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Mariner Energy 10-K 2009
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
 
 
 
 
     
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 2008
OR
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission file number 1-32747
 
 
 
 
MARINER ENERGY, INC.
 
 
 
 
     
Delaware
(State or other jurisdiction of
incorporation or organization)
  86-0460233
(I.R.S. Employer
Identification Number)
 
One BriarLake Plaza, Suite 2000
2000 West Sam Houston Parkway South
Houston, Texas 77042
(Address of principal executive offices and zip code)
 
(713) 954-5500
 
 
 
 
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of Each Class
 
Name of Each Exchange on Which Registered
 
Common Stock, $.0001 par value
Rights to Purchase Preferred Stock
  New York Stock Exchange
New York Stock Exchange
 
Securities registered pursuant to section 12(g) of the Act:
 
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes o     No þ
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ
 
The aggregate market value of the registrant’s common stock held by non-affiliates on June 30, 2008 was approximately $3,166,804,986 based on the closing sale price of $36.97 per share as reported by the New York Stock Exchange on June 30, 2008. The number of shares of common stock of the registrant issued and outstanding on February 20, 2009 was 90,057,276.
 
 
Portions of registrant’s Proxy Statement relating to the Annual Meeting of Stockholders to be held May 11, 2009 are incorporated by reference into Part III of this Form 10-K.
 


 

 
 
                 
      Business     3  
      Risk Factors     23  
      Unresolved Staff Comments     33  
      Properties     33  
      Legal Proceedings     33  
      Submission of Matters to a Vote of Security Holders     34  
 
PART II
      Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     36  
      Selected Financial Data     39  
      Management’s Discussion and Analysis of Financial Condition and Results of Operations     40  
      Quantitative and Qualitative Disclosures About Market Risk     61  
      Financial Statements and Supplementary Data     63  
      Changes in and Disagreements with Accountants on Accounting and Financial Disclosures     115  
      Controls and Procedures     115  
      Other Information     115  
 
PART III
      Directors, Executive Officers and Corporate Governance     115  
      Executive Compensation     115  
      Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     115  
      Certain Relationships and Related Transactions, and Director Independence     116  
      Principal Accounting Fees and Services     116  
 
PART IV
      Exhibits, Financial Statement Schedules     116  
 EX-12
 EX-21
 EX-23.1
 EX-23.2
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 
 
Various statements in this annual report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. 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,” “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 annual report speak only as of the date of this annual report; we disclaim any obligation to update these statements unless required by 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 described in “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” elsewhere in this annual report. These risks, contingencies and uncertainties relate to, among other matters, the following:
 
  •  the volatility of oil and natural gas prices;


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  •  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 events and natural disasters such as loop currents, hurricanes, fires, floods and other natural events, 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; and
 
  •  risks related to significant acquisitions or other strategic transactions, such as failure to realize expected benefits or objectives for future operations.


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The following discussion is intended to assist you in understanding our business and the results of our operations. It should be read in conjunction with the Consolidated Financial Statements and the related notes that appear elsewhere in this report. Certain statements made in our discussion may be forward looking. Forward-looking statements involve risks and uncertainties and a number of factors could cause actual results or outcomes to differ materially from our expectations. See “Cautionary Statements” at the beginning of this report on Form 10-K for additional discussion of some of these risks and uncertainties. Unless the context otherwise requires or indicates, references to “Mariner,” “we,” “our,” “ours,” and “us” refer to Mariner Energy, Inc. and its consolidated subsidiaries collectively. Certain oil and natural gas industry terms used in this annual report are defined in the “Glossary of Oil and Natural Gas Terms” set forth in “Item 1. Business” of this annual report.
 
Item 1.   Business.
 
 
Mariner Energy, Inc. is an independent oil and gas exploration, development, and production company. We were incorporated in August 1983 as a Delaware corporation. Our corporate headquarters are located at One BriarLake Plaza, Suite 2000, 2000 West Sam Houston Parkway South, Houston, Texas 77042. Our telephone number is (713) 954-5500 and our website address is www.mariner-energy.com. Our common stock is listed on the New York Stock Exchange and trades under the symbol “ME.”
 
We currently operate in three principal geographic areas:
 
  •  Permian Basin, where we are an active driller in the prolific Spraberry field at depths between 6,000 and 10,000 feet. Our increasing Permian Basin operation, which is characterized by long reserve life, stable drilling and production performance, and relatively lower capital requirements, somewhat counterbalances the higher geological risk, operational challenges and capital requirements attendant to most of our Gulf of Mexico deepwater operations. We have expanded our presence in the region, targeting a combination of infill drilling activities in established producing trends, including the Spraberry, Dean and Wolfcamp trends, as well as exploration activities in emerging plays such as the Wolfberry and newer Wolfcamp trends.
 
  •  Gulf of Mexico Deepwater, where we have actively conducted exploration and development projects since 1996 in water depths ranging from 1,300 feet up to 7,000 feet. Employing our experienced geoscientists, rich seismic database, and extensive subsea tieback expertise, we have participated in more than 84 deepwater wells. Our deepwater exploration operation targets larger potential reserve accumulations than are generally accessible onshore or on the Gulf of Mexico shelf.
 
  •  Gulf of Mexico Shelf, where we drill or participate in conventional shelf wells and deep shelf wells extending to 1,300 foot water depths. We currently pursue a two-pronged strategy on the shelf, combining opportunistic acquisitions of legacy producing fields believed to hold exploitation potential and active exploration activities targeting conventional and deep shelf opportunities. Given the highly mature nature of this area and the steep production declines characteristic of most wells in this region, the goal of our shallow water or shelf operation is to maximize cash flow for reinvestment in our deepwater and Permian Basin operations, as well as for expansion into new operating areas.
 
During 2008, we produced approximately 118.4 Bcfe and our average daily production rate was 323 MMcfe per day. At December 31, 2008, we had 973.9 Bcfe of estimated proved reserves, of which approximately 57% were natural gas and 43% were oil, natural gas liquids (“NGLs”) and condensate. Approximately 70% of our estimated proved reserves were classified as proved developed.
 
We file annual, quarterly and current reports, proxy statements and other information as required by the Securities and Exchange Commission (“SEC”). Our SEC filings are available to the public over the Internet at the SEC’s web site at www.sec.gov. or at the SEC’s public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information about the public reference room. Reports and other information about Mariner can be inspected at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005. Copies of our SEC filings are available free of


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charge on our website at www.mariner-energy.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information on our website is not a part of this annual report. Copies of our SEC filings can also be provided to you at no cost by writing or telephoning us at our corporate headquarters.
 
 
Gulf of Mexico Deepwater Acquisition — On December 19, 2008, we acquired additional working interests in our existing property, Atwater Valley Block 426 (Bass Lite), for approximately $32.6 million, increasing our working interest by 11.6% to 53.8%. We internally estimated proved reserves attributable to the acquisition of approximately 17.6 Bcfe (100% natural gas).
 
Acquisition of Incremental Spraberry Interests — On February 29, 2008 and December 1, 2008, we acquired additional working interests in certain of our existing properties in the Spraberry field in the Permian Basin, increasing our average working interest across these properties to approximately 80%. We internally estimated proved reserves attributable to the acquisition of approximately 27.4 Bcfe. We operate substantially all of the assets. The purchase prices were approximately $21.7 million for the February acquisition and $19.4 million for the December acquisition.
 
 
In recent years, oil and gas commodity prices generally trended upwards in response to robust demand and constrained supplies, with oil and gas prices peaking at more than $140.00 per barrel and $13.00 per Mcf, respectively, in July 2008. In response to the sustained increase in commodity prices, the oil and gas industry experienced significant increases in activity and in demand for oil field services. The increased demand for these services resulted in significant inflation in the cost of drilling rigs, services, equipment and labor.
 
In the second half of 2008, a world-wide economic recession and oversupply of natural gas in North America led to an unprecedented decline in oil and gas prices, with oil falling by more than $100.00 per barrel from its peak earlier in 2008. However, the inflated cost of oil field services resulting from sustained historically high commodity prices did not decrease in line with the decline in commodity prices. The prospect of continued low commodity prices and disproportionately high service costs has constrained the industry’s capital reinvestment and undermined rates of return in new projects, particularly those in areas characterized by high costs or long reserve lives. In order to manage our capital program within expected cash flows, we tentatively have reduced our 2009 capital budget by more than 50% from 2008.
 
Our 2009 activities in the Permian Basin will focus primarily on expanding beyond our typical Spraberry infill drilling operation into new exploration plays, such as the Wolfberry and Wolfcamp Detrital trends. We plan to delineate prospects and determine their economic viability. Our goal is to expand our prospect inventory and generate opportunities to drill when commodity prices or service costs adjust to levels expected to yield more attractive returns. Until then, we are scaling down our infill drilling and development activities to primarily lease-saving operations and contractual drilling commitments. We also anticipate substantially reduced recompletion and development activities in our Gulf of Mexico shelf operation until commodity price and service cost dynamics adjust to allow a more attractive rate of return. In addition, we are allocating a disproportionate portion of our 2009 capital budget to our Gulf of Mexico deepwater exploration program due primarily to contractual drilling commitments.
 
 
We are a growth company and strive to increase our reserves and production from our existing asset base as well as through expansion into new operating areas. Our management team pursues a balanced growth strategy employing varying elements of exploration, development, and acquisition activities in complementary operating regions intended to achieve an overall moderate-risk growth profile at attractive rates of return under most industry conditions.
 
  •  Exploration:  Our exploration program is designed to facilitate organic growth through exploration in a wide variety of exploratory drilling projects, including higher-risk, high-impact projects that have the potential to create substantial value for our stockholders. We view exploration as a core competency. We typically dedicate a significant portion of our capital program each year to prospecting for new oil


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  and gas fields, including in the Gulf of Mexico deepwater where reserve accumulations are typically much larger than those found onshore or on the shelf. Our explorationists have a distinguished track record in the Gulf of Mexico. Our reputation for generating high-quality exploration prospects also can create potentially valuable partnering opportunities, which can enable us to participate in exploration projects developed by other operators.
 
  •  Development:  Our development efforts are intended to complement our higher-risk exploration projects through a variety of moderate-risk activities targeted at maximizing recovery and production from known reservoirs as well as finding overlooked oil and gas accumulations in and around existing fields. Our geoscientists and engineers have a solid track record in effectively developing new fields, redeveloping legacy fields, rejuvenating production, controlling unit costs, and adding incremental reserves at attractive finding costs in both onshore and offshore fields. Our development and exploitation program strives to enhance the rate of returns of our projects, allowing us to establish critical operating mass from which to expand in our focus areas, and generate a rich portfolio of relatively lower-risk engineering/exploitation projects that counterbalance our higher-risk exploration activities.
 
  •  Acquisitions:  In addition to our internal exploration and development activities on our existing properties, we also compete actively for new oil and gas properties through property acquisitions as well as corporate transactions. Our management team has substantial experience identifying and executing a wide variety of tactical and strategic transactions that augment our existing operations or present opportunities to expand into new operating regions. We primarily focus our acquisition efforts on stable, onshore basins such as the Permian Basin, which can counterbalance our growing deepwater exploration operations, but we also respond in an opportunistic fashion to attractive acquisition opportunities in the Gulf of Mexico. Due to our existing prospect inventory, we are not compelled to make acquisitions in order to grow; however we expect to continue to pursue acquisitions aggressively on an opportunistic basis as an integral part of our growth strategy.
 
 
We believe our core resources and strengths include:
 
Diversity of assets and activities.  Our assets and operations are diversified among the Permian Basin and the Gulf of Mexico deepwater and shelf. Each of these areas involves distinctly different operational characteristics, as well as different financial and operational risks and rewards. Moreover, within these operating areas we pursue a breadth of exploration, development and acquisition activities, which in turn entail unique risks and rewards. By diversifying our assets both onshore and in the Gulf, and pursuing a full range of exploration, development and acquisition activities, we strive to mitigate concentration risk and avoid overdependence on any single activity to facilitate our growth. By maintaining a variety of investment opportunities ranging from high-risk, high-impact projects in the deepwater to relatively low-risk, repeatable projects in the Permian Basin, we attempt to execute a balanced capital program and attain a more moderate company-wide risk profile while still affording our stockholders the significant potential upside attendant to an active deepwater exploration company.
 
Large prospect inventory.  We believe we have significant potential for growth through the exploration and development of our existing asset base. We are one of the largest leaseholders among independent producers in the Gulf of Mexico. Additionally, we are an active participant at MMS lease sales. We were the apparent high bidder on three blocks at the Outer Continental Shelf 207 Lease Sale held on August 20, 2008 by the MMS. The MMS awarded all three blocks to us, yielding an aggregate exposure of $0.9 million. We hold a 100% working interest in each of these blocks. In addition, the MMS awarded us 19 blocks on which we were the apparent high bidder at the Central Gulf of Mexico Lease Sale 206 held by the MMS on March 19, 2008. The awarded blocks involve seven deepwater subsalt prospects (both Miocene and Lower Tertiary), four deepwater prospects, four deep shelf prospects, and one conventional shelf prospect. Our net exposure on the awarded bids was $79.1 million and our working interest ranges from 33% to 100%. Furthermore, in the Permian Basin we have a large and growing asset base that we anticipate is capable of sustaining our current drilling program for a number of years. We believe that our large acreage position makes us less dependent on acquisitions for our growth as compared to companies that have less extensive drilling inventories.


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Exploration expertise.  Our seasoned team of geoscientists has made significant discoveries in the Gulf of Mexico and has achieved a cumulative 65% success rate during the three years ended December 31, 2008. Our geoscientists each average almost 30 years of relevant industry experience. We believe our emphasis on exploration allows us a competitive advantage over other companies who are either wholly dependent on acquisitions for growth or only sporadically engage in more limited exploration activities.
 
Operational control and substantial working interests.  We serve as operator of properties representing approximately 87% of our production and have an average 74% working interest in our operated properties. We believe operating our properties gives us a competitive advantage over non-operating interest holders, particularly in a challenging financial environment, since operatorship better allows us to determine the extent and timing of our capital programs, as well as to assert the most direct impact on operating costs.
 
Extensive seismic library.  We have access to recent-vintage, regional 3-D seismic data covering a significant portion of the Gulf of Mexico. We use seismic technology in our exploration program to identify and assess prospects, and in our development program to assess hydrocarbon reservoirs with a goal of optimizing drilling, workover and recompletion operations. We believe that our investment in 3-D seismic data gives us an advantage over companies with less extensive seismic resources in that we are better able to interpret geological events and stratigraphic trends on a more precise geographical basis utilizing more detailed analytical data.
 
Subsea tieback expertise.  We have accumulated an extensive track record in the use of subsea tieback technology, which enables production from subsea wells to existing third-party production facilities through subsea flow line and umbilical infrastructure. This technology typically allows us to avoid the significant lead time and capital commitment associated with the fabrication and installation of production platforms or floating production facilities, thereby accelerating our project start ups and reducing our financial exposure. In turn, we believe this lowers the economic thresholds of our target prospects and allows us to exploit reserves that otherwise may be considered non-commercial because of the high cost of stand-alone production facilities.
 
 
Our principal oil and gas properties are located in the Permian Basin and the Gulf of Mexico deepwater and shelf. The Gulf of Mexico properties are primarily in federal waters. The following table presents our top fields by estimated proved reserves for each principal geographic area:
 
                                         
                      Net
     
          Approximate
          Estimated
    Estimated
          Working
    2008 Net
    Proved
    Proved Reserves
    Operator     Interest %     Production     Reserves     % Oil /% Gas(1)
                (Bcfe)     (Bcfe)      
 
Permian Basin:
                                       
Spraberry
    Mariner       80 %     13.5       419.1       69%/31%  
Gulf Of Mexico Deepwater:
                                       
Atwater Valley 426 (Bass Lite)
    Mariner       54 %     8.5       95.8       0%/100%  
Garden Banks 462 (Geauxpher)
    Mariner       60 %           32.7       3%/97%  
Green Canyon 646 (Daniel Boone)
    W&T Offshore       40 %           18.3       68%/32%  
East Breaks 558/602 (Northwest Nansen)
    Anadarko       33-50 %     12.9       16.6       34%/66%  
Ewing Bank 921 (North Black Widow)
    ENI       35 %     1.9       7.8       91%/9%  
Gulf Of Mexico Shelf:
                                       
Vermilion 380
    Mariner       80 %     0.5       33.1       50%/50%  
Vermilion 14/26/35
    Mariner       100 %     1.5       30.1       8%/92%  
West Cameron 110
    Mariner       100 %     4.7       29.3       4%/96%  
South Pass 24
    Mariner       97 %     1.8       21.5       61%/39%  
High Island 116
    Mariner       100 %     0.8       19.5       3%/97%  
 
 
(1) NGLs are included in Oil


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(MAP)
 
 
Our Permian Basin operations historically have emphasized downspacing redevelopment activities in the prolific oil-producing Spraberry field in the Permian Basin. Since we began our Permian Basin redevelopment initiative in 2002, we have increased by approximately five-fold our net acreage position in the related fields and are targeting the Permian Basin for continued expansion through our Permian Basin operation’s headquarters in Midland, Texas. Production from the region is primarily from the Spraberry, Dean and Wolfcamp formations at depths between 6,000 and 10,000 feet, and is heavily weighted toward long-lived oil and NGLs.
 
During 2008, our Permian Basin operations produced approximately 14.9 Bcfe (13% of our total production) and accounted for approximately 436.6 Bcfe or 45% of our total estimated proved reserves at year end. Oil and NGLs accounted for 73% of total the Permian Basin production for 2008. We drilled 122 wells in the region during 2008 with a 100% success rate. Based upon our current level of drilling activity, our drilling inventory in this area would sustain a five-year drilling program.
 
Our largest field in the Permian Basin by reserves is the Spraberry Field, where we have been active for more than 20 years. We operate our wells in this field and hold an average 80% working interest. This property consists of net developed and undeveloped acres of 55,989 and 8,907, respectively on which there were 829 wells as of December 31, 2008 producing approximately 13.5 Bcfe net in 2008. This field is located in the Spraberry trend and productive zones in the field include the Spraberry, Dean and Wolfcamp formations. At year-end 2008, our share of estimated proved reserves attributed to this field was 419.1 Bcfe, consisting of 69% oil and 31% natural gas.

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We have acquired and maintained a significant acreage position in the Gulf of Mexico deepwater. We have successfully generated and operated deepwater exploration and development projects since 1996. As a corollary to our exploration activities, we have pioneered sophisticated deepwater development strategies employing extensive subsea tieback technologies that allow us to produce our discoveries without the expense of permanent production facilities. As of December 31, 2008, we held interests in 95 deepwater blocks and 40 subsea wells. These wells were tied back to 31 host production facilities for production processing. An additional four wells were then under development for tieback to two additional host production facilities. Although we have interests throughout the Gulf of Mexico, we focus much of our efforts in infrastructure-dominated corridors where our subsea technology can be most efficiently deployed. We feel our geological understanding based on exploration success in these corridors gives us a competitive advantage in assessing prospects and vying for new leases.
 
Production in our Gulf of Mexico deepwater operations is largely from Pleistocene to lower Miocene aged formations and varies between oil and gas depending on formation and age. During 2008, our deepwater operation produced approximately 40.4 Bcfe (34% of our total production) and accounted for approximately 198.7 Bcfe or 20% of our total estimated proved reserves at year end. Natural gas accounted for 69% of total deepwater production for 2008. We drilled eight wells in the region during 2008 with a 63% success rate.
 
We operate Atwater Valley 426, known as Bass Lite, in which in December 2008 we increased our working interest by 11.6% to 53.8%. It is in the Pleistocene formation and is located in approximately 6,750 feet of water. The field consists of two development wells drilled during 2007 that are connected by a 56-mile subsea tieback to the Devil’s Tower spar. Production on Bass Lite began in February 2008 and the field produced 8.5 Bcfe net to our interest during 2008. The project commenced production at full capacity once the topside facilities work was completed in August 2008. At year end 2008, our share of estimated proved reserves attributed to this field was 95.8 Bcfe, of which 100% are natural gas.
 
