10-Q 1 form10q2ndqtr2010.htm FORM 10-Q form10q2ndqtr2010.htm


 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
     Washington, D.C. 20549     
 
FORM 10-Q
 
(Mark One)

ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2010

OR

 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from                   to                  

 
 
Commission File Number 1-8097
 

Ensco plc
(Exact name of registrant as specified in its charter)
 

 
England and Wales
(State or other jurisdiction of
incorporation or organization)
 
6 Chesterfield Gardens
London, England
(Address of principal executive offices)
 
98-0635229
(I.R.S. Employer
Identification No.)
 
W1J 5BQ
(Zip Code)
 
 
Registrant's telephone number, including area code:  44 (0) 20 7659 4660
 
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 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 ý        No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ý        No  o

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.

Large accelerated filer   ý
Non-accelerated filer   o  (Do not check if a smaller reporting company)
 
Accelerated filer         
Smaller reporting company   
o
o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes  o      No  ý
 
As of July 21, 2010, there were 142,959,478 American depositary shares of the registrant issued and outstanding, each representing one Class A ordinary share.
 
 
 
 



 
 
 
 

ENSCO PLC
INDEX TO FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2010
 

 
 
   
   
   
   
   
     
   
   
   
   
   
 
   
   
   
   
   


 
 

 
FORWARD-LOOKING STATEMENTS
 
    This report contains forward-looking statements that are subject to a number of risks and uncertainties and are based on information as of the date of this report. We assume no obligation to update these statements based on information after the date of this report.
 
    Forward-looking statements include words or phrases such as "anticipate," "believe," "estimate," "expect," "intend," "plan," "project," "could," "may," "might," "should," "will" and words and phrases of similar import. The forward-looking statements include, but are not limited to, statements about the impact of the December 2009 reorganization of the Company's corporate structure (referred to elsewhere herein as the "redomestication") and our plans, objectives, expectations and intentions with respect thereto and with respect to future operations, including the tax savings or other benefits that we expect to achieve as a result of the redomestication. Forward-looking statements also include statements regarding future operations, market conditions, cash generation, the impact of the BP Macondo well incident in the U.S. Gulf of Mexico, anticipated commencement of the ENSCO 8502 drilling contract, contributions from our ultra-deepwater semisubmersible rig fleet expansion program, expense management, industry trends or conditions and the overall business environment; statements regarding future levels of, or trends in, utilization, day rates, revenues, operating expenses, contract term, contract backlog, capital expenditures, insurance, financing and funding; statements regarding future rig construction (including construction in progress and completion thereof), enhancement, upgrade or repair and timing thereof; statements regarding future delivery, mobilization, contract commencement, relocation or other movement of rigs and timing thereof; statements regarding future availability or suitability of rigs and the timing thereof; and statements regarding the likely outcome of litigation, legal proceedings, investigations or insurance or other claims and the timing thereof.
 
   Forward-looking statements are made pursuant to safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Numerous factors could cause actual results to differ materially from those in the forward-looking statements, including:
 
 
changes in U.S. or non-U.S. laws, including tax laws, that could effectively reduce or eliminate the benefits we expect to achieve from our December 2009 redomestication or regulatory or legislative activity that would impact U.S. Gulf of Mexico operations, potentially resulting in a force majeure situation,
 
 
an inability to realize expected benefits from the redomestication,
 
 
costs related to the redomestication and ancillary matters, which could be greater than expected,
 
 
the impact of the BP Macondo well incident in the U.S. Gulf of Mexico upon future deepwater and other offshore drilling operations in general, and as respects current and future deepwater drilling permit and operations moratoria/suspensions, new and future legislative, regulatory or permit requirements (including requirements related to equipment and operations), future lease sales and other governmental activities that may impact deepwater and other offshore operations in the U.S. Gulf of Mexico in general, and our existing drilling contracts for ENSCO 8500, ENSCO 8501, ENSCO 8502, ENSCO 8503 and our U.S. Gulf of Mexico jackup rigs in particular,
 
 
 
industry conditions and competition, including changes in rig supply and demand or new technology, 
 
risks associated with the global economy and its impact on capital markets and liquidity,
 
 
prices of oil and natural gas and their impact upon future levels of drilling activity and expenditures,
 
 
further declines in drilling activity, which may cause us to idle or stack additional rigs,
 
 
excess rig availability or supply resulting from delivery of newbuild drilling rigs,
 
 
concentration of our rig fleet in premium jackups,
 
 
 
concentration of our active ultra-deepwater semisubmersible drilling rigs in the U.S. Gulf of Mexico,
 
cyclical nature of the industry,
 
 
worldwide expenditures for oil and natural gas drilling,
 
 
the ultimate resolution of the ENSCO 69 situation in general and the pending litigation, potential return of the rig or package policy political risk insurance recovery in particular,
 
 
changes in the timing of revenue recognition resulting from the deferral of certain revenues for mobilization of our drilling rigs, time waiting on weather or time in shipyards, which are recognized over the contract term upon commencement of drilling operations,
 
 
1

 
 
 
operational risks, including excessive unplanned downtime due to rig or equipment failure, damage or repair in general and hazards created by severe storms and hurricanes in particular,
 
 
changes in the dates our rigs will enter a shipyard, be delivered, return to service or enter service,
 
 
risks inherent to shipyard rig construction, repair or enhancement, including risks associated with concentration of our ENSCO 8500 Series® rig construction contracts in a single shipyard in Singapore, unexpected delays in equipment delivery and engineering or design issues following shipyard delivery,
 
 
changes in the dates new contracts actually commence,
 
 
renegotiation, nullification, cancellation or breach of contracts or letters of intent with customers or other parties, including failure to negotiate definitive contracts following announcements or receipt of letters of intent,
 
 
risks associated with offshore rig operations or rig relocations,
 
 
inability to collect receivables,
 
 
availability of transport vessels to relocate rigs,
 
 
environmental or other liabilities, risks or losses, whether related to hurricane damage, losses or liabilities (including wreckage or debris removal) in the Gulf of Mexico or otherwise, that may arise in the future which are not covered by insurance or indemnity in whole or in part,
 
 
limited availability or high cost of insurance coverage for certain perils such as hurricanes in the Gulf of Mexico or associated removal of wreckage or debris,
 
 
self-imposed or regulatory limitations on drilling locations in the Gulf of Mexico during hurricane season,
 
 
impact of current and future government laws and regulation affecting the oil and gas industry in general and our operations in particular, including taxation, as well as repeal or modification of same,
 
 
our ability to attract and retain skilled personnel,
 
 
 
governmental action and political and economic uncertainties, which may result in expropriation, nationalization, confiscation or deprivation of our assets or create a force majeure situation,
 
 
 
terrorism or military action impacting our operations, assets or financial performance,
 
 
 
outcome of litigation, legal proceedings, investigations or insurance or other claims,
 
 
 
adverse changes in foreign currency exchange rates, including their impact on the fair value measurement of our derivative instruments,
 
 
 
potential long-lived asset or goodwill impairments,
 
 
potential reduction in fair value of our auction rate securities and the ultimate resolution of our pending arbitration proceedings.
 
    Moreover, the United States Congress, the Internal Revenue Service, the United Kingdom Parliament or Her Majesty's Revenue and Customs may enact new statutory or regulatory provisions that could adversely affect our status as a non-U.S. corporation or otherwise adversely affect our anticipated consolidated effective income tax rate. Retroactive statutory or regulatory actions have occurred in the past, and there can be no assurance that any such provisions, if enacted or promulgated, would not have retroactive application.
   
    In addition to the numerous factors described above and in "Item 2.   Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part I and "Item 1A. Risk Factors" in Part II of this report, you should carefully read and consider "Item 1A.   Risk Factors" in Part I and  "Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II of our Annual Report on Form  10-K for the year ended December 31, 2009, as updated in the Current Report on Form 8-K dated June 8, 2010.
 
2

 
 
PART I - FINANCIAL INFORMATION
 
 
Item 1.  Financial Statements
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors and Shareholders
Ensco plc:
 
We have reviewed the condensed consolidated balance sheet of Ensco plc and subsidiaries as of June 30, 2010, the related condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010 and 2009, and the related condensed consolidated statements of cash flows for the six-month periods ended June 30, 2010 and 2009. These condensed consolidated financial statements are the responsibility of the Company's management.
 
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
 
Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.
 
We have previously audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Ensco plc and subsidiaries as of December 31, 2009, and the related consolidated statements of income and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2010 except for the updated disclosures and reclassification of ENSCO 50 and ENSCO 51 operating results from continuing to discontinued operations for all periods presented, as described in Note 11, as to which the date is June 8, 2010, we expressed an unqualified opinion on these consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2009, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
 
 
 
 
/s/ KPMG LLP
 
Dallas, Texas
July 22, 2010
 
 
 

 
3

 

 
ENSCO PLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
(Unaudited)
 
 
  Three Months Ended
             June 30,            
 
 
   2010 
    
      2009  
               
OPERATING REVENUES
     
$406.3
     
 
     
$497.3
    
               
OPERATING EXPENSES
             
Contract drilling (exclusive of depreciation)
 
207.0
     
171.2
 
Depreciation
 
52.8
     
45.8
 
General and administrative
 
22.0
     
16.0
 
   
281.8
     
233.0
 
OPERATING INCOME
 
124.5
     
264.3
 
               
OTHER INCOME, NET
 
12.8
     
6.9
 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
 
137.3
     
271.2
 
               
PROVISION FOR INCOME TAXES
             
Current income tax expense
 
26.3
     
38.2
 
Deferred income tax expense
 
(6.7
)    
11.3
 
   
19.6
     
49.5
 
INCOME FROM CONTINUING OPERATIONS
 
117.7
     
221.7
 
               
DISCONTINUED OPERATIONS
             
Income (loss) from discontinued operations, net
 
4.5
 
   
(8.5
)
   Gain (loss) on disposal of discontinued operations, net
 
5.7
 
   
(11.8
)
   
10.2
 
   
(20.3
)
NET INCOME
 
127.9
     
201.4
 
               
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
(1.6
)
   
(1.1
)
               
NET INCOME ATTRIBUTABLE TO ENSCO
 
$126.3
     
$200.3
 
               
EARNINGS (LOSS) PER SHARE - BASIC
             
Continuing operations
 
$  0.82
     
$  1.55
 
Discontinued operations
 
.07
 
   
(.14
)
   
$  0.89
     
$  1.41
 
EARNINGS (LOSS) PER SHARE - DILUTED
             
Continuing operations
 
$  0.82
     
$  1.55
 
Discontinued operations
 
.07
 
   
(.14
)
   
$  0.89
     
$  1.41
 
               
NET INCOME ATTRIBUTABLE TO ENSCO SHARES
             
Basic
 
$124.8
     
$197.9
 
Diluted
 
$124.8
     
$197.9
 
WEIGHTED-AVERAGE SHARES OUTSTANDING
             
Basic
 
140.9
     
140.3
 
Diluted
 
140.9
     
140.4
 
CASH DIVIDENDS PER SHARE
 
$   .35
     
$  .025
 
 
The accompanying notes are an integral part of these condensed consolidated financial statements.

