obligations of Mariner under the notes, the indenture and the registration rights agreement pursuant to agreements reasonably satisfactory to the trustee; provided that, unless such Person is a corporation, a corporate co-issuer of the notes will be added to the indenture by agreements reasonably satisfactory to the trustee;
 
(3) immediately after such transaction or transactions, no Default or Event of Default exists; and
 
(4) Mariner or the Person formed by or surviving any such consolidation, amalgamation or merger (if other than Mariner), or to which such sale, assignment, transfer, conveyance or other disposition has been made:
 
(a) would have Consolidated Net Worth immediately after the transaction equal to or greater than the Consolidated Net Worth of Mariner immediately preceding the transaction;
 
(b) would, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period, be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock”; or
 
(c) would, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period, have a Fixed Charge Coverage Ratio that is not less than the Fixed Charged Coverage Ratio of Mariner and its Restricted Subsidiaries immediately prior to such transaction.
 
For purposes of this covenant, the sale, lease, conveyance, assignment, transfer, or other disposition of all or substantially all of the properties and assets of one or more Subsidiaries of Mariner, which properties and


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assets, if held by Mariner instead of such Subsidiaries, would constitute all or substantially all of the properties and assets of Mariner on a consolidated basis, shall be deemed to be the transfer of all or substantially all of the assets of Mariner.
 
The surviving entity will succeed to, and be substituted for, and may exercise every right and power of, Mariner under the indenture, but, in the case of a lease of all or substantially all of its assets, Mariner will not be released from the obligation to pay the principal of and interest on the notes.
 
Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the property or assets of a Person.
 
Notwithstanding the restrictions described in the foregoing clause (4), any Restricted Subsidiary may consolidate with, merge into or transfer all or part of its properties and assets to Mariner, Mariner may merge into a Restricted Subsidiary for the purpose of reincorporating Mariner in another jurisdiction, and any Restricted Subsidiary may consolidate with, merge into or transfer all or part of its properties and assets to another Restricted Subsidiary.
 
Transactions with Affiliates
 
Mariner will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate of Mariner (each, an “Affiliate Transaction”), unless:
 
(1) the Affiliate Transaction is on terms that are no less favorable to Mariner or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by Mariner or such Restricted Subsidiary with an unrelated Person; and
 
(2) Mariner delivers to the trustee:
 
(a) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $10.0 million, a resolution of the Board of Directors of Mariner set forth in an officers’ certificate certifying that such Affiliate Transaction complies with this covenant and that such Affiliate Transaction has been approved by a majority of the disinterested members of the Board of Directors of Mariner; and
 
(b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $30.0 million, an opinion as to the fairness to Mariner or such Subsidiary of such Affiliate Transaction from a financial point of view issued by an accounting, appraisal or investment banking firm of national standing.
 
The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:
 
(1) any employment agreement or arrangement, stock option or stock ownership plan, employee benefit plan, officer or director indemnification agreement, restricted stock agreement, severance agreement or other compensation plan or arrangement entered into by Mariner or any of its Restricted Subsidiaries in the ordinary course of business and payments, awards, grants or issuances of securities pursuant thereto, including, without limitation, pursuant to Mariner’s Equity Participation Plan, as amended, and its Amended and Restated Stock Incentive Plan, as amended;
 
(2) transactions between or among Mariner and/or its Restricted Subsidiaries;
 
(3) transactions with a Person (other than an Unrestricted Subsidiary of Mariner) that is an Affiliate of Mariner solely because Mariner owns, directly or through a Restricted Subsidiary, an Equity Interest in, or controls, such Person;


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(4) reasonable fees and expenses and compensation paid to, and indemnity or insurance provided on behalf of, officers, directors or employees of Mariner or any Restricted Subsidiaries as determined in good faith by the Board of Directors;
 
(5) any issuance of Equity Interests (other than Disqualified Stock) of Mariner to, or receipt of a capital contribution from, Affiliates (or a Person that becomes an Affiliate) of Mariner;
 
(6) Restricted Payments that do not violate the provisions of the indenture described above under the caption “— Restricted Payments;”
 
(7) transactions between Mariner or any Restricted Subsidiaries and any Person, a director of which is also a director of Mariner or any direct or indirect parent company of Mariner and such director is the sole cause for such Person to be deemed an Affiliate of Mariner or any Restricted Subsidiaries; provided, however, that such director abstains from voting as director of Mariner or such direct or indirect parent company, as the case may be, on any matter involving such other Person;
 
(8) loans or advances to employees in the ordinary course of business or consistent with past practice not to exceed $5.0 million in the aggregate at any one time outstanding;
 
(9) advances to or reimbursements of employees for moving, entertainment and travel expenses, drawing accounts and similar expenditures in the ordinary course of business;
 
(10) any transaction in which Mariner or any of its Restricted Subsidiaries, as the case may be, deliver to the trustee a letter from an accounting, appraisal or investment banking firm of national standing stating that such transaction is fair to Mariner or such Restricted Subsidiary from a financial point of view or that such transaction meets the requirements of clause (i) of the preceding paragraph;
 
(11) the performance of obligations of Mariner or any of its Restricted Subsidiaries under the terms of any written agreement to which Mariner or any of its Restricted Subsidiaries is a party on the Issue Date and which is described in this prospectus, as these agreements may be amended, modified or supplemented from time to time; provided, however, that any future amendment, modification or supplement entered into after the Issue Date will be permitted to the extent that its terms do not materially and adversely affect the rights of any holders of the notes (as determined in good faith by the Board of Directors of Mariner) as compared to the terms of the agreements in effect on the Issue Date; and
 
(12) (a) guarantees of performance by Mariner and its Restricted Subsidiaries of Mariner’s Unrestricted Subsidiaries in the ordinary course of business, except for guarantees of Indebtedness in respect of borrowed money, and (b) pledges of Equity Interests of Mariner’s Unrestricted Subsidiaries for the benefit of lenders of Mariner’s Unrestricted Subsidiaries.
 
Additional Note Guarantees
 
The indenture will provide that if, after the Issue Date, any Domestic Subsidiary that is not already a Guarantor has outstanding or guarantees any other Indebtedness of Mariner or a Guarantor in excess of a De Minimis Guaranteed Amount, then such Domestic Subsidiary will become a Guarantor with respect to the notes issued thereunder by executing and delivering a supplemental indenture, in the form provided for in the indenture, to the trustee within 180 days of the date on which it guaranteed such Indebtedness.
 
Designation of Restricted and Unrestricted Subsidiaries
 
The Board of Directors of Mariner may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary is designated as an Unrestricted Subsidiary, the aggregate Fair Market Value of all outstanding Investments owned by Mariner and its Restricted Subsidiaries in the Subsidiary designated as Unrestricted will be deemed to be an Investment made as of the time of the designation and will reduce the amount available for Restricted Payments under the covenant described above under the caption “— Restricted Payments” or under one or more clauses of the definition of Permitted Investments, as determined by Mariner. That designation will only be permitted if the


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Investment would be permitted at that time and if the Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary.
 
Any designation of a Subsidiary of Mariner as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee a certified copy of a resolution of the Board of Directors of Mariner giving effect to such designation and an officers’ certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption “— Restricted Payments.” If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary of Mariner as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock,” Mariner will be in default of such covenant. The Board of Directors of Mariner may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary of Mariner; provided that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of Mariner of any outstanding Indebtedness of such Unrestricted Subsidiary, and such designation will only be permitted if (1) such Indebtedness is permitted under the covenant described under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock,” calculated on a pro forma basis as if such designation had occurred at the beginning of the four-quarter reference period; and (2) no Default or Event of Default would be in existence following such designation.
 
Reports
 
Whether or not required by the rules and regulations of the SEC, so long as any notes are outstanding, Mariner will file with the SEC for public availability, within the time periods specified in the SEC’s rules and regulations (unless the SEC will not accept such a filing, in which case Mariner will furnish to the holders of notes or cause the trustee to furnish to the holders of notes, within the time periods specified in the SEC’s rules and regulations):
 
(1) all quarterly and annual reports that would be required to be filed with the SEC on Forms 10-Q and 10-K if Mariner were required to file such reports; and
 
(2) all current reports that would be required to be filed with the SEC on Form 8-K if Mariner were required to file such reports.
 
All such reports will be prepared in all material respects in accordance with all of the rules and regulations applicable to such reports. Each annual report on Form 10-K will include a report on Mariner’s consolidated financial statements by Mariner’s certified independent accountants.
 
If, at any time, Mariner is no longer subject to the periodic reporting requirements of the Exchange Act for any reason, Mariner will nevertheless continue filing the reports specified in the preceding paragraphs of this covenant with the SEC within the time periods specified above unless the SEC will not accept such a filing. Mariner will not take any action for the purpose of causing the SEC not to accept any such filings. If, notwithstanding the foregoing, the SEC will not accept Mariner’s filings for any reason, Mariner will post the reports referred to in the preceding paragraphs on its website within the time periods that would apply if Mariner were required to file those reports with the SEC.
 
If Mariner has designated any of its Subsidiaries as Unrestricted Subsidiaries, then, to the extent material, the quarterly and annual financial information required by the preceding paragraphs will include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in Management’s Discussion and Analysis of Financial Condition and Results of Operations, of the financial condition and results of operations of Mariner and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of Mariner.
 
In addition, Mariner and the Guarantors agree that, for so long as any notes remain outstanding, if at any time they are not required to file the reports required by the preceding paragraphs with the SEC, they will


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furnish to the holders of notes and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.
 
Covenant Termination
 
From and after the occurrence of an Investment Grade Rating Event, we and our Restricted Subsidiaries will no longer be subject to the provisions of the indenture described above under the following headings:
 
  •  “— Repurchase at the Option of Holders — Change of Control,”
 
  •  “— Repurchase at the Option of the Holders — Asset Sales,”
 
  •  “— Certain Covenants — Restricted Payments,”
 
  •  “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock,”
 
  •  “— Certain Covenants — Dividend and Other Payment Restrictions Affecting Subsidiaries,”
 
  •  clause (4) of the covenant listed under “— Certain Covenants — Merger, Consolidation or Sale of Assets,”
 
  •  “— Certain Covenants — Transactions with Affiliates,” and
 
  •  “— Certain Covenants — Designation of Restricted and Unrestricted Subsidiaries.”
 
(collectively, the “Eliminated Covenants”). As a result, after the date on which we and our Restricted Subsidiaries are no longer subject to the Eliminated Covenants, the notes will be entitled to substantially reduced covenant protection.
 
Events of Default and Remedies
 
Each of the following is an “Event of Default”:
 
(1) default for 30 days in the payment when due of interest on, or Special Interest, if any, with respect to, the notes;
 
(2) default in the payment when due (at maturity, upon redemption or otherwise) of the principal of, or premium, if any, on, the notes;
 
(3) failure by Mariner or any of its Restricted Subsidiaries to comply with the provisions described under the captions “— Repurchase at the Option of Holders — Change of Control,” “— Repurchase at the Option of Holders — Asset Sales,” or “— Certain Covenants — Merger, Consolidation or Sale of Assets;”
 
(4) failure by Mariner or any of its Restricted Subsidiaries for 60 days after notice to Mariner by the trustee or the holders of at least 25% in aggregate principal amount of the notes then outstanding voting as a single class to comply with any of the other agreements in the indenture;
 
(5) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by Mariner or any of its Restricted Subsidiaries (or the payment of which is guaranteed by Mariner or any of its Restricted Subsidiaries), whether such Indebtedness or Guarantee now exists, or is created after the date of the indenture, if that default:
 
(a) is caused by a failure to pay principal of, or interest or premium, if any, on, such Indebtedness prior to the expiration of the grace period provided in such Indebtedness on the date of such default (a “Payment Default”); or
 
(b) results in the acceleration of such Indebtedness prior to its express maturity, and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $20.0 million or more; provided that if any such default is cured or waived or any such acceleration rescinded, or such Indebtedness is repaid, within a period of ten


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Business Days from the continuation of such default beyond the applicable grace period or the occurrence of such acceleration, as the case may be, such Event of Default and any consequential acceleration of the notes shall be automatically rescinded, so long as such rescission does not conflict with any judgment or decree;
 
(6) failure by Mariner or any of its Restricted Subsidiaries to pay final judgments entered by a court or courts of competent jurisdiction aggregating in excess of $20.0 million (net of any amount with respect to which a reputable and solvent insurance company has acknowledged liability in writing), which judgments are not paid, discharged, stayed or fully bonded for a period of 60 days (or, if later, the date when payment is due pursuant to such judgment);
 
(7) (i) except as permitted by the indenture, any Note Guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force and effect, or (ii) any Guarantor, or any Person acting on behalf of any Guarantor, denies or disaffirms its obligations under its Note Guarantee; and
 
(8) certain events of bankruptcy or insolvency described in the indenture with respect to Mariner or any of its Restricted Subsidiaries that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.
 
In the case of an Event of Default arising from certain events of bankruptcy or insolvency, with respect to Mariner, any Restricted Subsidiary of Mariner that is a Significant Subsidiary or any group of Restricted Subsidiaries of Mariner that, taken together, would constitute a Significant Subsidiary, all then outstanding notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the trustee may and, at the direction of the holders of at least 25% in aggregate principal amount of the then outstanding notes shall, declare all of the then outstanding notes to be due and payable immediately by notice in writing to Mariner and, in case of a notice by holders, also to the trustee specifying the respective Event of Default and that it is a notice of acceleration.
 
Subject to certain limitations, holders of a majority in aggregate principal amount of the then outstanding notes may direct the trustee in its exercise of any trust or power. The trustee may withhold from holders of the notes notice of any continuing Default or Event of Default if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal, interest or premium, if any, or Special Interest, if any.
 
Subject to the provisions of the indenture relating to the duties of the trustee, in case an Event of Default occurs and is continuing, the trustee will be under no obligation to exercise any of the rights or powers under the indenture at the request or direction of any holders of notes unless such holders have offered to the trustee reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest or Special Interest, if any, when due, no holder of a note may pursue any remedy with respect to the indenture or the notes unless:
 
(1) such holder has previously given the trustee notice that an Event of Default is continuing;
 
(2) holders of at least 25% in aggregate principal amount of the then outstanding notes have requested the trustee to pursue the remedy;
 
(3) such holders have offered the trustee reasonable security or indemnity against any loss, liability or expense;
 
(4) the trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and
 
(5) holders of a majority in aggregate principal amount of the then outstanding notes have not given the trustee a direction inconsistent with such request within such 60-day period.
 
The holders of a majority in aggregate principal amount of the notes then outstanding by notice to the trustee may, on behalf of the holders of all of the notes, rescind an acceleration or waive any existing Default


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or Event of Default and its consequences under the indenture except a continuing Default or Event of Default in the payment of interest or premium or Special Interest, if any, on, or the principal of, the notes.
 
Notwithstanding the foregoing, if an Event of Default specified in clause (5) above shall have occurred and be continuing, such Event of Default and any consequential acceleration shall be automatically rescinded if (i) the Indebtedness that is the subject of such Event of Default has been repaid, or (ii) if the default relating to such Indebtedness is waived or cured and if such Indebtedness has been accelerated, then the holders thereof have rescinded their declaration of acceleration in respect of such Indebtedness.
 
Mariner is required to deliver to the trustee annually a statement regarding compliance with the indenture. Upon becoming aware of any Default or Event of Default, Mariner is required within five Business Days to deliver to the trustee a statement specifying such Default or Event of Default.
 
No Personal Liability of Directors, Officers, Employees and Stockholders
 
No director, officer, employee, incorporator or stockholder of Mariner or any Guarantor, as such, will have any liability for any obligations of Mariner or the Guarantors under the notes, the indenture, the Note Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws.
 
Legal Defeasance and Covenant Defeasance
 
Mariner may at any time, at the option of its Board of Directors evidenced by a resolution set forth in an Officers’ Certificate, elect to have all of its obligations discharged with respect to the outstanding notes and all obligations of the Guarantors discharged with respect to their Note Guarantees (“Legal Defeasance”) except for:
 
(1) the rights of holders of outstanding notes to receive payments in respect of the principal of, or interest or premium and Special Interest, if any, on, such notes when such payments are due from the trust referred to below;
 
(2) Mariner’s obligations with respect to the notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;
 
(3) the rights, powers, trusts, duties and immunities of the trustee, and Mariner’s and the Guarantors’ obligations in connection therewith;
 
(4) the optional redemption provisions of the indenture; and
 
(5) the Legal Defeasance and Covenant Defeasance provisions of the indenture.
 
In addition, Mariner may, at its option and at any time, elect to have the obligations of Mariner and the Guarantors released with respect to certain covenants (including its obligation to make Change of Control Offers and Asset Sale Offers) that are described in the indenture (“Covenant Defeasance”) and thereafter any omission to comply with those covenants will not constitute a Default or Event of Default with respect to the notes. In the event Covenant Defeasance occurs, certain events (not including non-payment, bankruptcy, receivership, rehabilitation and insolvency events) described under “— Events of Default and Remedies” will no longer constitute an Event of Default with respect to the notes. If Mariner exercises either its Legal Defeasance or Covenant Defeasance option, each Guarantor will be released and relieved of any obligations under its Note Guarantee and any security for the notes (other than the trust) will be released.
 
In order to exercise either Legal Defeasance or Covenant Defeasance:
 
(1) Mariner must irrevocably deposit with the trustee, in trust, for the benefit of the holders of the notes, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient, in the opinion of a nationally


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recognized investment bank, appraisal firm or firm of independent public accountants, to pay the principal of, or interest and premium and Special Interest, if any, on, the outstanding notes on the stated date for payment thereof or on the applicable redemption date, as the case may be, and Mariner must specify whether the notes are being defeased to such stated date for payment or to a particular redemption date;
 
(2) in the case of Legal Defeasance, Mariner must deliver to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that (a) Mariner has received from, or there has been published by, the Internal Revenue Service a ruling or (b) since the date of the indenture, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such opinion of counsel will confirm that, the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred; (3) in the case of Covenant Defeasance, Mariner must deliver to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;
 
(4) no Default or Event of Default has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit) and the deposit will not result in a breach or violation of, or constitute a default under, any Indebtedness incurred under clause (1) of Permitted Debt;
 
(5) such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the indenture) to which Mariner or any of its Subsidiaries is a party or by which Mariner or any of its Subsidiaries is bound;
 
(6) Mariner must deliver to the trustee an officers’ certificate stating that the deposit was not made by Mariner with the intent of preferring the holders of notes over the other creditors of Mariner with the intent of defeating, hindering, delaying or defrauding any creditors of Mariner or others; and
 
(7) Mariner must deliver to the trustee an officers’ certificate and an opinion of counsel, each stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance have been complied with.
 
Amendment, Supplement and Waiver
 
Except as provided in the next two succeeding paragraphs, the indenture, the notes or the Note Guarantees may be amended or supplemented with the consent of the holders of at least a majority in aggregate principal amount of the notes then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes), and any existing Default or Event of Default or compliance with any provision of the indenture or the notes or the Note Guarantees may be waived with the consent of the holders of a majority in aggregate principal amount of the then outstanding notes (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes).
 
Without the consent of each holder of notes affected, an amendment, supplement or waiver may not (with respect to any notes held by a non-consenting holder):
 
(1) reduce the principal amount of notes whose holders must consent to an amendment, supplement or waiver;
 
(2) reduce the principal of or change the fixed maturity of any note or alter the provisions with respect to the redemption of the notes (other than provisions relating to the covenants described above under the caption “— Repurchase at the Option of Holders”);


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(3) reduce the rate of or change the time for payment of interest, including default interest, on any note;
 
(4) waive a Default or Event of Default in the payment of principal of, or interest or premium, or Special Interest, if any, on, the notes (except a rescission of acceleration of the notes by the holders of at least a majority in aggregate principal amount of the then outstanding notes and a waiver of the payment default that resulted from such acceleration);
 
(5) make any note payable in money other than that stated in the notes;
 
(6) make any change in the provisions of the indenture relating to waivers of past Defaults or the rights of holders of notes to receive payments of principal of, or interest or premium or Special Interest, if any, on, the notes (other than as permitted in clause (7) below);
 
(7) waive a redemption payment with respect to any note (other than a payment required by one of the covenants described above under the caption “— Repurchase at the Option of Holders”);
 
(8) allow any Guarantor to execute a supplemental indenture and/or a Note Guarantee with respect to the notes or release any Guarantor from any of its obligations under its Note Guarantee or the indenture, except in accordance with the terms of the indenture; or
 
(9) make any change in the preceding amendment and waiver provisions.
 
Notwithstanding the preceding, without the consent of any holder of notes, Mariner, the Guarantors and the trustee may amend or supplement the indenture, the notes or the Note Guarantees:
 
(1) to cure any ambiguity, defect or inconsistency;
 
(2) to provide for uncertificated notes in addition to or in place of certificated notes;
 
(3) to provide for the assumption of Mariner’s or a Guarantor’s obligations to holders of notes and Note Guarantees in the case of a merger or consolidation or sale of all or substantially all of Mariner’s or such Guarantor’s assets, as applicable;
 
(4) to make any change that would provide any additional rights or benefits to the holders of notes or that does not adversely affect the legal rights under the indenture of any such holder;
 
(5) to comply with requirements of the SEC in order to effect or maintain the qualification of the indenture under the Trust Indenture Act;
 
(6) to conform the text of the indenture, the Note Guarantees or the notes to any provision of this Description of Senior Notes;
 
(7) to provide for the issuance of additional notes in accordance with the limitations set forth in the indenture as of the date of the indenture;
 
(8) to allow any Guarantor to execute a supplemental indenture and/or a Note Guarantee with respect to the notes or release Note Guarantees pursuant to the terms of the indenture;
 
(9) to secure the notes; or
 
(10) to evidence and provide for the acceptance under the indenture of a successor trustee.
 
The consent of the holders is not necessary under the indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment. After an amendment under the indenture becomes effective, Mariner is required to mail to the holders a notice briefly describing such amendment. However, the failure to give such notice to all the holders, or any defect in the notice, will not impair or affect the validity of the amendment.


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Satisfaction and Discharge
 
The indenture will be discharged and will cease to be of further effect as to all notes issued thereunder, when:
 
(1) either:
 
(a) all notes that have been authenticated, except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has been deposited in trust and thereafter repaid to Mariner, have been delivered to the trustee for cancellation; or
 
(b) all notes that have not been delivered to the trustee for cancellation have become due and payable by reason of the mailing of a notice of redemption or otherwise or will become due and payable within one year, and Mariner or any Guarantor has irrevocably deposited or caused to be deposited with the trustee as trust funds in trust solely for the benefit of the holders, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and noncallable Government Securities, in amounts as will be sufficient, without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness on the notes not delivered to the trustee for cancellation for principal, premium and Special Interest, if any, and accrued interest to the date of maturity or redemption;
 
(2) no Default or Event of Default has occurred and is continuing on the date of the deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit) and the deposit will not result in a breach or violation of, or constitute a default under, any other instrument to which Mariner or any Guarantor is a party or by which Mariner or any Guarantor is bound;
 
(3) Mariner or any Guarantor has paid or caused to be paid all sums payable by it under the indenture; and
 
(4) Mariner has delivered irrevocable instructions to the trustee under the indenture to apply the deposited money toward the payment of the notes at maturity or on the redemption date, as the case may be.
 
In addition, Mariner must deliver an officers’ certificate and an opinion of counsel to the trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.
 
Concerning the Trustee
 
If the trustee becomes a creditor of Mariner or any Guarantor, the indenture limits the right of the trustee to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest (as defined in the Trust Indenture Act) after a Default has occurred and is continuing, it must eliminate such conflict within 90 days, apply to the SEC for permission to continue as trustee (if the indenture has been qualified under the Trust Indenture Act) or resign.
 
The holders of a majority in aggregate principal amount of the then outstanding notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee, subject to certain exceptions. The indenture provides that in case an Event of Default occurs and is continuing, the trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the trustee will be under no obligation to exercise any of its rights or powers under the indenture at the request of any holder of notes, unless such holder has offered to the trustee security and indemnity satisfactory to it against any loss, liability or expense.
 
Additional Information
 
Anyone who receives this prospectus may obtain a copy of the indenture and registration rights agreement without charge by writing to Mariner Energy, Inc., One Briar Lake Plaza, Suite 2000, 2000 West Sam Houston Parkway South, Houston, Texas 77042.


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Book-Entry; Delivery and Form
 
Except as set forth below, new notes will be issued in registered, global form (“global notes”).
 
The global notes will be deposited upon issuance with the trustee as custodian for The Depository Trust Company (”DTC”), in New York, New York, and registered in the name of DTC or its nominee, in each case, for credit to an account of a direct or indirect participant in DTC as described below.
 