We operate Garden Banks 462, known as Geauxpher, in which we hold a 60% working interest. We made this deepwater discovery in June 2008. The well, which lies in water depths of approximately 2,700 feet, was drilled to a total depth of 23,156 feet (measured depth). At year-end 2008, our share of estimated proved reserves attributed to the discovery was 32.7 Bcfe, consisting of 3% oil and 97% natural gas. A two-well development is underway, with initial production expected during the first half of 2009. Apache Corporation holds a 40% working interest in the development.
 
Green Canyon 646, known as Daniel Boone, is operated by W&T Offshore, Inc. and consists of one well in the Pliocene/Pleistocene formation. It is located in approximately 4,200 feet of water and we have an approximate 40% working interest in the well. The field is being developed and first production is expected in 2009. At year end 2008, our share of estimated proved reserves attributed to this field was 18.3 Bcfe, consisting of 68% oil and 32% natural gas.
 
East Breaks 558/602, known as Northwest Nansen, is operated by Anadarko Petroleum Corp. The field, which is in the Pliocene/Pleistocene formation, consists of four wells in approximately 3,500 feet of water that are connected by subsea tiebacks to the Nansen spar. We hold a 50% working interest in the East Breaks 558 well, which was completed as a gas well, and a 33% working interest in the three East Breaks 602 wells, which were completed as oil wells. The field began producing in February 2008 and the field produced 12.9 Bcfe net to our interest during 2008. At year end 2008, our share of estimated proved reserves attributed to the field was 16.6 Bcfe, consisting of 34% oil and 66% natural gas.
 
Ewing Bank 921, known as North Black Widow, is operated by ENI Petroleum US and began producing in the Pliocene/Pleistocene formation in 2007. We hold an approximate 35% working interest in one well, which is located in approximately 1,700 feet of water. Our share of net production during 2008 was approximately 1.9 Bcfe. At year end 2008, our share of estimated proved reserves attributed to the field was 7.8 Bcfe, consisting of 91% oil and 9% natural gas.
 
 
As an operator on the Gulf of Mexico shelf for a number of years, we expanded our Gulf of Mexico shelf operations in 2006 through our acquisition of the Gulf of Mexico operations of Forest Oil Corporation


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(“Forest”) and in January 2008 through our acquisition of an indirect subsidiary of StatoilHydro ASA that owns substantially all of its former Gulf of Mexico shelf assets and operations. We increased our interests in shelf operations to 335 blocks at year-end 2008 from 235 blocks at year-end 2007. Due to our operational scale and substantial lease position on the shelf, we are able to pursue a diverse array of exploration and development projects on the shelf, including numerous engineering projects designed to increase production and reserves, as well as to manage production costs through optimization of topside facilities and efficiencies of scale. Drilling prospects run the gamut from relatively small, low-risk, conventional shelf projects that can be drilled from one of our numerous existing platform facilities, to high-impact, deep shelf exploration prospects at depths approaching 20,000 total vertical feet.
 
During 2008, our Gulf of Mexico shelf operation produced approximately 63.1 Bcfe (53% of our total production) and accounted for approximately 338.6 Bcfe or 35% of our total estimated proved reserves at year end. Natural gas accounted for 76% of total shelf production for 2008. We drilled 17 wells in the region during 2008 with an 88% success rate.
 
Our largest field in the Gulf of Mexico Shelf by reserves is Vermilion 380. At year-end 2008, estimated proved reserves attributed to this field were 33.1 Bcfe, consisting of approximately 50% oil and 50% natural gas. During 2008, we drilled three wells and completed one well before Hurricane Ike damaged the platform. Hurricane Ike also interrupted the drilling of a fourth well. Remaining development involves finishing the drilling of the fourth well, drilling a fifth well and completing the remaining wells. We anticipate that production from the five new wells will commence by third quarter 2009. The field currently has two producing wells (one of which is the new well we drilled and completed in 2008) in 340 feet of water. These two wells produced approximately 0.5 Bcfe in 2008. We generated this prospect from former Forest properties and hold a 100% working interest in the newly drilled wells.
 
We operate Vermilion 14/26/35, which consists of 10 producing wells in less than 20 feet of water. We hold a 100% working interest in this field. It has been producing for more than 20 years from numerous formations and in 2008 produced approximately 1.5 Bcfe net. At year-end 2008, estimated proved reserves attributed to this field were 30.1 Bcfe, consisting of approximately 8% oil and 92% natural gas.
 
We operate our 100% working interest in West Cameron 110 which consists of six producing wells. We operate the field, which has been producing for more than 20 years from numerous formations in approximately 40 feet of water and produced approximately 4.7 Bcfe net in 2008. At year-end 2008, estimated proved reserves attributed to this field were 29.3 Bcfe, consisting of approximately 4% oil and 96% natural gas.
 
We operate South Pass 24, which consists of 25 producing wells in approximately 10 feet of water. We have a 97% working interest in the property. South Pass 24 has been producing for more than 50 years from numerous formations, and in 2008 produced approximately 1.8 Bcfe net. At year-end 2008, estimated proved reserves attributed to this field were 21.5 Bcfe, consisting of approximately 61% oil and 39% natural gas.
 
We operate High Island 116, which consists of one producing well in approximately 30 feet of water. We have a 100% working interest in the property. It has been producing for more than 20 years and in 2008 produced approximately 0.8 Bcfe net. At year-end 2008, estimated proved reserves attributed to this field were 19.5 Bcfe, consisting of approximately 3% oil and 97% natural gas.


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The following table presents our total production volumes and revenue, excluding the effects of hedging and other revenues, by area for the year ended December 31, 2008.
 
                 
    Volumes     Revenue  
          (In thousands)  
 
Permian Basin:
               
Natural Gas (Bcf)
    4.0     $ 31,339  
Oil (Mbbls)
    1,242.8       122,005  
NGLs (Mbbls)
    578.5       30,765  
                 
Total Natural Gas Equivalent (Bcfe)
    14.9     $ 184,109  
                 
Gulf of Mexico Deepwater:
               
Natural Gas (Bcf)
    27.7     $ 271,979  
Oil (Mbbls)
    1,850.5       180,131  
NGLs (Mbbls)
    264.7       15,053  
                 
Total Natural Gas Equivalent (Bcfe)
    40.4     $ 467,163  
                 
Gulf of Mexico Shelf:
               
Natural Gas (Bcf)
    48.1     $ 467,099  
Oil (Mbbls)
    1,787.7       190,504  
NGLs (Mbbls)
    714.7       39,897  
                 
Total Natural Gas Equivalent (Bcfe)
    63.0     $ 697,500  
                 
Total Production:
               
Natural Gas (Bcf)
    79.8     $ 770,417  
Oil (Mbbls)
    4,881.0       492,640  
NGLs (Mbbls)
    1,557.9       85,715  
                 
Total Natural Gas Equivalent (Bcfe)
    118.4     $ 1,348,772  
                 


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The following table presents certain information with respect to our estimated proved oil and natural gas reserves. The reserve information in the table below is based on estimates made in fully-engineered reserve reports prepared by Ryder Scott Company, L.P. Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of period end prices and current 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.
 
                         
    Year Ended December, 31  
    2008     2007     2006  
 
Estimated proved oil and natural gas reserves:
                       
Natural gas reserves (Bcf)
    558.0       448.4       426.7  
Oil (MMbbls)
    43.8       41.9       32.0  
Natural gas liquids (MMbbls)
    25.5       22.6       16.1  
Total proved oil and natural gas reserves (Bcfe)
    973.9       835.8       715.5  
Total proved developed reserves (Bcfe)
    677.7       563.9       408.7  
PV10 value(1) ($ in millions):
                       
Proved developed reserves
  $ 1,530.1     $ 2,389.1     $ 1,198.9  
Proved undeveloped reserves
    137.4       675.1       362.6  
                         
Total PV10 value(1)
  $ 1,667.5     $ 3,064.2     $ 1,561.5  
                         
Standardized measure of discounted future net cash flows
  $ 1,483.0     $ 2,231.9     $ 1,239.8  
                         
Prices used in calculating end of period proved reserve measures (excluding effects of hedging):
                       
Natural gas ($/MMBtu)
  $ 5.71     $ 6.79     $ 5.62  
Oil ($/bbl)
  $ 44.61     $ 96.01     $ 61.06  
 
The following table sets forth certain information with respect to our estimated proved reserves by geographic area as of December 31, 2008 based on estimates made in a reserve report prepared by Ryder Scott Company, L.P.
 
                                                                 
    Estimated Proved
                         
    Reserve Quantities                          
    Natural
                                           
    Gas
    Oil
    NGLs
    Total
    PV10 Value(1)     Standardized
 
Geographic Area
  (Bcf)     (MMbbls)     (MMbbls)     (Bcfe)     Developed     Undeveloped     Total     Measure  
                            (In millions of dollars)     (In millions)  
 
Permian Basin
    136.2       27.3       22.7       436.6       359.3       (46.3 )     313.0          
Gulf of Mexico Deepwater
    165.9       5.4       0.1       198.7       608.5       25.2       633.7          
Gulf of Mexico Shelf
    255.9       11.1       2.7       338.6       562.3       158.5       720.8          
                                                                 
Total
    558.0       43.8       25.5       973.9       1,530.1       137.4       1,667.5          
                                                                 
Proved Developed Reserves
    420.9       25.9       16.9       677.7                             $ 1,483.0  
                                                                 
 
 
(1) PV10 value (“PV10”) is not a measure under generally accepted accounting principles in the United States of America (“GAAP”) and differs from the corollary GAAP measure “standardized measure of discounted future net cash flows” in that PV10 is calculated without regard to future income taxes. Management believes that the presentation of PV10 values is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our estimated proved reserves independent of our individual income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to our reserves. Because many factors that are unique to each individual company affect the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. For these reasons, management uses, and believes the industry generally uses,


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the PV10 measure in evaluating and comparing acquisition candidates and assessing the potential return on investment related to investments in oil and natural gas properties.
 
PV10 is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. For our presentation of the standardized measure of discounted future net cash flows, please see “Note 16. Supplemental Oil and Gas Reserve and Standardized Measure Information” in the Notes to the Consolidated Financial Statements in Part II, Item 8 in this Annual Report on Form 10-K. The table below provides a reconciliation of PV10 to standardized measure of discounted future net cash flows.
 
                         
    Year Ended December 31,  
Non-GAAP Reconciliation:
  2008     2007     2006  
    (In millions)  
 
Present value of estimated future net revenues (PV10)
  $ 1,667.5     $ 3,064.2     $ 1,561.5  
Future income taxes, discounted at 10%
    (184.5 )     (832.3 )     (321.7 )
                         
Standardized measure of discounted future net cash flows
  $ 1,483.0     $ 2,231.9     $ 1,239.8  
                         
 
Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and the interpretation thereof. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as change in product prices and operating costs, may require revision of such estimates. Accordingly, oil and natural gas quantities ultimately recovered will vary from reserve estimates.
 
 
The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2008 and December 31, 2007.
 
                                 
    Year Ended December 31,  
    2008     2007  
    Gross     Net     Gross     Net  
 
Oil
    936.0       733.0       939.0       684.0  
Natural Gas
    154.0       90.2       223.0       130.0  
                                 
Total
    1,090.0       823.2       1,162.0       814.0  
                                 
 
Acreage
 
The following table sets forth certain information with respect to actual developed and undeveloped acreage in which we own an interest as of December 31, 2008.
 
                                 
    Year Ended December 31, 2008  
    Developed Acres     Undeveloped Acres  
    Gross     Net     Gross     Net  
 
Permian Basin
    72,818       60,801       79,299       48,827  
Gulf of Mexico Deepwater
    102,560       48,618       393,120       224,275  
Gulf of Mexico Shelf
    821,250       433,384       455,153       345,204  
Other Onshore
    1,477       373       5       127  
                                 
Total
    998,105       543,176       927,577       618,433  
                                 


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The following table sets forth that portion of our onshore and offshore undeveloped acreage as of December 31, 2008 that is subject to expiration absent drilling activity during the three years ended December 31, 2011.
 
                                                 
    Undeveloped Acreage
 
    Subject to Expiration in the Year Ended December 31,  
    2009     2010     2011  
    Gross     Net     Gross     Net     Gross     Net  
 
Permian Basin
    1,520       928       27,439       14,474       35,624       17,665  
Gulf of Mexico Deepwater
    17,280       14,112       23,040       3,456       40,320       30,960  
Gulf of Mexico Shelf
    83,526       59,646       37,665       25,364       135,087       103,508  
                                                 
Total
    102,326       74,686       88,144       43,294       211,031       152,133  
                                                 
 
Drilling Activity
 
Certain information with regard to our drilling activity during the years ended December 31, 2008, 2007 and 2006 is set forth below.
 
                                                 
    Year Ended December 31,  
    2008     2007     2006  
    Gross     Net     Gross     Net     Gross     Net  
 
Exploratory wells:
                                               
Productive
    17.00       10.59       11.00       5.96       14.00       5.83  
Dry
    5.00       2.98       8.00       4.91       8.00       3.65  
                                                 
Total
    22.00       13.57       19.00       10.87       22.00       9.48  
                                                 
Development wells:
                                               
Productive
    125.00       88.93       121.00       60.43       168.00       86.23  
Dry
                                   
                                                 
Total
    125.00       88.93       121.00       60.43       168.00       86.23  
                                                 
Total wells:
                                               
Productive
    142.00       99.52       132.00       66.39       182.00       92.06  
Dry
    5.00       2.98       8.00       4.91       8.00       3.65  
                                                 
Total
    147.00       102.5       140.00       71.30       190.00       95.71  
                                                 
 
 
We market substantially all of the oil and natural gas production from the properties we operate, as well as the properties operated by others where our interest is significant. Our natural gas, oil and condensate production is sold to a variety of customers under short-term marketing arrangements at market-based prices. The following table lists customers accounting for more than 10% of our total revenues for the year indicated.
 
                         
    Percentage of Total
 
    Revenues for
 
    Year Ended
 
    December 31,  
Customer
  2008     2007     2006  
 
BP Energy
    5 %     9 %     14 %
ChevronTexaco and affiliates
    16 %     23 %     23 %
Louis Dreyfus Energy
    6 %     9 %     10 %
Plains Marketing LP
    5 %     7 %     11 %
Shell
    10 %     10 %     8 %


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Substantially all of our properties currently are subject to liens securing our bank credit facility and obligations under hedging arrangements with lenders under our bank credit facility. In addition, our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other typical burdens and encumbrances. We do not believe that any of these burdens or encumbrances materially interfere with the use of such properties in the operation of our business. Our properties may also be subject to obligations or duties under applicable laws, ordinances, rules, regulations and orders of governmental authorities.
 
We believe that we have performed customary investigation of, and have satisfactory title to or rights in, all of our producing properties. As is customary in the oil and natural gas industry, minimal investigation of title is made at the time of acquisition of undeveloped properties. Title investigation is made usually only before commencement of drilling operations. We believe that title issues are less likely to arise with offshore oil and natural gas properties than with onshore properties.
 
 
We believe that our leasehold acreage, exploration, drilling and production capabilities, large 3-D seismic database and technical and operational experience enable us to compete effectively. However, our primary competitors include major integrated oil and natural gas companies, nationally owned or sponsored enterprises, and domestic independent oil and natural gas companies. Many of our larger competitors possess and employ financial and personnel resources substantially greater than those available to us. Such companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and discover reserves in the future is dependent upon our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position.
 
 
The Outer Continental Shelf Deep Water Royalty Relief Act (“RRA”), effective November 28, 1995, provides that all tracts in the Western and Central Planning Areas of the Gulf of Mexico, including whole lease blocks in the Eastern Planning Area of the Gulf of Mexico lying west of 87 degrees, 30 minutes West longitude, in water more than 200 meters deep and offered for bid within five years after the effective date of the RRA, will be entitled to royalty relief as follows:
 
     
Water Depth
 
Royalty Relief
 
200-400 meters
  no royalty payable on the first 17.5 million BOE produced
400-800 meters
  no royalty payable on the first 52.5 million BOE produced
800 meters or deeper
  no royalty payable on the first 87.5 million BOE produced
 
Leases offered for bid within five years after the effective date of the RRA are referred to as “post-Act leases.” The RRA also allows federal offshore lessees the opportunity to apply for discretionary royalty relief for new production on leases acquired before the RRA was enacted, or “pre-Act leases.” If the MMS determines that new production under a pre-Act lease would not be economic without royalty relief, then the MMS may relieve a portion of the royalty to make the project economic.
 
In addition to granting discretionary royalty relief, the MMS has elected to include royalty relief provisions in many leases issued after November 28, 2000, or “post-2000 leases.” For these post-2000 lease sales that have occurred to-date for which the MMS has elected to include royalty relief, the MMS has specified the water depth categories and royalty suspension volumes applicable to production from leases issued in the sale.
 
In 2004, the MMS adopted additional royalty relief incentives for production of natural gas from reservoirs located deep under shallow waters of the Gulf of Mexico. These incentives apply to natural gas


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produced in water depths of less than 200 meters and from deep natural gas accumulations of at least 15,000 feet of true vertical depth. Drilling of qualified wells must have started on or after March 26, 2003, and production must begin before May 3, 2009, unless the lessee obtains a one-year extension. These incentives generally apply only to production that occurs during years when the average price of natural gas on the New York Mercantile Exchange does not exceed the price threshold of $10.15 per million Btu, expressed in 2007 dollars. In regulations published in November 2008, the MMS implemented additional royalty relief provisions to reflect statutory changes enacted in the Energy Policy Act of 2005. The regulations provide enhanced incentives for gas production from wells of at least 20,000 feet of true vertical depth in waters of 400 meters or less. These regulations also expand the royalty relief incentives for natural gas produced from leases in waters 200 to 400 meters deep by entitling such leases to the royalty relief incentives available under the existing regulations for leases in less than 200 meters of water, with two exceptions. First, the incentive for production in waters 200 to 400 meters in depth applies to wells for which drilling began on or after May 18, 2007, rather than March 26, 2003, and that begin production before May 3, 2013, rather than May 3, 2009. Second, the applicable price threshold is $4.55 per million Btu, expressed in 2007 dollars, rather than $10.15.
 
The impact of royalty relief can be significant. Effective with lease sales in 2008, royalty rates for leases in all water depths in the Gulf of Mexico increased to 18.75% of production. For Gulf of Mexico leases awarded in 2007 lease sales, the royalty rate was 16.7% of production in all water depths. Royalty relief can substantially improve the economics of projects located in deepwater or in shallow water involving deep natural gas.
 
Many of our MMS leases that are subject to royalty relief contain language that suspends royalty relief if commodity prices exceed predetermined threshold levels for a given calendar year. As a result, royalty relief for a lease in a particular calendar year may be contingent upon average commodity prices remaining below the price threshold specified for that year. Since 2000, commodity prices have exceeded some of the predetermined price thresholds, except in 2002, for a number of our projects. For the affected leases, we have been ordered by the MMS to pay royalties for natural gas produced in some of those years. However, we have challenged the MMS’s authority to include price thresholds in six of our post-Act leases awarded in 1996 and 1997. We believe that post-Act leases are entitled to automatic royalty relief under the RRA, regardless of commodity prices, and have pursued administrative and judicial remedies in this dispute with the MMS. For more information concerning the contested royalty payments and the MMS’s demands, see “Item 3. Legal Proceedings.”
 
Regulation
 
Our operations are subject to extensive and continually changing regulation affecting the oil and natural gas industry. Many departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding on the oil and natural gas industry and its individual participants. The failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. We do not believe that we are affected in a significantly different manner by these regulations than are our competitors.
 
