Annual report pursuant to Section 13 and 15(d)

Supplemental Oil And Gas Disclosures (Tables)

v2.4.0.6
Supplemental Oil And Gas Disclosures (Tables)
12 Months Ended
Dec. 31, 2011
Supplemental Oil And Gas Disclosures [Abstract]  
Capitalized Costs Related To Oil And Natural Gas
     December 31,  
     2011     2010     2009  

Net capitalized cost:

      

Proved oil and natural gas properties and equipment

   $ 5,775.4      $ 5,130.9      $ 4,637.2   

Unproved oil and natural gas properties and equipment

     183.6        94.7        95.5   

Accumulated depreciation, depletion and amortization related to oil, NGLs and natural gas activities

     (4,307.1     (4,009.9     (3,743.3
  

 

 

   

 

 

   

 

 

 

Net capitalized costs related to producing activities

   $ 1,651.9      $ 1,215.7      $ 989.4   
  

 

 

   

 

 

   

 

 

 
Capitalized Costs Not Subject To Amortization
     Total      2011      2010      2009      Prior to
2009
 

Costs excluded by year incurred:

              

Acquisition costs

   $ 125.7       $ 81.3       $  —         $  —         $ 44.4   

Capitalized interest not subject to amortization

     28.8         9.6         4.8         4.2         10.2   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total costs not subject to amortization

   $ 154.5       $ 90.9       $ 4.8       $ 4.2       $ 54.6   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
Cost Incurred In Oil And Gas Property Acquisition Exploration And Development Activities
Schedule Of Depreciation, Depletion, Amortization And Accretion Expense
     Year Ended December 31,  
     2011      2010      2009  

Depreciation, depletion, amortization and accretion per Mcfe

   $ 3.24       $ 3.38       $ 3.61   
Schedule Of Oil And Natural Gas Information
                     Total Equivalent Reserves  
     Oil
(MMBbls) (1)
    NGLs
(MMBbls) (1)
    Natural Gas
(Bcf) (1)
    Oil
Equivalent
(MMBoe) (2)
    Natural Gas
Equivalent
(Bcfe) (2)
 

Proved reserves as of December 31, 2008

     40.0        3.9        227.9        81.9        491.1   

Revisions of previous estimates (3)

     (2.1     —          (13.0     (4.3     (25.4

Extensions and discoveries (4)

     1.2        0.3        14.5        3.9        23.4   

Purchase of minerals in place

     —          —          0.4        0.1        0.7   

Sales of reserves (5)

     (1.8     (0.1     (12.4     (4.0     (24.0

Production

     (6.1     (1.1     (51.6     (15.8     (94.8
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved reserves as of December 31, 2009

     31.2        3.0        165.8        61.8        371.0   

Revisions of previous estimates (6)

     (0.2     1.2        14.6        3.4        20.2   

Extensions and discoveries (7)

     1.2        0.5        19.1        4.9        29.2   

Purchase of minerals in place (8)

     7.7        0.7        101.5        25.3        152.0   

Production

     (5.9     (1.2     (44.7     (14.5     (87.0
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved reserves as of December 31, 2010

     34.0        4.2        256.3        80.9        485.4   

Revisions of previous estimates (9)

     0.8        5.5        13.5        8.6        51.1   

Extensions and discoveries (10)

     2.0        0.4        17.7        5.3        32.0   

Purchase of minerals in place (11)

     20.7        8.9        55.9        39.0        234.1   

Production

     (6.1     (1.9     (53.7     (16.9     (101.5
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Proved reserves as of December 31, 2011

     51.4        17.1        289.7        116.9        701.1   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Year-end proved developed reserves:

          

2011

     23.4        11.0        251.4        76.4        458.2   

2010

     23.6        3.4        229.1        65.2        391.3   

2009

     21.3        2.4        141.3        47.3        283.5   

Year-end proved undeveloped reserves:

          

2011

     28.0        6.1        38.3        40.5        242.9   

2010

     10.4        0.8        27.2        15.7        94.1   

2009

     9.9        0.6        24.5        14.5        87.5   

(1) Estimated reserves as of December 31, 2011, 2010 and 2009 are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for those years in accordance with current definitions and guidelines set forth by the SEC and the FASB. Estimated of reserves as of December 31, 2008 were based on end-of-year prices.
(2) Bcfe and MMBoe are determined using the ratio of six thousand cubic feet ("Mcf") of natural gas to one barrel ("Bbl") of crude oil, condensate or NGLs (totals may not compute due to rounding). The conversion ratio does not assume price equivalency, and the price per Mcfe for oil and NGLs may differ significantly from the price per Mcf for natural gas. Similarly, the price per Bbl for oil for may differ significantly from the price per Bbl for NGLs.
(3)

Revisions for 2009 included decreases attributable to revised reserve reporting requirements for oil and natural gas companies enacted by the SEC and the FASB, which became effective for annual reporting periods ending on or after December 31, 2009. The initial application of these rules resulted in the removal of 23.2 Bcfe of proved undeveloped reserves associated with two of our fields for which our plan of development was not within five years from when the reserves were initially recorded, as required. Also included in the revisions of previous estimates for 2009 are negative revisions of 4.7 Bcfe due to performance.