Except as set forth below, the global notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the global notes may not be exchanged for definitive notes in registered certificated form (”certificated notes”) except in the limited circumstances described below. See ” — Exchange of Global Notes for Certificated Notes.” Except in the limited circumstances described below, owners of beneficial interests in the global notes will not be entitled to receive physical delivery of notes in certificated form.
 
Transfers of beneficial interests in the global notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time.
 
Depository Procedures
 
The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. Mariner takes no responsibility for these operations and procedures and urges investors to contact the system or their participants directly to discuss these matters.
 
DTC has advised Mariner that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the ”Participants”) and to facilitate the clearance and settlement of transactions in those securities between the Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the ”Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.
 
Investors in the global notes who are Participants may hold their interests therein directly through DTC. Investors in the global notes who are not Participants may hold their interests therein indirectly through organizations (including Euroclear and Clearstream) which are Participants. Euroclear and Clearstream will hold interests in the global notes on behalf of their participants through customers’ securities accounts in their respective names on the books of their respective depositories, which are Euroclear Bank S.A./N.V, as operator of Euroclear, and Citibank, N.A., as operator of Clearstream. All interests in a global note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of such systems. The laws of some states require that certain persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a global note to such persons will be limited to that extent. Because DTC can act only on behalf of the Participants, which in turn act on behalf of the Indirect Participants, the ability of a person having beneficial interests in a global note to pledge such interests to persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.


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Except as described below, owners of interests in the global notes will not have notes registered in their names, will not receive physical delivery of notes in certificated form and will not be considered the registered owners or ”Holders” thereof under the Indenture for any purpose.
 
Payments in respect of the principal of, and interest and premium, if any, and Special Interest, if any, on a global note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the Indenture. Under the terms of the Indenture, Mariner, the subsidiary guarantors of the notes and the Trustee will treat the persons in whose names the notes, including the global notes, are registered as the owners of the notes for the purpose of receiving payments and for all other purposes. Consequently, neither Mariner, the subsidiary guarantors of the notes, the trustee nor any agent of Mariner, the subsidiary guarantors of the notes or the trustee has or will have any responsibility or liability for:
 
(1) any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interest in the global notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the global notes; or
 
(2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.
 
DTC has advised Mariner that its current practice, upon receipt of any payment in respect of securities such as the notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe that it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the trustee or Mariner. Neither Mariner nor the trustee will be liable for any delay by DTC or any of the Participants or the Indirect Participants in identifying the beneficial owners of the notes, and we and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.
 
Transfers between the Participants will be effected in accordance with DTC’s procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.
 
Cross-market transfers between the Participants, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by their respective depositaries; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant global note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.
 
DTC has advised Mariner that it will take any action permitted to be taken by a holder of notes only at the direction of one or more Participants to whose account DTC has credited the interests in the global notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the global notes for legended notes in certificated form, and to distribute such notes to its Participants.
 
Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures to facilitate transfers of interests in global notes among participants in DTC, Euroclear and Clearstream, they are under no


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obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time. None of Mariner, the trustee and any of their respective agents will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.
 
Exchange of Global Notes for Certificated Notes
 
A global note is exchangeable for certificated notes if:
 
(1) DTC (a) notifies Mariner that it is unwilling or unable to continue as depositary for the global notes or (b) has ceased to be a clearing agency registered under the Exchange Act and, in either case, Mariner fails to appoint a successor depositary;
 
(2) Mariner, at its option, notifies the trustee in writing that it elects to cause the issuance of the certificated notes; or
 
(3) there has occurred and is continuing a Default or Event of Default with respect to the notes.
 
In addition, beneficial interests in a global note may be exchanged for certificated notes upon prior written notice given to the trustee by or on behalf of DTC in accordance with the indenture. In all cases, certificated notes delivered in exchange for any global note or beneficial interests in global notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures).
 
Same Day Settlement and Payment
 
Mariner will make payments in respect of the notes represented by the global notes (including principal, premium, if any, interest and Special Interest, if any) by wire transfer of immediately available funds to the accounts specified by DTC or its nominee. Mariner will make all payments of principal, interest and premium, if any, and Special Interest, if any, with respect to certificated notes by wire transfer of immediately available funds to the accounts specified by the holders of the certificated notes or, if no such account is specified, by mailing a check to each such holder’s registered address. The notes represented by the global notes are expected to be eligible to trade in PORTALsm and to trade in DTC’s Same-Day Funds Settlement System, and any permitted secondary market trading activity in such notes will, therefore, be required by DTC to be settled in immediately available funds. Mariner expects that secondary trading in any certificated notes will also be settled in immediately available funds.
 
Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a global note from a Participant will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised us that cash received in Euroclear or Clearstream as a result of sales of interests in a global note by or through a Euroclear or Clearstream participant to a Participant will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC’s settlement date.
 
Certain Definitions
 
Set forth below are certain defined terms used in the indenture. Reference is made to the indenture for a full disclosure of all defined terms used therein, as well as any other capitalized terms used herein for which no definition is provided.
 
“Acquired Debt” means, with respect to any specified Person:
 
(1) Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Subsidiary of such specified Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Restricted Subsidiary


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of, such specified Person, but excluding Indebtedness which is extinguished, retired or repaid in connection with such Person merging with or becoming a Subsidiary of such specified Person; and
 
(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.
 
“Additional Assets” means:
 
(1) any assets used or useful in the Oil and Gas Business, other than Indebtedness or Capital Stock;
 
(2) the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by Mariner or any of its Restricted Subsidiaries; or
 
(3) Capital Stock constituting a minority interest in any Person that at such time is a Restricted Subsidiary;
 
provided, however, that any such Restricted Subsidiary described in clause (2) or (3) is primarily engaged in the Oil and Gas Business.
 
“Adjusted Consolidated Net Tangible Assets” means (without duplication), as of the date of determination:
 
(1) the sum of:
 
(a) discounted future net revenue from proved crude oil and natural gas reserves of Mariner and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated in a reserve report prepared as of the end of the fiscal year ending at least 91 days prior to the date of determination (or for the period prior to the earlier of April 1, 2006 and the date of the reserve report for 2006 is available, as of June 30, 2005), which reserve report is prepared or audited by independent petroleum engineers as increased by, as of the date of determination, the discounted future net revenue of:
 
(i) estimated proved crude oil and natural gas reserves of Mariner and its Restricted Subsidiaries attributable to acquisitions consummated since the date of such reserve report, and
 
(ii) estimated crude oil and natural gas reserves of Mariner and its Restricted Subsidiaries attributable to extensions, discoveries and other additions and upward determinations of estimates of proved crude oil and natural gas reserves (including previously estimated development costs incurred during the period and the accretion of discount since the prior period end) due to exploration, development or exploitation, production or other activities which reserves were not reflected in such reserve report which would, in accordance with standard industry practice, result in such determinations, in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report), and decreased by, as of the date of determination, the discounted future net revenue attributable to:
 
(iii) estimated proved crude oil and natural gas reserves of Mariner and its Restricted Subsidiaries reflected in such reserve report produced or disposed of since the date of such reserve report, and
 
(iv) reductions in the estimated oil and natural gas reserves of Mariner and its Restricted Subsidiaries reflected in such reserve report since the date of such reserve report attributable to downward determinations of estimates of proved crude oil and natural gas reserves due to exploration, development or exploitation, production or other activities conducted or otherwise occurring since the date of such reserve report which would, in accordance with standard industry practice, result in such determinations, in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such reserve report);
 
provided, however, that, in the case of each of the determinations made pursuant to clauses (i) through (iv), such increases and decreases shall be estimated by Mariner’s engineers, except that if as a result of such acquisitions, dispositions, discoveries, extensions or revisions, there is a Material


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Change, then such increases and decreases in the discounted future net revenue shall be confirmed in writing by an independent petroleum engineer;
 
(b) the capitalized costs that are attributable to crude oil and natural gas properties of Mariner and its Restricted Subsidiaries to which no proved crude oil and natural gas reserves are attributable, based on Mariner’s books and records as of a date no earlier than the date of Mariner’s latest available annual or quarterly financial statements;
 
(c) the Net Working Capital (excluding, to the extent included in the determination of discounted future net revenues under clause (1)(a) above, any adjustments made pursuant to FAS 143) as of a date no earlier than the date of Mariner’s latest available annual or quarterly financial statements; and
 
(d) the greater of (i) the net book value as of a date no earlier than the date of Mariner’s latest available annual or quarterly financial statements and (ii) the appraised value, as estimated by independent appraisers, of other tangible assets of Mariner and its Restricted Subsidiaries as of a date no earlier than the date of Mariner’s latest available annual or quarterly financial statements (provided that Mariner shall not be required to obtain such an appraisal of such assets if no such appraisal has been performed); minus
 
(2) the sum of:
 
(a) Minority Interests;
 
(b) any net natural gas balancing liabilities of Mariner and its Restricted Subsidiaries reflected in Mariner’s latest audited financial statements;
 
(c) to the extent included in clause (1)(a) above, the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices in Mariner’s year-end reserve report), attributable to reserves subject to participation interests, overriding royalty interests or other interests of third parties, pursuant to participation, partnership, vendor financing or other agreements then in effect, or which otherwise are required to be delivered to third parties;
 
(d) to the extent included in clause (1)(a) above, the discounted future net revenue calculated in accordance with SEC guidelines (utilizing the same prices utilized in Mariner’s year-end reserve report), attributable to reserves that are required to be delivered to third parties to fully satisfy the obligations of Mariner and its Restricted Subsidiaries with respect to Volumetric Production Payments on the schedules specified with respect thereto; and
 
(e) the discounted future net revenue, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments that, based on the estimates of production included in determining the discounted future net revenue specified in the immediately preceding clause (i)(a) (utilizing the same prices utilized in Mariner’s year-end reserve report), would be necessary to satisfy fully the obligations of Mariner and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments on the schedules specified with respect thereto.
 
If Mariner changes its method of accounting from the full cost method to the successful efforts method or a similar method of accounting, “Adjusted Consolidated Net Tangible Assets” will continue to be calculated as if Mariner were still using the full cost method of accounting.
 
“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control,” as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” have correlative meanings.


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“Asset Sale” means:
 
(1) the sale, lease, conveyance or other disposition of any assets or rights (including by way of a Production Payment or a sale and leaseback transaction); provided that the sale, lease, conveyance or other disposition of all or substantially all of the assets of Mariner and its Restricted Subsidiaries taken as a whole will be governed by the provisions of the indenture described above under the caption “— Repurchase at the Option of Holders — Change of Control” and/or the provisions described above under the caption “— Certain Covenants — Merger, Consolidation or Sale of Assets” and not by the provisions of the Asset Sale covenant; and
 
(2) the issuance of Equity Interests in any of Mariner’s Restricted Subsidiaries or the sale of Equity Interests held by Mariner or its Subsidiaries in any of its Subsidiaries.
 
Notwithstanding the preceding, none of the following items will be deemed to be an Asset Sale:
 
(1) any single transaction or series of related transactions that involves assets having a Fair Market Value of less than $5.0 million;
 
(2) a transfer of assets between or among Mariner and its Restricted Subsidiaries;
 
(3) an issuance of Equity Interests by a Restricted Subsidiary of Mariner to Mariner or to a Restricted Subsidiary of Mariner;
 
(4) the sale or lease of products, services or accounts receivable in the ordinary course of business and any sale or other disposition of damaged, worn-out or obsolete assets in the ordinary course of business;
 
(5) the sale or other disposition of cash or Cash Equivalents;
 
(6) a Restricted Payment that does not violate the covenant described above under the caption “— Certain Covenants — Restricted Payments;”
 
(7) a Permitted Investment, including, without limitation, unwinding Hedging Obligations;
 
(8) a disposition of Hydrocarbons or mineral products inventory in the ordinary course of business;
 
(9) the sale or transfer (whether or not in the ordinary course of business) of crude oil and natural gas properties or direct or indirect interests in real property; provided, that at the time of such sale or transfer such properties do not have associated with them any proved reserves;
 
(10) the farm-out, lease or sublease of developed or undeveloped crude oil or natural gas properties owned or held by Mariner or such Restricted Subsidiary in exchange for crude oil and natural gas properties owned or held by another Person;
 
(11) any trade or exchange by Mariner or any Restricted Subsidiaries of oil and gas properties or other properties or assets for oil and gas properties or other properties or assets owned or held by another Person, provided that the fair market value of the properties or assets traded or exchanged by Mariner or such Restricted Subsidiary (together with any cash) is reasonably equivalent to the fair market value of the properties or assets (together with any cash) to be received by Mariner or such Restricted Subsidiary, and provided further that any net cash received must be applied in accordance with the provisions described above under the caption “— Repurchase at the Option of Holders — Asset Sales;”
 
(12) the creation or perfection of a Lien (but not, except to the extent contemplated in clause (13) below, the sale or other disposition of the properties or assets subject to such Lien);
 
(13) the creation or perfection of a Permitted Lien and the exercise by any Person in whose favor a Permitted Lien is granted of any of its rights in respect of that Permitted Lien;
 
(14) the licensing or sublicensing of intellectual property, including, without limitation, licenses for seismic data, in the ordinary course of business and which do not materially interfere with the business of Mariner and its Restricted Subsidiaries; and


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(15) a surrender or waiver of contract rights or the settlement, release or surrender of contract, tort or other claims of any kind.
 
“Attributable Debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP.
 
“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only after the passage of time. The terms
 
“Beneficial Ownership”, “Beneficially Owns” and “Beneficially Owned” have a corresponding meaning.
 
“Board of Directors” means:
 
(1) with respect to a corporation, the board of directors of the corporation or any committee thereof duly authorized to act on behalf of such board;
 
(2) with respect to a partnership, the Board of Directors of the general partner of the partnership;
 
(3) with respect to a limited liability company, the managing member or members or any controlling committee of managing members thereof; and
 
(4) with respect to any other Person, the board or committee of such Person serving a similar function.
 
“Business Day” means each day that is not a Saturday, Sunday or other day on which banking institutions in New York, New York or another place of payment are authorized or required by law to close.
 
“Capital Lease Obligation” means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet prepared in accordance with GAAP, and the Stated Maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be prepaid by the lessee without payment of a penalty.
 
Capital Stock” means:
 
(1) in the case of a corporation, corporate stock;
 
(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;
 
(3) in the case of a partnership or limited liability company, partnership interests (whether general or limited) or membership interests; and
 
(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person, but excluding from all of the foregoing any debt securities convertible into Capital Stock, whether or not such debt securities include any right of participation with Capital Stock.
 
“Cash Equivalents” means:
 
(1) United States dollars;
 
(2) securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality of the United States government (provided that the full faith and credit of the United States is pledged in support of those securities) having maturities of not more than one year from the date of acquisition;


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(3) marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition thereof and, at the time of acquisition thereof, having a credit rating of “A” or better from either S&P or Moody’s;
 
(4) certificates of deposit, demand deposit accounts and eurodollar time deposits with maturities of one year or less from the date of acquisition, bankers’ acceptances with maturities not exceeding one year and overnight bank deposits, in each case, with any domestic commercial bank having capital and surplus in excess of $500.0 million and a Thomson Bank Watch Rating of “B” or better;
 
(5) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2), (3) and (4) above entered into with any financial institution meeting the qualifications specified in clause (4) above;
 
(6) commercial paper having one of the two highest ratings obtainable from Moody’s or S&P and, in each case, maturing within six months after the date of acquisition; and
 
(7) money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (6) of this definition.
 
“Change of Control” means the occurrence of any of the following:
 
(1) the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of Mariner and its Subsidiaries taken as a whole to any “person” (as that term is used in Section 13(d) of the Exchange Act);
 
(2) the adoption of a plan relating to the liquidation or dissolution of Mariner;
 
(3) the consummation of any transaction (including, without limitation, any merger or consolidation), the result of which is that any “person” (as defined above) becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of Mariner, measured by voting power rather than number of shares; or
 
(4) during any period of two consecutive years, Continuing Directors cease to constitute a majority of the Board of Directors of Mariner.
 
“Change of Control Triggering Event” means the occurrence of both a Change of Control and a Rating Decline with respect to the notes.
 
“Consolidated Cash Flow” means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period plus, without duplication:
 
(1) an amount equal to any extraordinary loss plus any net loss realized by such Person or any of its Restricted Subsidiaries in connection with an Asset Sale (together with any related provision for taxes and any related non-recurring charges relating to any premium or penalty paid, write-off of deferred financing costs or other financial recapitalization charges in connection with redeeming or retiring any Indebtedness prior to its Stated Maturity), to the extent such losses were deducted in computing such Consolidated Net Income; plus
 
(2) provision for taxes based on income or profits of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was deducted in computing such Consolidated Net Income; plus
 
(3) the Fixed Charges of such Person and its Restricted Subsidiaries for such period, to the extent that such Fixed Charges were deducted in computing such Consolidated Net Income; plus
 
(4) depreciation, depletion, amortization (including amortization of intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period), impairment and other non-cash expenses (excluding any such non-cash expense to the extent that it represents an accrual of or reserve for


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cash expenses in any future period or amortization of a prepaid cash expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, depletion, amortization, impairment and other non-cash expenses were deducted in computing such Consolidated Net Income; minus
 
(5) non-cash items increasing such Consolidated Net Income for such period, other than items that were accrued in the ordinary course of business, and minus
 
(6) the sum of (a) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments and (b) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments, in each case, on a consolidated basis and determined in accordance with GAAP.
 
Notwithstanding the foregoing, the provision for taxes on the income or profits of, and the depreciation, depletion and amortization and other non-cash charges and expenses of, a Restricted Subsidiary of the referent Person shall be added to Consolidated Net Income to compute Consolidated Cash Flow only to the extent (and in the same proportion) that the Net Income of such Restricted Subsidiary was included in calculating the Consolidated Net Income of such Person and only if a corresponding amount would be permitted at the date of determination to be dividended to the referent Person by such Restricted Subsidiary without prior governmental approval (that has not been obtained), and without direct or indirect restriction pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to that Restricted Subsidiary or its stockholders.
 
“Consolidated Net Income” means, with respect to any specified Person for any period, the aggregate of the Net Income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP; provided that:
 
(1) the Net Income (but not loss) of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting will be included only to the extent of the amount of dividends or similar distributions paid in cash to the specified Person or a Restricted Subsidiary of the Person;
 
(2) the Net Income of any Restricted Subsidiary will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that Net Income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders;
 
(3) the cumulative effect of a change in accounting principles will be excluded;
 
(4) income resulting from transfers of assets (other than cash) between such Person or any of its Restricted Subsidiaries, on the one hand, and an Unrestricted Subsidiary, on the other hand, will be excluded;
 
(5) any gain (loss) realized upon the sale or other disposition of any property, plant or equipment of such Person or its consolidated Restricted Subsidiaries (including pursuant to any sale or leaseback transaction) which is not sold or otherwise disposed of in the ordinary course of business and any gain (loss) realized upon the sale or other disposition of any Capital Stock of any Person will be excluded;
 
(6) any asset impairment writedowns on Oil and Gas Properties under GAAP or SEC guidelines will be excluded;
 
(7) any unrealized non-cash gains or losses or charges in respect of hedge or non-hedge derivatives (including those resulting from the application of FAS 133) will be excluded; and
 
(8) to the extent deducted in the calculation of Net Income, any non-cash or nonrecurring charges associated with any premium or penalty paid, write-off of deferred financing costs or other financial


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recapitalization charges in connection with redeeming or retiring any Indebtedness prior to its Stated Maturity will be excluded; and
 
(9) items classified as extraordinary or nonrecurring gains and losses (less all fees and expenses related thereto) or expenses (including without limitation, severance, relocation, other restructuring costs and expense arising from the transactions closing contemporaneously with the offering of the old notes), and the related tax effects according to GAAP, shall be excluded.
 
“Consolidated Net Worth” means, with respect to any specified Person as of any date, the sum of:
 
(1) the consolidated equity of the common stockholders of such Person and its consolidated Subsidiaries as of such date; plus
 
(2) the respective amounts reported on such Person’s balance sheet as of such date with respect to any series of preferred stock (other than Disqualified Stock) that by its terms is not entitled to the payment of dividends unless such dividends may be declared and paid only out of net earnings in respect of the year of such declaration and payment, but only to the extent of any cash received by such Person upon issuance of such preferred stock.
 
“Continuing Directors” means, as of any date of determination, any member of the Board of Directors of Mariner who:
 
(1) was a member of such Board of Directors on the Issue Date; or
 
(2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board of Directors at the time of such nomination or election.
 
“Credit Agreement” means that certain Amended and Restated Credit Agreement, dated as of March 2, 2006 by and among Mariner and Mariner Energy Resources, Inc., as borrowers, Union Bank of California, N.A., as administrative agent and issuing lender, BNP Paribas, as syndication agent, and the lenders from time to time party thereto, providing for up to $540 million of revolving credit and term loan borrowings and letters of credit, including any related notes, Guarantees, collateral documents, instruments and agreements executed in connection therewith, and, in each case, as amended, restated, modified, renewed, refunded, replaced (whether upon or after termination or otherwise), supplemented or refinanced (including by means of sales of debt securities to institutional investors) in whole or in part from time to time.
 
“Credit Facilities” means, with respect to Mariner or any of its Restricted Subsidiaries, one or more debt facilities (including, without limitation, the Credit Agreement), commercial paper facilities or Debt Issuances with banks, investment banks, insurance companies, mutual funds, other institutional lenders, institutional investors or any of the foregoing providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders, other financiers or to special purpose entities formed to borrow from (or sell such receivables to) such lenders or other financiers against such receivables), letters of credit, bankers’ acceptances, other borrowings or Debt Issuances, in each case, as amended, restated, modified, renewed, extended, refunded, replaced or refinanced (in each case, without limitation as to amount), in whole or in part, from time to time (including through one or more Debt Issuances) and any agreements and related documents governing Indebtedness or Obligations incurred to refinance amounts then outstanding or permitted to be outstanding, whether or not with the original administrative agent, lenders, investment banks, insurance companies, mutual funds, other institutional lenders, institutional investors or any of the foregoing and whether provided under the original agreement, indenture or other documentation relating thereto).
 
“Debt Issuances” means, with respect to Mariner or any Restricted Subsidiary, one or more issuances after the Issue Date of Indebtedness evidenced by notes, debentures, bonds or other similar securities or instruments.
 
“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.


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“De Minimis Guaranteed Amount” means a principal amount of Indebtedness that does not exceed $5.0 million.
 
“Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case, at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the notes mature; provided, that only the portion of Capital Stock which so matures or is mandatorily redeemable, or is so redeemable at the option of the holder thereof prior to such date, will be deemed to be Disqualified Stock. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require Mariner to repurchase such Capital Stock upon the occurrence of a change of control or an asset sale will not constitute Disqualified Stock if the terms of such Capital Stock provide that Mariner may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption “— Certain Covenants — Restricted Payments.” The amount of Disqualified Stock deemed to be outstanding at any time for purposes of the indenture will be the maximum amount that Mariner and its Restricted Subsidiaries may become obligated to pay upon the maturity of, or pursuant to any mandatory redemption provisions of, such Disqualified Stock, exclusive of accrued dividends.
 
“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.
 
“Domestic Subsidiary” means any Restricted Subsidiary of Mariner that was formed under the laws of the United States or any state of the United States or the District of Columbia or that guarantees or otherwise provides direct credit support for any Indebtedness of Mariner.
 
“Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).
 
“Equity Offering” means any public or private sale of Capital Stock (other than Disqualified Stock) by Mariner after the Issue Date.
 
“Existing Indebtedness” means Indebtedness of Mariner and its Subsidiaries (other than Indebtedness under the Credit Agreement) in existence on the date of the indenture, until such amounts are repaid.
 
“Fair Market Value” means the value that would be paid by a willing buyer to an unaffiliated willing seller in a transaction not involving distress or necessity of either party, determined in good faith by the Board of Directors of Mariner (unless otherwise provided in the indenture), which determination will be conclusive for all purposes under the indenture.
 
“Fixed Charge Coverage Ratio” means with respect to any specified Person for any period, the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, guarantees, repays, repurchases, redeems, defeases or otherwise discharges any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems preferred stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such incurrence, assumption, Guarantee, repayment, repurchase, redemption, defeasance or other discharge of Indebtedness, or such issuance, repurchase or redemption of preferred stock, and the use of the proceeds therefrom, as if the same had occurred at the beginning of the applicable four-quarter reference period.
 