 
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the regulations promulgated thereunder by the Federal Energy Regulatory Commission, or FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of natural gas sales by producers began with the enactment of the Natural Gas Policy Act of 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining Natural Gas Act of 1938 and Natural Gas Policy Act of 1978 price and non-price controls affecting producer sales of natural gas effective January 1, 1993. Congress could, however, re-enact price controls in the future. The FERC regulates interstate natural gas pipeline transportation rates and service conditions, which affect the marketing of gas produced by us and the revenues received by us for sales of such natural gas. The FERC requires interstate pipelines to provide open-


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access transportation on a non-discriminatory basis for all natural gas shippers. The FERC frequently reviews and modifies its regulations regarding the transportation of natural gas with the stated goal of fostering competition within all phases of the natural gas industry. In addition, with respect to production onshore or in state waters, the intra-state transportation of natural gas would be subject to state regulatory jurisdiction as well.
 
In August, 2005, Congress enacted the Energy Policy Act of 2005, or EP Act 2005. Among other matters, EP Act 2005 amends the Natural Gas Act, or NGA, to make it unlawful for “any entity”, including otherwise non-jurisdictional producers such as Mariner, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. On January 19, 2006, the FERC issued regulations implementing this provision. The regulations make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EP Act 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of the FERC’s enforcement authority. We do not anticipate we will be affected any differently than other producers of natural gas.
 
Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective or their effect, if any, on our operations. The natural gas industry historically has been closely regulated; thus, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future.
 
 
The production of oil and natural gas is subject to regulation under a wide range of state and federal statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning operations. Texas and Louisiana, the states in which we own and operate properties, have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells, the spacing of wells, and the plugging and abandonment of wells and removal of related production equipment. Texas and Louisiana also restrict production to the market demand for oil and natural gas and several states have indicated interests in revising applicable regulations. These regulations can limit the amount of oil and natural gas we can produce from our wells, limit the number of wells, or limit the locations at which we can conduct drilling operations. Moreover, each state generally imposes a production or severance tax with respect to production and sale of crude oil, natural gas and gas liquids within its jurisdiction.
 
Most of our offshore operations are conducted on federal leases that are administered by the MMS. Such leases require compliance with detailed MMS regulations and orders pursuant to the Outer Continental Shelf Lands Act that are subject to interpretation and change by the MMS. Among other things, we are required to obtain prior MMS approval for our exploration plans and development and production plans at each lease. MMS regulations also impose construction requirements for production facilities located on federal offshore leases, as well as detailed technical requirements for plugging and abandonment of wells, and removal of platforms and other production facilities on such leases. The MMS requires lessees to post surety bonds, or provide other acceptable financial assurances, to ensure all obligations are satisfied on federal offshore leases. The cost of these surety bonds or other financial assurances can be substantial, and there is no assurance that bonds or other financial assurances can be obtained in all cases. We are currently in compliance with all MMS financial assurance requirements. Under certain circumstances, the MMS is authorized to suspend or terminate


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operations on federal offshore leases. Any suspension or termination of operations on our offshore leases could have an adverse effect on our financial condition and results of operations.
 
Our crude oil and gas production is subject to royalty interests established under the applicable leases. Royalty on production from state and private leases is generally governed by state law and royalty on production from leases on federal or Indian lands is governed by federal law. The MMS is authorized by statute to administer royalty valuation and collection for production from federal and Indian leases. The MMS generally exercises this authority through standards established under its regulations and related policies. We do not anticipate that we will be affected by changes in federal or state law affecting royalty obligations any differently than other producers of crude oil and natural gas.
 
 
Our operations are subject to numerous stringent and complex laws and regulations at the federal, state and local levels governing the discharge of materials into the environment or otherwise relating to human health and environmental protection. These laws and regulations may, among other things:
 
  •  require acquisition of a permit before drilling commences;
 
  •  restrict the types, quantities and concentrations of various materials that can be released into the environment in connection with drilling and production activities; and
 
  •  limit or prohibit construction or drilling activities in certain ecologically sensitive and other protected areas.
 
Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements and the imposition of injunctions to force future compliance. Offshore drilling in some areas has been opposed by environmental groups and, in some areas, has been restricted. Our business and prospects could be adversely affected to the extent laws are enacted or other governmental action is taken that prohibits or restricts our exploration and production activities or imposes environmental protection requirements that result in increased costs to us or the oil and natural gas industry in general.
 
The following is a summary of some of the existing laws and regulations to which our business operations are subject:
 
Spills and Releases.  The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the “owner” and “operator” of the site where the release occurred, past owners and operators of the site, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Responsible parties under CERCLA may be liable for the costs of cleaning up hazardous substances that have been released into the environment and for damages to natural resources. Additionally, it is not uncommon for neighboring landowners and other third parties to file tort claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. In the course of our ordinary operations, we may generate waste that may fall within CERCLA’s definition of a “hazardous substance.”
 
We currently own, lease or operate, and have in the past owned, leased or operated, numerous properties that for many years have been used for the exploration and production of oil and gas. Many of these properties have been operated by third parties whose actions with respect to the treatment and disposal or release of hydrocarbons or other wastes were not under our control. It is possible that hydrocarbons or other wastes may have been disposed of or released on or under such properties, or on or under other locations where such wastes may have been taken for disposal. These properties and wastes disposed thereon may be subject to CERCLA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination, or to pay the costs of such remedial measures. Although we believe we have utilized operating and disposal practices that are standard in the industry, during the course of operations


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hydrocarbons and other wastes may have been released on some of the properties we own, lease or operate. We are not presently aware of any pending clean-up obligations that could have a material impact on our operations or financial condition.
 
The Oil Pollution Act (“OPA”).  The OPA and regulations thereunder impose strict, joint and several liability on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located. The OPA establishes a liability limit for onshore facilities of $350 million, while the liability limit for offshore facilities is equal to all removal costs plus up to $75 million in other damages. These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up.
 
The OPA also requires the lessee or permittee of an offshore area in which a covered offshore facility is located to provide financial assurance in the amount of $35 million to cover liabilities related to an oil spill. The amount of financial assurance required under the OPA may be increased up to $150 million depending on the risk represented by the quantity or quality of oil that is handled by a facility. The failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. We are not aware of any action or event that would subject us to liability under the OPA, and we believe that compliance with the OPA’s financial assurance and other operating requirements will not have a material impact on our operations or financial condition.
 
Water Discharges.  The Federal Water Pollution Control Act of 1972, also known as the Clean Water Act, imposes restrictions and controls on the discharge of produced waters and other oil and gas pollutants into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions may be imposed in the future. Permits must be obtained to discharge pollutants into state and federal waters. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System, or NPDES, program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and gas industry into certain coastal and offshore waters. The Clean Water Act provides for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants, and imposes liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. Comparable state statutes impose liabilities and authorize penalties in the case of an unauthorized discharge of petroleum or its derivatives, or other pollutants, into state waters.
 
In furtherance of the Clean Water Act, the Environmental Protection Agency (“EPA”) promulgated the Spill Prevention, Control, and Countermeasure (“SPCC”) regulations, which require facilities that possess certain threshold quantities of oil that could impact navigable waters or adjoining shorelines to prepare SPCC plans and meet specified construction and operating standards. The SPCC regulations were revised in 2002 and required the amendment of SPCC plans before February 18, 2006, if necessary, and required compliance with the implementation of such amended plans by August 18, 2006. This compliance deadline has been extended multiple times and on May 16, 2007 was extended until July 1, 2009. We have SPCC plans and similar contingency plans in place at several of our facilities, and may be required to prepare such plans for additional facilities where a spill or release of oil could reach or impact jurisdictional waters of the United States. We do not anticipate that the revisions to the SPCC regulations will cause a material impact on our operations or financial condition.
 
Air Emissions.  The Federal Clean Air Act and associated state laws and regulations restrict the emission of air pollutants from many sources, including oil and natural gas operations. New facilities may be required to obtain permits before operations can commence, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. We believe that compliance with the Clean Air


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Act and analogous state laws and regulations will not have a material impact on our operations or financial condition.
 
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least 17 states have declined to wait for Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA must consider whether it is required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases fall under the Federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under various Clean Air Act programs, including those that may be used in our operations. It is not possible at this time to predict how legislation that may be enacted to address greenhouse gas emissions would impact our business. However, future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our operations, results of operations, and cash flows.
 
Waste Handling.  The Resource Conservation and Recovery Act (“RCRA”), and analogous state and local laws and regulations govern the management of wastes, including the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. RCRA specifically excludes from the definition of hazardous waste drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil and natural gas. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate minimal quantities of hazardous wastes. However, these wastes may be regulated by EPA or state agencies as solid waste. In addition, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils, may be regulated under RCRA as hazardous waste. We do not believe the current costs of managing our wastes, as they are presently classified, to be significant. However, any repeal or modification of the oil and natural gas exploration and production exemption, or modifications of similar exemptions in analogous state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses.
 
Endangered Species Act.  The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. We believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
 
Safety.  The Occupational Safety and Health Act, or OSHA, and other similar laws and regulations govern the protection of the health and safety of employees. The OSHA hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and analogous state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governments and citizens. We believe that we are in substantial compliance with these requirements and with other applicable OSHA requirements.
 
 
As of December 31, 2008, we had 276 full-time employees. Our employees are not represented by any labor unions. We have never experienced a work stoppage or strike and we consider relations with our employees to be satisfactory.
 
 
Mariner is a member of OIL Insurance, Ltd. (“OIL”), an energy industry insurance cooperative, which provides our primary layer of physical damage and windstorm insurance coverage. Our coverage is subject to


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a $10.0 million per-occurrence deductible for our assets and a $250.0 million per-occurrence loss limit. However, if a single event causes losses to all OIL-insured assets in excess of $750.0 million, amounts covered for such losses will be reduced on a pro-rata basis among OIL members.
 
In addition to our primary coverage through OIL, we also maintain commercial “difference in conditions” insurance that would apply (with no additional deductible) once our limits with OIL are exhausted, as well as partial business interruption insurance covering certain of our significant producing fields and certain other fields situated in hurricane prone areas. Our business interruption coverage begins to provide benefits after a 60-day waiting period once the designated field is shut-in due to a covered event and is limited to 35% of the forecast cash flow from each designated property. Our commercial policy expires annually on June 1, and is subject to a general limit of $100.0 million per occurrence and in the case of named windstorms, a combined annual aggregate limit of $100.0 million covering both property damage and business interruption.
 
In 2008, our operations were adversely affected by Hurricane Ike. The hurricane resulted in shut-in and delayed production as well as facility repairs and replacement expenses. We are evaluating the nature and extent of damage resulting from the hurricane. With respect to Hurricane Ike, our OIL coverage has a $10.0 million per occurrence deductible and a $250.0 million per occurrence limit, subject to an industry-wide loss limit per occurrence of $750.0 million. To the extent that aggregate claims exceed the OIL industry-wide loss limit per occurrence, we expect our insurance recovery would be reduced pro-rata with all other competing claims from Hurricane Ike and the shortfall covered by our commercial excess insurance, subject to policy limits.
 
Applicable insurance for our Hurricane Katrina and Rita claims with respect to the Gulf of Mexico assets previously acquired from Forest is provided by OIL. Our coverage for the former Forest properties is subject to a deductible of $5.0 million per occurrence and a $1.0 billion industry-wide loss limit per occurrence. OIL has advised us that the aggregate claims resulting from each of Hurricanes Katrina and Rita are expected to exceed the $1.0 billion per occurrence loss limit and that therefore, our insurance recovery is expected to be reduced pro-rata with all other competing claims from the storms. During 2008, we settled our Katrina and Rita claims with our excess insurance providers for a one-time payment of $48.5 million. The insurance coverage for Mariner’s legacy properties is subject to a $3.75 million deductible. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for more information.
 
Glossary of Oil and Natural Gas Terms
 
The following is a description of the meanings of some of the oil and natural gas industry terms used in this annual report. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definitions of those terms can be viewed on the website at http://www.sec.gov/about/forms/forms-x.pdf. Effective for annual reports on Forms 10-K for years ending on or after December 31, 2009, certain definitions contained in Rule 4-10(a) will be revised to reflect the SEC’s adoption of its final rule on the Modernization of Oil and Gas Reporting. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Accounting Pronouncements” for more information.
 
3-D seismic data.  (Three-Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two dimensional seismic data.
 
Appraisal well.  A well drilled several spacing locations away from a producing well to determine the boundaries or extent of a productive formation and to establish the existence of additional reserves.
 
Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.
 
Bcf.  Billion cubic feet of natural gas.
 
Bcfe.  Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.


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Block.  A block depicted on the Outer Continental Shelf Leasing and Official Protraction Diagrams issued by the MMS or a similar depiction on official protraction or similar diagrams issued by a state bordering on the Gulf of Mexico.
 
Boe.  Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
 
Btu or British Thermal Unit.  The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
 
Completion.  The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
 
Condensate.  Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
 
Conventional shelf well.  A well drilled on the outer continental shelf to subsurface depths above 15,000 feet.
 
Deep shelf well.  A well drilled on the outer continental shelf to subsurface depths below 15,000 feet.
 
Deepwater.  Depths greater than 1,300 feet (the approximate depth of deepwater designation by the MMS).
 
Developed acreage.  The number of acres that are allocated or assignable to productive wells or wells capable of production.
 
Development costs.  Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. This definition of development costs has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the website at http://www.sec.gov/about/forms/forms-x.pdf.
 
Development well.  A well drilled within the proved boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive.
 
Differential.  An adjustment to the price of oil or gas from an established spot market price to reflect differences in the quality and/or location of oil or gas.
 
Dry hole.  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
 
Dry hole costs.  Costs incurred in drilling a well, assuming a well is not successful, including plugging and abandonment costs.
 
Exploitation.  Ordinarily considered to be a form of development within a known reservoir.
 
Exploration costs.  Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells. This definition of exploratory costs has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the website at http://www.sec.gov/about/forms/forms-x.pdf.
 
Exploratory well.  A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.
 
Farm-in or farm-out.  An agreement under which the owner of a working interest in an oil or gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”
 
Field.  An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
 
Gas.  Natural gas.


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Gross acres or gross wells.  The total acres or wells, as the case may be, in which a working interest is owned.
 
Lease operating expenses.  The expenses of lifting oil or gas from a producing formation to the surface, and the transportation and marketing thereof, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, ad valorem taxes and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.
 
Mbbls.  Thousand barrels of crude oil or other liquid hydrocarbons.
 
Mcf.  Thousand cubic feet of natural gas.
 
Mcfe.  Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
MMBls.  Million barrels of crude oil or other liquid hydrocarbons.
 
MMBtu.  Million British Thermal Units.
 
MMcf.  Million cubic feet of natural gas.
 
MMcfe.  Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.
 
MMS.  Minerals Management Service of the United States Department of the Interior.
 
Net acres or net wells.  The sum of the fractional working interests owned in gross acres or wells.
 
Net revenue interest.  An interest in all oil and natural gas produced and saved from, or attributable to, a particular property, net of all royalties, overriding royalties, net profits interests, carried interests, reversionary interests and any other burdens to which the person’s interest is subject.
 
Operator.  The individual or company responsible for the exploration and/or exploitation and/or production of an oil or gas well or lease.
 
Payout.  Generally refers to the recovery by the incurring party to an agreement of its costs of drilling, completing, equipping and operating a well before another party’s participation in the benefits of the well commences or is increased to a new level.
 
Plugging and abandonment.  Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of many states require plugging of abandoned wells.
 
PV10 or present value of estimated future net revenues.  An estimate of the present value of the estimated future net revenues from proved oil and gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future net revenues are discounted at an annual rate of 10%, in accordance with the SEC’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the date indicated and held constant for the life of the reserves.
 
Productive well.  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
 
Prospect.  A specific geographic area, which based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
 
Proved developed non-producing reserves.  Proved developed reserves expected to be recovered from zones behind casing in existing wells.
 
Proved developed producing reserves.  Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production to market.


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Proved developed reserves.  Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the website at http://www.sec.gov/about/forms/forms-x.pdf.
 
Proved reserves.  The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. This definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the website at http://www.sec.gov/about/forms/forms-x.pdf.
 
Proved undeveloped reserves.  Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire term definition can be viewed at website http://www.sec.gov/about/forms/forms-x.pdf.
 
Recompletion.  The completion for production in an existing well bore to another formation from that which the well has been previously completed.
 
Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
 
Shelf.  Areas in the Gulf of Mexico with depths less than 1,300 feet. Our shelf area and operations also includes a small amount of properties and operations in the onshore and bay areas of the Gulf Coast.
 
Subsea tieback.  A method of completing a productive well by connecting its wellhead equipment located on the sea floor by means of control umbilical and flow lines to an existing production platform located in the vicinity.
 
Subsea trees.  Wellhead equipment installed on the ocean floor.
 
Standardized measure of discounted future net cash flows.  The standardized measure represents value-based information about an enterprise’s proved oil and gas reserves based on estimates of future cash flows, including income taxes, from production of proved reserves assuming continuation of year-end economic and operating conditions.
 
Undeveloped acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether or not such acreage contains proved reserves.
 
Working interest.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.
 
Item 1A.   Risk Factors.
 
Risks Relating to the Oil and Natural Gas Industry and to Our Business
 
 
The recent worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets could lead to an extended worldwide economic recession. A recession or slowdown in economic activity would likely reduce worldwide demand for energy and result in lower oil and natural gas prices, which could materially adversely affect our profitability and results of operations.
 
In addition, the economic crisis may adversely affect our liquidity. We may be unable to obtain adequate funding under our bank credit facility because our lending counterparties may be unwilling or unable to meet their funding obligations, or because our borrowing base under the facility may be decreased as the result of a redetermination, reducing it due to lower oil or natural gas prices, operating difficulties, declines in reserves or


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other reasons. If funding is not available as needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or we may be unable to implement our business strategies or otherwise take advantage of business opportunities or respond to competitive pressures.
 
 
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 increased to, and then declined significantly from, historical highs in 2008 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. To the extent that oil or natural gas comprises more than 50% of our production or estimated proved reserves, our financial results may be more sensitive to movements in prices of that commodity. 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. See “Item 1. Business — Estimated Proved Reserves.” In addition, we may, from time to time, enter into long-term contracts based upon our reasoned expectations for commodity price levels. If commodity prices subsequently decrease significantly for a sustained period, we may be unable to perform our obligations or otherwise breach the contract and be liable for damages.
 
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 other factors, many of


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which are beyond our control. At December 31, 2008, approximately 30% of our estimated proved reserves were proved undeveloped.
 
If the interpretations or assumptions we use in arriving at our estimates prove to be inaccurate, the amount of oil and natural gas that we ultimately recover may differ materially from the estimated quantities and net present value of reserves shown in this report. See “Item 1. Business — Estimated Proved Reserves” for information about our oil and gas reserves.
 
In estimating future net revenues from estimated 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 estimated proved reserves referred to in this report 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 estimated 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.
 
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 estimated 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 SEC 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 natural 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.
 
 
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. At December 31, 2008, the net capitalized cost of our proved oil and gas properties exceeded the ceiling limit and we recorded a non-cash ceiling test impairment of $575.6 million during the fourth quarter. Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Oil and Gas Properties,” and “Note 1. Summary of Significant Accounting Policies” in the Notes to the Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K for a discussion of our use of the full cost method of accounting for our oil and gas properties and its impact at December 31, 2008. We may incur other 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.
 
 
Unless we conduct successful exploration and development activities or acquire properties containing proven reserves, our estimated 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. 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 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


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current and future production, our production rates will decline even if we drill the undeveloped locations that were included in our estimated 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.
 
 
As of December 31, 2008, approximately 20% of our total estimated proved reserves were developed non-producing and approximately 30% were undeveloped. 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 a material adverse effect on our results of operations.
 
 
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.
 
 
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 decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain. Even when used and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators. 3-D seismic data do 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 may 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.


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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 events and natural disasters, such as loop currents, and 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.
 
 
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.
 
Exploration for oil or natural gas in the Gulf of Mexico deepwater 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. Moreover, deepwater projects often lack proximity to the physical and oilfield service infrastructure present in the shallow waters of the Gulf of Mexico, necessitating significant capital investment in subsea flow line infrastructure. Subsea tieback production systems require 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. As a result, a significant amount of time and capital must be invested before we can market 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. See “Item 1. Business — Properties — Gulf of Mexico Deepwater Operations” in this Annual Report on Form 10-K for information about our use of tieback technology.
 