 
4

 
 
ENSCO PLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
(Unaudited)
 
     Six Months Ended
               June 30,          
 
 
         2010   
 
            2009  
               
OPERATING REVENUES
     
$847.8
     
 
     
$981.5
    
               
OPERATING EXPENSES
             
Contract drilling (exclusive of depreciation)
 
389.8
     
325.8
 
Depreciation
 
105.5
     
89.6
 
General and administrative
 
42.6
     
28.0
 
   
537.9
     
443.4
 
OPERATING INCOME
 
309.9
     
538.1
 
               
OTHER INCOME, NET
 
15.9
     
2.6
 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
 
325.8
     
540.7
 
               
PROVISION FOR INCOME TAXES
             
Current income tax expense
 
47.1
     
85.4
 
Deferred income tax expense
 
4.3
     
18.3
 
   
51.4
     
103.7
 
INCOME FROM CONTINUING OPERATIONS
 
274.4
     
437.0
 
               
DISCONTINUED OPERATIONS
             
Income (loss) from discontinued operations, net
 
10.2
 
   
(1.7
Gain (loss) on disposal of discontinued operations, net
 
34.9
 
   
(11.8
   
45.1
 
   
(13.5
NET INCOME
 
319.5
     
423.5
 
               
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
(3.4
)
   
(2.5
)
               
NET INCOME ATTRIBUTABLE TO ENSCO
 
$316.1
     
$421.0
 
               
EARNINGS (LOSS) PER SHARE - BASIC
             
Continuing operations
 
$  1.90
     
$  3.06
 
Discontinued operations
 
.32
 
   
(.09
)
   
$  2.22
     
$  2.97
 
EARNINGS (LOSS) PER SHARE - DILUTED
             
Continuing operations
 
$  1.90
     
$  3.06
 
Discontinued operations
 
.32
 
   
(.09
)
   
$  2.22
     
$  2.97
 
 
NET INCOME ATTRIBUTABLE TO ENSCO SHARES
             
Basic
 
$312.2
     
$415.9
 
Diluted
 
$312.2
     
$415.9
 
WEIGHTED-AVERAGE SHARES OUTSTANDING
             
Basic
 
140.8
     
140.2
 
Diluted
 
140.9
     
140.2
 
CASH DIVIDENDS PER SHARE
 
$  .375
     
$   .05
 
 
The accompanying notes are an integral part of these condensed consolidated financial statements.

 
5

 
ENSCO PLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions, except share and par value amounts)
 
 
June 30,
     2010     
December 31,
       2009       
 
 
(Unaudited)
 
ASSETS
         
           
CURRENT ASSETS
         
    Cash and cash equivalents
 
$1,237.1
 
$1,141.4
 
    Accounts receivable, net
 
302.7
 
324.6
 
    Other
 
147.8
 
186.8
 
       Total current assets
 
1,687.6
 
1,652.8
 
PROPERTY AND EQUIPMENT, AT COST
 
6,227.3
 
6,151.2
 
    Less accumulated depreciation
 
1,622.5
 
1,673.9
 
       Property and equipment, net
 
4,604.8
 
4,477.3
 
GOODWILL
 
336.2
 
336.2
 
           
LONG-TERM INVESTMENTS
 
45.2
 
60.5
 
           
OTHER ASSETS, NET
 
247.2
 
220.4
 
   
$6,921.0
 
$6,747.2
 
           
LIABILITIES AND SHAREHOLDERS' EQUITY
         
           
CURRENT LIABILITIES
         
    Accounts payable - trade
 
$   152.5
 
$   159.1
 
    Accrued liabilities and other
 
246.7
 
308.6
 
    Current maturities of long-term debt
 
17.2
 
17.2
 
       Total current liabilities
 
416.4
 
484.9
 
LONG-TERM DEBT
 
248.6
 
257.2
 
           
DEFERRED INCOME TAXES
 
365.1
 
377.3
 
           
OTHER LIABILITIES
 
117.2
 
120.7
 
           
COMMITMENTS AND CONTINGENCIES
         
           
ENSCO SHAREHOLDERS' EQUITY
         
    Class A ordinary shares, U.S. $.10 par value, 250.0 million shares
         authorized, 150.0 million shares issued
 
15.0
 
15.0
 
    Class B ordinary shares, £1 par value, 50,000 shares authorized and issued
  .1   .1  
    Additional paid-in capital
 
618.1
 
602.6
 
    Retained earnings
 
5,141.7
 
4,879.2
 
    Accumulated other comprehensive income
 
.7
 
5.2
 
    Treasury shares, at cost, 7.1 million shares and 7.5 million shares
 
(8.0
)
(2.9
)
       Total Ensco shareholders' equity
 
5,767.6
 
5,499.2
 
           
NONCONTROLLING INTERESTS
 
6.1
 
7.9
 
       Total equity
 
5,773.7
 
5,507.1
 
   
$6,921.0
 
$6,747.2
 
 
The accompanying notes are an integral part of these condensed consolidated financial statements.

 
6

 

 
ENSCO PLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)
 
 
     Six Months Ended
                 June 30,        
 
     2010   
          2009   
OPERATING ACTIVITIES
         
Net income
 
$ 319.5
 
$ 423.5
 
Adjustments to reconcile net income to net cash provided by operating
         
     activities of continuing operations:
         
    Depreciation expense
 
105.5
 
89.6
 
    Share-based compensation expense    22.4    17.0  
    Amortization expense    16.0   15.7  
    Loss on asset impairment   12.2   --  
    Deferred income tax expense
 
4.3
 
18.3
 
    (Income) loss from discontinued operations, net
 
(10.2
1.7
 
    (Gain) loss on disposal of discontinued operations, net
 
(34.9
11.8
 
    Other
 
5.5
 
1.5
 
    Changes in operating assets and liabilities:
         
Decrease in accounts receivable
 
5.8
 
35.7
 
Increase in other assets
 
(.1
)
(49.5
Decrease in liabilities
 
(102.4
)
(.8
)
Net cash provided by operating activities of continuing operations
 
343.6
 
564.5
 
           
INVESTING ACTIVITIES
         
Additions to property and equipment
 
(336.6
)
(469.1
)
Proceeds from disposal of discontinued operations
 
132.4
 
4.9
 
Proceeds from disposition of assets
 
.7
 
1.6
 
Net cash used in investing activities
 
(203.5
)
(462.6
)
           
FINANCING ACTIVITIES
         
   Cash dividends paid     (53.6  (7.1
Reduction of long-term borrowings
 
(8.6
)
(8.6
)
   Financing costs         (6.2 )  --  
Repurchase of shares
 
(5.1
)
(4.0
)
Other
 
(7.3
)
1.3
 
Net cash used in financing activities
 
(80.8
)
(18.4
)
           
Effect of exchange rate changes on cash and cash equivalents
 
(.7
)
.1
 
Net cash provided by operating activities of discontinued operations
 
37.1
 
8.8
 
           
INCREASE IN CASH AND CASH EQUIVALENTS
 
95.7
 
92.4
 
           
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
 
1,141.4
 
789.6
 
           
CASH AND CASH EQUIVALENTS, END OF PERIOD
 
$1,237.1
 
$ 882.0
 
 
The accompanying notes are an integral part of these condensed consolidated financial statements.

 
7

 

 
ENSCO PLC AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 
 
Note 1 - Unaudited Condensed Consolidated Financial Statements
 
    We prepared the accompanying condensed consolidated financial statements of Ensco plc and subsidiaries (the "Company", "Ensco", "we" or "us") in accordance with accounting principles generally accepted in the United States of America ("GAAP"), pursuant to the rules and regulations of the Securities and Exchange Commission (the "SEC") included in the instructions to Form 10-Q and Article 10 of Regulation S-X. The financial information included in this report is unaudited but, in our opinion, includes all adjustments (consisting of normal recurring adjustments) that are necessary for a fair presentation of our financial position, results of operations and cash flows for the interim periods presented. The December 31, 2009 condensed consolidated balance sheet data were derived from our 2009 audited consolidated financial statements, as updated in the Current Report on Form 8-K dated June 8, 2010, but do not include all disclosures required by GAAP. Certain previously reported amounts have been reclassified to conform to the current year presentation. The preparation of our condensed consolidated financial statements requires management to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities, the related revenues and expenses and disclosures of gain and loss contingencies as of the date of the financial statements. Actual results could differ from those estimates.
 
    The financial data for the three-month and six-month periods ended June 30, 2010 and 2009 included herein have been subjected to a limited review by KPMG LLP, our independent registered public accounting firm. The accompanying independent registered public accounting firm's review report is not a report within the meaning of Sections 7 and 11 of the Securities Act of 1933, and the independent registered public accounting firm's liability under Section 11 does not extend to it.
   
    Results of operations for the three-month and six-month periods ended June 30, 2010 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2010.  It is recommended that these condensed consolidated financial statements be read in conjunction with our audited consolidated financial statements and notes thereto for the year ended December 31, 2009 included in our Annual Report on Form 10-K filed with the SEC on February 25, 2010, as updated in the Current Report on Form 8-K dated June 8, 2010.
 
Note 2 - Noncontrolling Interests
 
    Noncontrolling interests are classified as equity on our consolidated balance sheets, and net income attributable to noncontrolling interests is presented separately on our consolidated statements of income. In our Asia Pacific operating segment, local third parties hold a noncontrolling ownership interest in three of our subsidiaries. No changes in the ownership interests of these subsidiaries occurred during the three-month and six-month periods ended June 30, 2010 and 2009.

 
8

 

 
    The following table is a reconciliation of income from continuing operations attributable to Ensco for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):
 
 
Three Months Ended  
           June 30,             
      Six Months Ended
               June 30,         
 
 2010 
  2009 
    2010 
       2009 
                   
Income from continuing operations
 
$117.7
 
$221.7
 
$274.4
 
$437.0
 
Income from continuing operations attributable to
noncontrolling interests
 
(1.6
)
(.9
)
(3.2
)
(2.1
)
Income from continuing operations attributable to Ensco
 
$116.1
 
$220.8
 
$271.2
 
$434.9
 
   
    The following table is a reconciliation of income (loss) from discontinued operations, net, attributable to Ensco for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):

 
Three Months Ended
           June 30,           
     Six Months Ended
                June 30,           
 
2010
    2009
     2010
       2009
                 
Income (loss) from discontinued operations 
$10.2
 
$(20.3
)
$45.1
 
$(13.5
)
Income from discontinued operations attributable to
   noncontrolling interests 
--
 
(.2
)
(.2
)
(.4
)
Income (loss) from discontinued operations attributable to Ensco
$10.2
 
$(20.5
)
$44.9
 
$(13.9
)
 
Note 3 - Earnings Per Share
 
    We compute basic and diluted earnings per share ("EPS") in accordance with the two-class method. Net income attributable to Ensco used in our computations of basic and diluted EPS is adjusted to exclude net income allocated to non-vested shares granted to our employees and non-employee directors. Weighted-average shares outstanding used in our computation of diluted EPS includes the dilutive effect of share options using the treasury stock method and excludes non-vested shares.
 