In addition, for purposes of calculating the Fixed Charge Coverage Ratio:
 
(1) acquisitions that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers, consolidations or otherwise (including acquisitions of assets used or useful in the Oil and Gas Business), or any Person or any of its Restricted Subsidiaries acquired by the specified


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Person or any of its Restricted Subsidiaries, and including any related financing transactions and including increases in ownership of Restricted Subsidiaries, during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date, shall be deemed to have occurred on the first day of the four-quarter reference period and the Consolidated Cash Flow for such reference period will be calculated giving pro forma effect to any expense and cost reductions that have occurred or, in the reasonable judgment of the chief financial officer of Mariner, are reasonably expected to occur (regardless of whether those operating improvements or cost savings could then be reflected in pro forma financial statements prepared in accordance with Regulation S-X under the Securities Act or any other regulation or policy of the SEC related thereto);
 
(2) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded;
 
(3) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date;
 
(4) any Person that is a Restricted Subsidiary on the Calculation Date will be deemed to have been a Restricted Subsidiary at all times during such four-quarter period;
 
(5) any Person that is not a Restricted Subsidiary on the Calculation Date will be deemed not to have been a Restricted Subsidiary at any time during such four-quarter period; and
 
(6) if any Indebtedness bears a floating rate of interest, the interest expense on such Indebtedness will be calculated as if the rate in effect on the Calculation Date had been the applicable rate for the entire period (taking into account any Hedging Obligation applicable to such Indebtedness if such Hedging Obligation has a remaining term as at the Calculation Date in excess of 12 months).
 
“Fixed Charges” means, with respect to any specified Person for any period, the sum, without duplication, of:
 
(1) the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued (excluding any interest attributable to Dollar-Denominated Production Payments but including, without limitation, amortization of debt issuance costs and original issue discount, noncash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings), and net of the effect of all payments made or received pursuant to Hedging Obligations in respect of interest rates; plus (2) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period; plus (3) any interest on Indebtedness of another Person that is guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries, whether or not such Guarantee or Lien is called upon; plus (4) all dividends, whether paid or accrued and whether or not in cash, on any series of preferred stock of such Person or any of its Restricted Subsidiaries, other than dividends on Equity Interests payable solely in Equity Interests of Mariner (other than Disqualified Stock) or to Mariner or a Restricted Subsidiary of Mariner.
 
“GAAP” means generally accepted accounting principles set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as have been approved by a significant segment of the accounting profession, which are in effect from time to time. All ratios and computations based on GAAP contained in the indenture will be computed in conformity with GAAP.


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“Guarantee” means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to maintain financial statement conditions or otherwise), or entered into for purposes of assuring in any other manner the obligee of such Indebtedness of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part).
 
“Guarantors” means each of:
 
(1) Mariner LP LLC, Mariner Energy Resources, Inc. and Mariner Energy Texas LP; and
 
(2) any other Subsidiary of Mariner that executes a Note Guarantee in accordance with the provisions of the indenture, and their respective successors and assigns, in each case, until the Note Guarantee of such Person has been released in accordance with the provisions of the indenture.
 
“Hedging Obligations” means, with respect to any specified Person, the obligations of such Person under:
 
(1) interest rate swap agreements (whether from fixed to floating or from floating to fixed), interest rate cap agreements and interest rate collar agreements entered into with one or more financial institutions and other arrangements or agreements designed to protect the Person entering into the agreement against fluctuations in interest rates with respect to Indebtedness incurred and not for purposes of speculation;
 
(2) foreign exchange contracts and currency protection agreements entered into with one or more financial institutions and designed to protect the Person entering into the agreement against fluctuations in currency exchange rates with respect to Indebtedness incurred and not for purposes of speculation;
 
(3) any commodity futures contract, commodity option or other similar agreement or arrangement designed to protect against fluctuations in the price of commodities used, produced, processed or sold by that Person or any of its Restricted Subsidiaries at the time; and
 
(4) other agreements or arrangements designed to protect such Person against fluctuations in interest rates, commodity prices or currency exchange rates.
 
“Hydrocarbons” means oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.
 
“Indebtedness” means, with respect to any specified Person, any indebtedness of such Person (excluding accrued expenses and trade payables), whether or not contingent:
 
(1) in respect of borrowed money;
 
(2) evidenced by bonds, notes, debentures or similar instruments or letters of credit (or reimbursement agreements in respect thereof);
 
(3) in respect of banker’s acceptances;
 
(4) representing Capital Lease Obligations or Attributable Debt in respect of sale and leaseback transactions;
 
(5) representing the balance deferred and unpaid of the purchase price of any property due more than nine months after such property is acquired;
 
(6) the principal component or liquidation preference of all obligations of such Person with respect to the redemption, repayment or other repurchase of any Disqualified Stock or, with respect to any Subsidiary, any Preferred Stock (but excluding, in each case, any accrued dividends);
 
(7) representing any Hedging Obligations;


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(8) the principal component of all Indebtedness of other Persons secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person; provided, however, that the amount of such Indebtedness will be the lesser of (a) the Fair Market Value of such asset at such date of determination and (b) the amount of such Indebtedness of such other Persons;
 
(9) the principal component of Indebtedness of other Persons to the extent Guaranteed by such Person (including, with respect to any Production Payment, any warranties or guarantees of production or payment by such Person with respect to such Production Payment, but excluding other contractual obligations of such Person with respect to such Production Payment);
 
provided that the indebtedness described in clauses (1), (2), (4) and (5) shall be included in this definition of Indebtedness only if, and to the extent that, the indebtedness described in such clauses would appear as a liability upon a balance sheet of such Person prepared in accordance with GAAP. Subject to clause (9) of the preceding sentence, neither Dollar-Denominated Production Payments nor Volumetric Production Payments shall be deemed to be Indebtedness.
 
The amount of any Indebtedness outstanding as of any date will be:
 
(1) the accreted value of the Indebtedness, in the case of any Indebtedness issued with original issue discount;
 
(2) in the case of any Hedging Obligation, the termination value of the agreement or arrangement giving rise to such Hedging Obligation that would be payable by such Person at such date; and
 
(3) the principal amount of the Indebtedness, together with any interest on the Indebtedness that is more than 30 days past due, in the case of any other Indebtedness.
 
The amount of Indebtedness of any Person at any date will be the outstanding balance at such date of all unconditional obligations as described above and the maximum liability, upon the occurrence of the contingency giving rise to the obligation, of any contingent obligations at such date.
 
In addition, “Indebtedness” of any Person shall include Indebtedness described in the preceding paragraph that would not appear as a liability on the balance sheet of such Person if:
 
(1) such Indebtedness is the obligation of a partnership or joint venture that is not a Restricted Subsidiary (a “Joint Venture”);
 
(2) such Person or a Restricted Subsidiary of such Person is a general partner of the Joint Venture (a “General Partner”); and
 
(3) there is recourse, by contract or operation of law, with respect to the payment of such Indebtedness to property or assets by such Person or a Restricted Subsidiary of such Person; and then such Indebtedness shall be included in an amount not to exceed:
 
(a) the lesser of (i) the net assets of the General Partner and (ii) the amount of such obligations to the extent that there is recourse, by contract or operation of law, to the property or assets of such Person or a Restricted Subsidiary of such Person; or
 
(b) if less than the amount determined pursuant to clause (a) immediately above, the actual amount of such Indebtedness that is recourse to such Person or a Restricted Subsidiary of such Person, if the Indebtedness is evidenced by a writing and is for a determinable amount and the related interest expense shall be included in Fixed Charges to the extent actually paid by such Person or its Restricted Subsidiaries.
 
“Investment Grade Rating” means a rating equal to or higher than:
 
(1) Baa3 (or the equivalent) by Moody’s; or
 
(2) BBB- (or the equivalent) by S&P, or, if either such entity ceases to rate the notes for reasons outside of Mariner’s control, the equivalent investment grade credit rating from any other Rating Agency.


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“Investment Grade Rating Event” means the first day on which the notes have an Investment Grade Rating from a Rating Agency and no Default has occurred and is then continuing under the indenture.
 
“Investment Grade Securities” means:
 
(1) securities issued or directly and fully guaranteed or insured by the U.S. government or any agency or instrumentality thereof (other than Cash Equivalents) and in each case with maturities not exceeding tow years from the date of acquisition;
 
(2) investments in any fund that invests exclusively in investments of the type described in clause (1) which fund may also hold immaterial amounts of cash pending investment and/or distribution; and
 
(3) corresponding instruments in countries other than the United States customarily utilized for high quality investments and in each case with maturities not exceeding two years from the date of acquisition.
 
“Investments” means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including Guarantees or other obligations, advances or capital contributions (excluding endorsements of negotiable instruments and documents in the ordinary course of business, and commission, travel and similar advances to officers, employees and consultants made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If Mariner or any Restricted Subsidiary of Mariner sells or otherwise disposes of any Equity Interests of any direct or indirect Subsidiary of Mariner such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary of Mariner, Mariner will be deemed to have made an Investment on the date of any such sale or disposition equal to the Fair Market Value of Mariner’s Investments in such Restricted Subsidiary that were not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption “— Certain Covenants — Restricted Payments.” The acquisition by Mariner or any Subsidiary of Mariner of a Person that holds an Investment in a third Person will be deemed to be an Investment by Mariner or such Subsidiary in such third Person in an amount equal to the Fair Market Value of the Investments held by the acquired Person in such third Person in an amount determined as provided in the final paragraph of the covenant described above under the caption “— Certain Covenants — Restricted Payments.” Except as otherwise provided in the indenture, the amount of an Investment will be determined at the time the Investment is made and without giving effect to subsequent changes in value.
 
“Issue Date” means the date of original issuance of the notes.
 
“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction.
 
“Material Change” means an increase or decrease (excluding changes that result solely from changes in prices and changes resulting from the incurrence of previously estimated future development costs) of more than 25% during a fiscal quarter in the discounted future net revenues from proved crude oil and natural gas reserves of Mariner and its Restricted Subsidiaries, calculated in accordance with clause (1)(a) of the definition of Adjusted Consolidated Net Tangible Assets; provided, however, that the following will be excluded from the calculation of Material Change:
 
(1) any acquisitions during the fiscal quarter of oil and gas reserves that have been estimated by independent petroleum engineers and with respect to which a report or reports of such engineers exist; and
 
(2) any disposition of properties existing at the beginning of such fiscal quarter that have been disposed of in compliance with the covenant described under “— Repurchase at the Option of Holders — Assets Sales.”


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“Minority Interest” means the percentage interest represented by any shares of stock of any class of Capital Stock of a Restricted Subsidiary of Mariner that are not owned by Mariner or a Restricted Subsidiary of Mariner.
 
“Moody’s” means Moody’s Investors Service, Inc. or any successor to the rating agency business thereof.
 
“Net Income” means, with respect to any specified Person, the net income (loss) of such Person, determined in accordance with GAAP and before any reduction in respect of preferred stock dividends, excluding, however:
 
(1) any gain (but not loss), together with any related provision for taxes on such gain (but not loss), realized in connection with: (a) any Asset Sale; or (b) the disposition of any securities by such Person or any of its Restricted Subsidiaries or the extinguishment of any Indebtedness of such Person or any of its Restricted Subsidiaries; and
 
(2) any extraordinary or nonrecurring gain (but not loss), together with any related provision for taxes on such extraordinary or nonrecurring gain (but not loss).
 
“Net Proceeds” means the aggregate cash proceeds received by Mariner or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of any non-cash consideration received in any Asset Sale), net of:
 
(1) all legal, accounting, investment banking, title and recording tax expenses, commissions and other fees and expense incurred, and all Federal, state, provincial, foreign and local taxes required to be paid or accrued as a liability under GAAP (after taking into account any available tax credits or deductions and any tax sharing agreements), as a consequence of such Asset Sale;
 
(2) all payments made on any Indebtedness which is secured by any assets subject to such Asset Sale, in accordance with the terms of any Lien upon such assets, or which must by its terms, or in order to obtain a necessary consent to such Asset Sale, or by applicable law be repaid out of the proceeds from such Asset Sale;
 
(3) all distributions and other payments required to be made to holders of Minority Interests in Subsidiaries or joint ventures as a result of such Asset Sale; and
 
(4) the deduction of appropriate amounts to be provided by the seller as a reserve, in accordance with GAAP, or held in escrow, in either case for adjustment in respect of the sale price or for any liabilities associated with the assets disposed of in such Asset Sale and retained by Mariner or any Restricted Subsidiary after such Asset Sale.
 
“Net Working Capital” means (a) all current assets of Mariner and its Restricted Subsidiaries except current assets from commodity price risk management activities arising in the ordinary course of business, less (b) all current liabilities of Mariner and its Restricted Subsidiaries, except current liabilities included in Indebtedness and any current liabilities from commodity price risk management activities arising in the ordinary course of business, in each case as set forth in the consolidated financial statements of Mariner prepared in accordance with GAAP (excluding any adjustments made pursuant to FAS 133).
 
“Non-Recourse Debt” means Indebtedness:
 
(1) as to which neither Mariner nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness), (b) is directly or indirectly liable as a guarantor or otherwise, or (c) constitutes the lender;
 
(2) no default with respect to which (including any rights that the holders of the Indebtedness may have to take enforcement action against an Unrestricted Subsidiary) would permit upon notice, lapse of time or both any holder of any other Indebtedness of Mariner or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment of the Indebtedness to be accelerated or payable prior to its Stated Maturity; and


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(3) as to which the lenders have been notified in writing that they will not have any recourse to the stock or assets of Mariner or any of its Restricted Subsidiaries, except as contemplated by clause (26) of the definition of Permitted Liens.
 
“Note Guarantee” means the Guarantee by each Guarantor of Mariner’s Obligations under the indenture and the notes, executed pursuant to the provisions of the indenture.
 
“Obligations” means any principal, interest, penalties, fees, indemnifications, reimbursements, damages and other liabilities payable under the documentation governing any Indebtedness.
 
“Oil and Gas Business” means:
 
(1) the acquisition, exploration, exploitation, development, production, operation and disposition of interests in oil, gas and other Hydrocarbon properties;
 
(2) the gathering, marketing, treating, processing (but not refining), storage, distribution, selling and transporting of any production from such interests or properties;
 
(3) any business relating to exploration for or development, production, exploitation, treatment, processing (but not refining), storage, transportation or marketing of oil, gas and other minerals and products produced in association therewith; and
 
(4) any activity that is ancillary or complementary to or necessary or appropriate for the activities described in clauses (1) through (3) of this definition.
 
“Permitted Acquisition Indebtedness” means Indebtedness or Disqualified Stock of Mariner or any of Mariner’s Restricted Subsidiaries to the extent such Indebtedness or Disqualified Stock was Indebtedness or Disqualified Stock of:
 
(1) a Subsidiary prior to the date on which such Subsidiary became a Restricted subsidiary; or
 
(2) a Person that was merged, consolidated or amalgamated into Mariner or a Restricted Subsidiary, provided that on the date such Subsidiary became a Restricted Subsidiary or the date such Person was merged, consolidated and amalgamated into Mariner or a Restricted Subsidiary, as applicable, after giving pro forma effect thereto,
 
(a) the Restricted Subsidiary or Mariner, as applicable, would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test described under “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock,”
 
(b) the Fixed Charge Coverage Ratio for the Restricted Subsidiary or Mariner, as applicable, would be greater than the Fixed Charge Coverage Ratio for such Restricted Subsidiary or Mariner immediately prior to such transaction, or
 
(c) the Consolidated Net Worth of the Restricted Subsidiary or Mariner, as applicable, would be greater than the Consolidated Net Worth of such Restricted Subsidiary or Mariner immediately prior to such transaction.
 
“Permitted Business Investments” means Investments made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business, including through agreements, transactions, interests or arrangements that permit one to share risk or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including without limitation:
 
(1) direct or indirect ownership of crude oil, natural gas, other restricted Hydrocarbon properties or any interest therein or gathering, transportation, processing, storage or related systems; and
 
(2) the entry into operating agreements, joint ventures, processing agreements, working interests, royalty interests, mineral leases, farm-in agreements, farm-out agreements, development agreements, production sharing agreements, area of mutual interest agreements, contracts for the sale, transportation or exchange of crude oil and natural gas and related Hydrocarbons and minerals, unitization agreements,


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pooling arrangements, joint bidding agreements, service contracts, partnership agreements (whether general or limited), or other similar or customary agreements, transactions, properties, interests or arrangements and Investments and expenditures in connection therewith or pursuant thereto, in each case made or entered into in the ordinary course of the Oil and Gas Business, excluding, however, Investments in corporations and publicly-traded limited partnerships.
 
“Permitted Investments” means:
 
(1) any Investment in Mariner or in a Restricted Subsidiary of Mariner;
 
(2) any Investment in Cash Equivalents or Investment Grade Securities;
 
(3) any Investment by Mariner or any Restricted Subsidiary of Mariner in a Person, if as a result of such Investment:
 
(a) such Person becomes a Restricted Subsidiary of Mariner; or
 
(b) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, Mariner or a Restricted Subsidiary of Mariner;
 
(4) any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption “— Repurchase at the Option of Holders — Asset Sales;”
 
(5) any acquisition of assets or Capital Stock solely in exchange for the issuance of Equity Interests (other than Disqualified Stock) of Mariner;
 
(6) any Investments received in compromise or resolution of (A) obligations of trade creditors or customers that were incurred in the ordinary course of business of Mariner or any of its Restricted Subsidiaries, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer; or (B) litigation, arbitration or other disputes with Persons who are not Affiliates;
 
(7) Investments represented by Hedging Obligations;
 
(8) advances to or reimbursements of employees for moving, entertainment and travel expenses, drawing accounts and similar expenditures in the ordinary course of business;
 
(9) loans or advances to employees in the ordinary course of business or consistent with past practice not to exceed $5.0 million in the aggregate at any one time outstanding;
 
(10) receivables owing to Mariner or any Restricted Subsidiary created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms; provided, however, that such trade terms may include such concessionary trade terms as Mariner or any such Restricted Subsidiary deems reasonable under the circumstances;
 
(11) surety and performance bonds and workers’ compensation, utility, lease, tax, performance and similar deposits and prepaid expenses in the ordinary course of business;
 
(12) Guarantees of Indebtedness permitted under the covenant contained under the caption “Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock”;
 
(13) guarantees by Mariner or any of its Restricted Subsidiaries of operating leases (other than Capital Lease Obligations) or of other obligations that do not constitute Indebtedness, in each case entered into by any Restricted Subsidiary in the ordinary course of business;
 
(14) Investments of a Restricted Subsidiary acquired after the Issue Date or of any entity merged into Mariner or merged into or consolidated or amalgamated with a Restricted Subsidiary in accordance with the covenant described under “— Certain Covenants — Merger, Consolidated or Sale of Assets” to the extent that such Investments were not made in contemplation of or in connection with such


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acquisition, merger, consolidation or amalgamation and were in existence on the date of such acquisition, merger or consolidation;
 
(15) Permitted Business Investments;
 
(16) Investments received as a result of a foreclosure by Mariner or any of its Restricted Subsidiaries with respect to any secured Investment in default;
 
(17) Investments in any units of any oil and gas royalty trust; and
 
(18) other Investments in any Person having an aggregate Fair Market Value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (18) that are at the time outstanding not to exceed the greater of (a) 1.00% of Adjusted Consolidated Net Tangible Assets or (b) $10.0 million.
 
“Permitted Liens” means, with respect to any Person:
 
(1) Liens securing Indebtedness incurred under the Credit Facilities pursuant to the covenant described under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock”;
 
(2) Liens in favor of Mariner or the Guarantors;
 
(3) Liens on property of a Person existing at the time such Person is merged with or into or consolidated or amalgamated with Mariner or any Subsidiary of Mariner; provided that such Liens were in existence prior to the contemplation of such merger, consolidation or amalgamation and do not extend to any assets other than those of the Person merged into or consolidated or amalgamated with Mariner or the Subsidiary and do not extend to any assets other than those of the Person merged into or consolidated or amalgamated with Mariner or the Subsidiary;
 
(4) Liens on property (including Capital Stock) existing at the time of acquisition of the property by Mariner or any Subsidiary of Mariner; provided that such Liens were in existence prior to, such acquisition, and not incurred in contemplation of, such acquisition;
 
(5) Liens existing on the Issue Date;
 
(6) Liens for taxes, assessments or governmental charges or claims that are not yet delinquent or that are being contested in good faith by appropriate proceedings promptly instituted and diligently concluded; provided that any reserve or other appropriate provision as is required in conformity with GAAP has been made therefor;
 
(7) survey exceptions, easements or reservations of, or rights of others for, licenses, rights-of-way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning or other restrictions as to the use of real property that were not incurred in connection with Indebtedness and that do not in the aggregate materially adversely affect the value of said properties or materially impair their use in the operation of the business of such Person;
 
(8) leases or subleases granted to others that do not materially interfere with the ordinary course of business of Mariner and its Restricted Subsidiaries, taken as a whole;
 
(9) landlords’, carriers’, warehousemen’s, mechanics’, materialmen’s, repairmen’s or the like Liens arising by contract or statute in the ordinary course of business and with respect to amounts which are not yet delinquent or are being contested in good faith by appropriate proceedings;
 
(10) pledges or deposits made in the ordinary course of business (A) in connection with leases, tenders, bids, statutory obligations, surety or appeal bonds, government contracts, performance bonds and similar obligations, or (B) in connection with workers’ compensation, unemployment insurance and other social security legislation;
 
(11) Liens encumbering property or assets under construction arising from progress or partial payments by a customer of Mariner or its Restricted Subsidiaries relating to such property or assets;


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(12) Liens in favor of customs and revenue authorities arising as a matter of law to secure payments of customs duties in connection with the importation of goods;
 
(13) any attachment or judgment Lien that does not constitute an Event of Default;
 
(14) Liens created for the benefit of (or to secure) the notes (or the Note Guarantees);
 
(15) Liens to secure any Permitted Refinancing Indebtedness permitted to be incurred under the indenture; provided, however, that:
 
(a) the new Lien shall be limited to all or part of the same property and assets that secured or, under the written agreements pursuant to which the original Lien arose, could secure the original Lien (plus improvements and accessions to, such property or proceeds or distributions thereof); and
 
(b) the Indebtedness secured by the new Lien is not increased to any amount greater than the sum of (x) the outstanding principal amount, or, if greater, committed amount, of the Permitted Refinancing Indebtedness and (y) an amount necessary to pay any fees and expenses, including premiums, related to such renewal, refunding, refinancing, replacement, defeasance or discharge; and
 
(16) Liens for the purpose of securing the payment of all or a part of the purchase price of, or Capital Lease Obligations with respect to, or the repair, improvement or construction cost of, assets or property acquired or repaired, improved or constructed in the ordinary course of business; provided that:
 
(a) the aggregate principal amount of Indebtedness secured by such Liens is otherwise permitted to be incurred under the indenture and does not exceed the cost of the assets or property so acquired or repaired, improved or constructed plus fees and expenses in connection therewith; and
 
(b) such Liens are created within 180 days of repair, improvement, construction or acquisition of such assets or property and do not encumber any other assets or property of Mariner or any of its Restricted Subsidiaries other than such assets or property and assets affixed or appurtenant thereto (including improvements);
 
(17) Liens arising solely by virtue of any statutory or common law provisions relating to banker’s Liens, rights of set-off or similar rights and remedies as to deposit accounts or other funds maintained or deposited with a depositary institution; provided that:
 
(a) such deposit account is not a dedicated cash collateral account and is not subject to restrictions against access by Mariner in excess of those set forth by regulations promulgated by the Federal Reserve Board; and
 
(b) such deposit account is not intended by Mariner or any Restricted Subsidiary to provide collateral to the depositary institution;
 
(18) Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by Mariner and its Restricted Subsidiaries in the ordinary course of business;
 
(19) Liens in respect of Production Payments and Reserve Sales;
 
(20) Liens on pipelines and pipeline facilities that arise by operation of law;
 
(21) farmout, carried working interest, joint operating, unitization, royalty, sales and similar agreements relating to the exploration or development of, or production from, oil and gas properties entered into in the ordinary course of business;
 
(22) Liens reserved in oil and gas mineral leases for bonus or rental payments and for compliance with the terms of such leases;
 
(23) Liens arising under the indenture in favor of the trustee for its own benefit and similar Liens in favor of other trustees, agents and representatives arising under instruments governing Indebtedness permitted to be incurred under the indenture, provided, however, that such Liens are solely for the benefit


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of the trustees, agents or representatives in their capacities as such and not for the benefit of the holders of the Indebtedness;
 
(24) Liens securing Hedging Obligations of Mariner and its Restricted Subsidiaries;
 
(25) Liens on and pledges of the Equity Interests of any Unrestricted Subsidiary or any joint venture owned by Mariner or any of its Restricted Subsidiary to the extent securing Non-Recourse Debt of such Unrestricted Subsidiary or joint venture;
 
(26) Liens upon specific items of inventory, receivables or other goods or proceeds of Mariner or any of its Restricted Subsidiaries securing such Person’s obligations in respect of bankers’ acceptances or receivables securitizations issued or created for the account of such Person to facilitate the purchase, shipment or storage of such inventory, receivables or other goods or proceeds and permitted by the covenant described under the caption “ — Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock;” and
 
(27) Liens incurred in the ordinary course of business of Mariner or any Subsidiary of Mariner with respect to Obligations that do not exceed the greater of (a) $10.0 million at any one time outstanding and (b) 1.00% of the Adjusted Consolidated Net Tangible Assets determined as of the date of the incurrence of such Obligations after giving pro forma effect to such incurrence and the application of proceeds therefrom.
 