 
We typically enter into hedging arrangements pertaining to a substantial portion of our expected future production in order 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


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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. Our hedging arrangements reduced the benefit we received from increases in oil and natural gas prices by approximately $100.8 million in 2008. 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.
 
 
Our revenues are generated under contracts with various counterparties. Results of operations would be adversely affected as a result of non-performance by any of these counterparties of their contractual obligations under the various contracts. A counterparty’s default or non-performance could be caused by factors beyond our control such as a counterparty experiencing credit default. A default could occur as a result of circumstances relating directly to the counterparty, such as defaulting on its credit obligations, or due to circumstances caused by other market participants having a direct or indirect relationship with the counterparty. Defaults by counterparties may occur from time to time, and this could negatively impact our results of operations, financial position and cash flows.
 
 
Properties we acquire may not produce as expected, may be in an unexpected condition and may subject us to increased costs and liabilities, including environmental liabilities. The reviews we conduct of acquired properties, prior to acquisition, are not capable of identifying all potential adverse conditions. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties or properties with known adverse conditions and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems or permit a buyer to become sufficiently familiar with the properties to assess fully their condition, any deficiencies, and development potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.
 
 
Market conditions, 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.
 
 
Increased drilling activity periodically results in service cost increases and shortages in drilling rigs, personnel, equipment and supplies in certain areas. 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. Increases in drilling activity in the United States or the Gulf of Mexico could exacerbate this situation.


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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.
 
 
From time to time, we enter into farm-out agreements to fund a portion of the exploration and development costs of our prospects. Moreover, other companies operate some of the other properties in which we have an ownership interest. Liquidity and cash flow problems encountered by our partners and co-owners of our properties may lead to a delay in the pace of drilling or project development that may be detrimental to a project. In addition, our farm-out partners and working interest owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farm-out partner, we may have to obtain alternative funding in order to complete the exploration and development of the prospects subject to the farm-out agreement. In the case of a working interest owner, we may be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary in order to fund either of these contingencies.
 
 
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.
 
 
Exploration for and development, production and sale of oil and natural gas in the United States 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


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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 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 “Item 1. Business — Regulation” for more information on our regulatory and environmental matters.
 
 
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 the installation and removal of all production facilities and govern the calculation of royalties and the valuation of crude oil produced from federal leases.
 
 
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 the losses sustained in 2005 from Hurricanes Katrina and Rita and in 2008 from Hurricane Ike, as well as other factors affecting market conditions, premiums and deductibles for certain insurance policies, including windstorm insurance, have increased substantially. 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 that 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. 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 “Item 1. Business — Insurance Matters” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for more information.
 
 
 
We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. Significant acquisitions and other strategic transactions may involve many risks, including:
 
  •  diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;


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  •  challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;
 
  •  our exposure to unforeseen liabilities of acquired businesses, operations or properties;
 
  •  possibility of faulty assumptions underlying our expectations, including assumptions relating to reserves, future production, volumes, revenues, costs and synergies;
 
  •  difficulty associated with coordinating geographically separate organizations; and
 
  •  challenge of attracting and retaining personnel associated with acquired operations.
 
The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
 
 
The success of a significant acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations with those of ours. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, or in oil and natural gas industry conditions, or by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.
 
 
Future significant acquisitions and other strategic transactions could result in our incurring additional debt, contingent liabilities and expenses, all of which could decrease our liquidity or otherwise have a material adverse effect on our financial condition and operating results. In addition, an issuance of securities in connection with such transactions could dilute or lessen the rights of our current common stockholders.
 
Risks Relating to Financings
 
 
We may require financing beyond our cash flow from operations to fully execute our business plan. 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 borrowings from affiliates. In the future, we will require substantial capital to fund our business plan and operations. We expect to meet our needs from one or more of our excess cash flow, debt financings and equity offerings. Sufficient capital may not be available on acceptable terms or at all. If we cannot obtain additional capital resources, we may curtail our drilling, development and other activities or be forced to sell some of our assets on unfavorable terms.
 
The issuance of additional debt would require that a portion of our cash flow from operations be used for the payment of interest on our debt, thereby reducing our ability to use our cash flow to fund working capital, capital expenditures, acquisitions and general corporate requirements, which could place us at a competitive disadvantage relative to other competitors. Additionally, if revenues decrease as a result of lower oil or natural gas prices, operating difficulties or declines in reserves, our ability to obtain the capital necessary to undertake or complete future exploration and development programs and to pursue other opportunities may be limited. This could also 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.


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We expect our earnings and cash flow to vary significantly from year to year due to price volatility. 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. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.
 
 
Our level of indebtedness and the covenants contained in the agreements governing our debt could have important consequences for our operations, including:
 
  •  making it more difficult for us to satisfy our debt obligations 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;
 
  •  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 bank 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 bank credit facility and the indentures governing our two series of senior unsecured notes, we must comply with certain financial covenants, including current asset and total debt ratio requirements under the bank credit facility. 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 indentures or the bank credit facility could result in a default under the applicable agreement or a cross default under each 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 that we will be able to generate sufficient cash flow to pay the interest on our debt or those 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


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bank 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, the value of our assets and our operating performance at the time of such offering or other financing. We cannot assure that any such offerings, refinancing or sale of assets could be successfully completed.
 
Item 1B.   Unresolved Staff Comments.
 
None.
 
Item 2.   Properties.
 
See “Item 1. Business” for discussion of oil and gas properties and locations.
 
We have offices in Houston and Midland, Texas and Lafayette, Louisiana. As of December 31, 2008, our leases covered approximately 94,226 square feet, 6,580 square feet and 14,376 square feet of office space in Houston, Midland and Lafayette, respectively. The leases run through October 31, 2018, October 31, 2011 and September 30, 2013 in Houston, Midland and Lafayette, respectively. The total annual costs of our leases for 2008 were approximately $2.1 million.
 
Item 3.   Legal Proceedings.
 
Mariner and its subsidiary, Mariner Energy Resources, Inc. (“MERI”), own numerous properties in the Gulf of Mexico. Certain of such properties were leased from the MMS subject to the RRA. Section 304 of the RRA relieves lessees of the obligation to pay royalties on certain leases until after a designated volume has been produced. Four of these leases held by Mariner and two held by MERI that are producing or have produced contain lease language (inserted by the MMS) that conditions royalty relief on commodity prices remaining below specified thresholds. Since 2000, commodity prices have exceeded some of the predetermined thresholds, except in 2002. In May 2006 and September 2008, the MMS issued orders asserting that the price thresholds had been exceeded in calendar years 2000, 2001, and each of the years from 2003 through 2007, and, accordingly, that royalties were due under such leases on oil and gas produced in those years. The potential liability of MERI under its leases relate to production from the leases commencing July 1, 2005, the effective date of Mariner’s acquisition of MERI. Mariner and MERI believe that the MMS did not have the statutory authority to include commodity price threshold language in the leases governed by Section 304 of the RRA and accordingly have withheld payment of royalties. Mariner and MERI have challenged the MMS’s authority in pending administrative appeals for those leases for which the MMS has issued orders to pay.
 
The enforceability of the price threshold provisions in leases granted pursuant to Section 304 of the RRA is currently being litigated in several administrative appeals filed by other companies in addition to Mariner, as well as in Kerr-McGee Oil & Gas Corp. v. Allred, No. 08-30069 (5th Cir.). In the Kerr-McGee litigation, the district court in the Western District of Louisiana granted Kerr-McGee’s motion for summary judgment, ruling that the price threshold provisions are unlawful and unenforceable under Section 304 of the RRA. Kerr-McGee Oil & Gas Corp. v. Allred, No. 2:06 CV 0439 (W.D. La.) (Mem. Ruling filed Oct. 30, 2007). The Department of the Interior appealed that judgment to the United States Court of Appeals for the Fifth Circuit. On January 12, 2009, the Fifth Circuit affirmed the district court’s judgment that the price provisions are unlawful based on Section 304 of the RRA. Kerr-McGee Oil & Gas Corp. v. U.S. Dep’t of Interior,   F.3d  , 2009 WL 57883 (5th Cir. Jan. 12, 2009). Until the appeals process is complete, we will continue to monitor the case. Given the judicial history of the case, we determined that as of December 31, 2008, we no longer will record a liability for our estimated exposure to the MMS on our leases granted pursuant to Section 304 of the RRA. At December 31, 2008, this liability would have been $57.3 million, including interest. In addition, as of December 31, 2008, we began including in our estimated proved reserves those reserves attributable to these RRA Section 304 leases which, at December 31, 2008, was approximately 18.1 Bcfe.
 
In the ordinary course of business, we are a claimant and/or a defendant in various legal proceedings, including proceedings as to which we have insurance coverage and those that may involve the filing of liens against us or our assets. We do not consider our exposure in these proceedings, individually or in the aggregate, to be material.


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Item 4.   Submission of Matters to a Vote of Security Holders.
 
Not applicable.
 
 
The following table sets forth the names, ages (as of February 20, 2009) and titles of the individuals who are executive officers of Mariner. All executive officers hold office until their successors are elected and qualified. There are no family relationships among any of our directors or executive officers.
 
             
Name
 
Age
 
Position with Company
 
Scott D. Josey
    51     Chairman of the Board, Chief Executive Officer and President
Dalton F. Polasek
    57     Chief Operating Officer
John H. Karnes
    47     Senior Vice President, Chief Financial Officer and Treasurer
Mike C. van den Bold
    46     Senior Vice President and Chief Exploration Officer
Judd A. Hansen
    53     Senior Vice President — Shelf and Onshore
Teresa G. Bushman
    59     Senior Vice President, General Counsel and Secretary
Cory L. Loegering
    53     Senior Vice President — Deepwater
Jesus G. Melendrez
    50     Senior Vice President — Corporate Development
Richard A. Molohon
    54     Vice President — Reservoir Engineering
Michael C. McCullough
    63     Vice President — Acquisitions and Divestitures
Kenneth E. Moore, Jr. 
    62     Vice President — Onshore Land
 
Scott D. Josey — Mr. Josey has served as Chairman of the Board since August 2001. Mr. Josey was appointed Chief Executive Officer in October 2002 and President in February 2005. From 2000 to 2002, Mr. Josey served as Vice President of Enron North America Corp. and co-managed its Energy Capital Resources group. From 1995 to 2000, Mr. Josey provided investment banking services to the oil and gas industry and portfolio management services. From 1993 to 1995, Mr. Josey was a Director with Enron Capital & Trade Resources Corp. in its energy investment group. From 1982 to 1993, Mr. Josey worked in all phases of drilling, production, pipeline, corporate planning and commercial activities at Texas Oil and Gas Corp. Mr. Josey is a member of the Society of Petroleum Engineers and the Independent Producers Association of America.
 
Dalton F. Polasek — Mr. Polasek was appointed Chief Operating Officer in February 2005. From April 2004 to February 2005, Mr. Polasek served as Executive Vice President — Operations and Exploration. From August 2003 to April 2004, he served as Senior Vice President — Shelf and Onshore. From August 2002 to August 2003, he was Senior Vice President, and from October 2001 to January 2003, he was a consultant to Mariner. Prior to joining Mariner, Mr. Polasek was self employed from February 2001 to October 2001 and served as: Vice President of Gulf Coast Engineering for Basin Exploration, Inc. from 1996 until February 2001; Vice President of Engineering for SMR Energy Income Funds from 1994 to 1996; director of Gulf Coast Acquisitions and Engineering for General Atlantic Resources, Inc. from 1991 to 1994; and manager of planning and business development for Mark Producing Company from 1983 to 1991. He began his career in 1975 as a reservoir engineer for Amoco Production Company. Mr. Polasek is a Registered Professional Engineer in Texas, and a member of the Independent Producers Association of America and the Society of Petroleum Engineers.
 
John H. Karnes — Mr. Karnes was appointed Senior Vice President, Chief Financial Officer and Treasurer in October 2006. He was Senior Vice President and Chief Financial Officer of CDX Gas, LLC from July 2006 to August 2006. He served as Executive Vice President and Chief Financial Officer of Maxxam Inc. from April 2006 to July 2006. He served as Senior Vice President and Chief Financial Officer of The Houston Exploration Company from November 2002 through December 2005. Earlier in his career, he served in senior management roles at several publicly-traded companies, including Encore Acquisition Company, Snyder Oil Corporation and Apache Corporation, practiced law with the national law firm of Kirkland & Ellis, and was employed in various roles in the securities industry.


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Mike C. van den Bold — Mr. van den Bold was promoted to Senior Vice President and Chief Exploration Officer in April 2006 and served as Vice President and Chief Exploration Officer from April 2004 to April 2006. From October 2001 to April 2004, he served as Vice President — Exploration. Mr. van den Bold joined Mariner in July 2000 as Senior Development Geologist. From 1996 to 2000, Mr. van den Bold worked for British-Borneo Oil & Gas plc. He began his career at British Petroleum. Mr. van den Bold has more than 20 years of industry experience. He is a Certified Petroleum Geologist, a Texas Board Certified Geologist and a member of the American Association of Petroleum Geologists.
 
Judd A. Hansen — Mr. Hansen was promoted to Senior Vice President — Shelf and Onshore in April 2006 and served as Vice President — Shelf and Onshore from February 2002 to April 2006. From April 2001 to February 2002, Mr. Hansen was self-employed as a consultant. From 1997 until March 2001, Mr. Hansen was employed as Operations Manager of the Gulf Coast Division for Basin Exploration, Inc. From 1991 to 1997, he was employed in various engineering positions at Greenhill Petroleum Corporation, including Senior Production Engineer and Workover/Completion Superintendent. Mr. Hansen started his career with Shell Oil Company in 1978 and has 30 years of experience in conducting operations in the oil and gas industry.
 
Teresa G. Bushman — Ms. Bushman was promoted to Senior Vice President, General Counsel and Secretary in April 2006 and served as Vice President, General Counsel and Secretary from June 2003 to April 2006. From 1996 until joining Mariner in 2003, Ms. Bushman was employed by Enron North America Corp., most recently as Assistant General Counsel representing the Energy Capital Resources group, which provided debt and equity financing to the oil and gas industry. Prior to joining Enron, Ms. Bushman was a partner with Jackson Walker, LLP, in Houston.
 
Cory L. Loegering — Mr. Loegering was promoted to Senior Vice President — Deepwater in September 2006 and served as Vice President — Deepwater from August 2002 to September 2006. Mr. Loegering joined Mariner in July 1990 and since 1998 has held various positions including Vice President of Petroleum Engineering and Director of Deepwater development. Mr. Loegering was employed by Tenneco from 1982 to 1988, in various positions including as senior engineer in the economic, planning and analysis group in Tenneco’s corporate offices. Mr. Loegering began his career with Conoco in 1977 and held positions in the construction, production and reservoir departments responsible for Gulf of Mexico production and development. Mr. Loegering has 31 years of experience in the industry.
 
Jesus G. Melendrez — Mr. Melendrez was promoted to Senior Vice President — Corporate Development in April 2006 and served as Vice President — Corporate Development from July 2003 to April 2006. Mr. Melendrez also served as a director of Mariner from April 2000 to July 2003. From February 2000 until July 2003, Mr. Melendrez was a Vice President of Enron North America Corp. in the Energy Capital Resources group where he managed the group’s portfolio of oil and gas investments. He was a Senior Vice President of Trading and Structured Finance with TXU Energy Services from 1997 to 2000, and from 1992 to 1997, Mr. Melendrez was employed by Enron in various commercial positions in the areas of domestic oil and gas financing and international project development. From 1980 to 1992, Mr. Melendrez was employed by Exxon in various reservoir engineering and planning positions.
 
Richard A. Molohon — Mr. Molohon was appointed Vice President — Reservoir Engineering in May 2006. He joined Mariner in January 1995 as a Senior Reservoir Engineer and since then has held various positions in reservoir engineering, economics, acquisitions and dispositions, exploration, development, and planning and basin analysis, including Senior Staff Engineer from January 2000 to January 2004, and Manager, Reserves and Economics from January 2004 to May 2006. Mr. Molohon has more than 30 years of industry experience. He began his career with Amoco Production Company as a Production Engineer from 1977 until 1980. From 1980 to 1991, he was a Project Petroleum Engineer for various subsidiaries of Tenneco, Inc. From 1991 to 1995 he was a Senior Acquisition Engineer for General Atlantic Inc. Mr. Molohon has been a Registered Professional Engineer in Texas since 1983 and is a member of the Society of Petroleum Engineers.
 
Michael C. McCullough — Mr. McCullough was promoted to Vice President — Acquisitions and Divestitures in February 2008. He served as Manager, Acquisitions/Exploitation from March 2006 to February 2008, and as Senior Reservoir Engineer from May 2004 to March 2006. Mr. McCullough was employed by Basin Exploration, Inc. from 1999 to 2001 and its successor, Stone Energy Corporation, from 2001 to 2004, in general reservoir engineering, lease sales and acquisitions capacities. He has approximately


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40 years of industry engineering experience, beginning his career in 1968 as a production engineer with Mobil Oil Corporation.
 
Kenneth E. Moore, Jr. — Mr. Moore was promoted to Vice President — Onshore Land in February 2008. A Certified Professional Landman, he was employed by Mariner in December 2004 as Onshore Business Development Manager and in November 2006, became Manager, Land/Business Development (Onshore). Mr. Moore served Mariner from November 2003 to December 2004 as an independent contractor performing land services through his firm Moore Land & Minerals which provided a full range of land services to various clients in the Texas Gulf Coast and the Permian Basin areas from September 2001 to December 2004. Mr. Moore has almost 35 years of industry land experience, beginning his career in 1974 as a landman with Gulf Oil Corporation.
 
 
Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.  
 
Mariner’s common stock trades on the New York Stock Exchange (“NYSE”) under the symbol “ME.” The following table sets forth the reported high and low closing sales prices of our common stock for the periods indicated:
 
                         
Year
   
Period Ended
  High     Low  
 
  2007     First Quarter   $ 20.33     $ 16.95  
        Second Quarter     25.65       19.30  
        Third Quarter     25.26       18.87  
        Fourth Quarter     25.00       20.67  
  2008     First Quarter   $ 29.60     $ 23.69  
        Second Quarter     37.01       26.84  
        Third Quarter     36.45       19.77  
        Fourth Quarter     19.54       7.48  
 
As of February 20, 2009 there were 763 holders of record of our issued and outstanding common stock. We believe that there are significantly more beneficial holders of our stock.
 
We currently intend to retain our earnings for the development of our business and do not expect to pay any cash dividends. We did not pay any cash dividends for fiscal years 2007 or 2008. Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Bank Credit Facility” and “Note 3. Long-Term Debt” in the Notes to the Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K for a discussion of certain covenants in our bank credit facility and indentures governing our senior unsecured notes which restrict our ability to pay dividends.


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The following graph compares the cumulative total stockholder return for our common stock to that of the Standard & Poor’s 500 Index and a peer group for the period indicated as prescribed by SEC rules. “Cumulative total return” means the change in share price during the measurement period, plus cumulative dividends for the measurement period (assuming dividend reinvestment), divided by the share price at the beginning of the measurement period. The graph assumes $100 was invested on March 3, 2006 (the date on which our common stock began regular way trading on the NYSE) in each of our common stock, the Standard & Poor’s Composite 500 Index and a peer group.
 
 
(PERFORMANCE GRAPH)
 
Note: The stock price performance of our common stock is not necessarily indicative of future performance.
 
                                 
    Cumulative Total Return(1)
    Initial   12/31/06   12/31/07   12/31/08
 
Mariner Energy, Inc. 
  $ 100.00     $ 96.69     $ 112.88     $ 50.32  
S&P 500 Index
  $ 100.00     $ 110.18     $ 114.07     $ 70.17  
Peer Group(2)
  $ 100.00     $ 97.09     $ 103.74     $ 37.16  
 
(1)  Total return assuming reinvestment of dividends. Assumes $100 invested on March 3, 2006 in each of Mariner’s common stock, the S&P 500 Index, and a peer group of companies. Initial data is taken from March 3, 2006, the date on which Mariner’s common stock began regular way trading on the NYSE.
 