    The following table is a reconciliation of net income attributable to Ensco shares used in our basic and diluted EPS computations for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):
 
 
Three Months Ended 
            June 30,            
     Six Months Ended
                  June 30,          
 
 
  2010 
  2009 
    2010 
      2009
                   
Net income attributable to Ensco
 
$126.3
 
$200.3
 
$316.1
 
$421.0
 
Net income allocated to non-vested share awards
 
(1.5
)
(2.4
)
(3.9
)
(5.1
)
Net income attributable to Ensco shares
 
$124.8
 
$197.9
 
$312.2
 
$415.9
 
 
    The following table is a reconciliation of the weighted-average shares used in our basic and diluted EPS computations for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):
 
 
Three Months Ended
             June 30,             
     Six Months Ended
                 June 30,           
 
 
  2010 
   2009 
       2010  
        2009 
                    
Weighted-average shares - basic
 
140.9
 
140.3
 
140.8
 
140.2
 
Potentially dilutive share options
 
.0
 
.1
 
.1
 
.0
 
Weighted-average shares - diluted
 
140.9
 
140.4
 
140.9
 
140.2
 
 
 
9

 
 
    Antidilutive share options totaling 1.1 million were excluded from the computation of diluted EPS for the three-month periods ended June 30, 2010 and 2009.  Antidilutive share options totaling 1.0 million and 1.3 million were excluded from the computation of diluted EPS for the six-month periods ended June 30, 2010 and 2009, respectively.
 
Note 4 - Derivative Instruments
   
    Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues are denominated in U.S. dollars, however, a portion of the revenues earned and expenses incurred by some of our subsidiaries are denominated in currencies other than the U.S. dollar ("foreign currencies"). These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. We use foreign currency forward contracts ("derivatives") to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. We maintain a foreign currency exchange rate risk management strategy that utilizes derivatives to reduce our exposure to unanticipated fluctuations in earnings and cash flows caused by changes in foreign currency exchange rates. Although no interest rate related derivatives were outstanding as of June 30, 2010 and December 31, 2009, we occasionally employ an interest rate risk management strategy that utilizes derivatives to minimize or eliminate unanticipated fluctuations in earnings and cash flows arising from changes in, and volatility of, interest rates. We minimize our credit risk relating to the counterparties of our derivatives by transacting with multiple, high-quality financial institutions, thereby limiting exposure to individual counterparties, and by monitoring the financial condition of our counterparties. We do not enter into derivatives for trading or other speculative purposes.
 
    All derivatives were recorded on our condensed consolidated balance sheets at fair value. Accounting for the gains and losses resulting from changes in the fair value of derivatives depends on the use of the derivative and whether it qualifies for hedge accounting.  As of June 30, 2010 and December 31, 2009, our condensed consolidated balance sheets included net foreign currency derivative assets of $3.0 million and $13.2 million, respectively. See "Note 9 - Fair Value Measurements" for additional information on the fair value measurement of our derivatives.
 
    Derivatives recorded at fair value in our condensed consolidated balance sheets as of June 30, 2010 and December 31, 2009 consisted of the following (in millions):
 
                       Derivative Assets                              Derivative Liabilities     
 
June 30,
                 2010    
  December 31, 
             2009        
June 30,
                 2010    
December 31,
       2009      
                             
Derivatives Designated as Hedging Instruments      
Foreign currency forward contracts - current(1)
 $3.5      $10.2        $3.1    $1.1      
Foreign currency forward contracts - non-current(2)
3.3      3.8        --    --      
 
6.8     
14.0       
3.1   
1.1      
         
Derivatives Not Designated as Hedging Instruments      
Foreign currency forward contracts - current(1)
--     
.3       
 .7   
.0      
 
--     
.3       
 .7   
.0      
Total
$6.8     
$14.3       
$3.8   
$1.1      
 
 
(1)
Derivative assets and liabilities that have maturity dates equal to or less than twelve months from the respective balance sheet date were included in other current assets and accrued liabilities and other, respectively, on our condensed consolidated balance sheets.
     
 
(2)
Derivative assets and liabilities that have maturity dates greater than twelve months from the respective balance sheet date were included in other assets, net, and other liabilities, respectively, on our condensed consolidated balance sheets.

 
10

 
 
We utilize derivatives designated as hedging instruments to hedge forecasted foreign currency denominated transactions ("cash flow hedges"), primarily to reduce our exposure to foreign currency exchange rate risk associated with the portion of our remaining ENSCO 8500 Series® construction obligations denominated in Singapore dollars and contract drilling expenses denominated in various other currencies. As of June 30, 2010, we had cash flow hedges outstanding to exchange an aggregate $230.3 million for various foreign currencies, including $161.5 million for Singapore dollars, $44.0 million for British pounds, $13.2 million for Australian dollars and $11.6 million for other currencies.
 
Gains and losses on derivatives designated as cash flow hedges included in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010 and 2009 were as follows (in millions):
 
Three Months Ended June 30, 2010 and 2009
 
Derivatives Designated
   as Cash Flow Hedges   
(Loss) Gain
 Recognized in
Other Comprehensive
Income ("OCI")
   (Effective Portion)   
 (Loss) Gain
 Reclassified from
Accumulated Other
Comprehensive Income
("AOCI") into Income
      (Effective Portion)    
 
(Loss) Gain
Recognized in Income on
Derivatives (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)(1)
   
 2010
 
2009
   
 2010  
 
  2009    
     
2010  
 
  2009       
                               
Interest rate lock contracts(2)
 
$    -- 
 
$    --
   
$(.2)
 
$  (.1)   
     
$ --    
 
$ --         
Foreign currency forward contracts(3)
 
   (1.6)
 
14.2
   
    .4 
 
 (5.0)   
     
   (.2)  
 
4.1        
Total
 
$(1.6)
 
$14.2
   
$ .2 
 
$(5.1)   
     
$(.2)  
 
$4.1        
 
 
Six Months Ended June 30, 2010 and 2009
 
Derivatives Designated
   as Cash Flow Hedges   
Loss Recognized
in OCI
   (Effective Portion)   
 (Loss) Gain
 Reclassified from
AOCI into Income
        (Effective Portion)    
 
Loss Recognized
in Income on
Derivatives (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)(1)
   
     2010
 
    2009
   
 2010   
 
 2009    
     
2010  
 
    2009        
                               
Interest rate lock contracts(2)
 
$    -- 
 
$    -- 
   
$(.3)
 
$    (.3)  
     
$ --    
 
$    --         
Foreign currency forward contracts(3)
 
   (3.0)
 
(1.2)
   
    1.8 
 
 (14.8)  
     
   (.2)  
 
(2.4)        
Total
 
$(3.0)
 
$(1.2)
   
$1.5 
 
$(15.1)  
     
$(.2)  
 
$(2.4)        
 
 
(1)
Gains and losses recognized in income for ineffectiveness and amounts excluded from effectiveness testing were included in other income, net, in our condensed consolidated statements of income.
     
 
(2)
Losses on derivatives reclassified from AOCI into income (effective portion) were included in other income, net, in our condensed consolidated statements of income.
     
 
(3)
Gains and losses on derivatives reclassified from AOCI into income (effective portion) were included in contract drilling expense in our condensed consolidated statements of income.
 
 
11

 
 
    We have net assets and liabilities denominated in numerous foreign currencies and use various methods to manage our exposure to foreign currency exchange rate risk. We predominantly structure our drilling contracts in U.S. dollars which significantly reduces the portion of our cash flows and assets denominated in foreign currencies. We occasionally enter into derivatives that hedge the fair value of recognized foreign currency denominated assets or liabilities but do not designate such derivatives as hedging instruments.  In these situations, a natural hedging relationship generally exists whereby changes in the fair value of the derivatives offset changes in the fair value of the underlying hedged items. As of June 30, 2010, we had derivatives not designated as hedging instruments outstanding to exchange an aggregate $26.7 million for various foreign currencies, including $15.7 million for Australian dollars, $4.5 million for British pounds and $6.5 million for other currencies.
 
    Net losses of $1.7 million and net gains of $3.2 million associated with our derivatives not designated as hedging instruments were included in other income, net, in our condensed consolidated statements of income for the three-month periods ended June 30, 2010 and 2009, respectively. Net losses of $1.1 million and net gains of $2.2 million associated with our derivatives not designated as hedging instruments were included in other income, net, in our condensed consolidated statements of income for the six-month periods ended June 30, 2010 and 2009, respectively.
 
    As of June 30, 2010, the estimated amount of net losses associated with derivative instruments, net of tax, that will be reclassified to earnings during the next twelve months was as follows (in millions):
 
Net unrealized losses to be reclassified to contract drilling expense
 
$1.5
 
Net realized losses to be reclassified to other income, net
 
.4
 
Net losses to be reclassified to earnings
 
$1.9
 
 
Note 5 - Accrued Liabilities and Other
 
    Accrued liabilities and other as of June 30, 2010 and December 31, 2009 consisted of the following (in millions):
 
 
 2010           
 2009   
       
Taxes $ 72.8    $ 97.3  
Deferred revenue
66.0 
  
89.0  
Wreckage and debris removal
  50.3   
50.3  
Personnel costs  39.5    48.6  
Other
    18.1   
23.4  
 
$246.7 
 
$308.6  
 
Note 6 - Long-Term Debt
 
    On May 28, 2010, we entered into an amended and restated agreement (the "2010 Credit Facility") with a syndicate of banks that provides for a $700.0 million unsecured revolving credit facility for general corporate purposes. The 2010 Credit Facility has a four-year term, expiring in May 2014, and replaces our $350.0 million five-year credit agreement which was scheduled to mature in June 2010. Advances under the 2010 Credit Facility bear interest at LIBOR plus an applicable margin rate (currently 2.0% per annum), depending on our credit rating. We are required to pay an annual undrawn facility fee (currently .25% per annum) on the total $700.0 million commitment, which is also based on our credit rating. We also are required to maintain a debt to total capitalization ratio less than or equal to 50% under the 2010 Credit Facility. We have the right, subject to lender consent, to increase the commitments under the 2010 Credit Facility up to $850.0 million.  We had no amounts outstanding under the 2010 Credit Facility or the prior credit agreement as of June 30, 2010 and December 31, 2009, respectively.
 
Note 7 - Share-Based Compensation
 
   During the quarter ended June 30, 2010, we granted 560,354 non-vested share awards to our employees, officers and non-employee directors for annual equity awards and for equity awards granted to new or recently promoted employees, pursuant to our 2005 Long-Term Incentive Plan ("LTIP").  Grants of non-vested share awards generally vest at a rate of 20% per year, as determined by a committee of the Board of Directors.  Non-vested share awards granted to certain officers vest at a rate of 33% per year. All non-vested share awards have voting and dividend rights effective on the date of grant and are measured using the market value of our shares on the date of grant. The weighted-average grant-date fair value of non-vested share awards granted during the quarter ended June 30, 2010 was $35.11 per share.  All non-vested share award grants were issued out of treasury.
 