“Permitted Refinancing Indebtedness” means any Indebtedness of Mariner or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to extend, renew, refund, refinance, replace, defease or discharge other Indebtedness of Mariner or any of its Restricted Subsidiaries (other than intercompany Indebtedness); provided that:
 
(1) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness extended, renewed, refunded, refinanced, replaced, defeased or discharged (plus all accrued interest on the Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith);
 
(2) such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being extended, renewed, refunded, refinanced, replaced, defeased or discharged;
 
(3) if the Indebtedness being extended, renewed, refunded, refinanced, replaced, defeased or discharged is subordinated in right of payment to the notes, such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and is subordinated in right of payment to, the notes on terms at least as favorable to the holders of notes as those contained in the documentation governing the Indebtedness being extended, renewed, refunded, refinanced, replaced, defeased or discharged; and
 
(4) such Indebtedness is incurred either by Mariner or by the Restricted Subsidiary who is the obligor on the Indebtedness being extended, renewed, refunded, refinanced, replaced, defeased or discharged; provided, however, that a Restricted Subsidiary that is also a Guarantor may guarantee Permitted Refinancing Indebtedness incurred by Mariner, whether or not such Restricted Subsidiary was an obligor or guarantor of the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged.
 
Notwithstanding the foregoing, any Indebtedness incurred under Credit Facilities pursuant to the covenant described above under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock” shall be subject to the refinancing provisions of the definition of “Credit Facilities” and not pursuant to the requirements set forth in this definition of Permitted Refinancing Indebtedness.


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“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.
 
“Production Payments” means, collectively, Dollar-Denominated Production Payments and Volumetric Production Payments.
 
“Production Payments and Reserve Sales” means the grant or transfer by Mariner or a Restricted Subsidiary of Mariner to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar denominated), partnership or other interest in oil and gas properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties, including any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the oil and gas business for geologists, geophysicists and other providers of technical services to Mariner or a Subsidiary of Mariner.
 
“Rating Agency” means each of S&P and Moody’s, or if S&P or Moody’s or both shall not make a rating on the notes publicly available, a nationally recognized statistical rating agency or agencies, as the case may be, selected by Mariner (as certified by a resolution of the Board of Directors) which shall be substituted for S&P or Moody’s, or both, as the case may be.
 
“Rating Decline” means the occurrence of:
 
(1) a decrease of one or more gradations (including gradations within Rating Categories as well as between Rating Categories) in the rating of the notes by either Rating Agency; or
 
(2) a withdrawal of the rating of the notes by either Rating Agency; provided, however, that such decrease or withdrawal occurs on, or within 90 days before or after the earlier of (a) a Change of Control, (b) the date of public notice of the occurrence of a Change of Control or (c) public notice of the intention by Mariner to effect a Change of Control (which period shall be extended so long as the rating of the notes is under publicly announced consideration for downgrade by either Rating Agency).
 
“Restricted Investment” means an Investment other than a Permitted Investment.
 
“Restricted Subsidiary” of a Person means any Subsidiary of the referent Person that is not an Unrestricted Subsidiary.
 
“S&P” means Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc.
 
“Senior Debt” means:
 
(1) all Indebtedness of Mariner or any of its Restricted Subsidiaries outstanding under Credit Facilities and all Hedging Obligations with respect thereto;
 
(2) any other Indebtedness of Mariner or any of its Restricted Subsidiaries permitted to be incurred under the terms of the indenture, unless the instrument under which such Indebtedness is incurred expressly provides that it is subordinated in right of payment to the notes or any note Guarantee; and
 
(3) all Obligations with respect to the items listed in the preceding clauses (1) and (2). Notwithstanding anything to the contrary in the preceding sentence, Senior Debt will not include:
 
(a) any intercompany Indebtedness of Mariner or any of its Subsidiaries to Mariner or any of its Affiliates; or
 
(b) any Indebtedness that is incurred in violation of the indenture.
 
For the avoidance of doubt, “Senior Debt” will not include any trade payables or taxes owed or owing by Mariner or any Restricted Subsidiary.
 
“Significant Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the date of the indenture.
 
“Special Interest” means all liquidated damages then owing pursuant to the registration rights agreement.


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“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the documentation governing such Indebtedness as of the date of the indenture, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.
 
“Subordinated Obligation” means any Indebtedness of Mariner (whether outstanding on the Issue Date or thereafter incurred) which is subordinate or junior in right of payment to the notes pursuant to a written agreement or any Indebtedness of a Guarantor (whether outstanding on the Issue Date or thereafter incurred) which is subordinate or junior in right of payment to the Note Guarantee pursuant to a written agreement, as the case may be.
 
“Subsidiary” means, with respect to any specified Person:
 
(1) any corporation, association or other business entity of which more than 50% of the total voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency and after giving effect to any voting agreement or stockholders’ agreement that effectively transfers voting power) to vote in the election of directors, managers or trustees of the corporation, association or other business entity is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and
 
(2) any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are that Person or one or more Subsidiaries of that Person (or any combination thereof).
 
“Unrestricted Subsidiary” means any Subsidiary of Mariner that is designated by the Board of Directors of Mariner as an Unrestricted Subsidiary pursuant to a resolution of the Board of Directors, but only to the extent that such Subsidiary:
 
(1) has no Indebtedness other than Non-Recourse Debt;
 
(2) except as permitted by the covenant described above under the caption “— Certain Covenants — Transactions with Affiliates,” is not party to any agreement, contract, arrangement or understanding with Mariner or any Restricted Subsidiary of Mariner unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to Mariner or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of Mariner;
 
(3) is a Person with respect to which neither Mariner nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and
 
(4) has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of Mariner or any of its Restricted Subsidiaries, other than pursuant to a Note Guarantee.
 
“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all related undertakings and obligations.
 
“Voting Stock” of any specified Person as of any date means the Capital Stock of such Person that is at the time entitled to vote in the election of the Board of Directors of such Person.
 
“Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing:
 
(1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by (2) the then outstanding principal amount of such Indebtedness.


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MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
 
The following summary of the material U.S. federal income tax considerations relevant to the exchange of new notes for old notes pursuant to the exchange offer does not purport to be a complete analysis of all potential tax effects. The discussion is based upon the Internal Revenue Code of 1986, as amended, Treasury Regulations, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which may be subject to change at any time by legislative, judicial or administrative action. These changes may be applied retroactively in a manner that could adversely affect a holder of new notes. The description does not consider the effect of any applicable foreign, state, local or other tax laws or estate or gift tax considerations.
 
The exchange of new notes for old notes pursuant to the exchange offer will not be a taxable exchange for U.S. federal income tax purposes. A holder will not recognize any taxable gain or loss as a result of the exchange and will have the same tax basis and holding period in the new notes as the holder had in the old notes immediately before the exchange.
 
PLAN OF DISTRIBUTION
 
Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. In addition, until January 8, 2007, all dealers effecting transactions in the new notes, whether or not participating in this distribution, may be required to deliver a prospectus. This requirement is in addition to the obligation of dealers to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
 
We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions:
 
  •  in the over-the-counter market,
 
  •  in negotiated transactions,
 
  •  through the writing of options on the new notes or a combination of such methods of resale,
 
  •  at market prices prevailing at the time of resale,
 
  •  at prices related to such prevailing market prices, or
 
  •  at negotiated prices.
 
Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes.
 
Any broker-dealer that resells new notes received for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such new notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of new notes and any commission on concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver a prospectus and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. The letter of transmittal also states that any holder participating in this exchange offer will have no arrangements or understanding with any person to participate in the distribution of the old notes or the new notes within the meaning of the Securities Act.
 
For a period of 90 days after the exchange date, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker dealer that requests such


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documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the holders of the old notes) other than certain taxes and commissions or concessions of any brokers or dealers, and will indemnify the holders of the old notes (including any broker dealers) against certain liabilities, including liabilities under the Securities Act.
 
LEGAL MATTERS
 
The validity of the notes and the validity of the subsidiary guarantees offered hereby has been passed upon for us by Baker Botts L.L.P.
 
EXPERTS
 
The financial statements of Mariner Energy, Inc. as of December 31, 2005 and 2004 and for the year ended December 31, 2005, for the period from January 1, 2004 through March 2, 2004 (Pre-merger), for the period from March 3, 2004 through December 31, 2004 (Post-merger), and for the year ended December 31, 2003 (Pre-merger) 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 a change in method of accounting for asset retirement obligations in 2003 and the merger of Mariner Energy, Inc.’s parent company on March 2, 2004) appearing herein and is 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, 2005 have been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said 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, 2003, 2004 and 2005 and prepared by or derived from estimates prepared by Ryder Scott Company, L.P., independent petroleum engineers. These estimates are included in this prospectus in reliance upon the authority of the firm as experts in these matters.


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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 interest in the


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acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”
 
Field.  An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
 
Gross acres or gross wells.  The total acres or wells, as the case may be, in which a working interest is owned.
 
Infill well.  A well drilled between known producing wells to better exploit the reservoir.
 
Lease operating expenses.  The expenses of lifting oil or gas from a producing formation to the surface, and the transportation and marketing thereof, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, ad valorem taxes and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.
 
Mbbls.  Thousand barrels of crude oil or other liquid hydrocarbons.
 
Mcf.  Thousand cubic feet of natural gas.
 
Mcfe.  Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
MMBls.  Million barrels of crude oil or other liquid hydrocarbons.
 
MMBtu.  Million British Thermal Units.
 
MMcf.  Million cubic feet of natural gas.
 
MMcfe.  Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
Net acres or net wells.  The sum of the fractional working interests owned in gross acres or wells, as the case may be.
 
Net revenue interest.  An interest in all oil and natural gas produced and saved from, or attributable to, a particular property, net of all royalties, overriding royalties, net profits interests, carried interests, reversionary interests and any other burdens to which the person’s interest is subject.
 
Payout.  Generally refers to the recovery by the incurring party to an agreement of its costs of drilling, completing, equipping and operating a well before another party’s participation in the benefits of the well commences or is increased to a new level.
 
PV10 or present value of estimated future net revenues.  An estimate of the present value of the estimated future net revenues from proved oil and gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future net revenues are discounted at an annual rate of 10%, in accordance with the Securities and Exchange Commission’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the date indicated and held constant for the life of the reserves.
 
Productive well.  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
 
Prospect.  A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
 
Proved developed non-producing reserves.  Proved developed reserves expected to be recovered from zones behind casing in existing wells.


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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.


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INDEX TO FINANCIAL STATEMENTS
 
         
MARINER ENERGY, INC.
   
  F-2
  F-3
  F-4
  F-5
  F-27
  F-28
  F-29
  F-30
  F-31
  F-32
FOREST GULF OF MEXICO OPERATIONS
   
  F-63
  F-64
  F-65


F-1


Table of Contents

MARINER ENERGY, INC.
 
CONDENSED CONSOLIDATED BALANCE SHEETS
 
                 
    September 30,
    December 31,
 
    2006     2005  
    (In thousands except share data)
 
    (Unaudited)
 
 
Current Assets:
               
Cash and cash equivalents
  $ 4,874     $ 4,556  
Receivables, net of allowances of $337 at September 30, 2006 and $500 at December 31, 2005
    163,579       84,109  
Insurance receivables
    61,586       4,542  
Derivative financial instruments
    55,265        
Prepaid seismic
    16,956       6,542  
Prepaid expenses and other
    15,149       15,666  
Deferred tax asset
    10,215       26,017  
                 
Total current assets
    327,624       141,432  
Property and Equipment:
               
Oil and gas properties, full cost method: Proved
    2,217,982       574,725  
Unproved, not subject to amortization
    121,297       40,176  
                 
Total
    2,339,279       614,901  
Other property and equipment
    13,749       11,048  
Accumulated depreciation, depletion and amortization
    (291,124 )     (110,006 )
                 
Total property and equipment, net
    2,061,904       515,943  
Goodwill
    263,750        
Derivative financial instruments
    18,674        
Other Assets, net of amortization
    28,772       8,161  
                 
TOTAL ASSETS
  $ 2,700,724     $ 665,536  
                 
Current Liabilities:
               
Accounts payable
  $ 35,806     $ 37,530  
Accrued liabilities
    107,765       75,324  
Accrued capital costs
    129,308       37,006  
Abandonment liability
    51,952       11,359  
Accrued interest
    12,580       614  
Derivative financial instruments
          42,173  
                 
Total current liabilities
    337,411       204,006  
Long-Term Liabilities:
               
Abandonment liability
    170,495       38,176  
Deferred income tax
    305,756       25,886  
Derivative financial instruments
          21,632  
Long term debt, revolving credit facility
    314,000       152,000  
Long term debt, senior unsecured notes
    300,000        
Note payable
          4,000  
Other long-term liabilities
    6,000       6,500  
                 
Total long-term liabilities
    1,096,251       248,194  
Commitments and Contingencies (see Note 8)
               
Stockholders’ Equity:
               
Common stock, $.0001 par value; 180,000,000 shares authorized, 86,269,563 shares issued and outstanding at September 30, 2006; 70,000,000 shares authorized, 35,615,400 shares issued and outstanding at December 31, 2005
    9       4  
Preferred stock, $.0001 par value; 20,000,000 shares authorized, no shares issued and outstanding at September 30, 2006 and December 31, 2005
           
Additional paid-in-capital
    1,042,544       160,705  
Accumulated other comprehensive income/(loss)
    52,185       (41,473 )
Accumulated retained earnings
    172,324       94,100  
                 
Total stockholders’ equity
    1,267,062       213,336  
                 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 2,700,724     $ 665,536  
                 
 
The accompanying notes are an integral part of these consolidated financial statements


F-2


Table of Contents

MARINER ENERGY, INC.
 
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 
                 
    Nine Months Ended
 
    September 30,  
    2006     2005  
    (In thousands except share data)
 
    (Unaudited)  
 
Revenues:
               
Oil sales
  $ 150,982     $ 53,579  
Gas sales
    285,008       94,913  
Other revenues
    2,401       2,753  
                 
Total revenues
    438,391       151,245  
                 
Costs and Expenses:
               
Lease operating expense
    62,863       17,678  
Severance and ad valorem taxes
    5,710       2,492  
Transportation expense
    4,031       1,697  
General and administrative expense
    25,050       26,726  
Depreciation, depletion and amortization
    192,222       43,457  
Impairment of production equipment held for use
          498  
                 
Total costs and expenses
    289,876       92,548  
                 
OPERATING INCOME
    148,515       58,697  
Interest:
               
Income
    486       696  
Expense, net of amounts capitalized
    (26,392 )     (5,416 )
                 
Income before taxes
    122,609       53,977  
Provision for income taxes
    (44,385 )     (18,414 )
                 
NET INCOME
  $ 78,224     $ 35,563  
                 
Earnings per share:
               
Net income per share — basic
  $ 1.07     $ 1.10  
Net income per share — diluted
  $ 1.06     $ 1.07  
Weighted average shares outstanding — basic
    73,270,309       32,438,240  
Weighted average shares outstanding — diluted
    73,694,727       33,312,831  
 
The accompanying notes are an integral part of these consolidated financial statements


F-3


Table of Contents

MARINER ENERGY, INC.
 
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                 
    Nine Months
 
    Ended September 30,  
    2006     2005  
    (In thousands)
 
    (Unaudited)  
 
Operating Activities:
               
Net income
  $ 78,224     $ 35,563  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Deferred income tax
    44,243       15,862  
Depreciation, depletion and amortization
    194,963       44,321  
Stock compensation expense
    9,016       17,614  
Impairment of production equipment held for use
          498  
Net realized loss on derivative contracts acquired
    5,144        
Changes in operating assets and liabilities:
               
Receivables
    (25,390 )     2,476  
Insurance receivable
    (41,916 )      
Prepaid expenses and other
    12,226       418  
Other assets
    (3,935 )     (629 )
Accounts payable and accrued liabilities
    (99,781 )     19,251  
                 
Net cash provided by operating activities
    172,794       135,374  
                 
Investing Activities:
               
Additions to properties and equipment
    (404,675 )     (142,102 )
Proceeds from property conveyances
    2,012       18  
Purchase price adjustment
    (20,808 )      
                 
Net cash used in investing activities
    (423,471 )     (142,084 )
                 
Financing Activities:
               
Repayment of term note
    (4,000 )     (6,000 )
Credit facility borrowings (repayments), net
    162,000       (30,000 )
Debt and working capital acquired from Forest Energy Resources, Inc. 
    (176,200 )      
Proceeds from note offering
    300,000        
Repurchase of stock
    (14,027 )      
Deferred offering costs
    (12,343 )     (2,680 )
Net realized loss on derivative contracts acquired
    (5,144 )      
Proceeds from private equity offering
          44,534  
Capital contribution from affiliates
          2,879  
Proceeds from exercise of stock options
    709        
                 
Net cash provided by financing activities
    250,995       8,733  
                 
Increase in Cash and Cash Equivalents
    318       2,023  
Cash and Cash Equivalents at Beginning of Period
    4,556       2,541  
                 
Cash and Cash Equivalents at End of Period
  $ 4,874     $ 4,564  
                 
 
The accompanying notes are an integral part of these consolidated financial statements


F-4


Table of Contents

MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 
1.   Summary of Significant Accounting Policies
 
Operations — Mariner Energy, Inc. (“Mariner” or “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 in West Texas. Effective March 2, 2006, a subsidiary of the Company completed a merger transaction with Forest Energy Resources, Inc. pursuant to which the Company acquired the Gulf of Mexico operations of Forest Oil Corporation. Please see Note 3, “Acquisitions” for further discussion of this transaction. Unless otherwise indicated, references to “Mariner”, “the Company”, “we”, “our”, “ours” and “us” refer to Mariner Energy, Inc. and its subsidiaries collectively.
 
Interim Financial Statements — The accompanying unaudited consolidated financial statements have been prepared without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although we believe that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. Our balance sheet at December 31, 2005 is derived from the December 31, 2005 audited financial statements, but does not include all disclosures required by GAAP. These unaudited condensed consolidated financial statements included herein should be read in conjunction with the Financial Statements and Notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005.
 
Use of Estimates — The preparation of the consolidated 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 dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Our most significant financial estimates are based on remaining proved natural gas and oil reserves. Estimates of proved reserves are key components of our depletion rate for natural gas and oil properties, our unevaluated properties and our full cost ceiling test. In addition, estimates are used in computing taxes, preparing accruals of operating costs and production revenues, asset retirement obligations, fair value and effectiveness of derivative instruments and fair value of stock options and the related compensation expense. Because of the inherent nature of the estimation process, actual results could differ materially from these estimates.
 
Principles of Consolidation — Our consolidated financial statements as of September 30, 2006 and December 31, 2005 and for the nine-month periods ended September 30, 2006 and 2005 include our accounts and the accounts of our wholly-owned subsidiaries. All significant inter-company balances and transactions have been eliminated.
 
Reclassifications — Certain prior year amounts have been reclassified to conform to current year presentation.
 
Income Tax Provision — Our provision for taxes includes both state and federal taxes. In May 2006, the State of Texas enacted substantial changes to its tax structure beginning in 2007 by implementing a new margin tax of 1% to be imposed on revenues less certain costs, as specified in the legislation. As a result, we increased our provision by an additional $1.3 million for the nine months ended September 30, 2006 to provide for deferred taxes to the State of Texas under the newly enacted state margin tax.
 
Recent Accounting Pronouncements — In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“FIN”) No. 48, Accounting for Uncertainty in Income Taxes. FIN No. 48 clarifies Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes, and requires us to evaluate our tax positions for all jurisdictions and all years where the statute of limitations has not expired.


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MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

FIN No. 48 requires companies to meet a “more-likely-than-not” threshold (i.e. greater than a 50 percent likelihood of being sustained under examination) prior to recording a benefit for their tax positions. Additionally, for tax positions meeting this “more-likely-than-not” threshold, the amount of benefit is limited to the largest benefit that has a greater than 50 percent probability of being realized upon ultimate settlement. The cumulative effect of applying the provisions of the new interpretation will be recorded as an adjustment to the beginning balance of retained earnings, or other components of stockholders’ equity, as appropriate, in the period of adoption. We will adopt the provisions of this interpretation effective January 1, 2007, and are currently evaluating the impact, if any, that this interpretation will have on our financial statements.
 
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. SFAS No. 157 does not require any new fair value measurements but rather it eliminates inconsistencies in the guidance found in various prior accounting pronouncements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. Earlier adoption is encouraged, provided the company has not yet issued financial statements, including for interim periods, for that fiscal year. Although we are still evaluating the potential effects of this standard, we do not expect the adoption of SFAS No. 157 to have a material impact on our consolidated financial position, results of operation, or cash flows.
 
In September 2006, the Securities and Exchange Commission released Staff Accounting Bulletin No. 108, “Quantifying Financial Statement Misstatements” (“SAB 108”). SAB 108 gives guidance on how errors, built up over time in the balance sheet, should be considered from a materiality perspective and corrected. SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. SAB 108 represents the SEC Staff’s views on the proper interpretation of existing rules and as such has no effective date. We do not expect the adoption of SAB No. 108 to have a material impact on our consolidated financial position, results of operation, or cash flows.
 
In June 2006, the Emerging Issues Task Force (“EITF”) reached a consensus on Issue No. 06-03, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That Is, Gross versus Net Presentation)”. EITF 06-03 requires that companies disclose the gross amounts of taxes reported. The consensus is effective for interim or annual reporting periods beginning after December 15, 2006. We do not expect the adoption of this EITF issue to have a material impact on our consolidated financial position, results of operations or cash flows.
 
2.   Related Party Transactions
 
Organization and Ownership of the Company — On March 2, 2004, Mariner Energy LLC, the Company’s indirect parent, 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”). Prior to the Merger, Joint Energy Development Investments Limited Partnership (“JEDI”), which was an indirect wholly-owned subsidiary of Enron Corp. (“Enron”), owned approximately 96% of the common stock of Mariner Energy 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, JEDI no longer owned any interest in Mariner Energy LLC, and the Company ceased to be affiliated with JEDI or Enron.
 
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. On February 10, 2005, in anticipation of the private placement by the Company and its sole stockholder of an aggregate 31,452,500 shares of the Company’s common stock in March 2005 (the “Private Equity Placement”), Mariner Holdings, Inc. and Mariner Energy LLC were merged into the Company 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,


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MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

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. In the Private Equity Placement, the Company sold 16,350,000 shares of its common stock and its sole stockholder sold 15,102,500 shares of the Company’s common stock. The Company’s net proceeds in the Private Equity Placement were $212.9 million, before offering costs of $2.2 million, of which $166.0 million was paid to its sole stockholder to redeem 12,750,000 shares of the Company’s common stock in March 2005.
 
The Company was previously party to management agreements with two affiliates of its former 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. Mariner Energy LLC also entered into monitoring agreements with two affiliates of its former parent, 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. Effective February 7, 2005, these contracts were terminated in consideration of lump sum cash payments by Mariner totaling $2.3 million. The Company recorded the termination payments as general and administrative expenses for the quarter ended March 31, 2005.
 
3.   Acquisitions
 
Forest Gulf of Mexico Operations — On March 2, 2006, a subsidiary of the Company completed a merger transaction with Forest Energy Resources, Inc. (the “Forest Transaction”). Prior to the consummation of the merger, Forest Oil Corporation (“Forest”) transferred and contributed the assets of, and certain liabilities associated with, its offshore Gulf of Mexico operations to Forest Energy Resources, Inc. Immediately prior to the merger, Forest distributed all of the outstanding shares of Forest Energy Resources, Inc. to Forest shareholders on a pro rata basis. Forest Energy Resources, Inc. then merged with a newly formed subsidiary of Mariner, became a new wholly owned subsidiary of Mariner and changed its name to Mariner Energy Resources, Inc. (“MERI”). Immediately following the merger, approximately 59% of the Mariner common stock was held by shareholders of Forest and approximately 41% of Mariner common stock was held by the pre-merger stockholders of Mariner.
 
To acquire MERI, Mariner issued 50,637,010 shares of its common stock to Forest shareholders. The aggregate consideration was valued at $890.0 million, comprised of $3.8 million in pre-merger costs and $886.2 million in common stock, based on the closing price of the Company’s common stock of $17.50 per share on September 12, 2005 (which was the date that the terms of the acquisition were announced).
 