(2)  Composed of the following seven independent oil and gas exploration and production companies: ATP Oil & Gas Corporation, Callon Petroleum Co., Energy Partners, Ltd., McMoRan Exploration Co., Plains Exploration & Production Company, Stone Energy Corporation, and W&T Offshore, Inc. This peer group differs by one member from the peer group for the stock performance graph included in our 2007 annual report. McMoRan Exploration Co. replaces Bois d’Arc Energy, Inc. which ceased to exist in 2008 when it was merged into a wholly-owned subsidiary of peer group member Stone Energy Corporation.
 
The above information under the caption “Performance Graph” shall not be deemed to be “soliciting material” and shall not be deemed to be incorporated by reference by any general statement incorporating by reference this Form 10-K into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, and shall not otherwise be deemed filed under such acts.


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Issuer Purchases of Equity Securities
 
                                 
                Total Number
       
                of Shares
    Maximum Number
 
                (or Units)
    (or Approximate
 
                Purchased as
    Dollar Value) of
 
    Total Number
    Average
    Part of Publicly
    Shares (or Units)
 
    of Shares
    Price Paid
    Announced
    that May Yet Be
 
    (or Units)
    per Share
    Plans or
    Purchased Under the
 
Period
  Purchased     (or Unit)     Programs     Plans or Programs  
 
October 1, 2008 to October 31, 2008(1)
    3,235     $ 16.31              
November 1, 2008 to November 30, 2008(1)
        $              
December 1, 2008 to December 31, 2008(1)
    2,639     $ 8.96              
                                 
Total
    5,874     $ 13.01              
                                 
 
 
(1) These shares were withheld upon the vesting of employee restricted stock grants in connection with payment of required withholding taxes.


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Item 6.   Selected Financial Data.
 
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 Merger”). Prior to the Merger, we were owned indirectly by Enron Corp. As a result of the Merger, we ceased being affiliated with Enron Corp in 2004.
 
The selected financial data table below shows our historical consolidated financial data as of and for the years ended December 31, 2008, 2007, 2006 and 2005, the period from March 3, 2004 through December 31, 2004, and the period from January 1, 2004 through March 2, 2004. The historical consolidated financial data as of and for the years ended December 31, 2008, 2007 and 2006, are derived from Mariner’s audited Consolidated Financial Statements included herein, and the historical consolidated financial data as of and for the year ended December 31, 2005, and for the periods March 3, 2004 through December 31, 2004 (“Post-2004 Merger”) and January 1, 2004 through March 2, 2004 (“Pre-2004 Merger”), are derived from Mariner’s audited Consolidated Financial Statements that are not included herein. The financial information contained herein is presented in the style of Post-2004 Merger activity and Pre-2004 Merger activity 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. You should read the following data in connection with “Item 7. — Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and related notes thereto included in Part II, Item 8 of this Annual Report on Form 10-K, where there is additional disclosure regarding the information in the following table. Mariner’s historical results are not necessarily indicative of results to be expected in future periods.
 
                                                 
    Post-2004 Merger     Pre-2004 Merger  
                            Period from
    Period from
 
                            March 3,
    January 1,
 
                            through
    through
 
    Year Ended December 31,     December 31,
    March 2,
 
    2008     2007     2006     2005     2004     2004  
    (In thousands, except per share data)  
 
Statement of Operations Data:
                                               
Total revenues(1)
  $ 1,300,507     $ 874,765     $ 659,505     $ 199,710     $ 174,423     $ 39,764  
Operating expenses(2)
    264,832       174,522       105,739       32,218       23,322       5,191  
Depreciation, depletion and amortization
    467,265       384,321       292,180       59,469       54,281       10,630  
General and administrative expense
    60,613       42,151       33,622       36,766       7,641       1,131  
Operating (loss) income(3)
    (381,712 )     268,710       227,470       69,168       88,222       22,812  
Interest expense, net of amounts capitalized
    56,398       54,665       39,649       8,172       6,045       5  
(Benefit) Provision for income taxes
    (48,223 )     77,324       67,344       21,294       28,783       8,072  
Net (loss) income
    (388,713 )     143,934       121,462       40,481       53,619       14,826  
Earnings per common share:
                                               
Net (loss) income per common share — basic
  $ (4.44 )   $ 1.68     $ 1.59     $ 1.24     $ 1.80     $ 0.50  
Net (loss) income per common share — diluted
  $ (4.44 )   $ 1.67     $ 1.58     $ 1.20     $ 1.80     $ 0.50  
 
(1) Includes effects of hedging.
 
(2) Operating expenses include lease operating expense, severance and ad valorem taxes and transportation expenses.
 
(3) 2008 includes $575.6 million of full cost ceiling test impairment, $295.6 million of goodwill impairment and $15.3 million of other property impairment.
 


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    December 31,  
    2008     2007     2006     2005     2004  
    (In thousands)  
 
Balance Sheet Data:(1)
                                       
Current Assets
  $ 374,953     $ 248,980     $ 306,018     $ 141,432     $ 65,746  
Current Liabilities
    425,564       315,189       239,727       204,006       101,412  
                                         
Working capital deficit
  $ (50,611 )   $ (66,209 )   $ 66,291     $ (62,574 )   $ (35,666 )
                                         
Property and equipment, net
    2,929,877       2,420,194       2,012,062       515,943       303,773  
Total assets
    3,392,793       3,083,635       2,680,153       665,536       376,019  
Long-term debt, less current maturities
    1,170,000       779,000       654,000       156,000       115,000  
Stockholders’ equity
    1,120,320       1,391,018       1,302,591       213,336       133,907  
 
 
(1) 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.
 
                                                 
    Post-2004 Merger     Pre-2004 Merger  
                            Period from
    Period from
 
                            March 3,
    January 1,
 
                            through
    through
 
    Year Ended December 31,     December 31,
    March 2,
 
    2008     2007     2006     2005     2004     2004  
    (In thousands)  
 
Cash Flow Data:
                                               
Net cash provided by operating activities
  $ 862,017     $ 536,113     $ 277,161     $ 165,444     $ 135,243     $ 20,295  
Net cash used in investing activities
  $ (1,264,784 )   $ (643,779 )   $ (561,390 )   $ (247,799 )   $ (132,977 )   $ (15,341 )
Net cash provided (used) by financing activities
  $ 387,429     $ 116,676     $ 289,252     $ 84,370     $ (64,853 )   $  
 
Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
 
We are an independent oil and natural gas exploration, development and production company with principal operations in the Permian Basin and the Gulf of Mexico. As of December 31, 2008, approximately 70% of our total estimated proved reserves were classified as proved developed, with approximately 45% of the total estimated proved reserves located in the Permian Basin, 20% in the Gulf of Mexico deepwater and 35% on the Gulf of Mexico shelf.
 
Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural 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 historically have been very volatile. Oil and natural gas prices increased to, and then declined significantly from, historical highs in 2008 and may fluctuate and decline 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 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.
 
The recent worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets could lead to an extended worldwide economic recession. A recession or slowdown in economic activity would likely reduce worldwide demand for energy and result in lower oil and natural gas prices, which could materially adversely affect our profitability and results of operations.

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Acquisitions.  On December 19, 2008, we acquired additional working interests in our existing property, Atwater Valley Block 426 (Bass Lite), for approximately $32.6 million, increasing our working interest by 11.6% to 53.8%. We internally estimated proved reserves attributable to the acquisition of approximately 17.6 Bcfe (100% natural gas).
 
On January 31, 2008, we acquired 100% of the equity in a subsidiary of Hydro Gulf of Mexico, Inc. pursuant to a Membership Interest Purchase Agreement executed on December 23, 2007. The acquired subsidiary, now known as Mariner Gulf of Mexico LLC (“MGOM”), was an indirect subsidiary of StatoilHydro ASA and owns substantially all of its former Gulf of Mexico shelf operations. A summary of these assets and operations as of January 1, 2008 includes:
 
  •  Ryder Scott Company, L.P. estimated proved oil and gas reserves of 49.7 Bcfe, 93% of which are developed;
 
  •  interests in 36 (16 net) producing wells producing approximately 53 MMcfe per day net to MGOM’s interest, 76% of which Mariner now operates;
 
  •  gas gathering systems comprised of 31 miles of 10-inch, 12-inch and 16-inch pipelines; and
 
  •  approximately 106,000 net acres of developed leasehold and 256,000 net acres of undeveloped leasehold.
 
We paid approximately $243.0 million for MGOM, subject to customary purchase price adjustments, including $8.0 million for reimbursement of drilling costs attributable to the High Island 166 #5 well.
 
On December 31, 2007, February 29, 2008, and December 1, 2008 we acquired additional working interests in certain of our existing properties in the Spraberry field in the Permian Basin. We internally estimated proved reserves attributable to the December 2007 acquisition of approximately 94.9 Bcfe (75% oil and NGLs), to the February 2008 acquisition of approximately 14.0 Bcfe (65% oil and NGLs) and to the December 2008 acquisition of approximately 13.4 Bcfe (66% oil and NGLs). We operate substantially all of the assets. The purchase prices, subject to customary purchase price adjustments, were approximately $122.5 million for the December 2007 acquisition, $21.7 million for the February 2008 acquisition and $19.4 million for the December 2008 acquisition.
 
On March 2, 2006, a subsidiary of Mariner completed a merger transaction with Forest Energy Resources, Inc. (the “Forest Merger”) pursuant to which Mariner effectively acquired Forest’s Gulf of Mexico operations. Prior to the consummation of the Forest 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 Forest Merger, Forest distributed all of the outstanding shares of Forest Energy Resources to Forest stockholders 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 Forest Merger, approximately 59% of Mariner common stock was held by stockholders of Forest and approximately 41% of Mariner common stock was held by the pre-merger stockholders of Mariner. In the Forest Merger, Mariner issued 50,637,010 shares of common stock to the stockholders of Forest Energy Resources, Inc. Our acquisition of Forest Energy Resources added approximately 298 Bcfe of estimated proved reserves. The Forest Merger has had a significant effect on the comparability of operating and financial results between periods.


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Results of Operations
 
Year Ended December 31, 2008 compared to Year Ended December 31, 2007
 
Operating and Financial Results for the Year Ended December 31, 2008
Compared to the Year Ended December 31, 2007
 
                                 
    Year Ended December 31,     Increase
       
    2008     2007     (Decrease)     % change  
    (In thousands, except average sales price)  
 
Summary Operating Information:
                               
Net Production:
                               
Natural gas (MMcf)
    79,756       67,793       11,963       18 %
Oil (Mbbls)
    4,881       4,214       667       16 %
Natural gas liquids (Mbbls)
    1,558       1,200       358       30 %
Total natural gas equivalent (MMcfe)
    118,389       100,273       18,116       18 %
Average daily production (MMcfe per day)
    323       275       48       18 %
Hedging Activities:
                               
Natural gas revenue gain (loss)
  $ (28,047 )   $ 58,465     $ (86,512 )     (148 )%
Oil revenue loss
    (72,762 )     (13,388 )     (59,374 )     443 %
                                 
Total hedging revenue gain (loss)
  $ (100,809 )   $ 45,077     $ (145,886 )     (324 )%
Average Sales Prices:
                               
Natural gas (per Mcf) realized(1)
  $ 9.31     $ 7.88     $ 1.43       18 %
Natural gas (per Mcf) unhedged
    9.66       7.02       2.64       38 %
Oil (per Bbl) realized(1)
    86.02       67.50       18.52       27 %
Oil (per Bbl) unhedged
    100.93       70.68       30.25       43 %
Natural gas liquids (per Bbl) realized(1)
    55.02       45.16       9.86       22 %
Natural gas liquids (per Bbl) unhedged
    55.02       45.16       9.86       22 %
Total natural gas equivalent ($/Mcfe) realized(1)
    10.54       8.71       1.83       21 %
Total natural gas equivalent ($/Mcfe) unhedged
    11.39       8.26       3.13       38 %
Summary of Financial Information:
                               
Natural gas revenue
  $ 742,370     $ 534,537     $ 207,833       39 %
Oil revenue
    419,878       284,405       135,473       48 %
Natural gas liquids revenue
    85,715       54,192       31,523       58 %
Other revenues
    52,544       1,631       50,913       3,122 %
Lease operating expense
    231,645       152,627       79,018       52 %
Severance and ad valorem taxes
    18,191       13,101       5,090       39 %
Transportation expense
    14,996       8,794       6,202       71 %
General and administrative expense
    60,613       42,151       18,462       44 %
Depreciation, depletion and amortization
    467,265       384,321       82,944       22 %
Full cost ceiling test impairment
    575,607             575,607       N/A  
Goodwill impairment
    295,598             295,598       N/A  
Other property impairment
    15,252             15,252       N/A  
Net interest expense
    56,398       53,262       3,136       6 %
Income (Loss) before taxes and minority interest
    (436,748 )     221,259       (658,007 )     (297 )%
(Benefit) Provision for income taxes
    (48,223 )     77,324       (125,547 )     (162 )%
Net income (loss)
    (388,713 )     143,934       (532,647 )     (370 )%
Average Unit Costs per Mcfe:
                               
Lease operating expense
  $ 1.96     $ 1.52     $ 0.44       29 %
Severance and ad valorem taxes
    0.15       0.13       0.02       15 %
Transportation expense
    0.13       0.09       0.04       44 %
General and administrative expense
    0.51       0.42       0.09       21 %
Depreciation, depletion and amortization
    3.95       3.83       0.12       3 %
 
 
(1) Average realized prices include the effects of hedges.


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Net loss for 2008 was $388.7 million compared to net income of $143.9 million for 2007. The decrease was primarily attributable to $886.5 million in impairments resulting from our full cost ceiling test, other property impairment and goodwill, as discussed below. Basic and fully-diluted earnings per share for 2008 were $(4.44) for each measure compared to $1.68 and $1.67, respectively for 2007.
 
Net production Natural gas production increased approximately 18% in 2008 to approximately 218 MMcf per day, compared to approximately 186 MMcf per day in 2007. Oil production increased 16% in 2008 to approximately 13,300 barrels per day, compared to approximately 11,500 barrels per day in 2007. Natural gas liquids production increased 30% in 2008 and total overall production increased 18% in 2008 to approximately 323 MMcfe per day, compared to 275 MMcfe per day in 2007. Natural gas production comprised approximately 67% of total production in both 2008 and 2007.
 
Net production in the Gulf of Mexico for 2008 increased 16% to 103.5 Bcfe from 89.1 Bcfe for 2007 primarily reflecting the start up in 2008 of production from several new projects, most notably, Northwest Nansen located in East Breaks 602 (which contributed 12.9 Bcfe) and Bass Lite located in Atwater 426 (which contributed 8.4 Bcfe), and the impact of our acquisition of MGOM (which contributed 13.1 Bcfe). This increase was offset by the impacts of Hurricanes Gustav and Ike in the third quarter which resulted in net shut-in production (assuming pre-hurricane net production levels remained constant) of approximately 20 Bcfe.
 
Onshore production for 2008 increased 33% to 14.9 Bcfe from 11.2 Bcfe for 2007, primarily as a result of our acquisition of additional interests and drilling and development of existing acreage in the Permian Basin (which contributed 2.6 Bcfe in 2008).
 
Natural gas, oil and NGL revenues for 2008 increased 43% to $1,248.0 million compared to $873.1 million for 2007 as a result of increased pricing (approximately $217.1 million, net of the effect of hedging), and increased production (approximately $157.8 million).
 
During 2008, our revenues reflected a net recognized hedging loss of $100.8 million comprised of $98.8 million in unfavorable cash settlements and an unrealized loss of $2.0 million related to the ineffective portion not eligible for deferral under SFAS 133. This compares to a net recognized hedging gain of approximately $45.1 million for 2007, comprised of $46.7 million in favorable cash settlements and an unrealized loss of $1.6 million related to the ineffective portion not eligible for deferral under SFAS 133.
 
Our natural gas and oil average sales prices, and the effects of hedging activities on those prices, were as follows:
 
                                 
                Hedging
       
    Realized     Unhedged     (Loss) Gain     % Change  
 
Year Ended December 31, 2008:
                               
Natural gas (per Mcf)
  $ 9.31     $ 9.66     $ (0.35 )     (4 )%
Oil (per Bbl)
    86.02       100.93       (14.91 )     (15 )%
Year Ended December 31, 2007:
                               
Natural gas (per Mcf)
  $ 7.88     $ 7.02     $ 0.86       12 %
Oil (per Bbl)
    67.50       70.68       (3.18 )     (4 )%
 
Other revenues for 2008 increased approximately $50.9 million to $52.5 million from $1.6 million for 2007 as a result of the release of suspended revenue of $46.5 million related to a potential MMS royalty liability and $4.3 million of imputed rent from the lease of office property acquired in January 2008.
 
Lease operating expense (“LOE”) in 2008 increased approximately $79.0 million to $231.6 million from $152.6 million for 2007, primarily as a result of a $36.0 million multiple-year retrospective contingent OIL insurance premium. LOE also was imparted by start-up of production in February 2008 from Bass Lite and Northwest Nansen, the acquisition of MGOM in January 2008, and the impact of the additional Permian Basin assets acquired at year-end 2007, which are long-lived and typically carry a higher per-unit LOE.
 
Severance and ad valorem tax for 2008 increased approximately $5.1 million to $18.2 million from $13.1 million for 2007 due to increased severance as a result of higher oil prices and increased production


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from the drilling and completion of additional wells and our acquisition of additional interests in the Permian Basin.
 
Transportation expense for 2008 increased approximately $6.2 million to $15.0 million from $8.8 million for 2007 due primarily to commencement of production in 2008 at Bass Lite, Northwest Nansen, Galveston 352 and High Island A467.
 
General and administrative expense (“G&A”) for 2008 increased approximately $18.4 million to $60.6 million from $42.2 million for 2007. The increase was due primarily to an increase in stock compensation expense of approximately $10.1 million to $21.0 million from $10.9 million for 2007. This increase was primarily due to long-term performance-based restricted stock awarded during 2008. See “Note 5. Share-Based Compensation” in the Notes to the Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K for more detail on stock grants. Beginning in 2008, that portion of Lafayette and Midland office expense that is directly related to production activity was classified as LOE, and we began capitalizing stock compensation expense attributable to those non-officer employees directly engaged in exploration, development and acquisition activities. Capitalized G&A related to our acquisition, exploration and development activities increased $5.8 million to $19.8 million in 2008 from $14.0 million in 2007.
 
Depreciation, depletion, and amortization expense for 2008 increased approximately $83.0 million to $467.3 million from $384.3 million for 2007, primarily as a result of increased production from our acquisitions of MGOM and additional interests in the Permian Basin properties, and start-up production from Bass Lite and Northwest Nansen.
 
Full cost ceiling test impairment of $575.6 million was recognized in December 2008 as a result of the net capitalized cost of our proved oil and gas properties exceeding our ceiling limit. See “— Critical Accounting Policies and Estimates — Oil and Gas Properties” for more detail on this impairment.
 
Goodwill impairment of $295.6 million was recorded in the fourth quarter of 2008 as a result of our annual impairment test. The goodwill was originally recorded in conjunction with the Forest Merger and the impairment is a result of weakened economic conditions and a decline in our stock price during the fourth quarter of 2008. See “— Critical Accounting Policies and Estimates — Goodwill” for more detail on this impairment.
 
Other property impairment of $15.3 million was recognized as a result of our annual impairment assessement performed on our other property. See “— Critical Accounting Policies and Estimates — Other Property” for more detail on this impairment.
 
Net interest expense for 2008 increased approximately $3.1 million to $56.4 million from $53.3 million for 2007 due primarily to an increase in average daily debt levels, partially offset by lower interest rates, and an additional four months of interest expense related to our 8% Senior Notes due 2017 issued on April 30, 2007. Capitalized interest increased to $9.7 million in 2008 from $0.5 million in 2007.
 
Income before taxes and minority interest for 2008 decreased approximately $658.0 million to a loss of $436.7 million from income of $221.3 million for 2007 due primarily to $886.5 million in impairments related to our full cost ceiling test, other property and goodwill as discussed above.
 