 
12

 
   
    During the quarter ended June 30, 2010, we granted 160,293 share options to certain officers as annual equity awards made pursuant to our LTIP.  The share options granted become exercisable in annual 33% increments over a three-year period and, to the extent not exercised, expire on the seventh anniversary of the date of grant. The following table summarizes the value of share options granted during the quarter ended June 30, 2010 (per share):
 
Weighted-average grant-date fair value
 
$11.05
 
Weighted-average exercise price
 
$34.45
 
 
    The exercise price of share options granted during the period equals the market value of the underlying stock on the date of grant. The fair value of each option award was estimated on the date of grant using the Black-Scholes option valuation model with the following weighted-average assumptions for the quarter ended June 30, 2010:
 
Risk-free interest rate
 
1.8
%
Expected life (in years)
 
4.01
 
Expected volatility
 
53.1
%
Dividend yield
 
4.1
%
 
    Expected volatility is based on the historical volatility in the market price of our shares over the period of time equivalent to the expected term of the options granted. The expected term of options granted is derived from historical exercise patterns over a period of time equivalent to the contractual term of the options granted. We have not experienced significant differences in the historical exercise patterns among officers, employees and non-employee directors for them to be considered separately for valuation purposes. The risk-free interest rate is based on the implied yield of U.S. Treasury zero-coupon issues on the date of grant with a remaining term approximating the expected term of the options granted.
 
Note 8 - Comprehensive Income
 
    Accumulated other comprehensive income as of June 30, 2010 and December 31, 2009 was comprised of gains and losses on derivative instruments, net of tax. The components of other comprehensive (loss) income, net of tax, for the three-month and six-month periods ended June 30, 2010 and 2009 were as follows (in millions):
 
 
  Three Months Ended
               June 30,           
    Six Months Ended
              June 30,         
 
 
     2010   
     2009   
     2010 
       2009 
                   
Net income
 
$127.9
 
$201.4
 
$319.5
 
$423.5
 
Other comprehensive (loss) income:
                 
Net change in fair value of derivatives
 
(1.6
14.2
 
(3.0
)
(1.2
)
Reclassification of gains and losses on derivative
                 
instruments from other comprehensive (income) loss
                 
into net income
 
(.2
)
5.1
 
(1.5
)
15.1
 
Net other comprehensive (loss) income
 
(1.8
)
19.3
 
(4.5
)
13.9
 
Comprehensive income
 
126.1
 
220.7
 
315.0
 
437.4
 
Comprehensive income attributable to noncontrolling interests
 
(1.6
)
(1.1
)
(3.4
)
(2.5
)
Comprehensive income attributable to Ensco
 
$124.5
 
$219.6
 
$311.6
 
$434.9
 
 

 
13

 

Note 9 - Fair Value Measurements
 
    The following fair value hierarchy table categorizes information regarding our financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2010 and December 31, 2009 (in millions):
 
 
Quoted Prices in
Active Markets
for
Identical Assets
    (Level 1)    
Significant
Other
Observable
Inputs
    (Level 2)    
 
Significant
Unobservable
Inputs
    (Level 3)    
 
 
 
 
     Total     
   
As of June 30, 2010
                       
Auction rate securities
 
$    --  
   
$    --  
   
$45.2
   
$45.2  
 
Supplemental executive retirement
   plan assets
  19.3       --       --     19.3    
Derivatives, net
 
--  
   
3.0  
   
--
     
3.0  
 
Total financial assets
 
$19.3  
   
$  3.0  
   
$45.2
   
$67.5  
 
 
As of December 31, 2009
                       
Auction rate securities
 
$    --  
   
$    --  
   
$60.5
   
$60.5  
 
Supplemental executive retirement
   plan assets
 
18.7  
   
    --  
   
--
   
18.7  
 
Derivatives, net 
 
    --  
   
13.2  
   
   --
   
13.2  
 
Total financial assets 
 
$18.7  
   
$13.2  
   
$60.5
   
$92.4  
 
 
    Auction Rate Securities
 
    As of June 30, 2010 and December 31, 2009, we held long-term debt instruments with variable interest rates that periodically reset through an auction process ("auction rate securities") totaling $50.9 million and $66.8 million (par value), respectively.  These auction rate securities were classified as long-term investments on our condensed consolidated balance sheets. Our auction rate securities were originally acquired in January 2008 and have maturity dates ranging from 2025 to 2047. Our auction rate securities were measured at fair value on a recurring basis using significant Level 3 inputs as of June 30, 2010 and December 31, 2009.  The following table summarizes the fair value measurements of our auction rate securities using significant Level 3 inputs, and changes therein, for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):
 
 
 Three Months Ended    
            June 30,              
      Six Months Ended
                June 30,         
 
  2010 
  2009 
      2010 
        2009  
                   
Beginning Balance
 
$55.4
 
$61.9  
 
$60.5
 
$64.2 
 
Sales
 
(10.5
)
(.3) 
 
(15.9
)
(2.6)
 
Unrealized gains*
 
.3
 
--  
 
.6
 
-- 
 
Transfers in and/or out of Level 3
 
--
 
--  
 
--
 
-- 
 
Ending balance
 
$45.2
 
$61.6  
 
$45.2
 
$61.6 
 
 
*Unrealized gains were included in other income, net, in our condensed consolidated statements of income.

 
14

 
 
    Before utilizing Level 3 inputs in our fair value measurement, we considered whether observable inputs were available. As a result of continued auction failures, quoted prices for our auction rate securities did not exist as of June 30, 2010. Accordingly, we concluded that Level 1 inputs were not available. Brokerage statements received from the three broker/dealers that held our auction rate securities included their estimated market value as of June 30, 2010.  All three broker/dealers valued our auction rate securities at par. Due to the lack of transparency into the methodologies used to determine the estimated market values, we have concluded that estimated market values provided on our brokerage statements do not constitute valid inputs, and we do not utilize them in measuring the fair value of our auction rate securities.
 
    We used an income approach valuation model to estimate the price that would be received in exchange for our auction rate securities in an orderly transaction between market participants ("exit price") as of June 30, 2010. The exit price was derived as the weighted-average present value of expected cash flows over various periods of illiquidity, using a risk-adjusted discount rate based on the credit risk and liquidity risk of our auction rate securities.  While our valuation model was based on both Level 2 (credit quality and interest rates) and Level 3 inputs, we determined that Level 3 inputs were significant to the overall fair value measurement of our auction rate securities, particularly the estimates of risk-adjusted discount rates and ranges of expected periods of illiquidity. We have the ability to maintain our investment in these securities until they are redeemed, repurchased or sold in a market that facilitates orderly transactions.
 
    Supplemental Executive Retirement Plan Assets
 
    Our Ensco supplemental executive retirement plans (the "SERP") are non-qualified plans that provide for eligible employees to defer a portion of their compensation for use after retirement. Assets held in the SERP were marketable securities measured at fair value on a recurring basis using Level 1 inputs and were included in other assets, net, on our condensed consolidated balance sheets as of June 30, 2010 and December 31, 2009. The fair value measurement of assets held in the SERP was based on quoted market prices.
 
    Derivatives
 
    Our derivatives were measured at fair value on a recurring basis using Level 2 inputs as of June 30, 2010 and December 31, 2009. See "Note 4 - Derivative Instruments" for additional information on our derivatives, including a description of our foreign currency hedging activities and related methodologies used to manage foreign currency exchange rate risk. The fair value measurement of our derivatives was based on market prices that are generally observable for similar assets or liabilities at commonly-quoted intervals.
 
    Other Financial Instruments
 
    The carrying values and estimated fair values of our debt instruments as of June 30, 2010 and December 31, 2009 were as follows (in millions):
 
 
June 30,
                  2010                   
December 31,
                   2009                  
 
 
Carrying
  Value  
Estimated
  Fair
   Value  
Carrying
  Value  
Estimated
  Fair
   Value  
 
 
         
7.20% Debentures       $148.9          $157.8         $148.9          $155.9         
6.36% Bonds, including current maturities
 
69.7       
 
79.4      
 
76.0       
 
85.8       
 
4.65% Bonds, including current maturities
 
47.2       
 
53.2      
 
49.5       
 
53.8       
 
 
 
 
15

 
   
    The estimated fair value of our 7.20% Debentures was determined using quoted market prices. The estimated fair values of our 6.36% Bonds and 4.65% Bonds were determined using an income approach valuation model. The estimated fair value of our cash and cash equivalents, receivables, trade payables and other liabilities approximated their carrying values as of June 30, 2010 and December 31, 2009.
 
    ENSCO I Impairment
   
    During the quarter ended June 30, 2010, we recorded a $12.2 million loss from the impairment of ENSCO I, the only barge rig in our fleet, which is currently cold-stacked in Singapore and is included in our Asia Pacific operating segment. The loss on impairment was included in contract drilling expense in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010. The impairment resulted from the adjustment of the rig’s carrying value to its estimated fair value based on a change in our expectation that it is more-likely-than-not that the rig will be disposed of significantly before the end of its estimated useful life. ENSCO I was not classified as held-for-sale as of June 30, 2010, as a sale was not deemed probable of occurring within the next twelve months.
 
    We utilized an income approach valuation model to estimate the price that would be received in exchange for the rig in an orderly transaction between market participants as of June 30, 2010. The resulting exit price was derived as the present value of expected cash flows from the use and eventual disposition of the rig, using a risk-adjusted discount rate.  Level 3 inputs were significant to the overall fair value measurement of ENSCO I, due to the limited availability of observable market data for similar assets.
 
Note 10 – Income Taxes
 
    Subsequent to our redomestication to the U.K. in December 2009, we reorganized our worldwide operations, which included, among other things, the transfer of ownership of several of our drilling rigs among our subsidiaries during the second quarter of 2010.  A $22.5 million income tax liability associated with the gain on the intercompany transfer was deferred and is being amortized on a straight-line basis over the remaining useful lives of the associated assets that were transferred, which range from five to thirty years. The pre-tax profit of the selling subsidiary resulting from the intercompany transfer was eliminated from our consolidated financial statements. Similarly, the carrying value of the assets in our consolidated financial statements remained at the historical net depreciated cost prior to the intercompany transfer and did not reflect the asset disposal transaction of the selling subsidiary or the asset acquisition transaction of the acquiring subsidiary.
 
 
16

 
 
Note 11 - Discontinued Operations
 
    Rig Sales
 
    In April 2010, we sold jackup rig ENSCO 57 for $47.1 million, of which $4.7 million was received in December 2009. We recognized a pre-tax gain of $17.9 million in connection with the disposal of ENSCO 57, which was included in gain on disposal of discontinued operations, net, in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010. The rig’s net book value and inventory and other assets on the date of sale totaled $29.2 million. ENSCO 57 operating results were reclassified as discontinued operations in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010 and 2009 and previously were included within our Asia Pacific operating segment.
 