The Forest Transaction was accounted for using the purchase method of accounting under the accounting standards established in SFAS No. 141, Business Combinations (“SFAS 141”) and No. 142, Goodwill and Other Intangible Assets.  As a result, the assets and liabilities acquired by Mariner in the Forest Transaction are included in the Company’s September 30, 2006 balance sheet. The Company reflected the results of operations of the Forest Transaction beginning March 2, 2006. The Company recorded the estimated fair


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MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

values of the assets acquired and liabilities assumed at the March 2, 2006 closing date, which are summarized in the following table:
 
         
    (In millions)  
 
Oil and natural gas properties
  $ 1,211.4  
Abandonment liabilities
    (165.2 )
Long-term debt
    (176.2 )
Fair value of oil and natural gas derivatives
    (17.5 )
Deferred tax liability
    (199.4 )
Other assets and liabilities
    (26.9 )
Goodwill
    263.8  
         
Net Assets Acquired
  $ 890.0  
         
 
The Forest Transaction includes a large undeveloped offshore acreage position which complements the Company’s large seismic database and a large portfolio of potential exploratory prospects. The initial fair value estimate of the underlying assets and liabilities acquired is determined by estimating the value of the underlying proved reserves at the transaction date plus or minus the fair value of other assets and liabilities, including inventory, unproved oil and gas properties, gas imbalances, debt (at face value), derivatives, and abandonment liabilities. The deferred tax liability recognizes the difference between the historical tax basis of the assets of Forest Energy Resources, Inc. and the acquisition cost recorded for book purposes. The purchase price allocation is preliminary and will be subject to change as additional information becomes available, including the final amount of the cash payment to be agreed to by Mariner and Forest under the distribution agreement that is part of the merger documentation. The cash payment is consideration to Forest, pertains to the period from July 1, 2005 to March 2, 2006, and is reflected in the purchase price allocation. In April 2006, Mariner made a preliminary cash payment to Forest of $20.8 million under the distribution agreement. The final purchase price allocation may differ in material respects from that presented above depending primarily upon final settlement of the cash payment under the distribution agreement. Carryover basis accounting applies for tax purposes.
 
Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in the acquisition. SFAS No. 142 requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis or more frequently if an event occurs or circumstances change that could potentially result in an impairment. The Company has elected November 30 as its assessment date.
 
On March 2, 2006, Mariner and MERI entered into a $500 million senior secured revolving credit facility and an additional $40 million senior secured letter of credit facility. Please refer to Note 4, “Long Term Debt” for further discussion of the amended and restated bank credit facility.
 
Payable to Forest — Forest and MERI entered into a transition services agreement under which Forest provided services to MERI on an as-needed basis for a limited period of time after the Forest Transaction until the services could be transitioned to Mariner. As a result of these arrangements, MERI incurred working capital charges that were payable to Forest. All amounts have been settled as of September 30, 2006 and no further charges are anticipated under the transition services agreement.
 
Pro Forma Financial Information — The pro forma information set forth below gives effect to our merger with Forest Energy Resources, Inc. as if it had been consummated as of the beginning of the applicable period. The merger was consummated on March 2, 2006. The pro forma information has been derived from the historical consolidated financial statements of the Company and the statements of revenues and direct


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MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

operating expenses of the Forest Gulf of Mexico operations. The pro forma 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 pro forma 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 the Company will achieve after the merger.
 
                 
    Nine Months Ended September 30.  
    2006     2005  
    (In thousands, except per share amounts)  
 
Pro Forma:
               
Revenue
  $ 505,873     $ 477,967  
Net income available to common stockholders
  $ 92,622     $ 71,221  
Basic earnings per share
  $ 1.09     $ 0.86  
Diluted earnings per share
  $ 1.09     $ 0.85  
 
4.   Long-Term Debt
 
Secured Bank Credit Facility — On March 2, 2004, the Company obtained a revolving line of credit with initial advances of $135 million from a group of banks led by Union Bank of California, N.A. and BNP Paribas. The bank credit facility initially provided 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 B loan was converted to a Tranche A note in July 2004 and all subsequent advances under the credit facility were Tranche A advances.
 
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. Substantially all of the Company’s assets are pledged to secure the bank credit facility.
 
Amendments of Secured Bank Credit Facility — In connection with the Forest Transaction, the Company amended and restated its existing secured credit facility on March 2, 2006 to, among other things, increase maximum credit availability to $500 million for revolving loans, including up to $50 million in letters of credit, with a $400 million borrowing base as of that date; add an additional dedicated $40 million letter of credit facility that does not affect the borrowing base; and add MERI as a co-borrower. The revolving credit facility will mature on March 2, 2010, and the $40 million letter of credit facility will mature on March 2, 2009. The Company used borrowings under its revolving credit facility to facilitate the Forest Transaction and to retire existing debt, and it may use borrowings in the future for general corporate purposes. The $40 million letter of credit facility was used to obtain a letter of credit in favor of Forest to secure the Company’s performance of its obligations to drill and complete 150 wells under an existing drill-to-earn program and is not included as a use of the borrowing base. This letter of credit will reduce periodically by an amount equal to the product of $0.5 million times the number of wells exceeding 75 that are drilled and completed. The first reduction of approximately $4.3 million occurred in October 2006 based upon the 83 wells drilled and completed as of September 30, 2006. The Company expects additional reductions based upon quarterly drilling activity, with the next reduction anticipated in January 2007.
 
At September 30, 2006, the Company had approximately $328.6 million in advances outstanding under its revolving credit facility, including two letters of credit for $4.2 million and $10.4 million required for plugging and abandonment obligations at certain of its offshore fields. The outstanding principal balance of loans under the revolving credit facility may not exceed the borrowing base. If the borrowing base falls below the outstanding balance under the revolving credit facility, the Company will be required to prepay the deficit,


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MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

pledge additional unencumbered collateral, repay the deficit and cash collateralize certain letters of credit, or effect some combination of such prepayment, pledge and repayment and collateralization. On April 7, 2006, the borrowing base was increased to $430 million, subject to redetermination or adjustment. On April 24, 2006, the borrowing base was reduced to $362.5 million in accordance with an amendment to the revolving credit facility related to the Company’s offering of $300 million of senior notes. For subsequent qualifying bond issuances, the amendment provides that the borrowing base in effect on the closing date of such a bond issuance will automatically reduce by 25% of the aggregate principal amount of such bond issuance to the extent that it does not refinance the principal amount of an existing bond issuance. The bank credit facility permits the Company’s issuance of certain unsecured bonds of up to $350 million in aggregate principal amount that have a non-default interest rate of 10% or less per annum and a scheduled maturity date after March 1, 2012. The Company’s sale and issuance of $300 million of senior notes in April 2006 constituted such a qualifying bond issuance. In October 2006, the borrowing base was increased to $450 million, subject to redetermination or adjustment.
 
The secured 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, the incurrence of additional debt, the sale of assets, and speculative hedging. The financial covenants were modified under the amended and restated bank credit facility to require the Company to, among other things:
 
  •  maintain a ratio of consolidated current assets plus the unused borrowing base to consolidated current liabilities of not less than 1.0 to 1.0; and
 
  •  maintain a ratio of total debt to EBITDA of not more than 2.5 to 1.0.
 
The Company was in compliance with the financial covenants under the secured bank credit facility as of September 30, 2006.
 
As of September 30, 2006 and December 31, 2005, $314.0 million and $152.0 million, respectively, was outstanding under the secured bank credit facility, and the weighted average interest rate was 7.16% and 7.15%, respectively.
 
The Company must pay a commitment fee of 0.25% to 0.50% per year on the unused availability under the bank credit facility.
 
Private Offering of Senior Unsecured Notes due 2013 — On April 24, 2006, the Company sold and issued to eligible purchasers $300 million aggregate principal amount of its 71/2% senior notes due 2013 (the “Notes”) pursuant to Rule 144A under the Securities Act of 1933, as amended. The Notes were priced to yield 7.75% to maturity. Net proceeds, after deducting initial purchasers’ discounts and commissions and offering expenses, were approximately $287.9 million. Mariner used the net proceeds of the offering to repay debt under the bank credit facility. The issuance of the Notes was a qualifying bond issuance under Mariner’s secured bank credit facility and resulted in an automatic reduction of its borrowing base to $362.5 million as of April 24, 2006.
 
The Notes are senior unsecured obligations of the Company, rank senior in right of payment to any future subordinated indebtedness, rank equally in right of payment with the Company’s existing and future senior unsecured indebtedness and are effectively subordinated in right of payment to the Company’s senior secured indebtedness, including its obligations under its credit facility, to the extent of the collateral securing such indebtedness, and to all existing and future indebtedness and other liabilities of any non-guarantor subsidiaries.
 
The Notes are jointly and severally guaranteed on a senior unsecured basis by the Company’s existing and future domestic subsidiaries. In the future, the guarantees may be released or terminated under certain circumstances. Each subsidiary guarantee ranks senior in right of payment to any future subordinated


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MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

indebtedness of the guarantor subsidiary, ranks equally in right of payment to all existing and future senior unsecured indebtedness of the guarantor subsidiary and effectively subordinate to all existing and future secured indebtedness of the guarantor subsidiary, including its guarantees of indebtedness under the Company’s credit facility, to the extent of the collateral securing such indebtedness.
 
The Company will pay interest on the Notes on April 15 and October 15 of each year, beginning on October 15, 2006. The Notes mature on April 15, 2013. There is no sinking fund for the Notes.
 
The Company may redeem the Notes at any time prior to April 15, 2010 at a price equal to the principal amount redeemed plus a make-whole premium, using a discount rate of the Treasury rate plus 0.50% and accrued but unpaid interest. Beginning on April 15 of the years indicated below, the Company may redeem the Notes from time to time, in whole or in part, at the prices set forth below (expressed as percentages of the principal amount redeemed) plus accrued but unpaid interest:
 
2010 at 103.750%
2011 at 101.875%
2012 and thereafter at 100.000%
 
In addition, prior to April 15, 2009, the Company may redeem up to 35% of the Notes with the proceeds of equity offerings at a price equal to 107.50% of the principal amount of the Notes redeemed. If the Company experiences a change of control (as defined in the indenture governing the Notes), subject to certain exceptions, the Company must give holders of the Notes the opportunity to sell to the Company their Notes, in whole or in part, at a purchase price equal to 101% of the principal amount, plus accrued and unpaid interest and liquidated damages to the date of purchase.
 
The Company and its restricted subsidiaries are subject to certain negative covenants under the indenture governing the Notes. The indenture governing the Notes limits the Company’s and each of its restricted subsidiaries’ ability to, among other things:
 
  •  make investments;
 
  •  incur additional indebtedness or issue preferred stock;
 
  •  create certain liens;
 
  •  sell assets;
 
  •  enter into agreements that restrict dividends or other payments from its subsidiaries to itself;
 
  •  consolidate, merge or transfer all or substantially all of its assets;
 
  •  engage in transactions with affiliates;
 
  •  pay dividends or make other distributions on capital stock or subordinated indebtedness; and
 
  •  create unrestricted subsidiaries.
 
Under an Exchange and Registration Rights Agreement executed on April 24, 2006 relating to the Notes, the Company agreed to:
 
  •  file a registration statement within 180 days after the closing date of the offering enabling holders of Notes to exchange the privately placed Notes for publicly registered Notes with substantially identical terms;


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MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

 
  •  use its reasonable best efforts to cause the registration statement to become effective within 270 days after the closing date of the offering and to complete the exchange offer within 360 days after the closing of the offering; and
 
  •  file a shelf registration statement for the resale of the Notes if it cannot effect an exchange offer within the time periods listed above and in other circumstances.
 
If the Company fails to comply with its obligations to register the Notes within the specified time periods, it will be required to pay special interest on the Notes. In September 2006, the Company filed a registration statement with the SEC covering an offer to exchange the privately placed Notes for registered notes with substantially identical terms. The SEC declared the registration statement effective in October 2006. The Company anticipates completing the exchange offer in November 2006.
 
Costs associated with the Notes offering were approximately $8.5 million, excluding discounts of $3.8 million.
 
JEDI Term Promissory Note — On March 2, 2004, the Company issued a $10 million term promissory note to JEDI as a part of merger consideration. The note matured on March 2, 2006, and bore 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 remained 10% per annum. We chose to pay interest in cash rather than in kind. The JEDI note was 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 could offset against the note the amount of certain claims for indemnification that could be asserted against JEDI under the terms of the merger agreement. The JEDI term promissory note contained 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 Equity Placement in March 2005. The $4.0 million balance remaining on the JEDI note was repaid in full on its maturity date of March 2, 2006.
 
Cash Interest Expense — For the nine-month periods ended September 30, 2006 and 2005, interest payments were $11.5 million and $4.1 million, respectively.
 
Bank Debt Issuance Costs — The Company capitalizes certain direct costs associated with the issuance of long term debt. In conjunction with the Forest Transaction, the Company’s bank credit facility was amended and restated to, among other things, increase the borrowing capacity from $185 million to $400 million, based upon an initial borrowing base of that amount. The amendment and restatement was treated as an extinguishment of debt for accounting purposes. This treatment resulted in a charge of approximately $1.2 million in the first quarter of 2006. This charge is included in the interest expense line of the consolidated statement of operations.
 
5.   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.
 
Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues (which excludes future cash outflows associated with settlement of asset retirement obligations), 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


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MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

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 No. 133, “Accounting for Derivative Instruments and Hedging Activities” 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. At September 30, 2006, the effects of the cash flow hedges impacted the ceiling test by $209.0 million. Without the hedges, a write-down of the carrying value of the full cost pool of $125.3 million on a pre-tax basis would have been indicated. On an after-tax basis, the write-down would have been $81.5 million.
 
6.   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. The Company adopted SFAS No. 143 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 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 December 31, 2005(1)
  $ 49.5  
Liabilities Incurred
    17.3  
Claims Settled
    (21.5 )
Accretion Expense
    11.1  
Revisions to previous estimates
    0.8  
Liabilities incurred from assets acquired(2)
    165.2  
         
Abandonment Liability as of September 30, 2006(3)
  $ 222.4  
         
 
 
(1) Includes $11.4 million classified as a current accrued liability at December 31, 2005.
 
(2) Represents the fair value of the asset retirement obligation acquired through the Forest Transaction.
 
(3) Includes $52.0 million classified as a current accrued liability at September 30, 2006.
 
7.   Stockholders’ Equity
 
Increase in Number of Shares Authorized — On March 2, 2006, the Company’s certificate of incorporation was amended to increase its authorized stock to 200,000,000 shares, of which 180,000,000 shares are common stock and 20,000,000 shares are preferred stock.


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MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

Equity Participation Plan — We adopted an Equity Participation Plan, as amended, 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 received such a grant are eligible for future awards of restricted stock or stock options under our Amended and Restated Stock Incentive Plan, as amended, 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. As a result of closing the Forest Transaction, all shares of restricted stock granted under the Equity Participation Plan vested as follows: (i) the 463,656 shares of restricted stock held by non-executive employees vested on March 2, 2006, and (ii) the 1,803,614 shares of restricted stock held by executive officers vested on May 31, 2006 pursuant to an agreement, made in exchange for a cash payment of $1,000 to each officer, that his or her shares of restricted stock would not vest before the later of March 11, 2006 or ninety days after the effective date of the merger. The Equity Participation Plan expired upon the vesting of all shares granted thereunder. Stock could 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 had the right to elect to have us withhold and cancel shares of the restricted stock to satisfy our tax withholding obligations. In such events, we would be required to pay any tax withholding obligation in cash. As a result of such participant elections, we withheld an aggregate 807,376 shares that otherwise would have remained outstanding upon vesting of the restricted stock, reducing the aggregate outstanding vested stock grants made under the Equity Participation Plan to 1,459,894 shares. The 807,376 shares withheld became treasury shares that were retired and restored to the status of authorized and unissued shares of common stock. The Company reduced the number of common shares outstanding and additional paid in capital for this transaction. We paid in cash the associated withholding taxes of $14.0 million.
 
Amended and Restated Stock Incentive Plan — We adopted a Stock Incentive Plan that became effective March 11, 2005, was amended and restated on March 2, 2006 and further amended on March 16, 2006. Awards to participants under the Amended and Restated 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, and the purchase price, conditions and other terms of each award are determined by the Board of Directors or a committee thereof. A total of 6,500,000 shares of Mariner’s common stock is subject to the Amended and Restated Stock Incentive Plan. No more than 2,850,000 shares issuable upon exercise of options or as restricted stock can be issued to any individual. Unless sooner terminated, no award may be granted under the Amended and Restated Stock Incentive Plan after October 12, 2015.
 
During the nine months ended September 30, 2006, we granted 796,171 shares of restricted common stock under the Amended and Restated Stock Incentive Plan. As of September 30, 2006, 772,593 shares of unvested restricted common stock and options exercisable for 709,400 shares of common stock (of which 346,736 were presently exercisable) remained outstanding under the Amended and Restated Stock Incentive Plan, and 4,966,071 shares remained available thereunder for future issuance to participants.
 
During the nine months ended September 30, 2005, we granted options to purchase 809,000 shares of common stock under the Stock Incentive Plan.
 
Rollover Options — In connection with the Forest Transaction and during the nine months ended September 30, 2006, the Company granted options to acquire 156,626 shares of its common stock to certain former employees of Forest or Forest Energy Resources, Inc. (“Rollover Options”). The Rollover Options are evidenced by non-qualified stock option agreements and are not covered by the Amended and Restated Stock


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Table of Contents

 
MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

Incentive Plan. As of September 30, 2006, Rollover Options to purchase 108,662 shares of the Company’s common stock remained outstanding, of which 2,641 were presently exercisable.
 
Accounting for Stock Options and Restricted Stock — The Company adopted SFAS No. 123-Revised 2004 (“SFAS No. 123(R)”), Share-Based Payment, using the modified retrospective application effective January 1, 2005. As a result of the adoption of SFAS No. 123(R), we recorded compensation expense for the value of restricted stock that was granted pursuant to our Equity Participation Plan. We also record compensation expense for the value of restricted stock and options granted under the Stock Incentive Plan before March 2, 2006 and the Amended and Restated Stock Incentive Plan, as amended, on and after March 2, 2006. 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 will then be amortized to compensation expense over the applicable vesting period. We recorded compensation expense of $9.0 million and $17.6 million for the nine-month periods ended September 30, 2006 and 2005, respectively, related to restricted stock grants in 2005 and 2006 and stock options outstanding for the periods then ended. As of May 31, 2006, the participants were fully vested in the restricted stock granted under the Equity Participation Plan and no unrecognized compensation remains. Under the Amended and Restated Stock Incentive Plan, unrecognized compensation expense at September 30, 2006 for the unvested portion of restricted stock granted was $13.5 million and for unvested options was $0.8 million.
 
A summary of stock option activity as of September 30, 2006 and 2005, respectively, and changes during the nine-month periods is as follows:
 
                                 
    2006     2005  
          Weighted
          Weighted
 
          Average
          Average
 
          Exercise
          Exercise
 
    Shares     Price     Shares     Price  
 
Outstanding at beginning of period: January 1,
    809,000     $ 14.02           $  —  
Granted
    156,626 (1)     8.31       809,000 (1)     14.02  
Exercised
    (50,600 )     14.00              
Expired
                       
Forfeited
    (96,964 )(2)     12.58              
                                 
Outstanding at end of period: September 30,
    818,062       13.69       809,000       14.02  
                                 
Outstanding exercisable at end of period: September 30,
    349,377       14.00              
Available for future grant as options or restricted stock
    4,966,071             1,191,000        
 
 
(1) The options exercisable for an aggregate 156,626 shares were Rollover Options granted pursuant to the Forest Transaction merger agreement. The options exercisable for an aggregate 809,000 shares were granted under the Stock Incentive Plan.
 
(2) Rollover Options exercisable for an aggregate 47,964 shares and an option exercisable for 40,000 shares granted under the Stock Incentive Plan were forfeited due to terminations of employment, but are not indicative of a historical forfeiture rate. In-the-money options exercisable for an aggregate 9,000 shares granted under the Stock Incentive Plan to two directors of the Company were cancelled on March 31, 2006 and replaced by restricted stock grants.


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Table of Contents

 
MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

The following table summarizes certain information about stock options outstanding at September 30, 2006:
 
                                         
    Options Outstanding              
          Weighted
          Options Exercisable  
          Average
    Weighted
          Weighted
 
          Remaining
    Average
          Average
 
    Number
    Contractual
    Exercise
    Number
    Exercise
 
Range of Exercise Prices
  Outstanding     Life (Years)     Price     Exercisable     Price  
 
$8.81 — $17.00
    818,062       8.5     $ 13.69       349,377     $ 14.00  
 
The following table summarizes certain information about stock options outstanding at September 30, 2005:
 
                                         
    Options Outstanding              
          Weighted
          Options Exercisable  
          Average
    Weighted
          Weighted
 
          Remaining
    Average
          Average
 
    Number
    Contractual
    Exercise
    Number
    Exercise
 
Range of Exercise Prices
  Outstanding     Life (Years)     Price     Exercisable     Price  
 
$14.00 — $17.00
    809,000       9.5     $ 14.02              
 
Options generally vest over one to three-year periods and are exercisable for periods ranging from seven to ten years. The weighted average fair value of options granted during the nine months ended September 30, 2006 and 2005 was $2.26 and $2.72, respectively. The fair value of each option award is estimated on the date of grant using the Black-Scholes option valuation model that uses the assumptions noted in the following table:
 
                 
    Nine Months Ended September 30, 2006:  
    Amended and
       
    Restated Stock
       
    Incentive Plan
       
    Options     Rollover Options  
 
Expected Life (years)
    5.7       4.6  
Risk Free Interest Rate
    4.87 %     4.87 %
Expected Volatility
    35 %     35 %
Dividend Yield
    0.0 %     0.0 %
 
The Black-Scholes option valuation model assumptions were for the nine-month period ended September 30, 2005:
 
         
    Stock
 
    Incentive
 
    Plan  
 
Expected Life (years)
    3.0  
Risk Free Interest Rate
    3.8 %
Expected Volatility
    38 %
Dividend Yield
    0.0 %
 
The expected life (estimated period of time outstanding) of options granted was estimated. The expected volatility was based on historical volatility for a period equal to the stock option’s expected life. The risk free rate is based on the U.S. Treasury yield curve in effect at the time of grant. The dividend yield is based on the Company’s ability to pay dividends.


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Table of Contents

 
MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

A summary of the activity for unvested restricted stock share awards under the Amended and Restated Stock Incentive Plan as of September 30, 2006 and 2005, respectively, and changes during the nine-month period is as follows:
 
                 
    Restricted Shares Under the
 
    Amended and Restated Stock
 
    Incentive Plan
 
    September 30,  
    2006     2005  
 
Total unvested shares at beginning of period: January 1
           
Shares granted
    796,171        
Shares vested
    (1,500 )      
Shares forfeited
    (22,078 )      
                 
Total unvested shares at end of period: September 30
    772,593        
                 
Total vested shares at end of period: September 30
    1,500        
Available for future grant as options or restricted stock
    4,966,071          
Average fair value of shares granted during the period
  $ 19.44     $  
 
A summary of the activity for unvested restricted stock share awards under the Equity Participation Plan as of September 30, 2006 and 2005, respectively, and changes during the nine-month periods is as follows:
 
                 
    Restricted Shares Under the
 
    Equity Participation Plan
 
    September 30,  
    2006     2005  
 
Total unvested shares at beginning of period: January 1
    2,267,270        
Shares granted
          2,267,270  
Shares vested
    (2,267,270 )      
Shares forfeited
           
                 
Total unvested shares at end of period: September 30
          2,267,270  
                 
Total vested shares at end of period: September 30
    2,267,270        
Available for future grant under Equity Participation Plan
           
Average fair value of shares granted during the period
        $ 14.00  
 
Private Equity Placement.  In March 2005, the Company sold and issued 16,350,000 shares of its common stock in the Private Equity Placement for net proceeds of $212.9 million, before offering expenses of $2.2 million, of which $166.0 million were used to redeem 12,750,000 shares of the Company’s common stock from its sole stockholder.


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Table of Contents

 
MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

8.   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 September 30, 2006 are as follows (in millions):
 
         
2007
  $ 1.5  
2008
    1.3  
2009
    1.1  
2010
    1.3  
2011 and thereafter
    2.4  
 
Hedging Program — The energy markets have historically been very volatile, and we expect that oil and gas prices will 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. In addition, forward price curves and estimates of future volatility are used to assess and measure the ineffectiveness of our open contracts at the end of each period. If open contracts cease to qualify for hedge accounting, the mark to market change in fair value is recognized in the income statement. Loss of hedge accounting and cash flow designation will cause volatility in earnings. The fair values we report in our financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.
 