Provision for income taxes for 2008 reflected an effective tax rate of 11.0% as compared to 34.9% for 2007. The decrease in our effective tax rate was due primarily to a permanent book-tax difference attributable to the goodwill impairment discussed above. Excluding this permanent book-tax difference, the effective rate for 2008 would have been 34.2%.


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Year Ended December 31, 2007 compared to Year Ended December 31, 2006
 
Operating and Financial Results for the Year Ended December 31, 2007
Compared to the Year Ended December 31, 2006
 
                                 
    Year Ended December 31,     Increase
       
    2007     2006     (Decrease)     % change  
    (In thousands, except average sales price)  
 
Summary Operating Information:
                               
Net Production:
                               
Natural gas (MMcf)
    67,793       56,064       11,729       21 %
Oil (Mbbls)
    4,214       3,237       977       30 %
Natural gas liquids (Mbbls)
    1,200       838       362       43 %
Total natural gas equivalent (MMcfe)
    100,273       80,512       19,761       25 %
Average daily production (MMcfe per day)
    275       221       54       25 %
Hedging Activities:
                               
Natural gas revenue gain
  $ 58,465     $ 32,881     $ 25,584       78 %
Oil revenue gain (loss)
    (13,388 )     90       (13,478 )     (100 )%
                                 
Total hedging revenue gain
  $ 45,077     $ 32,971     $ 12,106       37 %
Average Sales Prices:
                               
Natural gas (per Mcf) realized(1)
  $ 7.88     $ 7.37     $ 0.51       7 %
Natural gas (per Mcf) unhedged
    7.02       6.78       0.24       4 %
Oil (per Bbl) realized(1)
    67.50       62.63       4.87       8 %
Oil (per Bbl) unhedged
    70.68       62.61       8.07       13 %
Natural gas liquids (per Bbl) realized(1)
    45.16       48.37       (3.21 )     (7 )%
Natural gas liquids (per Bbl) unhedged
    45.16       48.37       (3.21 )     (7 )%
Total natural gas equivalent ($/Mcfe) realized(1)
    8.71       8.15       0.56       7 %
Total natural gas equivalent ($/Mcfe) unhedged
    8.26       7.74       0.52       7 %
Summary of Financial Information:
                               
Natural gas revenue
  $ 534,537     $ 412,967     $ 121,570       29 %
Oil revenue
    284,405       202,744       81,661       40 %
Natural gas liquids revenue
    54,192       40,507       13,685       34 %
Other revenues
    1,631       3,287       (1,656 )     (50 )%
Lease operating expense
    152,627       91,592       61,035       67 %
Severance and ad valorem taxes
    13,101       9,070       4,031       44 %
Transportation expense
    8,794       5,077       3,717       73 %
General and administrative expense
    42,151       33,622       8,529       25 %
Depreciation, depletion and amortization
    384,321       292,180       92,141       32 %
Net interest expense
    53,262       38,664       14,598       38 %
Income before taxes and minority interest
    221,259       188,806       32,453       17 %
Provision for income taxes
    77,324       67,344       9,980       15 %
Net income
    143,934       121,462       22,472       19 %
Average Unit Costs per Mcfe:
                               
Lease operating expense
  $ 1.52     $ 1.14     $ 0.38       33 %
Severance and ad valorem taxes
    0.13       0.11       0.02       18 %
Transportation expense
    0.09       0.06       0.03       50 %
General and administrative expense
    0.42       0.42              
Depreciation, depletion and amortization
    3.83       3.63       0.20       6 %
 
 
(1) Average realized prices include the effects of hedges.
 
Net income for 2007 was $143.9 million compared to $121.5 million for 2006. The increase was primarily the result of higher operating income attributable to 12 full months of our ownership of the Forest Gulf of Mexico operations. Basic and fully-diluted earnings per share for 2007 were $1.68 and $1.67, respectively compared to $1.59 and $1.58, respectively for 2006.
 
Net production Natural gas production increased 21% in 2007 to approximately 186 MMcf per day, compared to approximately 154 MMcf per day in 2006. Oil production increased 30% in 2007 to approximately 11,500 barrels per day, compared to approximately 8,900 barrels per day in 2006. Natural gas


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liquids increased 43% in 2007 and total overall production increased 25% in 2007 to approximately 275 MMcfe per day, compared to 221 MMcfe per day in 2006. Natural gas production comprised approximately 68% of total production in 2007 compared to approximately 70% in 2006. The increase in production and the oil to gas ratio resulted from the 12 full months of ownership of the Forest Gulf of Mexico operations in 2007, compared to approximately 10 months in 2006. Our Gulf of Mexico production in 2006 was adversely affected by the 2005 hurricane season, resulting in shut-in production and startup delays. As a result of ongoing repairs to pipelines, facilities, terminals and host facilities, most of the shut-in production recommenced by the end of 2006. Specifically, 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.
 
Production in the Gulf of Mexico increased 25% to 89.1 Bcfe for 2007 from 71.3 Bcfe for 2006, while onshore production increased 22% to 11.2 Bcfe for 2007 from 9.2 Bcfe for 2006.
 
Natural gas, oil and NGL revenues for 2007 increased 33% to $873.1 million compared to $656.2 million for 2006 as a result of increased pricing (approximately $161.1 million, net of the effect of hedging), and increased production (approximately $55.9 million).
 
During 2007, our revenues reflect a net recognized hedging gain of approximately $45.1 million, comprised of $46.7 million in favorable cash settlements and an unrealized loss of $1.6 million related to the ineffective portion not eligible for deferral under SFAS 133. This compares to a net recognized hedging gain of approximately $33.0 million for 2006, comprised of $11.3 million in favorable cash settlements and an unrealized gain of $4.2 million related to the ineffective portion not eligible for deferral under SFAS 133. In addition, the fair value of oil and natural gas derivatives acquired through the Forest Merger resulted in a $17.5 million non-cash gain. The fair value of the acquired derivatives was fully recognized in 2006.
 
The effects of hedging activities on our average sales prices were as follows:
 
                                 
                Hedging
       
    Realized     Unhedged     Gain (Loss)     % Change  
 
Year Ended December 31, 2007:
                               
Natural gas (per Mcf)
  $ 7.88     $ 7.02     $ 0.86       12 %
Oil (per Bbl)
    67.50       70.68       (3.18 )     (4 )%
Year Ended December 31, 2006:
                               
Natural gas (per Mcf)
  $ 7.37     $ 6.78     $ 0.59       9 %
Oil (per Bbl)
    62.63       59.68       2.95       5 %
 
Lease operating expense in 2007 increased 67% to $152.6 million from $91.6 million for 2006. The increase primarily was attributable to 12 full months of ownership of the Forest Gulf of Mexico shelf assets in 2007 as compared to only 10 months in 2006, which carry a higher operating cost than Mariner’s legacy deepwater operations. Additionally, insurance premiums increased to $17.8 million in 2007 from $10.5 million in 2006 as a result of Hurricanes Katrina and Rita. Field costs increased $7.6 million year-over-year in the Permian Basin with the addition of new productive wells in the Spraberry field.
 
Severance and ad valorem taxes were $13.1 million and $9.1 million for 2007 and 2006, respectively. The increase was primarily attributable to increased production and appreciated property values on the Permian Basin properties.
 
Transportation expense for 2007 was $8.8 million compared to $5.1 million for 2006. The increase was primarily due to increased production.
 
Depreciation, depletion and amortization (“DD&A”) expense increased 32% to $384.3 million from $292.2 million for 2007 and 2006, respectively. The increase was a result of increased production due to 12 full months of ownership of the Forest Gulf of Mexico operations in 2007 as compared to only ten months in 2006, as well as an increase in the unit-of-production depreciation, depletion and amortization rate. The per unit rate increased 6% primarily due to an increase in deepwater development activities and the Forest Gulf of Mexico operations, as well as increased accretion of asset retirement obligations due to the Forest Gulf of Mexico operations.


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General and administrative expense totaled $42.2 million for 2007, compared to $33.6 million for 2006. The increase was primarily related to a $4.4 million increase in professional fees associated with system enhancements, Sarbanes-Oxley compliance efforts, insurance claim activities and an increase in health insurance costs. In addition, overhead reimbursements billed or received from working interest owners decreased $4.2 million from $16.7 million in 2006 to $12.5 million in 2007. Salaries and wages for 2007 remained relatively flat at $35.2 million as the integration of the Forest Gulf of Mexico operations has stabilized. The 2006 G&A expenses included severance, retention, relocation and transition costs of $2.6 million related to the acquisition of the Forest Gulf of Mexico operations.
 
Capitalized G&A related to our acquisition, exploration and development activities increased to $14.0 million in 2007 from $11.0 million for 2006.
 
G&A expense includes charges for share-based compensation expense of $10.9 million for 2007 compared to $10.2 million for 2006. For 2007 and 2006, $7.0 and $6.6 million of share-based compensation expense, respectively, resulted from amortization of the cost of restricted stock granted at the closing of Mariner’s equity private placement in March 2005 and the remaining related to the amortization of new grants issued in 2007 and 2006 with vesting periods of three to four years. The restricted stock related to Mariner’s equity private placement fully vested by May 2006 and there will be no further charges related to those stock grants.
 
Net interest expense increased to $53.3 million from $38.7 million for 2007 and 2006, respectively. This increase was primarily due to an increase in average debt levels to $632.1 million for 2007 from $475.1 million for 2006. Debt increased during 2007 as a result of the April 2007 issuance of $300 million principal amount of 8% Senior Notes due 2017, as well as continuing hurricane-related repair and abandonment costs of $37.8 million. Additionally, the amendment and restatement of the bank 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. Capitalized interest decreased from $1.5 million in 2006 to $0.5 million in 2007.
 
Income before taxes and minority interest increased 17% to $221.3 million from $188.8 million for 2007 and 2006, respectively. This increase was primarily the result of higher operating income attributed to 12 full months of ownership of the Forest Gulf of Mexico operations.
 
Provision for income taxes reflected an effective tax rate of 34.9% for 2007 as compared to an effective tax rate of 35.7% for the comparable period of 2006.
 
Liquidity and Capital Resources
 
Financial Condition
 
                 
    Years Ended December 31,  
    2008     2007  
    (In thousands, except ratios)  
 
Current ratio(1)
    0.9 to 1       0.8 to 1  
Working capital deficit(2)
    (50,611 )     (66,209 )
Total debt
    1,170,000       779,000  
Operating cash flow(3)
    885,887       622,610  
Interest expense, net of capitalization
    56,398       54,665  
Fixed-charge coverage ratio(4)
    (5.63 )     4.93  
Total cash and marketable securities less debt
    (1,166,749 )     (760,411 )
Stockholders’ equity
    1,120,320       1,391,018  
Total liabilities to equity
    2.03 to 1       1.22 to 1  
 
 
(1) Current ratio is current assets divided by current liabilities.
 
(2) Working capital deficit is the difference between current assets and current liabilities.
 
(3) Operating cash flow is net income before allowance for doubtful accounts, deferred income tax, DD&A, amortization of deferred financing costs, ineffectiveness of derivative instruments, share-based compensation expense, impairments and minority interest. See the following “Reconciliation of Non-GAAP Measure: Operating Cash Flow.”


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(4) Fixed-charge coverage ratio is net earnings before taxes, minority interest and fixed charges divided by fixed charges (interest expense, net of capitalization plus amortization of discounts.)
 
 
Operating cash flow (“OCF”) is not a financial or operating measure under GAAP. The table below reconciles OCF to related GAAP information. We believe that OCF 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 OCF should not be considered in isolation or as a substitute for net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP or as a measure of our profitability or liquidity.
 
                 
    Years Ended December 31,  
    2008     2007  
    (In thousands)  
 
Cash flow from operating activities (GAAP)
  $ 862,017     $ 536,113  
Changes in operating assets and liabilities
    23,870       86,497  
                 
Operating cash flow (Non-GAAP)
  $ 885,887     $ 622,610  
                 
 
2008 Cash Flows
 
The following table presents cash payments for interest and income taxes:
 
                         
    Years Ended December 31,  
    2008     2007     2006  
    (In millions)  
 
Cash payments for interest
  $ 62.2     $ 49.1     $ 28.8  
Cash payments for income taxes
    2.9     $ 0.6     $  
 
Net cash provided by operating activities increased by $325.9 million to $862.0 million in 2008 from $536.1 million in 2007. The increase was due to greater operating revenue due to an increase in production of 48 MMcfe per day or $157.8 million and an increase in the realized price per Mcfe of $1.83 or $217.1 million, offset by higher lease operating expense.
 
As of December 31, 2008, the Company had a working capital deficit of $50.6 million, including non-cash current derivative assets and liabilities and deferred tax assets and liabilities. In addition, working capital is negatively impacted by accrued capital expenditures. This deficit will be funded by cash flow from operating activities and our bank credit facility, as needed.
 
Net cash flows used in investing activities increased to $1,264.8 million in 2008 from $643.8 million in 2007 primarily due to the acquisition of MGOM (including approximately $15.0 million of mid-stream assets reflected in other property), increased capital expenditures attributable to increased activity in our drilling programs, and an increase in other property reflecting an investment of approximately $34.6 million in office property. This increase was partially offset by $31.8 million of restricted cash released in January 2007 from the sale of our interest in Garden Banks 422 (Cottonwood).
 
Net cash flows provided by financing activities were $387.4 million for 2008 compared to $116.7 million for 2007. The increase was due primarily to $223.5 million borrowed in January 2008 under our bank credit facility to finance the purchase of MGOM and net increased borrowings of $342.5 million for working capital requirements. This increase was partially offset by the decrease attributable to the proceeds received from our issuance in April 2007 of $300.0 million aggregate principal amount of 8% senior notes due in 2017.
 
2008 Uses of Capital.  Our primary uses of capital during 2008 were as follows:
 
  •  funding capital expenditures (excluding hurricane repairs and acquisitions) of approximately $1,005.7 million;
 
  •  funding hurricane repairs and hurricane-related abandonment expenditures of approximately $55.6 million;
 
  •  paying interest of approximately $62.2 million;


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  •  funding the purchase of MGOM for approximately $223.5 million; and
 
  •  paying routine operating and administrative expenses.
 
2008 Capital Expenditures.  The following table presents major components of our capital expenditures during 2008 compared to 2007.
 
                 
    Year Ended December 31,  
    2008     2007  
    (In thousands)  
 
Capital expenditures:
               
Oil and natural gas development
  $ 588,456     $ 448,577  
Oil and natural gas property acquisitions
    302,629       122,895  
Oil and natural gas exploration
    270,767       182,645  
Leasehold acquisitions
    152,567       24,189  
Corporate expenditures and other
    66,668       15,952  
Proceeds from property conveyances(1)
          (4,116 )
                 
Total capital expenditures, net of proceeds from property conveyances
  $ 1,381,087     $ 790,142  
                 
 
 
(1) Proceeds from sale of Cottonwood project in 2006 (Garden Banks 244) were recorded as restricted cash of which $5.0 million remained as of December 31, 2007 (Refer to “Restricted Cash” under “Note 1. — Summary of Significant Accounting Policies” in the Notes to the Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K).
 
2008 Hurricane Expenditures.  During the year ended 2008, we incurred approximately $21.7 million in hurricane expenditures resulting from Hurricanes Ike and Gustav, of which $0.8 million were repairs and $20.9 were capital expenditures. Since 2004, we have incurred approximately $213.5 million in hurricane expenditures from Hurricanes Ike, Gustav, Ivan, Katrina and Rita, of which $0.8 million were repairs, $158.2 were capital expenditures and $54.5 million were hurricane-related abandonment costs. Net of our deductible of $14.4 million and insurance proceeds received of $69.4 million, our insurance receivable at December 31, 2008 was $35.3 million, of which an estimated $13.1 million is expected to be settled within the next 12 months. However, due to the magnitude of Hurricanes Ike, Katrina and Rita and the complexity of the insurance claims being processed by the insurance industry, the timing of our ultimate insurance recovery cannot be assured. We expect to maintain a potentially significant insurance receivable through 2010 in respect of Hurricane Ike while we actively pursue settlement of our claims to minimize the impact to our working capital and liquidity. We expect to recover substantially all of our outstanding OIL claims in respect of Hurricanes Katrina and Rita by 2010. Any differences between our insurance recoveries and insurance receivables will be recorded as adjustments to our oil and natural gas properties.
 
2008 Sources of Capital.  Our primary sources of capital during 2008 were as follows:
 
  •  cash flow from operations;
 
  •  borrowings under our revolving bank credit facility; and
 
  •  insurance proceeds.
 
Bank Credit Facility — We have a secured revolving credit facility with a group of banks pursuant to an amended and restated credit agreement dated March 2, 2006, as further amended. The credit facility matures January 31, 2012 and is subject to a borrowing base which is redetermined periodically. As of December 31, 2008, maximum credit availability under the facility was $1.0 billion, including up $50.0 million in letters of credit, subject to a borrowing base of $850.0 million scheduled to be redetermined in February 2009. The redetermination was pending on February 28, 2009, and we anticipate that it will occur in March 2009.
 
The lenders redetermine the borrowing base periodically based upon their evaluation of our oil and gas reserves and other factors. Any increase in the borrowing base requires the consent of all lenders. The outstanding principal balance of loans under the credit facility may not exceed the borrowing base. If the borrowing base falls below the sum of the amount borrowed and uncollateralized letter of credit exposure,


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then to the extent of the deficit, we must prepay borrowings and cash collateralize letter of credit exposure, pledge additional unencumbered collateral, repay borrowings and cash collateralize letters of credit on an installment basis, or effect some combination of these actions.
 
Borrowings under the bank credit facility bear interest at either a LIBOR-based rate or a prime-based rate, at our option, plus a specified margin. We must pay a commitment fee of 0.250% to 0.375% per year on unused availability under the bank credit facility. We have used borrowings under the facility to facilitate the Forest Merger and acquisition of MGOM, and have used and may use borrowings under the facility for general corporate purposes.
 
As of December 31, 2008 and 2007, $570.0 million and $179.0 million, respectively, were outstanding under the credit facility, and the interest rates were 3.31% and 7.25%, respectively. In addition, as of December 31, 2008 five letters of credit totaling $7.2 million were outstanding, of which $4.2 million was required for plugging and abandonment obligations at certain of our offshore fields.
 
Payment and performance of our obligations under the credit facility (including any obligations under commodity and interest rate hedges entered into with facility lenders) are secured by liens upon substantially all of our assets, and guaranteed by our subsidiaries, other than MERI which is a co-borrower. We also are subject to various restrictive covenants and other usual and customary terms and conditions, including limits on additional debt, cash dividends and other restricted payments, liens, investments, asset dispositions, mergers and speculative hedging. Financial covenants under the credit facility require us to, among other things:
 
  •  maintain a ratio of consolidated current assets plus the unused borrowing base to consolidated current liabilities of not less than 1.0 to 1.0; and
 
  •  maintain a ratio of total debt to EBITDA (as defined in the credit agreement) of not more than 2.5 to 1.0.
 
We were in compliance with the financial covenants under the bank credit facility as of December 31, 2008. Our breach of these covenants would be an event of default, after which the lenders could terminate their lending obligations and accelerate maturity of any outstanding indebtedness under the credit facility which then would become due and payable in full. An unrescinded acceleration of maturity under the bank credit facility would constitute an event of default under our senior notes described below, which could trigger acceleration of maturity of the indebtedness evidenced by the senior notes.
 
Senior Notes — Mariner has outstanding the following two issues of debt issued in registered transactions, referred to collectively as the “Notes”:
 
  •  $300 million principal amount of 71/2% Senior Notes due 2013 issued in March 2006 (“the 71/2% Notes”)
 
  •  $300 million principal amount of 8% Senior Notes due 2017 issued in April 2007 (“the 8% Notes”)
 
The Notes are senior unsecured obligations of Mariner, rank senior in right of payment to any future subordinated indebtedness, rank equally in right of payment with each other and with Mariner’s existing and future senior unsecured indebtedness and are effectively subordinated in right of payment to Mariner’s senior secured indebtedness, including its obligations under its bank credit facility, to the extent of the collateral securing such indebtedness, and to all existing and future indebtedness and other liabilities of any non-guarantor subsidiaries.
 