    In March 2010, we sold jackup rigs ENSCO 50 and ENSCO 51 for an aggregate $94.7 million, of which $4.7 million was received in December 2009. We recognized an aggregate pre-tax gain of $33.9 million in connection with the disposals of ENSCO 50 and ENSCO 51, which was included in gain on disposal of discontinued operations, net, in our condensed consolidated statement of income for the six-month period ended June 30, 2010.  The two rigs' aggregate net book value and inventory and other assets on the date of sale totaled $60.8 million. ENSCO 50 and ENSCO 51 operating results were reclassified as discontinued operations in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010 and 2009 and previously were included within our Asia Pacific operating segment.
 
    ENSCO 69
 
    From May 2007 to June 2009, ENSCO 69 was contracted to Petrosucre, a subsidiary of Petróleos de Venezuela S.A., the national oil company of Venezuela ("PDVSA"). In January 2009, we suspended drilling operations on ENSCO 69 after Petrosucre failed to satisfy its contractual obligations and meet commitments relative to the payment of past due invoices. Petrosucre then took over complete control of ENSCO 69 drilling operations utilizing Petrosucre employees and a portion of the Venezuelan rig crews we had utilized.
 
    On June 4, 2009, after Petrosucre's failure to satisfy its contractual payment obligations, failure to reach a mutually acceptable agreement with us and denial of our request to demobilize ENSCO 69 from Venezuela, Petrosucre advised that it would not return the rig and would continue to operate it without our consent. Petrosucre further advised that it would release ENSCO 69 after a six-month period, subject to a mutually agreed accord addressing the resolution of all remaining obligations under the ENSCO 69 drilling contract. On June 6, 2009, we terminated our contract with Petrosucre and removed all remaining Ensco employees from the rig.
 
 
17

 
 
    Due to Petrosucre's failure to satisfy its contractual obligations and meet payment commitments, and in consideration of the Venezuelan government's nationalization of assets owned by international oil and gas companies and oilfield service companies, we concluded it was remote that ENSCO 69 would be returned to us by Petrosucre and operated again by Ensco. Therefore, we recorded the disposal of ENSCO 69 during the second quarter of 2009. ENSCO 69 operating results were reclassified as discontinued operations in our condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010 and 2009.
 
    In November 2009, we executed an agreement with Petrosucre to mitigate our losses and resolve issues relative to outstanding amounts owed by Petrosucre for drilling operations performed by Ensco through the date of termination of the drilling contract in June 2009 (the "agreement"). Although ENSCO 69 will continue to be fully controlled and operated by Petrosucre, the agreement requires Petrosucre to compensate us for its ongoing use of the rig. We recognized $5.5 million and $12.4 million of pre-tax income from discontinued operations for the three-month and six-month periods ended June 30, 2010 associated with collections under the agreement.
 
    Although the agreement obligates Petrosucre to make additional payments for its use of the rig through June 30, 2010, the associated income was not recognized in our condensed consolidated statements of income, as collectability was not reasonably assured.  There can be no assurances relative to the recovery of outstanding contract entitlements, insurance recovery and related pending litigation, the possible return of ENSCO 69 to us by Petrosucre or the imposition of customs duties in relation to the rig's ongoing presence in Venezuela.  See "Note 12 - Contingencies" for additional information on insurance and legal remedies related to ENSCO 69.
 
    The following table summarizes our income (loss) from discontinued operations for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):
 
 
   Three Months Ended
             June 30,             
        Six Months Ended
                   June 30,            
    2010 
    2009 
     2010 
        2009 
                   
Revenues
 
$ 5.0
 
$ 14.3
 
$24.7
 
$ 44.2
 
Operating expenses
 
1.3
 
19.4
 
10.7
 
42.2
 
Operating income (loss) before income taxes
 
3.7
 
(5.1
)
14.0
 
2.0
 
Income tax (benefit) expense
 
(.8
)
3.4
 
3.8
 
3.7
 
Gain (loss) on disposal of discontinued operations, net
 
5.7
 
(11.8
)
34.9
 
(11.8
)
Income (loss) from discontinued operations
 
$10.2
 
$(20.3
)
$45.1
 
$(13.5
)
 
    Debt and interest expense are not allocated to our discontinued operations.
 
 
18

 
 
Note 12 - Contingencies
 
    FCPA Internal Investigation
 
    Following disclosures by other offshore service companies announcing internal investigations involving the legality of amounts paid to and by customs brokers in connection with temporary importation of rigs and vessels into Nigeria, the Audit Committee of our Board of Directors and management commenced an internal investigation in July 2007. The investigation initially focused on our payments to customs brokers relating to the temporary importation of ENSCO 100, our only rig that operated offshore Nigeria during the pertinent period.
 
    As is customary for companies operating offshore Nigeria, we had engaged independent customs brokers to process customs clearance of routine shipments of equipment, materials and supplies and to process the ENSCO 100 temporary importation permits, extensions and renewals. One or more of the customs brokers that our subsidiary in Nigeria used to obtain the ENSCO 100 temporary import permits, extensions and renewals also provided this service to other offshore service companies that have undertaken Foreign Corrupt Practices Act ("FCPA") compliance internal investigations.
 
    The principal purpose of our investigation was to determine whether any of the payments made to or by our customs brokers were inappropriate under the anti-bribery provisions of the FCPA or whether any violations of the recordkeeping or internal accounting control provisions of the FCPA occurred. Our Audit Committee engaged a Washington, D.C. law firm with significant experience in investigating and advising upon FCPA matters to assist in the internal investigation.
 
    Following notification to the Audit Committee and to KPMG LLP, our independent registered public accounting firm, in consultation with the Audit Committee's external legal counsel, we voluntarily notified the United States Department of Justice and SEC that we had commenced an internal investigation. We expressed our intention to cooperate with both agencies, comply with their directives and fully disclose the results of the investigation. The internal investigation process has involved extensive reviews of documents and records, as well as production to the authorities, and interviews of relevant personnel. In addition to the temporary importation of ENSCO 100, the investigation has examined our customs clearance of routine shipments and immigration activities in Nigeria.
 
   Our internal investigation has essentially been concluded. Discussions were held with the authorities to review the results of the investigation and discuss associated matters during 2009 and the first half of 2010.  On May 24, 2010, we received notification from the SEC Division of Enforcement advising that it does not intend to recommend any enforcement action.  We expect to receive a determination by the United States Department of Justice in the near-term. 
 
    Although we believe the United States Department of Justice will take into account our voluntary disclosure, our cooperation with the agency and the remediation and compliance enhancement activities that are underway, we are unable to predict the ultimate disposition of this matter, whether we will be charged with violation of the anti-bribery, recordkeeping or internal accounting control provisions of the FCPA or whether the scope of the investigation will be extended to other issues in Nigeria or to other countries. We also are unable to predict what potential corrective measures, fines, sanctions or other remedies, if any, the United States Department of Justice may seek against us or any of our employees.
 
    In November 2008, our Board of Directors approved enhanced FCPA compliance recommendations issued by the Audit Committee's external legal counsel, and the Company embarked upon an enhanced compliance initiative that included appointment of a Chief Compliance Officer and a Director - Corporate Compliance. We engaged consultants to assist us in implementing the compliance recommendations approved by our Board of Directors, which include an enhanced compliance policy, increased training and testing, prescribed contractual provisions for our service providers that interface with foreign government officials, due diligence for the selection of such service providers and an increased Company-wide awareness initiative that includes periodic issuance of FCPA Alerts.
 
    Since ENSCO 100 completed its contract commitment and departed Nigeria in August 2007, this matter is not expected to have a material effect on or disrupt our current operations. As noted above, we are unable to predict the outcome of this matter or estimate the extent to which we may be exposed to any resulting potential liability, sanctions or significant additional expense.
 
 
19

 
 
    ENSCO 74 Loss
 
    In September 2008, ENSCO 74 was lost as a result of Hurricane Ike in the Gulf of Mexico.  Portions of its legs remained underwater adjacent to the customer's platform, and we conducted extensive aerial and sonar reconnaissance but did not locate the rig hull. The rig was a total loss, as defined under the terms of our insurance policies.
 
    In March 2009, the sunken rig hull of ENSCO 74 was located approximately 95 miles from the original drilling location when it was struck by an oil tanker. Following discovery of the sunken rig hull, we removed the accessible hydrocarbons onboard and began planning for removal of the wreckage. As an interim measure, the wreckage was appropriately marked, and the U.S. Coast Guard issued a Notice to Mariners.
 
    Physical damage to our rigs caused by a hurricane, the associated "sue and labor" costs to mitigate the insured loss and removal, salvage and recovery costs are all covered by our property insurance policies subject to a $50.0 million per occurrence self-insured retention.  The insured value of ENSCO 74 was $100.0 million, and we have received the net $50.0 million due under our policy for loss of the rig.
 
    Coverage for ENSCO 74 sue and labor costs and wreckage and debris removal costs under our property insurance policies is limited to $25.0 million and $50.0 million, respectively. Supplemental wreckage and debris removal coverage is provided under our liability insurance policies, subject to an annual aggregate limit of $500.0 million. We also have a customer contractual indemnification that provides for reimbursement of any ENSCO 74 wreckage and debris removal costs that are not recovered under our insurance policies.
 
    We believe it is probable that we are required to remove the leg sections of ENSCO 74 remaining adjacent to the customer's platform because they may interfere with the customer's future operations, and we recently commenced removal of the hull wreckage and related debris.  We estimate the leg removal costs to range from $16.0 million to $30.0 million and the costs of the hull and related debris removal to range from $36.0 million to $55.0 million. We expect the cost of removal of the legs and the hull and related debris to be fully covered by our insurance without any additional retention.
 
    A $16.0 million liability, representing the low end of the range of estimated leg removal costs, and a corresponding receivable for recovery of those costs was recorded as of June 30, 2010. A $34.3 million liability, representing the low end of the range of estimated remaining hull and related debris removal costs, and a corresponding receivable for recovery of those costs was recorded as of June 30, 2010. As of June 30, 2010, $1.7 million of wreckage and debris removal costs had been incurred and paid, primarily related to removal of hydrocarbons from the rig. The remaining estimated aggregate $50.3 million liability for leg and hull and related debris removal costs was included in accrued liabilities and other in our June 30, 2010 condensed consolidated balance sheet.  The aggregate $50.8 million receivable for recovery of those costs was included in other assets, net, on our June 30, 2010 condensed consolidated balance sheet.
 
    In March 2009, we received notice from legal counsel representing certain underwriters in a subrogation claim alleging that ENSCO 74 caused a pipeline to rupture during Hurricane Ike. On September 4, 2009, civil litigation was filed seeking damages for the cost of repairs and business interruption in an amount in excess of $26.0 million. Based on information currently available, primarily the adequacy of available defenses, we have not concluded that it is probable a liability exists with respect to this matter.
 
    In March 2009, the owner of the oil tanker that struck the hull of ENSCO 74 commenced civil litigation against us seeking monetary damages of $10.0 million for losses incurred when the tanker struck the sunken hull of ENSCO 74. Based on information currently available, primarily the adequacy of available defenses, we have not concluded that it is probable a liability exists with respect to this matter.
 