The cash activity on contracts settled for natural gas and oil produced during the nine-month period ended September 30, 2006 was an $8.3 million loss. An $8.3 million non-cash gain was recorded for the nine-month period ended September 30, 2006 relating to the hedges acquired through the Forest transaction. Additionally, an unrealized gain of $1.4 million was recognized for the nine-month period ended September 30, 2006 related to the ineffective portion of open contracts that were not eligible for deferral under SFAS 133 due primarily to the basis differentials between the contract price, which is NYMEX-based for oil and Henry Hub-based for gas, and the indexed price at the point of sale.
 
As of September 30, 2006, Mariner had the following hedge contracts outstanding:
 
                         
                September 30,
 
                2006 Fair Value
 
Fixed Price Swaps
  Quantity     Fixed Price     Gain/(Loss)  
                (In millions)  
 
Crude Oil (Bbls)
                       
October 1–December 31, 2006
    644,920     $ 72.24     $ 5.1  
Natural Gas (MMbtus)
                       
October 1–December 31, 2006
    9,315,000       7.97       20.9  
January 1–December 31, 2007
    15,846,323       9.68       31.7  
January 1–September 30, 2008
    3,059,689       9.58       4.3  
                         
Total
                  $ 62.0  
                         


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Table of Contents

 
MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

 
As of September 30, 2006, the Company had the following costless collars outstanding:
 
                                 
                      September 30,
 
                      2006 Fair Value
 
Costless Collars
  Quantity     Floor     Cap     Gain/(Loss)  
                      (In millions)  
 
Crude Oil (Bbls)
                               
October 1–December 31, 2006
    63,480     $ 32.65     $ 41.52     $ (1.4 )
January 1–December 31, 2007
    2,032,689       59.84       84.21       (1.0 )
January 1–December 31, 2008
    1,195,495       61.66       86.80       2.7  
Natural Gas (MMbtus)
                               
October 1–December 31, 2006
    1,851,960       5.78       7.85       0.9  
January 1–December 31, 2007
    14,106,750       6.87       11.82       1.7  
January 1–December 31, 2008
    12,347,000       7.83       14.60       9.1  
                                 
Total
                          $ 12.0  
                                 
 
As of November 3, 2006, there were no hedging transactions entered into subsequent to September 30, 2006. 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.
 
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 $22.9 million, $19.5 million and $4.0 million in 2006, 2007 and 2008, respectively. In 2005, the Company entered into a joint exploration agreement granting the joint venture partner the right to participate in prospects covered by certain seismic data licensed by the Company in return for $6.0 million in scheduled payments to be received by the Company over a two-year period.
 
MMS Proceedings — Mariner and a subsidiary own numerous properties in the Gulf of Mexico. Certain of such properties were leased from the Minerals Management Service (“MMS”) subject to the 1996 Royalty Relief Act. This Act relieved the obligation to pay royalties on certain leases until a designated volume is produced. Two of these leases held by the Company and one held by MERI contained language that limited royalty relief if commodity prices exceeded predetermined levels. Since 2000, commodity prices have exceeded the predetermined levels, except in 2002. The Company and its subsidiary believe the MMS did not have the authority to set pricing limits in these leases and have withheld payment of royalties on the leases while disputing the MMS’ authority in two pending proceedings. The Company has recorded a liability for 100% of the exposure on its two leases, which at September 30, 2006 was $19.9 million. Various legal proceedings are pending concerning this potential liability and further proceedings may be initiated with respect to years not covered by the pending proceedings. In April 2005, the MMS denied Mariner’s administrative appeal of the MMS’ April 2001 order asserting royalties were due because price limits had been exceeded. In October 2005, Mariner filed suit in the U.S. District Court for the Southern District of Texas seeking judicial review of the dismissal. Upon motion of the MMS, the Company’s lawsuit was dismissed on procedural grounds. In August 2006, the Company filed an appeal of such dismissal. The Company had also filed an administrative appeal of a December 2005 order of the MMS demanding royalties for calendar year 2004 under the same leases at issue in the April 2001 MMS order. However, the MMS withdrew such order, rendering the appeal moot. Thereafter, in May 2006, the MMS issued an order asserting price limits were exceeded in calendar years 2001, 2003 and 2004 and, accordingly, that royalties were due under such leases on oil and gas produced in those years. Mariner has filed and is pursuing an administrative appeal of that order.
 
The potential liability of MERI under its lease subject to the 1996 Royalty Relief Act containing such commodity price threshold language is approximately $2.2 million as of September 30, 2006. This potential liability relates to production from the lease commencing July 1, 2005, the effective date of Mariner’s


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Table of Contents

 
MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

acquisition of MERI. A reserve for this possible liability will be made when deemed appropriate. The MMS has not yet made demand for non-payment of royalties alleged to be due for calendar years subsequent to 2004 on the basis of price thresholds being exceeded.
 
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 Ochre was shut-in until September 2006, when repairs to a host platform were completed and production recommenced at about the same net rate of approximately 6.5 MMcfe per day as it was prior to Hurricane Ivan. Production from Mississippi Canyon 357 was shut-in until March 2005, when necessary repairs were completed and production recommenced. It subsequently has been shut-in since Hurricane Katrina, with production expected to recommence in the first quarter of 2007 after completion of host platform repairs. The Company expects to be reimbursed for costs expended in excess of its annual deductible of $1.25 million plus a single occurrence deductible of $.375 million in effect for the insurance period ended September 30, 2004. Through September 30, 2006, the Company has recovered approximately $2.4 million in insurance proceeds pertaining to damage caused by Hurricane Ivan.
 
In 2005, the Company’s operations were adversely affected by one of the most active and severe hurricane seasons in recorded history, resulting in shut-in production and startup delays. The Company estimates that as of September 30, 2006, approximately 12 MMcfe per day of production remained shut-in and approximately 33 MMcfe per day of production had recommenced since June 30, 2006. The four deepwater projects that experienced startup delays have recommenced production. As a result of ongoing repairs to pipelines, facilities, terminals and host facilities, the Company expects most of the remaining shut-in production to recommence by the end of 2006 and the balance in 2007, except that an immaterial amount of production is not expected to recommence. Actual commencement or recommencement of deferred or shut-in production will vary based on circumstances beyond the Company’s control, including the timing of repairs to both onshore and offshore platforms, pipelines and facilities, the actions of operators on its fields, availability of service equipment, and weather.
 
As of September 30, 2006, we had paid $72.8 million toward the repair of physical damage caused by Hurricanes Katrina and Rita and we estimate that total hurricane-related repairs during 2006 and 2007 will be approximately $85.0 million. While this is our current estimate of the cost of all hurricane-related repairs, the ultimate cost cannot be ascertained until we are able to complete all of the repairs. Approximately $82.4 million of this amount relates to the Gulf of Mexico assets which Mariner acquired from Forest and which were more directly affected by the path of the hurricanes than were Mariner’s historical assets. As a result of the Forest Transaction, Mariner is responsible for the 2005 season hurricane-related repairs to the Forest assets and is entitled to the proceeds from Forest’s insurance policies applicable to such repairs. Mariner’s historical Gulf assets sustained only $2.6 million in physical damage from the hurricanes.
 
Forest’s insurance coverage for the hurricane damage is subject to a $10 million deductible. Forest’s primary carrier has advised the Company that, inasmuch as aggregate claims resulting from the hurricanes are expected to exceed the carrier’s $500 million per occurrence loss limit, the Company’s primary claim pertaining to the Forest assets is expected to be reduced pro rata with all other competing claims from the storms. To the extent insurance recovery under the primary policy relating to the Forest assets is reduced, Mariner believes the shortfall would be collectible under Forest’s excess insurance coverage. The insurance coverage pertaining to Mariner’s historical properties is subject to an aggregate $3.75 million deductible, which we do not expect to exceed given the limited physical damage sustained by Mariner’s historical properties.
 
Taking into account Forest’s insurance coverage in effect at the time of Hurricanes Katrina and Rita, we currently estimate our unreimbursed losses from hurricane-related repairs should not exceed $15 million. Given the magnitude and complexity of the insurance claims currently being processed by the insurance industry with respect to these two significant storms, however, the timing of our ultimate insurance recovery


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Table of Contents

 
MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

presently cannot be ascertained. Although we expect to begin receiving insurance proceeds early in 2007, we believe that a complete insurance settlement of all hurricane-related claims may take several additional quarters. As a result, we expect to maintain a possibly significant insurance receivable for the indefinite future while we actively pursue settlement of our claims to minimize the impact to our working capital and liquidity.
 
Effective March 2, 2006, Mariner has been accepted as a member of OIL Insurance, Ltd., or OIL, an industry insurance cooperative, through which the assets of both Mariner and the Forest Gulf of Mexico operations are insured. The coverage contains a $5 million annual per occurrence deductible for the combined assets and a $250 million per occurrence loss limit. However, if a single event causes losses to OIL insured assets in excess of $500 million, amounts covered for such losses will be reduced on a pro rata basis among OIL members. We maintained our commercially underwritten insurance coverage for the pre-merger Mariner assets which expired on September 30, 2006. This coverage contained a $3 million annual deductible and a $500,000 occurrence deductible, $150 million of aggregate loss limits, and limited business interruption coverage. While the coverage was in effect, it was primary to the OIL coverage for the pre-Forest Transaction Mariner assets. We have acquired additional windstorm/physical damage insurance covering all of Mariner’s assets to supplement the existing OIL coverage. The coverage provides up to $31 million of annual loss coverage (with no additional deductible) if recoveries from OIL for insured losses are reduced by the OIL overall loss limit (i.e., if losses to OIL insured assets from a single event exceed $500 million). We have also acquired additional limited business interruption insurance on most of our deep water producing fields which becomes effective 60 days after a field is shut-in due to a covered event. The coverage varies by field and is limited to a maximum recovery resulting from windstorm damage of approximately $43 million (assuming all covered fields are shut-in for the full insurance term of 365 days).
 
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 and those that may involve the filing of liens against the Company or its assets. The Company does not consider its exposure in these proceedings, individually or in the aggregate, to be material.
 
Letters of Credit — On March 2, 2006, Mariner obtained a $40 million letter of credit under its senior secured credit facility that is not included as a use of the borrowing base. The letter of credit was issued in favor of Forest to secure performance of our obligations under an existing drill-to-earn program. This letter of credit will reduce periodically by an amount equal to the product of $0.5 million times the number of wells exceeding 75 that are drilled and completed. The first reduction of approximately $4.3 million occurred in October 2006 based upon the 83 wells drilled and completed as of September 30, 2006. We expect additional reductions based upon quarterly drilling activity, with the next reduction anticipated in January 2007.
 
Mariner’s senior secured credit facility also has a letter of credit facility of up to $50 million that is included as a use of the borrowing base. As of September 30, 2006, two such letters of credit for $4.2 million and $10.4 million were outstanding. These two letters of credit are required for plugging and abandonment obligations at certain of Mariner’s offshore fields.
 
9.   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. 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.
 


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Table of Contents

MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

                 
    Nine Months Ended
 
    September 30,  
    2006     2005  
    (In thousands except per share data)  
 
Numerator:
               
Net Income
  $ 78,224     $ 35,563  
Denominator:
               
Weighted average shares outstanding
    73,270       32,438  
Add dilutive securities
    425       875  
                 
Total weighted average shares outstanding and dilutive securities
    73,695       33,313  
                 
Earnings per share — basic:
  $ 1.07     $ 1.10  
Earnings per share — diluted:
  $ 1.06     $ 1.07  
 
Please refer to Note 7 “Stockholder’s Equity” for option and share activity for the nine months ended September 30, 2006 and 2005. Outstanding restricted stock and unexercised stock options had a $0.01 effect on diluted earnings per share for the nine-month period ended September 30, 2006.
 
10.   Comprehensive Income
 
Comprehensive income includes net income and certain items recorded directly to stockholder’s equity and classified as other comprehensive income. The table below summarizes comprehensive income and provides the components of the change in accumulated other comprehensive income for the nine-month period ended September 30, 2006 and 2005:
 
                 
    Nine Months Ended
 
    September 30,  
    2006     2005  
    (In thousands)  
 
Net Income
  $ 78,224     $ 35,563  
Other comprehensive income (loss)
               
Derivative contracts settled and reclassified, net of tax
    1,506       23,401  
Change in unrealized mark to market gains/(losses) arising during period, net of tax
    92,152       (79,479 )
                 
Change in accumulated other comprehensive income (loss)
    93,658       (56,078 )
                 
Comprehensive income/(loss)
  $ 171,882       (20,515 )
                 
 
11.   Supplemental Guarantor Information
 
On April 24, 2006, the Company sold and issued to eligible purchasers $300 million aggregate principal amount of its 71/2% senior notes due 2013. The Notes are jointly and severally guaranteed on a senior unsecured basis by the Company’s existing and future domestic subsidiaries (“Subsidiary Guarantors”). In the future, the guarantees may be released or terminated under certain circumstances. Each subsidiary guarantee ranks senior in right of payment to any future subordinated indebtedness of the guarantor subsidiary, ranks equally in right of payment to all existing and future senior unsecured indebtedness of the guarantor subsidiary and effectively subordinate to all existing and future secured indebtedness of the guarantor subsidiary, including its guarantees of indebtedness under the Company’s credit facility, to the extent of the collateral securing such indebtedness.

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MARINER ENERGY, INC.
 
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)

On March 2, 2006, a subsidiary of the Company completed a merger transaction with Forest Energy Resources, Inc. Prior to the transaction, Forest transferred and contributed the assets of, and certain liabilities associated with, its Gulf of Mexico operations to Forest Energy Resources, Inc. Immediately prior to the merger, Forest distributed all of the outstanding shares of Forest Energy Resources, Inc. to Forest shareholders on a pro rata basis. Forest Energy Resources, Inc. then merged with a newly formed subsidiary of Mariner, became a new wholly owned subsidiary of Mariner and changed its name to MERI. The other two guarantors were formed on December 29, 2004, did not commence operations prior to January 1, 2005 and did not have material operations in 2005. The net equity of the guarantors was $0 as of December 31, 2004 and December 31, 2005, therefore, historical information prior to 2006 is not presented.
 
The following information sets forth our Condensed Consolidating Statement of Operations for the nine months ended September 30, 2006, our Condensed Consolidating Balance Sheet as of September 30, 2006 and our Condensed Consolidating Statement of Cash Flows for the nine months ended September 30, 2006. Investments in our subsidiaries are accounted for on the equity method; accordingly, entries necessary to consolidate the Parent Company and the Subsidiary Guarantors are reflected in the eliminations column. In the opinion of management, separate complete financial statements of the Subsidiary Guarantors would not provide additional material information that would be useful in assessing their financial composition.


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MARINER ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEET
September 30, 2006
(In thousands except share data)
(Unaudited)
 
                                 
                      Consolidated
 
    Parent
    Subsidiary
          Mariner
 
    Company     Guarantors     Eliminations     Energy, Inc.  
 
Current Assets:
                               
Cash and cash equivalents
  $ 4,874     $     $     $ 4,874  
Receivables, net
    100,344       63,235             163,579  
Insurance receivables
    4,552       57,034             61,586  
Derivative financial instruments
    64,458       (9,193 )           55,265  
Prepaid seismic
    16,291       665             16,956  
Prepaid expenses and other
    13,779       1,370             15,149  
Deferred tax asset
          10,215             10,215  
                                 
Total current assets
    204,298       123,326             327,624  
Property and Equipment:
                               
Oil and gas properties, full cost method:
                               
Proved
    843,821       1,374,161             2,217,982  
Unproved, not subject to amortization
    116,644       4,653             121,297  
                                 
Total
    960,465       1,378,814             2,339,279  
Other property and equipment
    13,465       284             13,749  
Accumulated depreciation, depletion and amortization
    (188,412 )     (102,712 )           (291,124 )
                                 
Total property and equipment, net
    785,518       1,276,386             2,061,904  
Investment in subsidiaries
    958,250             (958,250 )      
Intercompany
    156,393       (156,393 )            
Goodwill
          263,750             263,750  
Derivative financial instruments
    18,674                   18,674  
Other Assets, Net of Amortization
    20,968       7,804             28,772  
                                 
TOTAL ASSETS
  $ 2,144,101     $ 1,514,873     $ (958,250 )   $ 2,700,724  
                                 
Current Liabilities:
                               
Accounts payable
  $ 34,453     $ 1,353     $     $ 35,806  
Accrued liabilities
    95,792       11,973             107,765  
Accrued capital costs
    100,201       29,107             129,308  
Abandonment liability
    6,623       45,329             51,952  
Accrued interest
    12,404       176             12,580  
Intercompany note payable/(receivable)
    (176,200 )     176,200              
                                 
Total current liabilities
    73,273       264,138             337,411  
Long-Term Liabilities:
                               
Abandonment liability
    53,398       117,097             170,495  
Deferred income tax
    123,296       182,460             305,756  
Long term debt, revolving credit facility
    314,000                   314,000  
Long term debt, senior unsecured notes
    300,000                   300,000  
Other long-term liabilities
    6,000                   6,000  
                                 
Total long-term liabilities
    796,694       299,557             1,096,251  
Commitments and Contingencies
                               
Stockholders’ Equity:
                               
Common stock, $.0001 par value; 180,000,000 shares authorized, 86,269,563 shares issued and outstanding at September 30, 2006
    9       5       (5 )     9  
Preferred stock, $.0001 par value; 20,000,000 shares authorized, no shares issued and outstanding at September 30, 2006
                       
Additional paid-in-capital
    1,042,544       886,142       (886,142 )     1,042,544  
Accumulated other comprehensive income/(loss)
    59,257       (7,072 )           52,185  
Accumulated retained earnings
    172,324       72,103       (72,103 )     172,324  
                                 
Total stockholders’ equity
    1,274,134       951,178       (958,250 )     1,267,062  
                                 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 2,144,101     $ 1,514,873     $ (958,250 )   $ 2,700,724  
                                 


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MARINER ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
Nine Months Ended September 30, 2006
(In thousands)
(Unaudited)
 
                                 
                      Consolidated
 
    Parent
    Subsidiary
          Mariner
 
    Company     Guarantors     Eliminations     Energy, Inc.  
 
Revenues:
                               
Oil sales
  $ 84,009     $ 66,973     $     $ 150,982  
Gas sales
    123,930       161,078             285,008  
Other revenues
    2,401                   2,401  
                                 
Total revenues
    210,340       228,051             438,391  
                                 
Costs and Expenses:
                               
Lease operating expense
    28,073       34,790             62,863  
Severance and ad valorem taxes
    5,205       505             5,710  
Transportation expense
    2,728       1,303             4,031  
General and administrative expense
    23,613       1,437             25,050  
Depreciation, depletion and amortization
    82,191       110,031             192,222  
                                 
Total costs and expenses
    141,810       148,066             289,876  
                                 
OPERATING INCOME
    68,530       79,985             148,515  
Earnings of Affiliates
    72,103             (72,103 )      
Interest:
                               
Income
    486                   486  
Expense, net of amounts capitalized
    (18,510 )     (7,882 )           (26,392 )
                                 
Income before taxes
    122,609       72,103       (72,103 )     122,609  
Provision for income taxes
    (44,385 )                 (44,385 )
                                 
NET INCOME
  $ 78,224     $ 72,103     $ (72,103 )   $ 78,224  
                                 


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MARINER ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
Nine Months Ended September 30, 2006
(In thousands)
(Unaudited)
 
                         
                Consolidated
 
    Parent
    Subsidiary
    Mariner
 
    Company     Guarantors     Energy, Inc.  
 
Net cash provided by operating activities
  $ 129,880     $ 42,914     $ 172,794  
                         
Investing Activities:
                       
Additions to properties and equipment
    (266,853 )     (137,822 )     (404,675 )
Proceeds from property conveyances
    2,012             2,012  
Purchase price adjustment
          (20,808 )     (20,808 )
                         
Net cash used in investing activities
    (264,841 )     (158,630 )     (423,471 )
                         
Financing Activities:
                       
Repayment of term note
    (4,000 )           (4,000 )
Credit facility repayments, net
    162,000             162,000  
Debt and working capital acquired from Forest Energy Resources, Inc. 
          (176,200 )     (176,200 )
Proceeds from note offering
    300,000             300,000  
Repurchase of stock
    (14,027 )           (14,027 )
Deferred offering costs
    (12,343 )           (12,343 )
Net realized loss on derivative contracts acquired
          (5,144 )     (5,144 )
Proceeds from exercise of stock options
    709             709  
Net activity in investments from subsidiaries
    (297,060 )     297,060        
                         
Net cash provided by financing activities
    135,279       115,716       250,995  
                         
Increase in Cash and Cash Equivalents
    318             318  
Cash and Cash Equivalents at Beginning of Period
    4,556             4,556  
                         
Cash and Cash Equivalents at End of Period
  $ 4,874     $     $ 4,874  
                         


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
Board of Directors & Stockholders
Mariner Energy, Inc.
Houston, Texas
 
We have audited the accompanying consolidated balance sheets of Mariner Energy, Inc. (the “Company”) as of December 31, 2005 and 2004 and the related consolidated statements of operations, stockholders’ equity and comprehensive income and cash flows for the year ended December 31, 2005, for the period January 1, 2004 through March 2, 2004 (Pre-merger), for the period from March 3, 2004 through December 31, 2004 (Post merger), and for the year 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 consolidated financial statements present fairly, in all material respects, the financial position of Mariner Energy, Inc. as of December 31, 2005 and 2004, and the results of its operations and cash flows for the year ended December 31, 2005, for the period January 1, 2004 through March 2, 2004 (Pre-merger), for the period from March 3, 2004 through December 31, 2004 (Post merger), and for the year 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 Consolidated 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
March 30, 2006
(September 18, 2006 as to Note 13)


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MARINER ENERGY, INC.
 
BALANCE SHEETS
 
                 
    December 31,
    December 31,
 
    2005     2004  
    (In thousands except share data)  
 
Current Assets:
               
Cash and cash equivalents
  $ 4,556     $ 2,541  
Receivables, net of allowances of $500 and $307 at December 31, 2005 and December 31, 2004, respectively
    88,651       52,734  
Deferred tax asset
    26,017        
Prepaid expenses and other
    22,208       10,471  
                 
Total current assets
    141,432       65,746  
Property and Equipment:
               
Oil and gas properties, full cost method:
               
Proved
    574,725       319,553  
Unproved, not subject to amortization
    40,176       36,245  
                 
Total
    614,901       355,798  
Other property and equipment
    11,048       960  
Accumulated depreciation, depletion and amortization
    (110,006 )     (52,985 )
                 
Total property and equipment, net
    515,943       303,773  
Deferred Tax Asset
          3,029  
Other Assets, Net of Amortization
    8,161       3,471  
                 
TOTAL ASSETS
  $ 665,536     $ 376,019  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
               
Accounts payable
  $ 37,530     $ 2,526  
Accrued liabilities
    123,689       81,831  
Accrued interest
    614       79  
Derivative liability
    42,173       16,976  
                 
Total current liabilities
    204,006       101,412  
Long-Term Liabilities:
               
Abandonment liability
    38,176       19,268  
Deferred income tax
    25,886        
Derivative liability
    21,632       5,432  
Bank debt
    152,000       105,000  
Note payable
    4,000       10,000  
Other long-term liabilities
    6,500       1,000  
                 
Total long-term liabilities
    248,194       140,700  
Commitments and Contingencies (see Note 7) 
               
Stockholders’ Equity:
               
Common stock, $.0001 par value; 70,000,000 shares authorized, 35,615,400 and 29,748,130 shares issued and outstanding at December 31, 2005 and December 31, 2004, respectively
    4       1  
Additional paid-in-capital
    167,318       91,917  
Unearned compensation
    (6,613 )      
Accumulated other comprehensive (loss)
    (41,473 )     (11,630 )
Accumulated retained earnings
    94,100       53,619  
                 
Total stockholders’ equity
    213,336       133,907  
                 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 665,536     $ 376,019  
                 
 
The accompanying notes are an integral part of these financial statements


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MARINER ENERGY, INC.
 