The Notes are jointly and severally guaranteed on a senior unsecured basis by Mariner’s existing and future domestic subsidiaries. In the future, the guarantees may be released or terminated under certain circumstances. Each subsidiary guarantee ranks senior in right of payment to any future subordinated indebtedness of the guarantor subsidiary, ranks equally in right of payment to all existing and future senior unsecured indebtedness of the guarantor subsidiary and effectively subordinate to all existing and future secured indebtedness of the guarantor subsidiary, including its guarantees of indebtedness under Mariner’s bank credit facility, to the extent of the collateral securing such indebtedness.
 
Interest on the 71/2% Notes is payable on April 15 and October 15 of each year. The 71/2% Notes mature on April 15, 2013. Interest on the 8% Notes is payable on May 15 and November 15 of each year, beginning November 15, 2007. The 8% Notes mature on May 15, 2017. There is no sinking fund for the Notes.


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The Company may redeem the 71/2% Notes at any time before April 15, 2010 and the 8% Notes at any time before May 15, 2012, in each case at a price equal to the principal amount redeemed plus a make-whole premium, using a discount rate of the Treasury rate plus 0.50% and accrued but unpaid interest. Beginning on the dates indicated below, the Company may redeem the Notes from time to time, in whole or in part, at the prices set forth below (expressed as percentages of the principal amount redeemed) plus accrued but unpaid interest:
 
     
71/2% Notes
 
8% Notes
 
April 15, 2010 at 103.750%
  May 15, 2012 at 104.000%
April 15, 2011 at 101.875%
  May 15, 2013 at 102.667%
April 15, 2012 and thereafter at 100.000%
  May 15, 2014 at 101.333%
    May 15, 2015 and thereafter at 100.000%
 
In addition, before April 15, 2009, the Company may redeem up to 35% of the 71/2% Notes with the proceeds of equity offerings at a price equal to 107.50% of the principal amount of the 71/2% Notes redeemed. Before May 15, 2010, the Company may redeem up to 35% of the 8% Notes with the proceeds of equity offerings at a price equal to 108% of the principal amount of the 8% Notes redeemed plus accrued but unpaid interest.
 
If the Company experiences a change of control (as defined in each of the indentures governing the Notes), subject to certain exceptions, the Company must give holders of the Notes the opportunity to sell to the Company their Notes, in whole or in part, at a purchase price equal to 101% of the principal amount, plus accrued and unpaid interest and liquidated damages to the date of purchase.
 
The Company and its restricted subsidiaries are subject to certain negative covenants under each of the indentures governing the Notes. The indentures limit the ability of the Company and each of its restricted subsidiaries to, among other things:
 
  •  make investments;
 
  •  incur additional indebtedness or issue preferred stock;
 
  •  create certain liens;
 
  •  sell assets;
 
  •  enter into agreements that restrict dividends or other payments from its subsidiaries to itself;
 
  •  consolidate, merge or transfer all or substantially all of its assets;
 
  •  engage in transactions with affiliates;
 
  •  pay dividends or make other distributions on capital stock or subordinated indebtedness; and
 
  •  create unrestricted subsidiaries.
 
Costs associated with the 71/2% Notes offering were approximately $8.5 million, excluding discounts of $3.8 million. Costs associated with the 8% Notes offering included aggregate underwriting discounts of approximately $5.3 million and offering expenses of approximately $1.3 million.
 
Future Uses of Capital.  Our identified needs for liquidity in the future are as follows:
 
  •  funding future capital expenditures;
 
  •  funding hurricane repairs and hurricane-related abandonment operations;
 
  •  financing any future acquisitions that Mariner may identify;
 
  •  paying routine operating and administrative expenses; and
 
  •  paying other commitments comprised largely of cash settlement of hedging obligations and debt service.
 
2009 Capital Expenditures.  In the second half of 2008, a world-wide economic recession and oversupply of natural gas in North America led to an unprecedented decline in oil and gas prices. However, the inflated cost of oil field services resulting from sustained historically high commodity prices did not decrease


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in line with the decline in commodity prices. The prospect of continued low commodity prices and disproportionately high service costs has constrained the industry’s capital reinvestment and undermined rates of return in new projects, particularly those in areas characterized by high costs or long reserve lives. In order to manage our capital program within expected cash flows, we tentatively have reduced our 2009 capital budget by more than 50% from 2008. Refer to “Item. 1. Business — Impact of Worldwide Financial Crisis and Lower Commodity Prices on Capital Program” in Part I of this Annual Report on Form 10-K for an outline of our planned 2009 activities in the Permian Basin and Gulf of Mexico.
 
We anticipate that our base operating capital expenditures for 2009 will be approximately $430.6 million (excluding hurricane-related expenditures and acquisitions), with significant potential for increase or decrease depending upon drilling success and cash flow experience during the year. Approximately 48% of the base operating capital program is planned to be allocated to development activities, 45% to exploration activities, and the remainder to other items (primarily capitalized overhead and interest). In addition, we estimate to incur additional hurricane-related costs of $36.1 million during 2009 related to Hurricane Ike, that we believe is substantially covered under applicable insurance. Complete recovery or settlement is not expected to occur during the next 12 months.
 
Obligations and Commitments
 
Consolidated Contractual Obligations — The following table presents a summary of our consolidated contractual obligations and commercial commitments as of December 31, 2008:
 
                                         
    Payments Due By Period  
    Total     2009     2010-2011     2012-2013     Thereafter  
    (In thousands)  
 
Debt obligations(1)
  $ 1,170,000     $     $     $ 870,000     $ 300,000  
Interest obligations(2)
    355,523       65,367       130,734       78,545       80,877  
Operating leases
    21,646       2,240       5,031       4,498       9,877  
Abandonment liabilities
    408,244       82,364       73,393       83,205       169,282  
Seismic obligations
    3,000       2,333       667              
Capital accrual obligations
    195,833       195,833                    
OIL Theoretical Withdrawal(3)
    36,000       6,391       14,586       15,023        
Rig commitment
    183,882       124,450       59,432              
Other liabilities(4)
    99,091       99,091                    
                                         
Total contractual cash commitments
  $ 2,473,219     $ 578,069     $ 283,843     $ 1,051,271     $ 560,036  
                                         
 
 
(1) As of December 31, 2008, we incurred debt obligations under our bank credit facility, the Notes.
 
(2) Interest obligations represent interest due on the bank credit facility and the Notes at 7.5% and 8%. Future interest obligations under our bank credit facility are uncertain, due to the variable interest rate on fluctuating balances. Based on a 3.31% weighted average interest rate on amounts outstanding under our bank credit facility as of December 31, 2008, our cash payments for interest would be $18.9 million annually for 2009 through 2011 and $1.6 million in 2012.
 
(3) We accrued approximately $36.0 million as of December 31, 2008, for an insurance premium contingency related to our membership in OIL. As part of our membership, we are obligated to pay a withdrawal premium if we elect to withdraw from OIL. We do not anticipate withdrawing from OIL; however, due to the contingency, OIL calculates a potential withdrawal premium annually based on past losses and we accrue a liability for the potential premium. OIL requires smaller members to provide a letter of credit or other acceptable security in favor of OIL to secure payment of the withdrawal premium. Acceptable security has included a letter of credit or a security agreement pursuant to which a member grants OIL a security interest in certain claim proceeds payable by OIL to the member. We anticipate that we will enter into such a security agreement, granting to OIL a security interest in a portion of our Hurricane Ike claim proceeds payable by OIL. We expect to have the ability to replace the security agreement with a letter of credit or other acceptable security in favor of OIL.


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(4) Other liabilities include accrued LOE of $30.9 million, accrued liabilities of $11.0 million, gas balancing of $15.9 million, oil and gas payable of $24.5 million, accrued compensation of $10.7 million, other G&A of $4.2 million and other liabilities for $1.9 million.
 
 
Future Capital Resources.  Our anticipated sources of liquidity in the future are as follows:
 
  •  cash flow from operations in future periods;
 
  •  proceeds under our bank credit facility;
 
  •  proceeds from insurance policies relating to hurricane repairs; and
 
  •  proceeds from future capital markets transactions as needed.
 
In 2009, we intend to tailor our operating capital program (exclusive of hurricane-related expenditures and acquisitions) within our projected operating cash flow so that our operating capital requirements are largely self-funding under normal commodity price assumptions. We anticipate using proceeds under our bank credit facility only for working capital needs or acquisitions and not generally to fund our operations. We would generally expect to fund future acquisitions on a case by case basis through a combination of bank debt and capital markets activities. Based on our current operating plan and assumed price case, our expected cash flow from operations and continued access to our bank credit facility allows us ample liquidity to conduct our operations as planned for the foreseeable future.
 
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. 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 bank credit facility are largely dependent on our level of estimated proved reserves and current oil and natural gas prices. If either our estimated proved reserves or commodity prices decrease, amounts available to us to borrow under our bank credit facility could be reduced. If our cash flows are less than anticipated or amounts available for borrowing are reduced, we may be forced to defer planned capital expenditures.
 
In addition, the recent worldwide financial and credit crisis may adversely affect our liquidity. We may be unable to obtain adequate funding under our bank credit facility because our lending counterparties may be unwilling or unable to meet their funding obligations, or because our borrowing base under the facility may be decreased as the result of a redetermination, reducing it due to lower oil or natural gas prices, operating difficulties, declines in reserves or other reasons. If funding is not available as needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or we may be unable to implement our business strategies or otherwise take advantage of business opportunities or respond to competitive pressures.
 
 
Mariner’s bank credit facility has a letter of credit subfacility of up to $50.0 million that is included as a use of the borrowing base. As of December 31, 2008, five such letters of credit totaling $7.2 million were outstanding.
 
 
We determine fair value for our natural gas and crude oil costless collars using fair value measurements based on the Black-Scholes valuation model, adjusted for credit risk. The credit risk adjustment for collar liabilities is based on our credit quality and the credit risk adjustment for collar assets is based on the credit quality of our counterparty. Such valuations have historically approximated our exit price for such derivatives. We validate the fair value measurements of our collars using a Black-Scholes pricing model using observable market data, to the extent available, and unobservable or adjusted data, if observable data is not available or is not representative of fair value. As of December 31, 2008, our internal calculations of fair value were determined using market data.


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We determine the fair value of our natural gas and crude oil fixed price swaps by reference to forward pricing curves for natural gas and oil futures contracts. The difference between the forward price curve and the contractual fixed price is discounted to the measurement date using a credit-risk adjusted discount rate. The credit risk adjustment for swap liabilities is based on our credit quality and the credit risk adjustment for swap assets is based on the credit quality of our counterparty. Our fair value determinations of our swaps have historically approximated our exit price for such derivatives.
 
Due to unavailability of observable volatility data input or use of adjusted implied volatility for our collars, we have determined that fair value measurements of all of our collars are categorized as level 3 in accordance with SFAS No. 157, “Fair Value Measurements” (“SFAS 157”) (see Note 9, “Fair Value Measurements” in the Notes to Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K). As of December 31, 2008 we had no collars outstanding. We have determined that the fair value methodology described above for our swaps is consistent with observable market inputs and have categorized our swaps as level 2 in accordance with SFAS 157.
 
During the twelve months ended December 31, 2008, we recorded an asset for the increase in the fair value of our derivative financial instruments of $154.2 million, principally due to the decrease in natural gas and oil commodity prices below our swap prices and floor prices in our collars. The increase was comprised of an increase in accumulated other comprehensive income of approximately $165.7 million, net of income taxes of $91.3 million, approximately $98.8 million of unfavorable cash hedging settlements during the period reflected in natural gas and oil revenues, and an unrealized non-cash loss due to hedging ineffectiveness under SFAS 133 of approximately $2.0 million reflected in natural gas revenues.
 
We expect the continued volatility of natural gas and oil commodity prices to have a material impact on the fair value of our derivatives positions. It is our intent to hold all of our derivatives positions to maturity such that realized gains or losses are generally recognized in income when the hedged natural gas or oil is produced and sold. While the derivatives settlements may decrease (or increase) our effective price realized, the ultimate settlement of our derivatives positions is not expected to materially adversely affect our liquidity, results of operations or cash flows.
 
 
Our discussion and analysis of Mariner’s financial condition and results of operations are based upon Consolidated Financial Statements that have been prepared in accordance with GAAP. The preparation of these Consolidated 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 Consolidated Financial Statements. See “Note 1. — Summary of Significant Accounting Policies” in the Notes to the Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K. We analyze our estimates, including those related to oil and gas revenues; oil and gas properties; fair value of derivative instruments; goodwill; abandonment liabilities; income taxes; commitments and contingencies; depreciation, depletion and amortization; share-based compensation; and full-cost ceiling calculation. Our estimates are based on historical experience and various 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 Consolidated Financial Statements.
 
 
Our 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, including certain G&A costs. G&A costs associated with production, operations, marketing and general corporate activities are expensed as incurred. The capitalized costs, coupled with our estimated asset retirement obligations recorded in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), are included in the amortization base and amortized to expense using the unit-of-production method. Amortization is calculated based on estimated proved oil and gas reserves. Proceeds from the sale or disposition of oil and gas properties are applied to


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reduce net capitalized costs unless the sale or disposition causes a significant change in the relationship between costs and the estimated value of proved reserves.
 
Capitalized costs (net of accumulated depreciation, depletion and amortization and deferred income taxes) of proved oil and gas properties are subject to a ceiling. The ceiling limits these costs to an amount equal to the present value, discounted at 10%, of estimated future net cash flows from estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future income taxes. The full-cost ceiling limitation is calculated using natural gas and oil prices in effect as of the balance sheet date and is adjusted for “basis” or location differentials. Price is held constant over the life of the reserves.
 
We use derivative financial instruments that qualify for cash flow hedge accounting under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS 133”) to hedge against the volatility of natural gas prices. In accordance with Securities and Exchange Commission (“SEC”) guidelines, we include estimated future cash flows from our hedging program in our ceiling test calculation. If net capitalized costs related to proved properties exceed the ceiling limit, the excess is impaired and recorded in the Consolidated Statements of Operations.
 
At December 31, 2008, the net capitalized cost of proved oil and gas properties exceeded the ceiling limit due to a decline in oil and gas commodity prices during the fourth quarter 2008 and the Company recorded a non-cash ceiling test impairment of $575.6 million during the fourth quarter. The writedown would have been $695.6 million if we had not used hedge adjusted prices for the volumes that were subject to hedges. The ceiling limit of our proved reserves was calculated based upon quoted market prices of $5.71 per Mcfe for gas and $44.61 per barrel for oil, adjusted for market differentials for the year ended December 31, 2008. If commodity prices continue to deteriorate during the first quarter of 2009, we may be required to record a ceiling test impairment which could be material to our financial position and results of operations.
 
 
Our most significant financial estimates are based on estimates of proved oil and natural gas reserves. Estimates of proved reserves are key components in determining 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. 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 Company, L.P.
 
 
The costs associated with unevaluated properties and properties under development are not initially included in the full-cost amortization base. These costs relate to unproved leasehold acreage and include costs for seismic data, wells and production facilities in progress and wells pending determination. Interest is capitalized on the costs in unproved properties while in the development stage. Unevaluated leasehold costs are transferred to the amortization base once determination has been made or upon expiration of a lease. Geological and geophysical costs, including 3-D seismic data costs, are included in the full-cost amortization base as incurred when such costs cannot be associated with specific unevaluated properties for which we own a direct interest. Seismic data costs are associated with specific unevaluated properties if the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by us. We make this determination based on an analysis of leasehold and seismic maps and discussions with our Chief Exploration Officer. Geological and geophysical costs included in unproved properties are transferred to the full-cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. All items included in our unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value.


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In accordance with SFAS 143, we record the fair value of a liability for the legal obligation to retire an asset in the period in which it is incurred and capitalize the corresponding cost by increasing the carrying amount of the related long-lived asset. Upon our adoption of SFAS 143, we recorded an asset retirement obligation to reflect our legal obligations related to future plugging and abandonment of its oil and natural gas wells. 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, the difference is recognized in Oil and Gas Properties.
 
To estimate the fair value of an asset retirement obligation, we employ a present value technique, which reflects certain assumptions, including our credit-adjusted risk-free interest rate, the estimated settlement date of the liability and the estimated current cost to settle the liability. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability.
 
 
Other property and equipment is recorded at cost and consists of real estate, IT equipment, office furniture and fixtures, leasehold improvements and gas gathering systems. Acquisitions and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation of other property and equipment is provided on a straight-line basis over their estimated useful lives, which range from three to twenty-two years. Per SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”), we assess other property for impairment when events indicate the carrying value exceeds fair value. As a result of our SFAS 144 assessment performed at December 31, 2008, an impairment of $15.3 million was recorded related to office property.
 
 
We account for goodwill in accordance with SFAS No. 142 “Goodwill and Other Intangible Assets” (“SFAS 142”). SFAS 142 requires goodwill to be tested for impairment on an annual basis and between annual tests when events or circumstances indicate a potential impairment. In a purchase transaction, goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed. We follow the full cost method of accounting and all of our oil and gas properties are located in the United States. For the purpose of performing an impairment test, we have determined that we have one reporting unit. Our goodwill impairment reviews consist of a two-step process. The first step is to determine the fair value of our reporting unit and compare it to the carrying value of the related net assets. Fair value is determined based on our estimates of market values. If this fair value exceeds the carrying value no further analysis or goodwill write-down is required. The second step is required if the fair value of the reporting unit is less than the carrying value of the net assets. In this step the implied fair value of the reporting unit is allocated to all the underlying assets and liabilities, including both recognized and unrecognized tangible and intangible assets, based on their fair values. If necessary, goodwill is then written-down to its implied fair value.
 
We perform our goodwill test annually on November 30 and more often if circumstances require. Amounts recorded in goodwill relate to the excess purchase price paid in association with the Forest Merger. See “Note 2. Acquisitions and Dispositions — Forest Gulf of Mexico Operation” in the Notes to the Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K.
 
In connection with our annual impairment test on November 30, 2008, we performed a step one impairment analysis. As a result of weakened economic conditions and a decline in our stock price during the fourth quarter of 2008, the carrying value of our reporting unit exceeded the fair value and a step two analysis was required to determine the impairment. Our fair value estimates in step two were developed using a weighted average cost of capital (“WACC”) of 12.0% and a control premium of 25.0%. A 1.0% increase and decrease of the WACC would have changed the fair value by (3.7%) and 4.0% respectively. We allocated the estimated fair value determined using these assumptions to the identifiable tangible and intangible assets and liabilities of our reporting unit based on their respective values. This allocation indicated no residual value for goodwill and we recorded approximately $295.6 million of goodwill impairment in continuing operations as of December 31, 2008. We had previously determined that there was no impairment loss in continuing operations


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as of December 31, 2007 and 2006, respectively. In 2007, goodwill decreased as a result of changes in the book and tax basis related to the Forest Merger.
 
 
Our provision for taxes includes both state and federal taxes. The Company records its federal income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”) 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 basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carry forwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amount more likely than not to be recovered.
 
Effective January 1, 2007, we adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes (an interpretation of FASB Statement No. 109)” (“FIN 48”). This interpretation clarified the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact our financial position, results of operations and cash flows. We do not have uncertain tax positions outstanding and, as such, did not recorded a FIN 48 liability for the years ended December 31, 2008 and 2007.
 
Additionally, 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.
 
 
The Company utilizes derivative instruments in the form of natural gas and crude oil price swap agreements and costless collar arrangements in order to manage price risk associated with future crude oil and natural gas production and fixed-price crude oil and natural gas purchase and sale commitments. Such agreements are accounted for as cash flow hedges in accordance with SFAS 133. Gains and losses resulting from these transactions, recorded at market value, are deferred and recorded in Accumulated Other Comprehensive Income as appropriate, until recognized as operating income in the Company’s Consolidated Statements of Operations as the physical production hedged by the contracts is delivered. The Company presents the fair value of its derivatives on a net basis in accordance with FASB Interpretation No. 39 “Offsetting of Amounts Related to Certain Contracts an interpretation of APB Opinion No. 10 and FASB Statement No. 105” (“FIN 39”).
 