 
20

 
   
    We filed a petition for exoneration or limitation of liability under U.S. admiralty and maritime law in September 2009. The petition seeks exoneration from or limitation of liability for any and all injury, loss or damage caused, occasioned or occurred in relation to the ENSCO 74 loss in September 2008. The owner of the tanker that struck the hull of ENSCO 74 and the owners of four subsea pipelines have presented claims in the exoneration/limitation proceedings.  The matter is scheduled for trial in September 2011.
 
    We have liability insurance policies that provide coverage for claims such as the tanker and pipeline claims as well as removal of wreckage and debris in excess of the property insurance policy sublimit, subject to a $10.0 million per occurrence self-insured retention for third-party claims and an annual aggregate limit of $500.0 million. We believe all liabilities associated with the ENSCO 74 loss during Hurricane Ike resulted from a single occurrence under the terms of the applicable insurance policies. However, legal counsel for certain liability underwriters have asserted that the liability claims arise from separate occurrences. In the event of multiple occurrences, the self-insured retention is $15.0 million for two occurrences and $1.0 million for each occurrence thereafter.
 
    Although we do not expect final disposition of the claims associated with the ENSCO 74 loss to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome.
 
    ENSCO 69
 
   We have filed an insurance claim under our package policy, which includes coverage for certain political risks, and are evaluating legal remedies against Petrosucre for contractual and other ENSCO 69 related damages. ENSCO 69 has an insured value of $65.0 million under our package policy, subject to a $10.0 million deductible.
 
    In September 2009, legal counsel acting for the package policy underwriters denied coverage under the package policy and reserved rights. In March 2010, underwriters commenced litigation in the U.K. for purposes of enforcing mediation under the disputes clause of our package policy and precluding us from pursuing litigation in the United States. On that date, we commenced litigation to recover on our political risk package policy claim. Our lawsuit seeks recovery under the policy for the loss of ENSCO 69 and includes claims for wrongful denial of coverage, breach of contract, breach of the Texas insurance code, failure to timely respond to the claim and bad faith. Our lawsuit seeks actual damages in the amount of $55.0 million (insured value of $65.0 million less a $10.0 million deductible), punitive damages and attorneys' fees. On April 26, 2010, we obtained a temporary injunction that effectively prohibits the insurance underwriters from pursuing litigation they filed in the U.K.
 
    We were unable to conclude that collection of insurance proceeds associated with the loss of ENSCO 69 was probable as of June 30, 2010. Accordingly, no ENSCO 69 related insurance receivables were recorded on our condensed consolidated balance sheet as of June 30, 2010. See "Note 11 - Discontinued Operations" for additional information on ENSCO 69.
 
    ENSCO 29 Wreck Removal
 
    A portion of the ENSCO 29 platform drilling rig was lost over the side of a customer's platform as a result of Hurricane Katrina during 2005. Although beneficial ownership of ENSCO 29 was transferred to our insurance underwriters when the rig was determined to be a total loss, management believes we may be legally required to remove ENSCO 29 wreckage and debris from the seabed and currently estimates the removal cost could range from $5.0 million to $15.0 million. Our property insurance policies include coverage for ENSCO 29 wreckage and debris removal costs up to $3.8 million. We also have liability insurance policies that provide specified coverage for wreckage and debris removal costs in excess of the $3.8 million coverage provided under our property insurance policies.
 
 
21

 
 
    Our liability insurance underwriters have issued letters reserving rights and effectively denying coverage by questioning the applicability of coverage for the potential ENSCO 29 wreckage and debris removal costs.  During 2007, we commenced litigation against certain underwriters alleging breach of contract, wrongful denial, bad faith and other claims which seek a declaration that removal of wreckage and debris is covered under our liability insurance, monetary damages, attorneys' fees and other remedies. The matter is scheduled for trial in August 2010.
 
    While we anticipate that any ENSCO 29 wreckage and debris removal costs incurred will be largely or fully covered by insurance, a $1.2 million provision, representing the portion of the $5.0 million low end of the range of estimated removal cost we believe is subject to liability insurance coverage, was recognized during 2006.
 
    Asbestos Litigation
 
    During 2004, we and certain current and former subsidiaries were named as defendants, along with numerous other third-party companies as co-defendants, in three multi-party lawsuits filed in Mississippi. The lawsuits sought an unspecified amount of monetary damages on behalf of individuals alleging personal injury or death, primarily under the Jones Act, purportedly resulting from exposure to asbestos on drilling rigs and associated facilities during the period 1965 through 1986.
 
    In compliance with the Mississippi Rules of Civil Procedure, the individual claimants in the original multi-party lawsuits whose claims were not dismissed were ordered to file either new or amended single plaintiff complaints naming the specific defendant(s)  against whom they intended to pursue claims. As a result, out of more than 600 initial multi-party claims, we have been named as a defendant by 65 individual plaintiffs. Of these claims, 62 claims or lawsuits are pending in Mississippi state courts and three are pending in the U.S. District Court as a result of their removal from state court.
 
    To date, written discovery and plaintiff depositions have taken place in eight cases involving us.  While several cases have been selected for trial during 2010 and 2011, none of the cases pending against us in Mississippi state court are included within those selected cases.
 
   We intend to vigorously defend against these claims and have filed responsive pleadings preserving all defenses and challenges to jurisdiction and venue. However, discovery is still ongoing and, therefore, available information regarding the nature of all pending claims is limited. At present, we cannot reasonably determine how many of the claimants may have valid claims under the Jones Act or estimate a range of potential liability exposure, if any.
 
    In addition to the pending cases in Mississippi, we have two other asbestos or lung injury claims pending against us in litigation in other jurisdictions. Although we do not expect the final disposition of the Mississippi and other asbestos or lung injury lawsuits to have a material adverse effect upon our financial position, operating results or cash flows, there can be no assurances as to the ultimate outcome of the lawsuits.
 
 
22

 
 
    Working Time Directive
 
    Legislation known as the U.K. Working Time Directive ("WTD") was introduced during 2003 and may be applicable to our employees and employees of other drilling contractors that work offshore in U.K. territorial waters or in the U.K. sector of the North Sea. Certain trade unions representing offshore employees have claimed that drilling contractors are not in compliance with the WTD in respect of paid time off (vacation time) for employees working offshore on a rotational basis (generally equal time working and off).
   
    A Labor Tribunal in Aberdeen, Scotland, rendered decisions in claims involving other offshore drilling contractors and offshore service companies in February 2008. The Tribunal decisions effectively held that employers of offshore workers in the U.K. sector employed on an equal time on/time off rotation are obligated to accord such rotating personnel two-weeks annual paid time off from their scheduled offshore work assignment period. Both sides of the matter, employee and employer groups, appealed the Tribunal decision. The appeals were heard by the Employment Appeal Tribunal ("EAT") in December 2008.
 
    In an opinion rendered in March 2009, the EAT determined that the time off work enjoyed by U.K. offshore oil and gas workers, typically 26 weeks per year, meets the amount of annual leave employers must provide to employees under the WTD. The employer group was successful in all arguments on appeal, as the EAT determined that the statutory entitlement to annual leave under the WTD can be discharged through normal field break arrangements for offshore workers. As a consequence of the EAT decision, an equal on/off time offshore rotation has been deemed to be fully compliant with the WTD.  The employee group (led by a trade union) was granted leave to appeal to the highest civil court in Scotland (the Court of Session).  A hearing on the appeal occurred in June 2010 and a decision is expected in the near-term.
 
    Based on information currently available, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, operating results or cash flows.
 
    Other Matters
 
    In addition to the foregoing, we are named defendants in certain other lawsuits, claims or proceedings incidental to our business and are involved from time to time as parties to governmental investigations or proceedings, including matters related to taxation, arising in the ordinary course of business. Although the outcome of such lawsuits or other proceedings cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, we do not expect these matters to have a material adverse effect on our financial position, operating results or cash flows.
 
Note 13 - Segment Information
 
    Our business consists of four operating segments: (1) Deepwater, (2) Asia Pacific, (3) Europe and Africa (4) North and South America. Each of our four operating segments provides one service, contract drilling. Segment information for the three-month and six-month periods ended June 30, 2010 and 2009 is presented below (in millions). General and administrative expense is not allocated to our operating segments for purposes of measuring segment operating income and is included in "Reconciling Items." Assets not allocated to our operating segments consisted primarily of cash and cash equivalents and goodwill and also are included in "Reconciling Items."
 
 
23

 
 
Three Months Ended June 30, 2010
 
 
 
Deepwater
 
 
  Asia
  Pacific
 
 
Europe
and Africa
 North
 and
 South
  America 
 
   Operating
  Segments
       Total     
 
 
Reconciling
    Items    
 
 
Consolidated
    Total    
               
Revenues
$   120.9
 
$    121.3
 
$  73.5  
 
$  90.6
 
$   406.3
 
$         --
 
$   406.3  
 
Operating expenses
Contract drilling (exclusive
of depreciation)
46.5
 
 65.8
 
 51.0  
 
43.7
 
207.0
 
--
 
207.0  
 
Depreciation
9.7
 
18.2
 
11.9  
 
12.7
 
52.5
 
.3
 
52.8  
 
General and administrative
--
 
--
 
--  
 
--
 
--
 
22.0
 
22.0  
 
Operating income (loss)
 $     64.7
 
$     37.3
 
$  10.6  
 
$  34.2
 
$   146.8
 
$    (22.3
$   124.5  
 
Total assets
$2,774.8
 
$1,153.2
 
$822.9  
 
$794.5
 
$5,545.4
 
$1,375.6
 
$6,921.0  
 
 
Three Months Ended June 30, 2009
 
 
 
Deepwater
 
 
   Asia
    Pacific 
 
 
Europe
and Africa
 North
 and
 South
  America 
 
   Operating
  Segments
       Total     
 
 
Reconciling
    Items    
 
 
Consolidated
    Total    
               
Revenues
$     67.7
 
$   147.2
 
$176.0  
 
$106.4
 
$   497.3
 
$         --
 
$   497.3  
 
Operating expenses
Contract drilling (exclusive
of depreciation)
23.7
 
54.4
 
52.6  
 
40.5
 
171.2
 
--
 
171.2  
 
Depreciation
3.7
 
18.7
 
11.0  
 
12.1
 
45.5
 
.3
 
45.8  
 
General and administrative
--
 
--
 
--  
 
--
 
--
 
16.0
 
16.0  
 
Operating income (loss)
$     40.3
 
$     74.1
 
$112.4  
 
$  53.8
 
$   280.6
 
$    (16.3
$   264.3  
 
Total assets
$2,172.4
 
$1,300.7
 
$813.2  
 
$823.4
 
$5,109.7
 
$1,239.3
 
$6,349.0  
 
 
Six Months Ended June 30, 2010
 
 
 