STATEMENTS OF OPERATIONS
 
                                   
    Post-Merger       Pre-Merger  
          Period from
      Period from
       
          March 3,
      January 1,
       
          2004
      2004
       
    Year Ended
    through
      through
    Year Ended
 
    December 31,
    December 31,
      March 2,
    December 31,
 
    2005     2004       2004     2003  
    (In thousands except share data)  
Revenues:
                                 
Oil sales
  $ 73,831     $ 63,498       $ 12,709     $ 37,992  
Gas sales
    122,291       110,925         27,055       104,551  
Other revenues
    3,588                      
                                   
Total revenues
    199,710       174,423         39,764       142,543  
                                   
Costs and Expenses:
                                 
Lease operating expense
    29,882       21,363         4,121       24,719  
Transportation expense
    2,336       1,959         1,070       6,252  
General and administrative expense
    37,053       7,641         1,131       8,098  
Depreciation, depletion and amortization
    59,426       54,281         10,630       48,339  
Derivative settlements
                        3,222  
Impairment of production equipment held for use
    1,845       957                
                                   
Total costs and expenses
    130,542       86,201         16,952       90,630  
                                   
OPERATING INCOME
    69,168       88,222         22,812       51,913  
Interest:
                                 
Income
    779       225         91       756  
Expense, net of amounts capitalized
    (8,172 )     (6,045 )       (5 )     (6,981 )
                                   
Income before taxes
    61,775       82,402         22,898       45,688  
Provision for income taxes
    (21,294 )     (28,783 )       (8,072 )     (9,387 )
                                   
Income before cumulative effect of change in accounting method, net of tax effects
    40,481       53,619         14,826       36,301  
Cumulative effect of change in accounting method, net of tax effects
                        1,943  
                                   
NET INCOME
  $ 40,481     $ 53,619       $ 14,826     $ 38,244  
                                   
Earnings per share:
                                 
Net income per share — basic
                                 
Income before cumulative effect of change in accounting method, net of tax effects
  $ 1.24     $ 1.80       $ .50     $ 1.22  
Cumulative effect of change in accounting method, net of tax effects
                        .07  
                                   
Income per share — basic
  $ 1.24     $ 1.80       $ .50     $ 1.29  
                                   
Net income per share — diluted
                                 
Income before cumulative effect of change in accounting method, net of tax effects
  $ 1.20     $ 1.80       $ .50     $ 1.22  
Cumulative effect of change in accounting method, net of tax effects
                        .07  
                                   
Income per share — diluted
  $ 1.20     $ 1.80       $ .50     $ 1.29  
                                   
Weighted average shares outstanding — basic
    32,667,582       29,748,130         29,748,130       29,748,130  
Weighted average shares outstanding — diluted
    33,766,577       29,748,130         29,748,130       29,748,130  
 
The accompanying notes are an integral part of these financial statements


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Table of Contents

MARINER ENERGY, INC.
 
STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
 
                                                         
                            Accumulated
    Accumulated
       
                Additional
          Other
    Retained
    Total
 
    Common Stock     Paid-In
    Unearned
    Comprehensive
    Earnings
    Stockholders’
 
    Shares     Amount     Capital     Compensation     Income (Loss)     (Deficit)     Equity  
    (In thousands)  
 
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  
                                                         
Common shares issued — private equity offering
    3,600       2       44,331                         44,333  
Common shares issued — restricted stock
    2,267       1       31,741       (31,742 )                  
Amortization of unearned compensation — net of income taxes
                      25,129                   25,129  
Stock compensation expense — stock options — net of income taxes
                594                         594  
Contributed capital — Mariner Energy, LLC and Mariner Holdings, Inc. 
                3,057                         3,057  
Merger adjustments
                (4,322 )                       (4,322 )
Comprehensive income:
                                                       
Net income
                                  40,481       40,481  
Other comprehensive income (loss):
                                                       
Change in fair value of derivative hedging instruments — net of income taxes
                            (61,878 )           (61,878 )
Hedge settlements reclassified to income — net of income taxes
                            32,035             32,035  
Total comprehensive income (loss)
                                        10,638  
                                                         
Balance at December 31, 2005
    35,615     $ 4     $ 167,318     $ (6,613 )   $ (41,473 )   $ 94,100     $ 213,336  
                                                         
 
The accompanying notes are an integral part of these financial statements


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Table of Contents

MARINER ENERGY, INC.
 
STATEMENTS OF CASH FLOWS
 
                                   
    Post-Merger       Pre-Merger  
          Period from
      Period from
       
          March 3,
      January 1,
       
          2004
      2004
       
    Year Ended
    through
      through
    Year Ended
 
    December 31,
    December 31,
      March 2,
    December 31,
 
    2005     2004       2004     2003  
    (In thousands)  
Operating Activities:
                                 
Net income
  $ 40,481     $ 53,619       $ 14,826     $ 38,244  
Adjustments to reconcile net income to net cash provided by operating activities:
                                 
Deferred income tax
    21,294       27,162         8,072        
Depreciation, depletion and amortization
    60,640       55,067         10,630       48,414  
Stock compensation expense
    25,726                      
Hedge activities
                        (2,030 )
Impairment of production equipment held for use
    1,845       957                
Cumulative effect of changes in accounting method
                        (2,988 )
Changes in operating assets and liabilities:
                                 
Receivables
    (32,916 )     (10,615 )       (8,847 )     (3,599 )
Prepaid expenses and other
    (5,201 )     (965 )       551       (2,257 )
Other assets
    (184 )     321         (963 )     1,485  
Accounts payable and accrued liabilities
    53,759       9,697         (3,974 )     1,208  
Taxes payable to parent company and deferred income tax
                        10,432  
                                   
Net cash provided by operating activities
    165,444       135,243         20,295       88,909  
                                   
Investing Activities:
                                 
Additions to oil and gas properties
    (237,729 )     (133,425 )       (15,264 )     (83,228 )
Proceeds from property conveyances
    18                     121,625  
Additions to other property and equipment
    (10,088 )     (172 )       (78 )     (50 )
Restricted cash
          620         1       14,574  
                                   
Net cash (used in) provided by investing activities
    (247,799 )     (132,977 )       (15,341 )     52,921  
                                   
Financing Activities:
                                 
Initial borrowings from revolving credit facility, net of fees
          131,579                
Repayment of subordinated notes
                        (100,000 )
Repayment of term note
    (6,000 )                    
Credit facility borrowings (repayments), net
    47,000       (30,000 )              
Proceeds from private equity offering
    44,331                      
Deferred offering costs
    (3,840 )                    
Capital contribution from affiliates
    2,879                      
                                   
Dividend to Mariner Energy LLC
          (166,432 )              
                                   
Net cash (used in) provided by financing activities
    84,370       (64,853 )             (100,000 )
                                   
Increase (Decrease) in Cash and Cash Equivalents
    2,015       (62,587 )       4,954       41,830  
Cash and Cash Equivalents at Beginning of Period
    2,541       65,128         60,174       18,344  
                                   
Cash and Cash Equivalents at End of Period
  $ 4,556     $ 2,541       $ 65,128     $ 60,174  
                                   
 
The accompanying notes are an integral part of these financial statements


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Table of Contents

MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003
 
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.
 
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”). 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 2). 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 JEDI 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.
 
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


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Table of Contents

 
MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

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. Based on subsequent tax filings during the year ended December 31, 2005, the Company recorded a $4.3 million adjustment to the estimated tax basis at acquisition. 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.
 
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  


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Table of Contents

 
MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

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.
 
On March 2, 2006, the Company completed a merger transaction with Forest Energy Resources, Inc. As a result of this merger, the Company acquired the offshore Gulf of Mexico operations of Forest Oil Corporation and amended and restated its credit facility. See Note 9, “Subsequent Events.”
 
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. 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.
 


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Table of Contents

MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

                                 
    Post-Merger     Pre-Merger  
          Period from
    Period from
       
          March 3,
    January 1,
       
          2004
    2004
       
    Year Ended
    through
    through
    Year Ended
 
    December 31,
    December 31,
    March 2,
    December 31,
 
    2005     2004     2004     2003  
    (In thousands except per share data)  
 
Numerator:
                               
Income before cumulative effect of change in accounting method, net of tax effects
  $ 40,481     $ 53,619     $ 14,826     $ 36,301  
Cumulative effect of change in accounting method, net of tax effects
                      1,943  
Net income
  $ 40,481     $ 53,619     $ 14,826     $ 38,244  
Denominator:
                               
Weighted average shares outstanding
    32,668       29,748       29,748       29,748  
Add dilutive securities
    1,099                    
Total weighted average shares outstanding and dilutive securities
    33,767       29,748       29,748       29,748  
Earnings per share — basic:
                               
Income before cumulative effect of change in accounting method, net of tax effects
  $ 1.24     $ 1.80     $ 0.50     $ 1.22  
Cumulative effect of change in accounting method, net of tax effects
                      0.07  
Net income per share — basic
  $ 1.24     $ 1.80     $ 0.50     $ 1.29  
Earnings per share — diluted:
                               
Income before cumulative effect of change in accounting method, net of tax effects
  $ 1.20     $ 1.80     $ 0.50     $ 1.22  
Cumulative effect of change in accounting method, net of tax effects
                      0.07  
Net income per share — diluted
  $ 1.20     $ 1.80     $ 0.50     $ 1.29  
 
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 December 31, 2005. Outstanding restricted stock and unexercised stock options diluted earnings by $0.04 per share for the year ended December 31, 2005.

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Table of Contents

 
MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

Cash and Cash Equivalents — All short-term, highly liquid investments that have an original maturity date of three months or less are considered cash equivalents.
 
Receivables — Substantially all of the Company’s receivables arise from sales of oil or natural gas, or from reimbursable expenses billed to the other participants in oil and gas wells for which the Company serves as operator. We routinely assess the recoverability of all material trade and other receivables to determine their collectibility. We accrue a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated.
 
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.
 
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


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Table of Contents

 
MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

amortization base along with the associated leasehold costs on a specific project basis. Costs associated with ells 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.
 
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 $3.3 million of oil and gas lease and well equipment held in inventory at December 31, 2005. In 2005 and 2004, we reduced the carrying cost of our inventory by $1.8 million and $1.0 million, respectively, to account for a reduction in the estimated value, primarily related to subsea trees and wellhead equipment held in inventory. Other current assets at December 31, 2005 also include prepaid insurance and seismic costs of $13.9 million and deferred offering costs of $3.8 million related to the merger with Forest Energy Resources.
 
Other Assets — Other assets as of December 31, 2005 were primarily comprised of $1.4 million of amortizable bank fees, $2.3 million in non-current receivables and $4.3 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. Accumulated amortization as of December 31, 2005 and 2004 was $2.1 million and $0.9 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 2005, 2004 and 2003 of $5.3 million, $6.9 million and $6.6 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 $6.9 million, $4.4 million and $1.8 million for the years ended December 31, 2005, 2004 and 2003, 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. In February 2005, Mariner Energy LLC was merged into Mariner Energy, Inc. Following the effective date of that merger through March 2006, Mariner Energy, Inc. will file its own income tax return. After the Forest merger in March 2006 merger, the Company’s taxable income will be included in a consolidated United States income tax return with Forest Energy Resources and the Company’s other subsidiaries. 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


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Table of Contents

 
MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

bases of assets and liabilities. Valuation allowances are established when necessary to reduce deferred tax assets to the amount more likely than not to be recovered.
 
Capitalized Interest Costs — The Company capitalizes interest based on the cost of major development projects which are excluded from current depreciation, depletion, and amortization calculations. Capitalized interest costs were approximately $0.7 million for 2005, $0.4 and $-0- million for 2004 Post-merger and 2004 Pre-merger, respectively, and $0.7 million for 2003.
 
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.
 
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, 2004 (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
    28.6  
Claims Settled
    (5.5 )
Accretion Expense
    2.4  
         
Abandonment Liability as of December 31, 2005 (Post-merger)(2)
  $ 49.5  
         
 
 
(1) Includes $4.7 million classified as a current accrued liability at December 31, 2004.
 
(2) Includes $11.4 million classified as a current accrued liability at December 31, 2005.


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

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.
 
The net cash flows related to any recognized gains or losses associated with these hedges are reported as oil and gas revenues and presented in cash flows from operations. If the hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period as the physical production hedged by the contracts is delivered.
 
The conditions to be met for a derivative instrument to qualify as a cash flow hedge are the following: (i) the item to be hedged exposes the Company to price risk; (ii) the derivative reduces the risk exposure and is designated as a hedge at the time the derivative contract is entered into; and (iii) at the inception of the hedge and throughout the hedge period there is a high correlation of changes in the market value of the derivative instrument and the fair value of the underlying item being hedged.
 
When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on sale or settlement of the underlying item. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if correlation no longer exists, the gain or loss on the derivative is recognized in income to the extent the future results have not been offset by the effects of price or interest rate changes on the hedged item since the inception of the hedge.
 
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.
 
The Company’s gas balancing assets and liabilities are not material as 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.


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

Major Customers — During the twelve months ended December 31, 2005, sales of oil and gas to three purchasers accounted for 24%, 10% and 15% of total revenues. During the year 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. Management believes that the loss of any of these purchasers would not have a material impact on the Company’s financial condition, results of operations or cash flows.
 
Stock Options — The Company (as allowed by SFAS No. 123 “Accounting for Stock Based Compensation” as amended by SFAS No. 148 “Accounting for Stock-Based Compensation — Transition and Disclosure”) has historically applied APB Opinion No. 25 “Accounting for Stock Issued to Employees” for its grants made pursuant to its employee stock option plans. The Company applies APB Opinion 25 and related interpretations in accounting for the Stock Option Plan. Accordingly, no compensation cost has been 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 and 2003 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 year ended December 31, 2005 includes $25.7 million of compensation expense related to restricted stock granted in 2005 and $0.6 million of compensation expense related to stock options outstanding as of December 31, 2005. For the year ended December 31, 2004, we recorded no stock compensation expense related to either restricted stock or stock options.
 
Recent Accounting Pronouncements — In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 153, “Exchanges of Nonmonetary Assets, an Amendment of APB Opinion No. 29,” which provides that all nonmonetary asset exchanges that have commercial substance must be measured based on the fair value of the assets exchanged and any resulting gain or loss recorded. An exchange is defined as having commercial substance if it results in a significant change in expected future cash flows. Exchanges of operating interests by oil and gas producing companies to form a joint venture continue to be exempted. APB Opinion No. 29 previously exempted all exchanges of similar productive assets from fair value accounting, therefore resulting in no gain or loss recorded for such exchanges. SFAS No. 153 became effective for fiscal periods beginning on or after June 15, 2005. Accordingly, we adopted this statement effective June 30, 2005


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

and it did not have a material impact on our consolidated financial position, results of operations or cash flows.
 
In March 2005, the FASB issued Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations,” which clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when the obligation is incurred — generally upon acquisition, construction, or development and/or through the normal operation of the asset, if the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Uncertainty about the timing and/or method of settlement is required to be factored into the measurement of the liability when sufficient information exists. We adopted FIN No. 47 on December 31, 2005 and it did not have a material impact on our consolidated financial position, results of operations or cash flows.
 
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3.” SFAS No. 154 changes the requirements for the accounting and reporting of a change in accounting principle, including voluntary changes in accounting principle and changes required by an accounting pronouncement that does not include specific transition provisions. SFAS No. 154 requires retrospective application to prior period financial statements of changes in accounting principle. If impractical to determine either the period-specific effects or the cumulative effect of the change, the new accounting principle would be applied as if it were adopted prospectively from the earliest date practical. The correction of errors in prior period financial statements should be identified as a “restatement.” SFAS No. 154 is effective for fiscal years beginning after December 15, 2005. Accordingly, adopted this statement effective January 1, 2006 and, upon adoption, it did not have a material impact on our consolidated financial position, results of operations or cash flows.
 
In September 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF Issue 04-13 requires that purchases and sales of inventory with the same counterparty in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. The consensus is effective for inventory arrangements entered into, modified or renewed in interim or annual reporting periods beginning after March 15, 2006. We do not expect the adoption of this EITF Issue to have a material impact on our consolidated financial position, results of operations or cash flows.
 
In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140.” SFAS No. 155 simplifies the accounting for certain hybrid financial instruments, eliminates the FASB’s interim guidance which provides that beneficial interests in securitized financial assets are not subject to the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and eliminates the restriction on the passive derivative instruments that a qualifying special-purpose entity may hold. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We do not expect this Statement to have a material impact on our consolidated financial position, results of operations or cash flows.
 
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.


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

From April 1, 1996, until October 1998, Mariner Holdings, Inc. was a majority-owned subsidiary of JEDI, an affiliate of Enron. In October 1998, JEDI and other stockholders of Mariner Holdings, Inc. exchanged all of their common shares of Mariner Holdings, Inc. for an equivalent ownership percentage in Mariner Energy LLC. From October 1998 until the Merger, Mariner Energy LLC was a majority-owned subsidiary of JEDI.
 
During the period of JEDI’s ownership of the Company, Mariner Energy LLC and the Company entered into various financing and operating transactions, such as oil and gas sale transactions, commodity price hedge transactions, and financial transactions with affiliates of Enron. Below is a summary of key transactions between the Company or Mariner Energy LLC and Enron-affiliated entities.
 
On February 10, 2005, in anticipation of the Private Equity Offering, Mariner Holdings, Inc. (the direct parent of Mariner Energy, Inc.) and Mariner Energy LLC (the direct parent of Mariner Holdings, Inc.) were merged into Mariner Energy, Inc. and ceased to exist. The mergers of Mariner Holdings, Inc. and Mariner Energy LLC into the Company had no operational or financial impact on the Company.
 
Mariner Energy LLC
 
Enron Affiliate Term Loan — In March 2000, Mariner Energy LLC established an unsecured term loan with Enron North America Corp. (“ENA”), an affiliate of Enron, to repay amounts outstanding under various affiliate credit facilities at Mariner Energy LLC and the Company and provide additional working capital. The loan bore interest at 15%, which interest accrued and was added to the loan principal. In conjunction with the loan, warrants were issued to ENA providing the right to purchase up to 900,000 common shares of Mariner Energy LLC for $0.01 per share. The loan and warrants were subsequently assigned by ENA to another Enron affiliate. In connection with the Merger, the loan balance, which was approximately $192.8 million as of December 31, 2003, was repaid in full, and the warrants were exercised and the holders received their pro rata portion of the Merger consideration.
 
Mariner Energy, Inc.
 
As of March 2, 2004 the Company is no longer affiliated with Enron.
 
Oil and Gas Production Sales to Enron Affiliates — During the years ending December 31, 2004 and 2003, sales of oil and gas production to Enron affiliates were $62.6 million and $32.6 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


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

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.
 
As of March 2, 2004 the Company is no longer affiliated with ENA. 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  
Stockholders’ Equity:
               
Common Stock
  $     $ .001  
Additional Paid in Capital
          227.3  
Accumulated other Comprehensive Income
  $     $ 227.3  
 


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

                 
    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. 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 year ended December 31, 2005.
 
3.   Property Conveyances
 
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
 
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

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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

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 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. 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.
 
In connection with the merger with Forest Energy Resources on March 2, 2006, the Company amended and restated the existing bank credit facility to, among other things, increase maximum credit availability to $500 million, with a $400 million borrowing base as of that date, add an additional dedicated $40 million letter of credit facility, and add Mariner Energy Resources, Inc. as a co-borrower. Please see Note 9,


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

Subsequent Events.” The financial covenants were modified under the amended and restated bank credit facility to require the Company to, among other things:
 
  •  maintain a ratio of consolidated current assets plus the unused borrowing base to consolidated current liabilities of not less than 1.0 to 1.0; and
 
  •  maintain a ratio of total debt to EBITDA of not more than 2.5 to 1.0.
 
The Company is in compliance with the financial covenants under the bank credit facility as of December 31, 2005.
 
As of December 31, 2005, $152.0 million was outstanding under the bank credit facility, and the weighted average interest rate was 7.15%. Net proceeds of approximately $38 million generated by the private placement in March 2005 were used to repay existing bank debt.
 
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.
 
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 matured on March 2, 2006, and bore 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 remained 10% per annum. We chose to pay interest in cash rather than in kind. The JEDI note was 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 could offset against the note the amount of certain claims for indemnification that could be asserted against JEDI under the terms of the merger agreement. The JEDI term promissory note contained 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. The $4.0 million balance remaining on the JEDI note at December 31, 2005 was repaid in full on its maturity date of March 2, 2006.
 
Cash Interest Expense
 
Cash paid for interest was $6.1 million for 2005, $5.4 million and -0- million for 2004 Post-Merger and 2004 Pre-Merger, respectively, and $4.0 million for 2003.
 
5.   Stockholders’ Equity
 
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 Amended and Restated 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


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

for the stock. 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. In connection with the merger with Forest Energy Resources, (i) the 463,656 shares of restricted stock held by non-executive employees vested, and (ii) each of Mariner’s executive officers 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, which is May 31, 2006.
 
We adopted a Stock Incentive Plan which became effective March 11, 2005 and was amended and restated on March 2, 2006. Awards to participants under the Amended and Restated 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 a committee thereof. A total of 6.5 million shares of Mariner’s common stock is subject to the Amended and Restated Stock Incentive Plan. No more than 2.85 million shares issuable upon exercise of options or as restricted stock can be issued to any individual. As of March 17, 2006, approximately 5.7 million shares remained available under the Amended and Restated Stock Incentive Plan for future issuance to participants. Unless sooner terminated, no award may be granted under the Amended and Restated Stock Incentive Plan after October 12, 2015.
 
For the two years ended December 31, 2004 and 2003, Mainer Energy, Inc. had no outstanding stock options. During the year ended December 31, 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. The fair value of the restricted shares at date of grant has been recorded in stockholders’ equity as unearned compensation and is being amortized over the vesting period as compensation expense. We recorded compensation expense of $25.7 million in the year ended December 31, 2005 related to the restricted stock granted in 2005 and stock options outstanding as of December 31, 2005. The weighted average fair value of options granted during the year ended December 31, 2005 was $2.69. For the year ended December 31, 2004, we recorded no stock compensation expense related to either restricted stock or stock options.
 
The following table is a summary of stock option activity for the year ended and as of December 31, 2005:
 
                 
          Weighted
 
          Average
 
          Exercise
 
    Shares     Price  
 
Outstanding at beginning of year
        $  
Granted
    809,000       14.02  
Exercised
           
Forfeited
           
                 
Outstanding at end of year
    809,000     $ 14.02  
                 
Outstanding exercisable at end of year
           
                 
Available for future grant as options or restricted stock
    1,191,000          


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

The following table summarizes certain information about stock options outstanding at December 31, 2005:
 
                                                 
          Weighted
                         
          Average
    Weighted
          Weighted
       
          Remaining
    Average
          Average
       
    Number
    Contractual
    Exercise
    Number
    Exercise
       
    Outstanding     Life (Years)     Price     Exercisable     Price        
 
$14.00-$17.00
    809,000       9.2     $ 14.02                      
 
The following table summarizes shares of restricted stock granted for the year ended December 31, 2005:
 
         
    Restricted
 
    Shares  
 
Outstanding at beginning of year
     
Granted
    2,267,270  
Vested
     
Forfeited
     
Outstanding at end of year
    2,267,270  
Outstanding vested at end of year
     
Available for future grant under Equity Participation Plan
     
Average Fair Value of Shares Granted During Year
  $ 14.00  
 
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 December 31, 2005, 2004 and 2003, the Company contributed $240,650, $193,521 and $159,241, 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 $2.6 million for 2005, $2.5 million and $0.2 million for 2004 Post-Merger and 2004 Pre-Merger, respectively, and $2.0 million for 2003.


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

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, 2005 are as follows (in thousands):
 
         
2006
  $ 1,161.4  
2007
    942.7  
2008
    941.0  
2009
    941.0  
2010 and thereafter
    3,448.1  
 
Rental expense, before capitalization, was approximately $509,000 for 2005, $486,000 and $78,000 for 2004 Post-Merger and 2004 Pre-Merger, respectively, and $569,000 for 2003.
 
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 December 31, 2005, the Company had the following fixed price swaps outstanding:
 
                         
                December 31,
 
                2005 Fair Value
 
Fixed Price Swaps
  Quantity     Fixed Price     Gain/(Loss)  
                (In millions)  
 
Crude Oil (Bbls)
                       
January 1 — December 31, 2006
    140,160     $ 29.56     $ (4.7 )
Natural Gas (MMbtus)
                       
January 1 — December 31, 2006
    1,827,547       5.53       (9.9 )
                         
Total
                  $ (14.6 )
                         
 
As of December 31, 2005, the Company had the following costless collars outstanding:
 
                                 
                      December 31,
 
                      2005 Fair Value
 
Fixed Price Swaps
  Quantity     Floor     Cap     Gain/(Loss)  
                      (In millions)  
 
Crude Oil (Bbls)
                               
January 1 — December 31, 2006
    251,850     $ 32.65     $ 41.52     $ (5.3 )
January 1 — December 31, 2007
    202,575       31.27       39.83       (4.7 )
Natural Gas (MMbtus)
                               
January 1 — December 31, 2006
    7,347,450       5.78       7.85       (22.3 )
January 1 — December 31, 2007
    5,310,750       5.49       7.22       (16.9 )
                                 
Total
                          $ (49.2 )
                                 


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

The Company has not entered into any hedge transactions subsequent to December 31, 2005.
 
As of December 31, 2004, the Company had the following fixed price swaps outstanding:
 
                         
                December 31,
 
                2005 Fair Value
 
Fixed Price Swaps
  Quantity     Fixed 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,
 
                      2005 Fair Value
 
Fixed Price Swaps
  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.


