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As filed with the Securities and Exchange Commission on November 13, 2006
Registration No. 333-137441
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
Post-Effective Amendment No. 1
to
Form S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
 
 
 
 
Mariner Energy, Inc.
(Exact name of registrant as specified in its charter)
 
         
Delaware   1311   86-0460233
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification No.)
 
One Briar Lake Plaza, Suite 2000
2000 West Sam Houston Parkway South
Houston, Texas 77042
(713) 954-5500
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
 
Teresa Bushman
Senior Vice President and General Counsel
Mariner Energy, Inc.
One Briar Lake Plaza, Suite 2000
2000 West Sam Houston Parkway South
Houston, Texas 77042
(713) 954-5505
(Name, address, including zip code, and telephone number, including area code, of agent for service)
 
Copies to:
 
Kelly B. Rose
Baker Botts L.L.P.
910 Louisiana
One Shell Plaza
Houston, Texas 77002
(713) 229-1234
 
Approximate date of commencement of proposed sale of the securities to the public:  As soon as practicable following the effectiveness of this Registration Statement.
 
If the securities being registered on this Form are to be offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box.  o
 
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act of 1933, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act of 1933, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
TABLE OF ADDITIONAL REGISTRANT GUARANTORS
 
                         
    State or Other
          Primary Standard
 
    Jurisdiction of
    I.R.S. Employer
    Industrial
 
    Incorporation or
    Identification
    Classification
 
Exact Name of Registrant Guarantor(1)
  Organization     Number     Code Number  
 
Mariner Energy Resources, Inc. 
    Delaware       20-3541629       1311  
Mariner LP LLC
    Delaware       20-4414029       1311  
Mariner Energy Texas LP
    Delaware       20-2341980       1311  
(1) The address and telephone number for each guarantor is One BriarLake Plaza, Suite 2000, 2000 West Sam Houston Parkway South, Houston, Texas 77042, and the telephone number at that address is (713) 954-5500.
 
The registrants hereby amend this registration statement on such date or dates as may be necessary to delay its effective date until the registrants shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission acting pursuant to said section 8(a), may determine.
 


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The information in this prospectus is not complete and may be changed. Certain broker-dealers may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where such offer or sale is not permitted.
 
Registration No. 333-137441
 
SUBJECT TO COMPLETION
PRELIMINARY PROSPECTUS DATED NOVEMBER 13, 2006
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   , 2006.


 

 
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  165
  F-1
 Statement re Computation of Ratio of Earnings to Fixed Charges
 Consent of Deloitte & Touche LLP
 Consent of KPMG LLP
 
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