Deepwater
 
 
Asia
 Pacific 
 
 
Europe
and Africa
 North
 and
 South
  America 
 
   Operating
  Segments
       Total    
 
 
Reconciling
    Items    
 
 
Consolidated
    Total    
               
Revenues
$   251.3
 
$    253.3
 
$161.1  
 
$182.1
 
$   847.8
 
$         --
 
$   847.8  
 
Operating expenses
Contract drilling (exclusive
of depreciation)
91.5
 
117.6
 
 98.1  
 
82.6
 
389.8
 
--
 
389.8  
 
Depreciation
19.5
 
36.5
 
23.7  
 
25.2
 
104.9
 
.6
 
105.5  
 
General and administrative
--
 
--
 
--  
 
--
 
--
 
42.6
 
42.6  
 
Operating income (loss)
$   140.3
 
$     99.2
 
$  39.3  
 
$  74.3
 
$   353.1
 
$    (43.2
$   309.9  
 
Total assets
$2,774.8
 
$1,153.2
 
$822.9  
 
$794.5
 
$5,545.4
 
$1,375.6
 
$6,921.0  
 
 
Six Months Ended June 30, 2009
 
 
Deepwater
 
 
Asia
 Pacific 
 
 
Europe
and Africa
 North
 and
 South
  America 
 
  Operating  
  Segments  
    Total    
 
 
Reconciling
    Items    
 
 
Consolidated
    Total    
               
Revenues
$   67.7  
 
$  343.0 
 
$372.4  
 
$198.4
 
$   981.5
 
$         --
 
$    981.5  
 
Operating expenses
Contract drilling (exclusive
of depreciation)
28.5
 
111.6
 
106.1  
 
79.6
 
325.8
 
--
 
325.8  
 
Depreciation
6.0
 
37.0
 
21.9  
 
24.1
 
89.0
 
.6
 
89.6  
 
General and administrative
--
 
--
 
--  
 
--
 
--
 
28.0
 
28.0  
 
Operating income (loss)
$     33.2
 
$   194.4
 
$244.4  
 
$  94.7
 
$   566.7
 
$    (28.6
)
$   538.1  
 
Total assets
$2,172.4
 
$1,300.7
 
$813.2  
 
$823.4
 
$5,109.7
 
$1,239.3
 
$6,349.0  
 

 
24

 
 
 
    Information about Geographic Areas
 
    As of June 30, 2010, our Deepwater operating segment consisted of three ultra-deepwater semisubmersible rigs located in the Gulf of Mexico, one ultra-deepwater semisubmersible rig located in Australia and four ultra-deepwater semisubmersible rigs under construction in Singapore. Our Asia Pacific operating segment consisted of 16 jackup rigs and one barge rig deployed in various locations throughout Asia, the Middle East and Australia. Our Europe and Africa operating segment consisted of eight jackup rigs deployed in various territorial waters of the North Sea and two jackup rigs located offshore Tunisia. Our North and South America operating segment consisted of eight jackup rigs located in the Gulf of Mexico and five jackup rigs located offshore Mexico.
 
    Certain of our ultra-deepwater semisubmersible rigs currently contracted in the U.S. Gulf of Mexico are affected by a drilling moratorium/suspension imposed by the U.S. Department of Interior in response to the BP Macondo well incident. This moratorium/suspension and related Notices to Lessees (“NTLs”) are being challenged in litigation by Ensco and others.  The operations of certain of our jackup rigs not expressly covered by the moratorium/suspension are being delayed due to the requirements of the NTLs and the permit approval process.   Current or future NTLs or other directives may impact our customers' ability to obtain permits and commence or continue deepwater or shallow-water operations in the U.S. Gulf of Mexico. During the three-month and six-month periods ended June 30, 2010, revenues provided by our drilling operations in the U.S. Gulf of Mexico totaled $93.8 million and $188.4 million, or 23% and 22%, of our consolidated revenues, respectively. Of these amounts, 62% and 65% were provided by our deepwater drilling operations in the U.S. Gulf of Mexico for the three-month and six-month periods ended June 30, 2010, respectively. A prolonged suspension of drilling activity in the U.S. Gulf of Mexico and associated new legislation or regulations in the U.S. or elsewhere could materially adversely affect our financial condition, operating results or cash flows.
 
Note 14 - Subsequent Events
   
    On July 7, 2010, we acquired a KFELS Super B Class design jackup rig for $186.0 million, of which $18.6 million was paid as a deposit in June 2010.  The rig was constructed in 2008 and has been renamed ENSCO 109.  ENSCO 109 is currently operating offshore Australia and will be reported within our Asia Pacific operating segment in future periods.
 
 
 
25

 
Item 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations
 
BUSINESS ENVIRONMENT
   
    In May 2010, the U.S. Department of Interior implemented a six-month moratorium/suspension on certain drilling activities in water depths greater than 500 feet in the U.S. Gulf of Mexico in response to the BP Macondo well incident. The U.S. Department of Interior subsequently issued Notices to Lessees ("NTLs") implementing additional safety and certification requirements applicable to drilling activities in the U.S. Gulf of Mexico, imposed additional requirements for approval of development and production activities in the U.S. Gulf of Mexico and has delayed the approval of applications to drill in both deepwater and shallow-water areas. On June 22, 2010, the U.S. District Court for the Eastern District of Louisiana granted a temporary injunction which immediately prohibited enforcement of the moratorium/suspension and an appeal to the Fifth Circuit Court of Appeals declined the government's petition to stay enforcement of the injunction.  On July 12, 2010, the U.S. Department of Interior issued a revised moratorium/suspension on drilling in the U.S. Gulf of Mexico that generally applies to mobile offshore drilling units that utilize subsea blowout prevention equipment required for deepwater drilling operations.
 
    Some U.S. Gulf of Mexico deepwater projects have been delayed as a result of the moratorium/suspension, which does not prohibit certain well operations.  Although global deepwater drilling activity has remained stable during 2010, there is significant uncertainty as to the near-term and long-term impact the BP Macondo well incident may have on deepwater drilling in the U.S. Gulf of Mexico, in addition to its potential impact on the global deepwater market.
 
    Semisubmersible rig supply also continues to increase as a result of newbuild construction programs. It has been reported that 29 newbuild semisubmersible rigs are currently under construction, approximately half of which are scheduled for delivery during the remainder of 2010. The majority of semisubmersible rigs scheduled for delivery during 2010 are contracted. Based on the current level of uncertainty regarding deepwater drilling in the U.S. Gulf of Mexico, we are unable to predict whether newbuild semisubmersible rigs will be absorbed into the global market without a significant effect on utilization and day rates.
 
    The significant decline in oil and natural gas prices during the latter half of 2008 and the deterioration of the global economy led to an abrupt reduction in demand for jackup rigs during 2009. Although oil prices have stabilized, incremental drilling activity during 2010 has remained limited resulting in continued softness in jackup rig day rates. While we are encouraged by continued rig inquiries, it remains uncertain whether they will ultimately result in a measurable increase in jackup rig demand in the near-term. Furthermore, it is uncertain as to the impact the BP Macondo well incident may have on jackup rig demand in general, and in the U.S. Gulf of Mexico in particular.
 
    Jackup rig supply continues to increase as a result of newbuild construction programs which were initiated prior to the 2008 decline in oil and natural gas prices. It has been reported that 41 newbuild jackup rigs are currently under construction, over half of which are scheduled for delivery during the remainder of 2010. The majority of jackup rigs scheduled for delivery during 2010 are not contracted. It is unlikely that the market in general or any geographic region in particular will be able to fully absorb newbuild jackup rig deliveries in the near-term, especially in consideration of the existing oversupply of jackup rigs.

    For additional information concerning the potential impact the aforementioned events and circumstances may have on our business, our industry and global supply, see "Item 1A. Risk Factors" in Part I and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II of our Annual Report on Form 10-K for the year ended December 31, 2009, as updated in the Current Report on Form 8-K dated June 8, 2010 and in this report. 
 
    Deepwater
 
    During 2009, depressed oil and natural gas prices resulted in a modest decline in demand for ultra-deepwater semisubmersible rigs, however, global utilization and day rates generally were stable. Although utilization and day rates remained stable during the first six months of 2010, utilization and day rates may come under pressure if deepwater contracts in the U.S. Gulf of Mexico are terminated and/or those rigs are marketed in other regions.  Future ultra-deepwater semisubmersible rig utilization and day rates will depend in large part on projected oil and natural gas prices, the global economy and the potential long-term impact the BP Macondo well incident may have on the global deepwater market.
 
    ENSCO 8502 was delivered in January 2010 and is scheduled to commence drilling operations under a two-year contract in August 2010.  Although our customer has questioned whether the new requirements of the moratorium/suspension and related NTLs will delay contract commencement, we believe ENSCO 8502 is in compliance with contractual requirements and current applicable regulations and that the drilling contract should commence in accordance with its terms.  We also have four ENSCO 8500 Series® rigs under construction with scheduled delivery dates during the fourth quarter of 2010, the second half of 2011 and the first and second half of 2012. ENSCO 8503 is committed under a long-term drilling contract in the Gulf of Mexico and is scheduled to commence drilling operations during the first quarter of 2011.  The remaining ENSCO 8500 Series® rigs under construction are without contracts. Our ENSCO 7500 ultra-deepwater semisubmersible rig currently is operating under contract in Australia.
 
 
26

 
    Asia Pacific
   
    During 2009, Asia Pacific jackup rig utilization and day rates were significantly impacted by the 2008 decline in oil and natural gas prices. While the Asia Pacific jackup market began to show signs of stability during the first six months of 2010, competition for work remained intense due to the oversupply of jackup rigs and limited contract opportunities. With an expected increase in the supply of available jackup rigs from newbuild deliveries and expiring drilling contracts, we anticipate that Asia Pacific jackup rig utilization and day rates will remain under pressure in the near-term.
 
    In conjunction with our long-established strategy of high-grading our jackup rig fleet by investing in newer equipment, we sold three jackup rigs located in the Asia Pacific region during the first six months of 2010.  In July 2010, we acquired a KFELS Super B Class design jackup rig constructed in 2008.  The rig was renamed ENSCO 109 and is currently operating in Australia.
 
    Europe and Africa
 
    Our Europe and Africa offshore drilling operations are mainly conducted in Northern Europe. The 2008 decline in oil and natural gas prices resulted in several cancelled tenders and unexercised contract extension options during the latter portion of 2009. Tender activity in the region during the first six months of 2010 was limited with some inquiries for work beginning in 2011, and we expect this trend to continue in the near-term. With limited tender activity and additional jackup rigs projected to complete their current contracts later this year, we anticipate this market will experience excess rig availability, and utilization and day rates will remain under pressure in the near-term.
 
    North and South America
 
    A significant portion of our North and South America offshore drilling operations are conducted in Mexico, where demand for rigs increased in recent years as Petróleos Mexicanos ("PEMEX"), the national oil company of Mexico, accelerated drilling activities in an attempt to offset continued depletion of its major oil and natural gas fields. During 2009 and the first six months of 2010, demand for jackup rigs in Mexico remained high despite global economic conditions. PEMEX recently issued additional tenders for several jackup rigs to commence drilling operations in late 2010 in response to contracts expiring later this year. We expect future day rates in Mexico to face pressure as jackup rig contracts in the region expire and drilling contractors with idle rigs in the Gulf of Mexico and other geographic regions pursue the available contract opportunities.
 