(4) The majority of these volumes are attributable to extensions and discoveries resulting from our participation in the drilling of eight successful exploratory wells in 2009, all of which were on the conventional shelf.
(5) In the second quarter of 2009, we sold one of our fields in Louisiana state waters, and in the fourth quarter of 2009, we sold 36 non-core oil and natural gas fields in the Gulf of Mexico, subject to the terms of the purchase and sale agreements.
(6) Includes revisions due to price of 17.5 Bcfe.
(7) Includes discoveries of 21.9 Bcfe primarily in the Main Pass 108, Main Pass 98 and Main Pass 283 fields and extensions of 7.2 Bcfe primarily in the Main Pass 283 field.
(8) Primarily due to the properties acquired from Total (Matterhorn and Virgo fields) and the properties acquired from Shell (Tahoe, Southeast Tahoe and Droshky fields).
(9) Includes revision of 6.3 Bcfe due to an increase in average prices, 16.5 Bcfe for a change in NGLs marketing arrangements that allow us to recover a greater percentage of our NGLs from the gas stream, 11.3 Bcfe increase due to additional compression at our Tahoe field that allows us to reduce the drawdown pressure that increases production and ultimate recoveries, and 10.6 Bcfe at Fairway for revisions to reserve estimates from the acquisition date to year end.
(10) Includes discoveries of 13.9 Bcfe at Main Pass 98 and 8.0 Bcfe at Ship Shoal 349/359 and extensions of 3.7 Bcfe at Main Pass 108.
(11) Primarily due to the properties acquired from Opal (the Yellow Rose Properties) and the properties acquired from Shell (the Fairway Properties).
Schedule Of Prices Weighted By Field Production Related To The Proved Reserves
     December 31,  
     2011      2010      2009      2008  

Oil – per barrel

   $ 97.36       $ 76.28       $ 55.87       $ 38.85   

NGLs – per barrel

     51.30         44.92         33.36         25.90   

Natural gas – per Mcf

     4.11         4.57         3.80         6.17   
Schedule Of Changes In Standardized Measure
     Year Ended December 31,  
     2011     2010     2009  

Standardized Measure of Discounted Future Net Cash Flows

      

Future cash inflows

   $ 7,077,206      $ 3,953,655      $ 2,474,260   

Future costs:

      

Production

     (1,862,488     (1,011,552     (604,794

Development

     (543,017     (243,570     (212,835

Dismantlement and abandonment

     (513,620     (520,490     (496,540

Income taxes

     (1,126,573     (495,696     (186,101
  

 

 

   

 

 

   

 

 

 

Future net cash inflows before 10% discount

     3,031,508        1,682,347        973,990   

10% annual discount factor

     (1,025,131     (503,275     (313,594
  

 

 

   

 

 

   

 

 

 
   $ 2,006,377      $ 1,179,072      $ 660,396   
  

 

 

   

 

 

   

 

 

 
     Year Ended December 31,  
     2011     2010     2009  

Changes in Standardized Measure

      

Standardized measure, beginning of year

   $ 1,179,072      $ 660,396      $ 761,682   

Increases (decreases):

      

Sales and transfers of oil and gas produced, net of production costs

     (729,574     (521,551     (386,331

Net changes in price, net of future production costs

     634,174        367,575        (34,841

Extensions and discoveries, net of future production and development costs

     219,924        143,612        98,087   

Changes in estimated future development costs

     (4,572     (59,124     144,590   

Previously estimated development costs incurred

     173,911        97,188        224,802   

Revisions of quantity estimates

     204,988        94,735        (86,600

Accretion of discount

     135,791        68,862        78,789   

Net change in income taxes

     (398,204     (221,226     (32,394

Purchases of reserves in-place

     483,286        624,302        (9,927

Sales of reserves in-place

     —          —          (205,691

Changes in production rates due to timing and other

     107,581        (75,697     108,230   
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in standardized measure

     827,305        518,676        (101,286
  

 

 

   

 

 

   

 

 

 

Standardized measure, end of year

   $ 2,006,377      $ 1,179,072      $ 660,396