We are required to assess the effectiveness of all our derivative contracts at inception and at every quarter-end. If open contracts cease to qualify for hedge accounting, mark-to-market accounting is utilized and changes in the fair value of open contracts are recognized in the Consolidated Statements of Operations. Mark-to-market accounting may cause volatility in Net Income. Fair value is assessed, measured and estimated by obtaining forward commodity pricing, credit adjusted risk-free interest rates and estimated volatility factors. In addition, forward price curves and estimates of future volatility factors are used to assess and measure the effectiveness of our open contracts at the end of each period. The fair values we report in our Consolidated Financial Statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.
 
The 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.


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The conditions to be met for a derivative instrument to qualify as a cash flow hedge are the following: (i) the item to be hedged exposes the Company to price risk; (ii) the derivative reduces the risk exposure and is designated as a hedge at the time the derivative contract is entered into; and (iii) at the inception of the hedge and throughout the hedge period there is a high correlation of changes in the market value of the derivative instrument and the fair value of the underlying item being hedged.
 
When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on sale or settlement of the underlying item. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if correlation no longer exists, the gain or loss on the derivative is recognized in income to the extent the future results have not been offset by the effects of price or interest rate changes on the hedged item since the inception of the hedge.
 
 
Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, and delivery has occurred and title has transferred. Natural gas and NGLs revenues are recorded using the entitlement method. Under the entitlement method, revenue is recorded when title passes based on the Company’s net interest or nominated deliveries. The Company records its entitled share of revenues based on entitled volumes and contracted sales prices. The sales price for natural gas, crude oil and NGLs are adjusted for revenue deductions. The revenue deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third party documents. Historically, these adjustments have been insignificant. Since there is a ready market for natural gas, crude oil and NGLs, the Company sells the majority of its products soon after production at various locations at which time title and risk of loss pass to the buyer. As a result, the Company maintains a minimum amount of product inventory in storage.
 
Gas imbalances occur when Mariner sells more or less than its entitled ownership percentage of total gas production. Any amount received in excess (overproduction) of Mariner’s share is treated as a liability. If Mariner receives less than it is entitled, the shortage (underproduction) is recorded as a receivable. Imbalances are reduced either by subsequent recoupment of over-and-under deliveries or by cash settlement, as required by applicable contracts. Production imbalances are recorded 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 exists. Mariner’s gas imbalances are not material, as oil and natural gas volumes sold are not significantly different from its share of production
 
 
We account for share-based compensation in accordance with the fair value recognition provisions of SFAS No. 123(R), “Share-Based Payment” (“SFAS 123(R)”). Under the fair value recognition provisions of SFAS 123(R), share-based compensation cost is measured at the grant date based on the value of the award and is recognized as expense over the vesting period. We use the Black-Scholes option pricing model to determine the fair value of options on the grant date, which requires judgment in estimating the expected life of the option and the expected volatility of our stock. We use a Monte Carlo simulation to estimate the fair value of restricted stock granted in 2008 under our stock incentive plan’s long-term performance-based restricted stock program.
 
 
On December 31, 2008, the SEC issued the final rule, “Modernization of Oil and Gas Reporting” (“Final Rule”). The Final Rule adopts revisions to the SEC’s oil and gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. Early adoption of the Final Rule is prohibited. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to align


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them with current practices and changes in technology. Revised requirements in the SEC’s Final Rule include, but are not limited to:
 
  •  Oil and gas reserves must be reported using the average price over the prior 12 month period, rather than year-end prices;
 
  •  Companies will be allowed to report, on an optional basis, probable and possible reserves;
 
  •  Non-traditional reserves, such as oil and gas extracted from coal and shales, will be included in the definition of “oil and gas producing activities”;
 
  •  Companies will be permitted to use new technologies to determine proved reserves, as long as those technologies have been demonstrated empirically to lead to reliable conclusions with respect to reserve volumes;
 
  •  Companies will be required to disclose, in narrative form, additional details on their proved undeveloped reserves (PUDs), including the total quantity of PUDs at year end, any material changes to PUDs that occurred during the year, investments and progress made to convert PUDs to developed oil and gas reserves and an explanation of the reasons why material concentrations of PUDs in individual fields or countries have remained undeveloped for five years or more after disclosure as PUDs;
 
  •  Companies will be required to report the qualifications and measures taken to assure the independence and objectivity of any business entity or employee primarily responsible for preparing or auditing the reserves estimates.
 
We are currently evaluating the potential impact of the Final Rule. The SEC is discussing the Final Rule with the FASB staff to align FASB accounting standards with the new SEC rules. These discussions may delay the required compliance date. Absent any change in the effective date, we will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ended December 31, 2009.
 
In October 2008, the FASB issued Staff Position (“FSP”) No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (“FSP 157-3”). FSP 157-3 applies to financial assets within the scope of accounting pronouncements that require or permit fair value measurements in accordance with SFAS No. 157, “Fair Value Measurements” (“SFAS 157”) and clarifies the application of SFAS 157 in a market that is not active. This FSP also provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. This FSP was effective upon issuance, including prior periods for which financial statements have not been issued. Revisions resulting from a change in the valuation technique or its application are accounted for as a change in accounting estimate according to SFAS No. 154 “Accounting Changes and Error Corrections”. The adoption of FSP 157-3 did not have a material effect on the Company’s results of operations, financial position or cash flows.
 
In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”). SFAS 162 is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities. The FASB believes that the GAAP hierarchy should be directed to entities because it is the entity (not its auditor) that is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. This statement became effective on November 15, 2008 following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” The adoption of SFAS 162 did not have a material effect on our results of operations, financial position or cash flows.
 
In April 2008, the FASB issued FSP No. 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP 142-3”). FSP 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets.” FSP 142-3 is effective for financial statements issued after December 15, 2008. The adoption of FSP 142-3 did not have a material effect on our results of operations, financial position, or cash flows.


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In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. SFAS 161 also improves transparency about the location and amounts of derivative instruments in an entity’s financial statements; how derivative instruments and related hedged items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”); and how derivative instruments and related hedged items affect its financial position, financial performance, and cash flows. SFAS 161 achieves these improvements by requiring disclosure of the fair values of derivative instruments and their gains and losses in a tabular format. It also provides more information about an entity’s liquidity by requiring disclosure of derivative features that are credit-risk related. Finally, it requires cross-referencing within footnotes to enable financial statement users to locate important information about derivative instruments. We currently are evaluating the effect the adoption of SFAS 161 will have on our results of operations, financial position and cash flows.
 
In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”), which replaces SFAS 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for fiscal years beginning after December 15, 2008. The adoption of SFAS 141(R) will have an impact on accounting for business combinations with the effect dependent upon acquisitions at that time.
 
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of Accounting Research Bulletin No. 51” (“SFAS 160”), which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The Statement also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. SFAS 160 is effective for fiscal years beginning after December 15, 2008. The adoption of SFAS 160 is not expected to have a material effect on our results of operations, financial position or cash flows.
 
During February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value, and thereby mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. This Statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS 159 was effective for the Company as of January 1, 2008. SFAS 159 did not have an impact on the Company’s Consolidated Financial Statements as the Company elected not to measure at fair value additional financial assets and liabilities not already required to be measured at fair value.
 
In September 2006, the FASB issued SFAS 157, which establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements but rather it eliminates inconsistencies in the guidance found in various prior accounting pronouncements. SFAS 157 was effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157,” which delayed the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This FSP is effective for financial statements issued during fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of this FSP. Accordingly, our adoption of


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SFAS 157 was limited to financial assets and liabilities, which primarily affects the valuation of the Company’s derivative contracts. The adoption of SFAS 157 with respect to financial assets and liabilities did not have a material impact on our net asset values (see Note 11 to the Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K). The Company is still in the process of evaluating SFAS 157 with respect to its effect on nonfinancial assets and liabilities and therefore has not yet determined the impact that it will have on its financial statements upon full adoption in 2009. Nonfinancial assets and liabilities for which the Company has not applied the provisions of SFAS 157 include its asset retirement obligations and assets held for future sale when applicable.
 
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk.
 
Commodity Prices and Related Hedging Activities
 
Our major market risk exposure continues to be the prices applicable to our natural gas and oil production. The sales price of our production is primarily driven by the prevailing market price. Historically, prices received for our natural gas and oil production have been volatile and unpredictable. Hypothetically, if production levels were to remain at 2008 levels, a 10% increase in commodity prices from those as of December 31, 2008 would increase our cash flow by approximately $134.9 million for the year ended December 31, 2009.
 
The energy markets have historically been very volatile, and we can reasonably expect that oil and gas prices will be subject to wide fluctuations in the future. In an effort to reduce the effects of the volatility of the price of oil and natural gas on our operations, management has adopted a policy of hedging oil and natural gas prices from time to time primarily through the use of commodity price swap agreements and costless collar arrangements. While the use of these hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements. In addition, forward price curves and estimates of future volatility are used to assess and measure the ineffectiveness of our open contracts at the end of each period. If open contracts cease to qualify for hedge accounting, the mark-to-market change in fair value is recognized in oil and natural gas revenue in the Consolidated Statements of Operations. Not qualifying for hedge accounting and cash flow hedge designation will cause volatility in Net Income. The fair values we report in our Consolidated Financial Statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.
 
Hedge gains and losses are recorded by commodity type in oil and natural gas revenues in the Consolidated Statements of Operations. The effects on our oil and gas revenues from our hedging activities were as follows:
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In thousands)  
 
Cash (Loss) Gain on Settlements
  $ (98,814 )   $ 46,732     $ 11,273  
(Loss) Gain on Hedge Ineffectiveness(1)
    (1,995 )     (1,655 )     4,175  
Non-cash Gain on hedges acquired(2)
                17,523  
                         
Total
  $ (100,809 )   $ 45,077     $ 32,971  
                         
 
 
(1) Unrealized (loss) gain recognized in natural gas revenue related to the ineffective portion of open contracts that are not eligible for deferral under SFAS 133 “Accounting for Derivative Instruments and Hedging Activities”, due primarily to the basis differentials between the contract price and the indexed price at the point of sale.
 
(2) In 2006, relating to the hedges acquired through the Forest transaction.


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As of December 31, 2008, the Company had the following hedging activity outstanding:
 
                         
          Weighted-Average
    Fair Value
 
Fixed Price Swaps
  Quantity     Fixed Price     Asset  
          (In thousands)        
 
Natural Gas (MMbtus)
                       
January 1 — December 31, 2009
    31,642,084     $ 8.48     $ 74,709  
Crude Oil (Bbls)
                       
January 1 — December 31, 2009
    2,172,210     $ 76.15       47,220  
                         
Total
                  $ 121,929  
                         
 
As of December 31, 2007, the Company had the following hedging activity outstanding:
 
                         
          Weighted-Average
    Fair Value
 
Fixed Price Swaps
  Quantity     Fixed Price     Asset/(Liability)  
          (In thousands)        
 
Natural Gas (MMBtus)
                       
January 1 — December 31, 2008
    40,583,847     $ 8.46     $ 27,672  
January 1 — December 31, 2009
    31,642,084     $ 8.48       (1,494 )
Crude Oil (Bbls)
                       
January 1 — December 31, 2008
    2,263,552     $ 78.99       (31,219 )
January 1 — December 31, 2009
    2,172,210     $ 76.15       (23,158 )
                         
Total
                  $ (28,199 )
                         
 
                                 
                      Fair Value
 
Costless Collars
  Quantity     Floor     Cap     Asset/(Liability)  
          (In thousands)        
 
Natural Gas (MMBtus)
                               
January 1 — December 31, 2008
    12,347,000     $ 7.83     $ 14.60     $ 7,201  
Crude Oil (Bbls)
                               
January 1 — December 31, 2008
    1,195,495     $ 61.66     $ 86.81       (11,259 )
                                 
Total
                          $ (4,058 )
                                 
 
As of February 20, 2009, there were no hedging transactions entered into subsequent to December 31, 2008 except as follows:
 
                         
                Weighted Average
 
Period
  Instrument Type     Quantity     Price  
 
Natural Gas (MMbtus) 2009
                       
January 1 — December 31
    Fixed Price Swaps       19,665,000     $ 6.19 Fixed  
Crude Oil (Bbls) 2009
                       
February 1 — December 31
    Fixed Price Swaps       977,047     $ 51.46 Fixed  
 
We have reviewed the financial strength of our counterparties and believe the credit risk associated with these swaps and costless collars to be minimal. Hedges with counterparties that are lenders under our bank credit facility are secured under the bank credit facility.
 
As of December 31, 2008, the Company expects to realize within the next 12 months approximately $121.9 million in net gains resulting from hedging activities that are currently recorded in accumulated other comprehensive income. These hedging gains are expected to be realized as an increase of $47.2 million to oil revenues and an increase of $74.7 million to natural gas revenues. On January 29, 2008, the Company liquidated crude oil fixed price swaps in respect of 977 thousand barrels in exchange for a cash payment of $10.1 million and installment payments of $13.5 million to be received monthly throughout 2009.


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Borrowings under our bank credit facility mature on January 31, 2012 and bear interest at either a LIBOR-based rate or a prime-based rate, at our option, plus a specified margin. Both options expose us to risk of earnings loss due to changes in market rates. We have not entered into interest rate hedges that would mitigate such risk. During 2008, the interest rate on our outstanding bank debt was 3.31%. If the balance of our bank debt at December 31, 2008 were to remain constant, a 10% increase in market interest rates would decrease our cash flow by approximately $1.9 million for the year ended December 31, 2008.
 
Item 8.   Financial Statements and Supplementary Data.
 
 
         
    64  
    65  
    66  
    67  
    68  
    69  
    70  


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Management, including Mariner’s chief executive officer and chief financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting for Mariner. Mariner’s internal control system was designed to provide reasonable assurance to Mariner’s management and directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.
 
Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Mariner’s internal control over financial reporting was effective as of December 31, 2008. Deloitte & Touche LLP, Mariner’s independent auditor for 2008, has issued an attestation report on Mariner’s internal control over financial reporting that is included in the accompanying Report of Independent Registered Public Accounting Firm.
 
     
/s/  SCOTT D. JOSEY

 
/s/  JOHN H. KARNES

Scott D. Josey,
Chairman of the Board,
Chief Executive Officer and President
  John H. Karnes,
Senior Vice President,
Chief Financial Officer and Treasurer
 
Houston, Texas
March 2, 2009


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To the Board of Directors and Stockholders of
Mariner Energy, Inc.
Houston, Texas
 
We have audited the accompanying consolidated balance sheets of Mariner Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. We also have audited the Company’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
 
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Mariner Energy, Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
DELOITTE & TOUCHE LLP
 
Houston, Texas
March 2, 2009


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MARINER ENERGY, INC.
 
 
                 
    December 31,
    December 31,
 
    2008     2007  
    (In thousands, except share data)  
 
Current Assets:
               
Cash and cash equivalents
  $ 3,251     $ 18,589  
Receivables, net of allowances of $3,868 and $2,449, respectively
    219,920       157,774  
Insurance receivables
    13,123       26,683  
Derivative financial instruments
    121,929       11,863  
Intangible assets
    2,353       17,209  
Prepaid expenses and other
    14,377       10,630  
Deferred tax asset
          6,232  
                 
Total current assets
    374,953       248,980  
Property and Equipment:
               
Proved oil and gas properties, full-cost method
    4,448,146       3,118,273  
Unproved properties, not subject to amortization
    201,121       40,455  
                 
Total oil and gas properties
    4,649,267       3,158,728  
Other property and equipment
    53,115       15,545  
Accumulated depreciation, depletion and amortization:
               
Proved oil and gas properties
    (1,767,028 )     (751,127 )
Other properties
    (5,477 )     (2,952 )
Total accumulated depreciation, depletion and amortization
    (1,772,505 )     (754,079 )
Total property and equipment, net
    2,929,877       2,420,194  
Restricted Cash
          5,000  
Goodwill
          295,598  
Insurance Receivables
    22,132       56,924  
Derivative Financial Instruments
          691  
Other Assets, net of amortization
    65,831       56,248  
                 
TOTAL ASSETS
  $ 3,392,793     $ 3,083,635  
                 
Current Liabilities:
               
Accounts payable
  $ 3,837     $ 1,064  
Accrued liabilities
    107,815       96,936  
Accrued capital costs
    195,833       159,010  
Deferred income tax
    23,148        
Abandonment liability
    82,364       30,985  
Accrued interest
    12,567       7,726  
Derivative financial instruments
          19,468  
                 
Total current liabilities
    425,564       315,189  
Long-Term Liabilities:
               
Abandonment liability
    325,880       191,021  
Deferred income tax
    319,766       343,948  
Derivative financial instruments
          25,343  
Long-term debt
    1,170,000       779,000  
Other long-term liabilities
    31,263       38,115  
                 
Total long-term liabilities
    1,846,909       1,377,427  
Commitments and Contingencies (see Note 8)
               
Minority Interest
          1  
Stockholders’ Equity:
               
Preferred stock, $.0001 par value; 20,000,000 shares authorized, no shares issued and outstanding at December 31, 2008 and December 31, 2007
           
Common stock, $.0001 par value; 180,000,000 shares authorized, 88,846,073 shares issued and outstanding at December 31, 2008; 180,000,000 shares authorized, 87,229,312 shares issued and outstanding at December 31, 2007
    9       9  
Additional paid-in-capital
    1,071,347       1,054,089  
Accumulated other comprehensive income/(loss)
    78,181       (22,576 )
Accumulated retained earnings
    (29,217 )     359,496  
                 
Total stockholders’ equity
    1,120,320       1,391,018  
                 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 3,392,793     $ 3,083,635  
                 
 
The accompanying Notes to the Consolidated Financial Statements
are an integral part of these financial statements


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MARINER ENERGY, INC.
 
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (In thousands except share data)  
 
Revenues:
                       
Natural gas
  $ 742,370     $ 534,537     $ 412,967  
Oil
    419,878       284,405       202,744  
Natural gas liquids
    85,715       54,192       40,507  
Other revenues
    52,544       1,631       3,287  
                         
Total revenues
    1,300,507       874,765       659,505  
                         
Costs and Expenses:
                       
Lease operating expense
    231,645       152,627       91,592  
Severance and ad valorem taxes
    18,191       13,101       9,070  
Transportation expense
    14,996       8,794       5,077  
General and administrative expense
    60,613       42,151       33,622  
Depreciation, depletion and amortization
    467,265       384,321       292,180  
Full cost ceiling test impairment
    575,607              
Goodwill impairment
    295,598              
Other property impairment
    15,252              
Other miscellaneous expense
    3,052       5,061       494  
                         
Total costs and expenses
    1,682,219       606,055       432,035  
                         
OPERATING (LOSS) INCOME
    (381,712 )     268,710       227,470  
Other Income/(Expenses):
                       
Interest income
    1,362       1,403       985  
Interest expense, net of amounts capitalized
    (56,398 )     (54,665 )     (39,649 )
Other income
          5,811        
                         
(Loss) Income Before Taxes and Minority Interest
    (436,748 )     221,259       188,806  
Benefit (Provision) for Income Taxes
    48,223       (77,324 )     (67,344 )
Minority Interest
    (188 )     (1 )      
                         
NET (LOSS) INCOME
  $ (388,713 )   $ 143,934     $ 121,462  
                         
Earnings per share:
                       
Net (loss) income per share — basic
  $ (4.44 )   $ 1.68     $ 1.59  
Net (loss) income per share — diluted
  $ (4.44 )   $ 1.67     $ 1.58  
Weighted average shares outstanding — basic
    87,491,385       85,645,199       76,352,666  
Weighted average shares outstanding — diluted
    87,491,385       86,125,811       76,810,466  
 
The accompanying Notes to the Consolidated Financial Statements
are an integral