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

The following table sets forth the results of hedging transactions during the periods indicated:
 
                                 
    Post-Merger     Pre-Merger  
          Period from
    Period from
       
          March 3,
    January 1,
       
          2004
    2004
       
    Year Ended
    through
    through
    Year Ended
 
    December 31,
    December 31,
    March 2,
    December 31,
 
    2005     2004     2004     2003  
    (In thousands except per share data)  
 
Natural Gas
                               
Quantity hedged (MMbtu)
    15,917,159       16,723,063       2,100,000       25,520,000  
Increase (Decrease) in Natural Gas Sales (in thousands)
  $ (33,010 )   $ (12,223 )   $ 1,431     $ (27,097 )
Crude Oil
                               
Quantity hedged (MBbls)
    836       1,375       179       730  
Increase (Decrease) in Crude Oil Sales (in thousands)
  $ (20,789 )   $ (16,221 )   $ (686 )   $ (4,969 )
 
The Company’s hedge transactions resulted in a $53.8 million loss for 2005 and a $28.4 million loss for 2004 Post-Merger and a $0.7 million gain for 2004 Pre-Merger. $4.5 million of the 2005 loss and $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 $14.5 and $6.5 million in 2006 and 2007, respectively. In 2005, the Company entered into a joint exploration agreement granting the joint venture partner the right to participate in prospects covered by certain seismic data licensed by the Company in return for $6.0 million in scheduled payments to be received by the Company over a two-year period. Subsequent to December 31, 2005, the Company entered into four additional long-term commitments to purchase seismic data in the amount of $26.9 million.
 
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,


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

2001, 2003, 2004 and 2005, commodity prices exceeded the predetermined levels. The Company believes the MMS did not have the authority to set pricing limits in these leases and has filed an administrative appeal with the MMS regarding this matter and withheld payment of royalties on the leases. The Company has recorded a liability for 100% of the exposure on this matter which on December 31, 2005 was $16.0 million. In April 2005, the MMS denied the administrative 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.
 
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 second 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 the second quarter of 2006 for Pluto and Ochre. Rigel production began in the first quarter of 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.
 
Effective March 2, 2006, Mariner has been accepted as a member of OIL Insurance, Ltd., or OIL, an industry insurance cooperative, through which the assets of both Mariner and the Forest Gulf of Mexico operations are insured. The coverage contains a $5 million annual per occurrence deductible for the combined assets and a $250 million per occurrence loss limit. However, if a single event causes losses to OIL insured assets in excess of $1 billion in the aggregate (effective June 1, 2006, such amount will be reduced to $500 million), amounts covered for such losses will be reduced on a pro rata basis among OIL members. Pending review of our insurance program, we have maintained our commercially underwritten insurance coverage for the pre-merger Mariner assets which expires on September 30, 2006. This coverage contains a 3 million annual deductible and a $500,000 occurrence deductible, $150 million of aggregate loss limits, and limited business interruption coverage. While the coverage remains in effect, it will be primary to the OIL coverage for the pre-merger Mariner assets.


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

Litigation — The Company, in the ordinary course of business, is a claimant and/or a defendant in various legal proceedings, including proceedings as to which the Company has insurance coverage. The Company does not consider its exposure in these proceedings, individually and in the aggregate, to be material.
 
8.   Income Taxes
 
The components of the federal income tax provision are:
 
                                 
    Post-Merger     Pre-Merger  
          Period from
    Period from
       
          March 3,
    January 1,
       
          2004
    2004
       
    Year Ended
    through
    through
    Year Ended
 
    December 31,
    December 31,
    March 2,
    December 31,
 
    2005     2004     2004     2003  
    $     $     $     $  
    (In thousands)  
 
Current
                       
Deferred
    21,294       28,783       8,072       10,432  
                                 
Total
    21,294       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
    through
    through
    Year Ending
 
    December 31,
    December 31,
    March 2,
    December 31,
 
    2005     2004     2004     2003  
    $     %     $     %     $     %     $     %  
    (In thousands, except percentages)  
 
Income before income taxes including change in accounting in 2003
    61,775               82,402             22,898             48,676        
Income tax expense (benefit) computed at statutory rates
    21,621       35       28,841       35       8,014       35       17,037       35  
Change in valuation allowance
                                          (7,090 )     (14 )
Other
    (327 )     (1 )     (58 )           58             485        
Tax Expense
    21,294       34       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 2005. 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.


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

The Company’s deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Significant components of the deferred tax assets and liabilities are as follows (in thousands):
 
                 
    Year Ending
 
    December 31,  
    2005     2004  
    (In thousands)  
 
Deferred Tax Assets:
               
Net operating loss carry forwards
  $ 45,171     $ 15,639  
Alternative minimum Tax Credit
    1,606       1,606  
Differences between book and tax basis of receivables
           
Other comprehensive income-derivative instruments
    22,332       6,262  
Employee stock compensation
    9,004        
Valuation allowance
    (5,909 )     (5,909 )
Other
    671        
Total net deferred tax assets
    72,875       17,598  
Deferred Tax Liabilities:
               
Differences between book and tax basis of properties
    (72,744 )     (14,569 )
                 
Total net deferred asset (liability)
    131     $ 3,029  
                 
 
At December 31, 2005, the Company had federal and state net operating loss carryforwards of approximately $129,059 and $7,055 respectively, which will expire in varying amounts between 2018 and 2025 and are subject to certain limitations on an annual basis. A valuation allowance has been established against net operating losses where it is more likely than not that such losses will expire before they are utilized.
 
9.   Subsequent Events
 
On March 2, 2006, we completed a merger transaction with Forest Energy Resources (the Forest Transaction). Prior to the consummation of the merger, Forest transferred and contributed the assets and certain liabilities associated with its offshore Gulf of Mexico operations to Forest Energy Resources. Immediately prior to the merger, Forest distributed all of the outstanding shares of Forest Energy Resources to Forest shareholders on a pro rata basis. Forest Energy Resources then merged with a newly formed subsidiary of Mariner, and became a new wholly owned subsidiary of Mariner. Immediately following the merger, approximately 59% of the Mariner common stock was held by shareholders of Forest and approximately 41% of Mariner common stock was held by the pre-merger stockholders of Mariner. In the merger Mariner issued 50,637,010 shares of common stock to Forest shareholders.
 
The sources and uses of funds related to the Forest Transaction were as follows:
 
         
Mariner Energy, Inc. bank loan proceeds
  $ 180.2  
Refinancing of assumed debt
  $ 176.2  
Acquisition costs and other expenses
    4.0  
Total
  $ 180.2  


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

In addition, approximately $3.8 million in merger-related costs were funded from bank loan proceeds prior to the closing of the transaction.
 
Mariner Energy, Inc. is the acquiring entity in accordance with the provisions of Statement of Financial Accounting Standards No. 141, Business Combinations (“SFAS 141”). As a results, the assets and liabilities acquired by Mariner in the Forest Transaction will be adjusted to their estimated fair values as of the effective date of the transaction (March 2, 2006).
 
The initial fair value estimate of the underlying assets and liabilities acquired is determined by estimating the value of the underlying proved reserves at the transaction date plus or minus the fair value of other assets and liabilities, including inventory, unproved oil and gas properties, gas imbalances, debt (at face value), derivatives, and abandonment liabilities. 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 unproved oil and gas properties and identifiable intangible assets. We are continuing to evaluate all of these items; accordingly, the final purchase price may differ in material respects from that presented below. Carryover basis accounting applies for tax purposes. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the March 2, 2006 transaction date:
 
         
    (In millions)  
 
Oil and natural gas properties
  $ 1,617.0  
Other assets
    14.5  
Abandonment liabilities
    (148.0 )
Long-term debt
    (176.2 )
Fair value of oil and natural gas derivatives
    (17.5 )
Deferred tax liability(1)
    (397.6 )
Total
  $ 892.2  
 
 
(1) Represents deferred income taxes recorded at the date of the transaction due to differences between the book basis and the tax basis of assets. For book purposes, the assets of the Forest Gulf of Mexico operations had a step-up in basis while the existing tax basis carried over.
 
On March 2, 2006, Mariner and Mariner Energy Resources, Inc. entered into a $500 million senior secured revolving credit facility, and an additional $40 million senior secured letter of credit facility. The revolving credit facility will mature on March 2, 2010, and the $40 million letter of credit facility will mature on March 2, 2009. Mariner used borrowings under the revolving credit facility to facilitate the merger and to retire existing debt, and we may use borrowings in the future for general corporate purposes. The $40 million letter of credit facility has been used to obtain a letter of credit in favor of Forest to secure Mariner’s performance of its 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 has been set at $400 million. If the borrowing base falls below the outstanding balance under the revolving credit facility, Mariner will be required to prepay the deficit, pledge additional unencumbered collateral, repay the deficit and cash collateralize certain letters of credit, or effect some combination of such prepayment, pledge and repayment and collateralization.
 
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 matured on March 2, 2006, and bore 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


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

cash in which event the rate remained 10% per annum. In March 2005, the Company repaid $6.0 million of the note utilizing proceeds from the private placement in March 2005. The $4.0 million balance remaining on the JEDI note at December 31, 2005 was repaid in full on its maturity date of March 2, 2006.
 
Effective March 2, 2006, Mariner has been accepted as a member of OIL, an industry insurance cooperative, through which the assets of both Mariner and the Forest Gulf of Mexico operations are insured. The coverage contains a $5 million annual per occurrence deductible for the combined assets and a $250 million per occurrence loss limit. However, if a single event causes losses to OIL insured assets in excess of $1 billion in the aggregate (effective June 1, 2006, such amount will be reduced to $500 million), amounts covered for such losses will be reduced on a pro rata basis among OIL members. Pending review of its insurance program, the Company has maintained our commercially underwritten insurance coverage for the pre-merger Mariner assets which expires on September 30, 2006. This coverage contains a $3 million annual deductible and a $500,000 occurrence deductible, $150 million of aggregate loss limits, and limited business interruption coverage. While the coverage remains in effect, it will be primary to the OIL coverage for the pre-merger Mariner assets.
 
The Company has 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. In connection with the merger with Forest Energy Resources on March 2, 2006, (i) the 463,656 shares of restricted stock held by non-executive employees vested, and (ii) each of Mariner’s executive officers 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, which is May 31, 2006.
 
The Company adopted a Stock Incentive Plan which became effective March 11, 2005 and was amended and restated on March 2, 2006. A total of 6.5 million shares of Mariner’s common stock is subject to the Amended and Restated Stock Incentive Plan. No more than 2.85 million shares issuable upon exercise of options or as restricted stock can be issued to any individual. As of March 17, 2006, approximately 5.7 million shares remained available under the Amended and Restated Stock Incentive Plan for future issuance to participants. Unless sooner terminated, no award may be granted under the Amended and Restated Stock Incentive Plan after October 12, 2015.
 
10.   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  
    2005     2004     2003  
    (In thousands)  
 
Oil and gas sales
  $ 196,122     $ 214,187     $ 142,543  
Lease operating costs
    (29,882 )     (25,484 )     (24,719 )
Transportation
    (2,336 )     (3,029 )     (6,252 )
Depreciation, depletion and amortization
    (59,426 )     (64,911 )     (48,339 )
                         
Results of operations
  $ 104,478     $ 120,763     $ 63,233  
                         


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

The following table summarizes the Company’s capitalized costs of oil and gas properties.
 
                         
    Year Ending December 31  
    2005     2004     2003  
    (In thousands)  
 
Unevaluated properties, not subject to amortization
  $ 40,176     $ 36,245     $ 36,619  
Properties subject to amortization
    574,725       319,553       599,762  
                         
Capitalized costs
    614,901       355,798       636,381  
Accumulated depreciation, depletion and amortization
    (109,183 )     (52,680 )     (429,323 )
                         
Net capitalized costs
  $ 505,718     $ 303,118     $ 207,058  
                         
 
Costs incurred in property acquisition, exploration and development activities were as follows (in thousands, except per equivalent mcf amounts):
 
                         
    Year Ending December 31  
    2005     2004     2003  
    (In thousands)  
 
Property acquisition costs
                       
Unproved properties
  $ 12,366     $ 4,844     $ 4,746  
Proved properties
    52,503       4,863        
Exploration costs
    50,049       43,022       26,823  
Development costs
    121,685       88,626       44,299  
Capitalized internal costs
    6,016       7,334       7,360  
                         
Total costs incurred
  $ 242,619     $ 148,689     $ 83,228  
                         
Depreciation, depletion and amortization rate per equivalent Mcf
  $ 2.04     $ 1.73     $ 1.45  
 
The Company capitalizes internal costs associated with exploration activities in progress. These capitalized costs were approximately 35%, 46% and 48% of the Company’s gross general and administrative expenses, excluding stock compensation expense for the years ended December 31, 2005, 2004 and 2003, respectively.
 
The following table summarizes costs related to unevaluated properties that have been excluded from amounts subject to amortization at December 31, 2005. Three relatively significant projects were included in unproved properties with balances of $6.0 million, $5.8 million and $5.5 million at December 31, 2005. These projects are expected to be evaluated within the next twelve months. The Company regularly evaluates these


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

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     Total at
 
    Year Ended December 31,           December 31,
 
    2005     2004     2003     Prior     2005  
 
Unproved leasehold acquisition and geological and geophysical costs
  $ 15,735     $ 2,455     $ 2,741     $ 3,428       24,359  
Unevaluated exploration and development costs
    14,975       173                   15,148  
Capitalized interest
    450       123       96             669  
                                         
Total
  $ 31,160     $ 2,751     $ 2,837     $ 3,428     $ 40,176  
                                         
 
All of the excluded costs at December 31, 2005 relate to activities in the Gulf of Mexico.
 
11.   Supplemental Oil and Gas Reserve and Standardized Measure Information (Unaudited)
 
Estimated proved net recoverable reserves as shown below include only those quantities that are expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved developed reserves represent only those reserves expected to be recovered through existing wells. Proved undeveloped reserves include those reserves expected to be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure is required for recompletion. Also included in the Company’s proved undeveloped reserves as of December 31, 2005 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.


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Actual results will differ, and are likely to differ materially, from the results estimated.
 
ESTIMATED QUANTITIES OF PROVED RESERVES
 
                         
          Natural Gas
    Natural Gas
 
    Oil (Mbbl)     (MMcf)     Equivalent (MMcfe)  
 
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  
                         
Revisions of previous estimates
    835       963       5,971  
Extensions, discoveries and other additions
    1,167       22,307       29,309  
Purchases of reserves in place
    7,181       50,837       93,923  
Sales of reserves in place
                 
Production
    (1,791 )     (18,354 )     (29,100 )
                         
December 31, 2005
    21,647       207,686       337,568  
                         
 
ESTIMATED QUANTITIES OF PROVED DEVELOPED RESERVES
 
                         
          Natural Gas
    Natural Gas
 
    Oil (Mbbl)     (MMcf)     Equivalent (MMcfe)  
 
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  
December 31, 2005
    9,564       110,011       167,395  


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

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 calculation 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  
    2005     2004     2003  
    (In thousands)  
 
Future cash inflows
  $ 3,451,321     $ 1,601,240     $ 1,182,509  
Future production costs
    (687,583 )     (308,190 )     (196,695 )
Future development costs
    (386,497 )     (193,689 )     (138,694 )
Future income taxes
    (695,921 )     (285,701 )     (183,199 )
Future net cash flows
    1,681,320       813,660       663,921  
Discount of future net cash flows at 10% per annum
    (774,755 )     (319,278 )     (245,762 )
Standardized measure of discounted future net cash flows
  $ 906,565     $ 494,382     $ 418,159  
 
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, 2005, 2004 and 2003, used in the above table, were $61.04, $43.45 and $32.52 per Bbl, respectively, and $10.05, $6.15 and $5.96 per Mmbtu, respectively, and do not include the effect of hedging contracts in place at period end.


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

The following are the principal sources of change in the Standardized Measure of discounted future net cash flows (in thousands):
 
                         
    Year Ending December 31  
    2005     2004     2003  
    (In thousands)  
 
Sales and transfers of oil and gas produced, net of production costs
  $ (213,189 )   $ (185,673 )   $ (111,572 )
Net changes in prices and production costs
    425,317       27,767       27,403  
Extensions and discoveries, net of future development and production costs
    119,501       88,167       180,237  
Purchases of reserves in place
    189,782       14,738        
Development costs during period and net change in development costs
    46,632       44,417       31,709  
Revision of previous quantity estimates
    16,323       89,814       6,276  
Sales of reserves in place
                (138,016 )
Net change in income taxes
    (201,647 )     (27,634 )     (63,962 )
Accretion of discount before income taxes
    49,438       41,816       51,500  
Changes in production rates (timing) and other
    (19,974 )     (17,189 )     (28,988 )
Net change
  $ 412,183     $ 76,223     $ (45,413 )
 
12.   Unaudited Quarterly Financial Information
 
The following table presents Mariner’s unaudited quarterly financial information for 2005 and 2004:
 
                                                                         
    Post-Merger     Pre-Merger  
                                              Period from
    Period from
 
                                              March 3,
    January 1,
 
                                              2004
    2004
 
    2005 Quarter Ended     2004 Quarter Ended     through
    through
 
    December
    September
    June
    March
    December
    September
    June
    March 31,
    March 2,
 
    31     30     30     31     31     30     30     2004     2004  
 
Total revenues
  $ 48,465     $ 43,662     $ 51,776     $ 55,807     $ 51,897     $ 50,202     $ 51,086     $ 21,238     $ 39,764  
Operating income
  $ 10,471     $ 12,263     $ 18,070     $ 28,364     $ 29,108     $ 24,403     $ 25,045     $ 9,666     $ 22,812  
Income before income taxes
  $ 7,798     $ 10,549     $ 16,382     $ 27,046     $ 27,501     $ 22,804     $ 23,071     $ 9,026     $ 22,898  
Provision for income taxes
    2,880       3,606       5,537       9,271       9,562       8,498       7,630       3,093       8,072  
Net income
  $ 4,918     $ 6,943     $ 10,845     $ 17,775     $ 17,939     $ 14,306     $ 15,441     $ 5,933     $ 14,826  
Earnings per share:(1) Net income per share — basic
  $ 0.15     $ 0.21     $ 0.33     $ 0.58     $ 0.60     $ 0.48     $ 0.52     $ 0.20     $ 0.50  
Net income per share — diluted
  $ 0.14     $ 0.20     $ 0.32     $ 0.58     $ 0.60     $ 0.48     $ 0.52     $ 0.20     $ 0.50  
Weighted average shares outstanding — basic(2)
    33,348,130       33,348,130       33,348,130       30,558,130       29,748,130       29,748,130       29,748,130       29,748,130       29,748,130  
Weighted average shares outstanding — diluted
    35,189,290       34,806,842       33,822,079       30,599,152       29,748,130       29,748,130       29,748,130       29,748,130       29,748,130  


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MARINER ENERGY, INC.
 
NOTES TO THE FINANCIAL STATEMENTS — (Continued)
For the Year Ended December 31, 2005,
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 Year Ended December 31, 2003

 
(1) The sum of quarterly net income per share may not agree with total year net income per share, as each quarterly computation is based on the weighted average shares outstanding.
 
(2) Restated for the 1,380 to 29,748,130 stock split, effective March 3, 2005.
 
13.   Supplemental Guarantor Information
 
On April 24, 2006, the Company sold and issued to eligible purchasers $300 million aggregate principal amount of its 71/2% senior notes due 2013. The Notes are jointly and severally guaranteed on a senior unsecured basis by the Company’s existing and future domestic subsidiaries (“Subsidiary Guarantors”). In the future, the guarantees may be released or terminated under certain circumstances. Each subsidiary guarantee ranks senior in right of payment to any future subordinated indebtedness of the guarantor subsidiary, ranks equally in right of payment to all existing and future senior unsecured indebtedness of the guarantor subsidiary and effectively subordinate to all existing and future secured indebtedness of the guarantor subsidiary, including its guarantees of indebtedness under the Company’s credit facility, to the extent of the collateral securing such indebtedness.
 
Guarantors Mariner LP, LLC and Mariner Energy Texas LP were formed on December 29, 2004, did not commence operations prior to January 1, 2005 and did not have material operations in 2005. The net equity of these guarantors was $0 as of December 31, 2005 and 2004, therefore, condensed consolidating statements of operations, condensed consolidating balance sheets and condensed consolidating statement of cash flows is not presented.


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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, 2005 (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 of America. 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, 2005 in conformity with accounting principles generally accepted in the United States of America.
 
KPMG LLP
 
Denver, Colorado
March 27, 2006


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FOREST GULF OF MEXICO OPERATIONS
 
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
 
                         
    Years Ended December 31,  
    2005     2004     2003  
    (In thousands)  
 
Oil and natural gas revenues
  $ 392,272     $ 453,139     $ 342,019  
Direct operating expenses:
                       
Lease operating expenses
    78,524       80,079       45,716  
Transportation
    3,383       2,175       2,652  
Production taxes
    2,215       1,548       1,521  
                         
Total direct operating expenses
    84,122       83,802       49,889  
                         
Revenues in excess of direct operating expenses
  $ 308,150     $ 369,337     $ 292,130  
                         
 
See accompanying notes to statements of revenues and direct operating expenses.


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FOREST GULF OF MEXICO OPERATIONS
 
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
For the Years Ended December 31, 2005, 2004 and 2003
 
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.
 
The following table sets forth information regarding the commodity swap agreements that will be transferred to Forest Energy Resources, Inc. in the spin-off. The fair value of the commodity swaps based on the futures prices quoted on December 31, 2005 was a liability of approximately $66.0 million.
 
                 
    Natural Gas (NYMEX HH)  
          Weighted Average
 
    Bbtu per
    Hedged Price per
 
    Day     MMBtu  
 
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  
 
Net losses related to hedging activities of $128.2 million, $57.1 million and $40.9 million were recognized for the years ended December 31, 2005, 2004 and 2003, 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.


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FOREST GULF OF MEXICO OPERATIONS
 
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
For the Years Ended December 31, 2005, 2004 and 2003

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.
 
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, 2005, 2004 and 2003 is shown below:
 
                         
    Liquids (MBbls)     Gas (MMcf)     Total (MMcfe)  
 
Balance at January 1, 2003
    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  
Revisions of previous estimates
    3,123       4,815       23,553  
Extensions and discoveries
    504       5,639       8,663  
Production
    (2,783 )     (49,120 )     (65,818 )
                         
Balance at December 31, 2005
    12,494       231,142       306,106  
                         


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FOREST GULF OF MEXICO OPERATIONS
 
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
For the Years Ended December 31, 2005, 2004 and 2003

                         
    Liquids (MBbls)     Gas (MMcf)     Total (MMcfe)  
 
Proved developed reserves at:
                       
December 31, 2003
    7,920       205,334       252,854  
December 31, 2004
    9,471       201,759       258,585  
December 31, 2005
    8,792       142,143       194,895  
 
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, 2005, 2004, and 2003 calculations were $61.04, $43.45 and $32.55 per barrel of oil and $10.08, $6.15 and $5.97 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, 2005, 2004 and 2003 is shown below.
 
                         
    December 31,  
    2005     2004     2003  
    (In thousands)  
 
Future cash inflows
  $ 2,849,998     $ 2,155,217     $ 2,105,447  
Future production costs
    (226,248 )     (272,020 )     (272,335 )
Future development costs
    (386,855 )     (357,592 )     (372,139 )
Future income taxes
    (649,002 )     (412,477 )     (360,707 )
Future net cash flows
    1,587,893       1,113,128       1,100,266  
10% annual discount
    (292,730 )     (187,291 )     (150,845 )
Standardized measure of discounted future net cash flows relating to proved reserves
  $ 1,295,163     $ 925,837     $ 949,421  
 
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, 2005, 2004 and 2003 is shown below.
 

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FOREST GULF OF MEXICO OPERATIONS
 
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES — (Continued)
For the Years Ended December 31, 2005, 2004 and 2003

                         
    December 31,  
    2005     2004     2003  
    (In thousands)  
 
Balance, beginning of period
  $ 925,837     $ 949,421     $ 648,040  
Increase (decrease) in discounted future net cash flows:
                       
Sales of oil and gas, net of production costs
    (436,385 )     (426,405 )     (333,029 )
Net changes in prices and future production costs
    692,164       11,628       345,947  
Net changes in future development costs
    (80,948 )     9,615       (82,874 )
Extensions, discoveries and improved recovery
    53,744       88,999       98,561  
Previously estimated development costs incurred during the period
    87,970       70,027       74,690  
Revisions of previous quantity estimates
    109,207       28,701       (104,674 )
Purchases of reserves in place
          100,681       307,686  
Accretion of discount
    122,217       121,720       82,808  
Net change in income taxes
    (178,643 )     (28,550 )     (87,734 )
Balance, end of period
  $ 1,295,163     $ 925,837     $ 949,421  

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