    We also conduct a portion of our North and South America jackup rig operations in the U.S. Gulf of Mexico. The U.S. Gulf of Mexico jackup rig market remained extremely weak during 2009, with drilling activity reaching historic lows as a result of the deterioration in the global economy. During early 2010, tender activity in the U.S. Gulf of Mexico improved as operators capitalized on cost-effective terms offered by drilling contractors. Due to the potential for delays from hurricane season, certain operators’ inability to timely obtain drilling permits and the uncertainty regarding the impact the BP Macondo well incident may have on jackup rig drilling operations in the region, we do not expect meaningful improvement in U.S. Gulf of Mexico jackup rig utilization and day rates in the near-term.
 
RESULTS OF OPERATIONS
 
    The following table summarizes our condensed consolidated results of operations for the three-month and six-month periods ended June 30, 2010 and 2009 (in millions):
 
 
Three Months Ended
         June 30,          
Six Months Ended
          June 30,        
 
 2010 
   2009  
      2010  
   2009  
                   
Revenues
 
$406.3
 
$497.3
 
$847.8
 
$981.5
 
Operating expenses
                 
Contract drilling (exclusive of depreciation)
 
207.0
 
171.2
 
389.8
 
325.8
 
Depreciation
 
52.8
 
45.8
 
105.5
 
89.6
 
General and administrative
 
22.0
 
16.0
 
42.6
 
28.0
 
Operating income
 
124.5
 
264.3
 
309.9
 
538.1
 
Other income, net
 
12.8
 
6.9
 
15.9
 
2.6
 
Provision for income taxes
 
19.6
 
49.5
 
51.4
 
103.7
 
Income from continuing operations
 
117.7
 
221.7
 
274.4
 
437.0
 
Income (loss) from discontinued operations, net
 
10.2
 
(20.3
)
45.1
 
(13.5
)
Net income
 
127.9
 
201.4
 
319.5
 
423.5
 
Net income attributable to noncontrolling interests
 
(1.6
)
(1.1
)
(3.4
)
(2.5
)
Net income attributable to Ensco
 
$126.3
 
$200.3
 
$316.1
 
$421.0
 
 
 
27

 
    For the quarter ended June 30, 2010, revenues declined by $91.0 million, or 18%, and operating income declined by $139.8 million, or 53%, as compared to the prior year quarter. For the six-month period ended June 30, 2010, revenues declined by $133.7 million, or 14%, and operating income declined by $228.2 million, or 42%, as compared to the prior year period. These declines were primarily due to a decline in average day rates and utilization for our Europe and Africa and Asia Pacific jackup rig fleets, partially offset by significant increases in revenues and operating income generated by our ultra-deepwater semisubmersible rig fleet.
 
    A significant number of our drilling contracts are of a long-term nature. Accordingly, a decline in demand for contract drilling services typically affects our operating results and cash flows gradually over many quarters as long-term contracts expire. The significant decline in oil and natural gas prices during the latter half of 2008 and the deterioration of the global economy resulted in a dramatic decline in demand for contract drilling services during 2009, which will continue to negatively impact our operating results during 2010.  While we have substantial contract backlog for 2010, it is unlikely that revenue and operating income levels achieved during 2009 will be sustained during 2010.
   
    Certain of our ultra-deepwater semisubmersible rigs currently contracted in the U.S. Gulf of Mexico are affected by the drilling moratorium/suspension imposed by the U.S. Department of Interior in response to the BP Macondo well incident.  This moratorium/suspension and related NTLs are being challenged in litigation by Ensco and others.  The operations of certain of our jackup rigs not expressly covered by the moratorium/suspension are being delayed due to the requirements of the NTLs and the drilling permit approval process.   Current or future NTLs or other directives may impact our customers' ability to obtain drilling permits and commence or continue deepwater or shallow-water operations in the U.S. Gulf of Mexico.
 
    Customers recently have submitted force majeure notices involving our ultra-deepwater semisubmersible (ENSCO 8500) and four of our jackup rigs (ENSCO 68, ENSCO 82, ENSCO 86 and ENSCO 87) in the U.S. Gulf of Mexico.  We have rejected all of these force majeure notices as invalid under the applicable terms of the contract.  All four jackup rigs (ENSCO 68, ENSCO 82, ENSCO 86 and ENSCO 87) currently are operating and earning full day rate.  In the event of valid force majeure circumstances, the contracts for our ultra-deepwater semisubmersible rigs currently in the U.S. Gulf of Mexico generally provide that a reduced rate applies for a specified number of days (approximately ten weeks) after which our customers have a right to terminate, subject to payment of a significant portion of the day rate for the remainder of the contract term (which, in some cases, is to be offset by other drilling work obtained during said period).  As respects our jackup rigs in the U.S. Gulf of Mexico, the contractual force majeure provisions generally provide for payment of full day rate for a specified number of days (approximately two weeks) after which our customers have a right to terminate without further payment.
 
    We are working with our customers on mutually agreeable contingency plans for our rigs in the U.S. Gulf of Mexico that may involve day rate adjustments or rig relocations. As respects ENSCO 8502, our customer has questioned whether the new requirements of the moratorium/suspension and related NTLs will delay contract commencement.  We believe ENSCO 8502 is in compliance with contractual requirements and current applicable regulations and that the drilling contract should commence in accordance with its terms.
 
    Significant uncertainty remains as to the near-term and long-term impact the BP Macondo well incident may have on our operating results in general, and in the U.S. Gulf of Mexico in particular.
 
Rig Locations, Utilization and Average Day Rates
 
    We manage our business through four operating segments. Our jackup rigs are mobile and occasionally move between operating segments in response to market conditions and contract opportunities. The following table summarizes our offshore drilling rigs by segment and rigs under construction as of June 30, 2010 and 2009:
 
 
June 30,
  2010  
 
June 30, 
  2009   
               
Deepwater(1)
 
4
     
3  
 
Asia Pacific
 
17
     
17  
 
Europe and Africa
 
10
     
10  
 
North and South America
 
13
     
13  
 
Under construction
 
4
     
5  
 
Total(2)
 
48
     
48  
 
 
    (1)
 
In January 2010, we accepted delivery of ENSCO 8502, which is scheduled to commence drilling operations in the Gulf of Mexico under a two-year contract in August 2010.
 
   (2)
 
The total number of rigs for each period excludes rigs reclassified as discontinued operations.
 
 
28

 
 
   The following table summarizes our rig utilization and average day rates from continuing operations by operating segment for the three-month and six-month periods ended June 30, 2010 and 2009:
 
 
Three Months Ended
          June 30,           
      Six Months Ended
                 June 30,          
 
2010  
2009  
2010
2009   
Rig utilization(1)
                 
Deepwater 
 
91%
 
96%
 
95%
 
98%
 
Asia Pacific(3)
 
68%
 
69%
 
72%
 
75%
 
Europe and Africa
 
63%
 
87%
 
66%
 
93%
 
North and South America 
 
87%
 
72%
 
86%
 
70%
 
Total
 
74%
 
75%
 
76%
 
79%
 
                   
Average day rates(2)
                 
Deepwater 
 
$403,307
 
$490,865
 
$407,334
 
$490,865
 
Asia Pacific(3)
 
116,529
 
142,195
 
116,716
 
152,290
 
Europe and Africa
 
125,257
 
219,715
 
133,423
 
219,309
 
North and South America 
 
 82,939
 
119,190
 
 85,482
 
119,127
 
Total
 
$131,231
 
$171,428
 
$135,033
 
$169,567
 
 
   (1)
 
Rig utilization is derived by dividing the number of days under contract by the number of days in the period. Days under contract equals the total number of days that rigs have earned a day rate, including days associated with compensated downtime and mobilizations. For newly constructed or acquired rigs, the number of days in the period begins upon commencement of drilling operations for rigs with a contract or when the rig becomes available for drilling operations for rigs without a contract.
 
   (2)
 
Average day rates are derived by dividing contract drilling revenues, adjusted to exclude certain types of non-recurring reimbursable revenues and lump sum revenues, by the aggregate number of contract days, adjusted to exclude contract days associated with certain mobilizations, demobilizations, shipyard contracts and standby contracts.
 
   (3)
 
Rig utilization and average day rates for the Asia Pacific operating segment include our jackup rigs only. The ENSCO I barge rig has been excluded.
 
    Detailed explanations of our operating results, including discussions of revenues, contract drilling expense and depreciation expense by operating segment, are provided below.
 
Operating Income
 
    Our business consists of four operating segments: (1) Deepwater, (2) Asia Pacific, (3) Europe and Africa (4) North and South America. Each of our four operating segments provides one service, contract drilling. Segment information for the three-month and six-month periods ended June 30, 2010 and 2009 is presented below (in millions). General and administrative expense is not allocated to our operating segments for purposes of measuring segment operating income and is included in "Reconciling Items."
 

 
29

 
 
Three Months Ended June 30, 2010
 
 
 
 
Deepwater
 
 
Asia
 Pacific 
 
 
Europe
and Africa
  North
  and
  South
   America 
 
  Operating
  Segments
       Total     
 
 
Reconciling
   Items   
 
 
Consolidated
    Total    
               
Revenues 
$120.9 
 
$121.3  
 
$73.5  
 
$90.6
 
$406.3
 
$      --     
 
$406.3  
 
Operating expenses
Contract drilling (exclusive
of depreciation) 
46.5  
 
65.8  
 
51.0  
 
43.7
 
207.0
 
--     
 
207.0  
 
Depreciation 
9.7  
 
18.2  
 
11.9  
 
12.7
 
52.5
 
.3     
 
52.8  
 
General and administrative 
--  
 
--  
 
--  
 
--
 
--
 
22.0     
 
22.0  
 
Operating income (loss) 
$ 64.7  
 
$ 37.3  
 
$10.6  
 
$34.2
 
$146.8
 
$(22.3)    
 
$124.5  
 
 
Three Months Ended June 30, 2009
 
 
 
 
Deepwater
 
 
Asia
 Pacific 
 
 
Europe
and Africa
  North
  and
  South
   America 
 
  Operating
  Segments
      Total    
 
 
Reconciling
   Items   
 
 
Consolidated
    Total    
               
Revenues
$ 67.7  
 
$147.2  
 
$176.0  
 
$106.4
 
$497.3
 
$      --     
 
$497.3  
 
Operating expenses
Contract drilling (exclusive
of depreciation)
23.7  
 
54.4  
 
52.6  
 
40.5
 
171.2
 
--     
 
171.2  
 
Depreciation
3.7  
 
18.7  
 
11.0  
 
12.1
 
45.5
 
.3     
 
45.8  
 
General and administrative
--  
 
--  
 
--  
 
--
 
--
 
16.0     
 
16.0  
 
Operating income (loss)
$ 40.3  
 
$  74.1  
 
$112.4  
 
$  53.8
 
$280.6
 
$(16.3)    
 
$264.3  
 
 
Six Months Ended June 30, 2010
 
 
 
 
Deepwater
 
 
Asia
 Pacific 
 
 
Europe
and Africa
  North
  and
  South
   America 
 
  Operating
  Segments
       Total    
 
 
Reconciling
   Items   
 
 
Consolidated
    Total