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EX-32.1 - SECTION 906 CERTIFICATION OF CEO AND CFO - HELIX ENERGY SOLUTIONS GROUP INCexh32.htm
EX-15.1 - IND. REGISTERED PUBLIC ACCOUNTING FIRM ACKNOWLEDGEMENT LETTER - HELIX ENERGY SOLUTIONS GROUP INCexh15.htm
EX-31.1 - RULE 13A-14A CERTIFICATION OF OWEN KRATZ, CEO - HELIX ENERGY SOLUTIONS GROUP INCexh311.htm
EX-99.1 - REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM - HELIX ENERGY SOLUTIONS GROUP INCexh991.htm
EX-31.2 - RULE 13A-14A CERTIFICATION OF ANTHONY TRIPODO, CFO - HELIX ENERGY SOLUTIONS GROUP INCexh312.htm

 

 


 UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
Form 10-Q
 
[X]
 
Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the quarterly period ended September 30, 2009
 
or
[   ]
 
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 001-32936
 

HELIX ENERGY SOLUTIONS GROUP, INC.
(Exact name of registrant as specified in its charter)

Minnesota
(State or other jurisdiction
of incorporation or organization)
             
95–3409686
(I.R.S. Employer
Identification No.)
  
   
400 North Sam Houston Parkway East
Suite 400
Houston, Texas
(Address of principal executive offices)
 
 
77060
(Zip Code)

(281) 618–0400
(Registrant's telephone number, including area code)
 
NOT APPLICABLE
(Former name, former address and former fiscal year, if changed since last report)
 
 
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  
[ √ ] 
    No 
[  ] 
 
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  
[   ] 
    No 
[  ] 
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
 ] 
Accelerated filer  
[    ] 
    Non-accelerated filer 
[    ] 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
     Yes  
[   ] 
    No 
[ √ ] 
 
As of October 28, 2009, 104,312,684 shares of common stock were outstanding.


TABLE OF CONTENTS
 
         
PART I.
 
FINANCIAL INFORMATION
 
PAGE
 
Item 1.
 
Financial Statements:
   
   
 
 
1
 
  
 
Condensed Consolidated Statements of Operations (Unaudited) –
 
2
3
   
 
 
4
   
 
 
6
 
Item 2.
 
 
  
41
 
Item 3.
   
63
 
Item 4.
   
64
 
PART II.
 
OTHER INFORMATION
   
Item 1.
 
 
 
64
 
Item 2.
   
64
Item 6.
 
 
 
65
   
 
 
66
   
 
 
67


PART I.  FINANCIAL INFORMATION
Item 1.  Financial Statements.
 
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
 (in thousands)

   
September 30,
 
December 31,
   
2009
 
2008
   
(Unaudited)
   
         
ASSETS
Current assets:
               
  Cash and cash equivalents
 
$
410,506
   
$
223,613
 
  Accounts receivable —
     Trade, net of allowance for uncollectible accounts
         of $4,399 and $5,905, respectively
   
185,519
     
427,856
 
     Unbilled revenue
   
22,558
     
42,889
 
     Costs in excess of billing
   
16,624
     
74,361
 
  Other current assets
   
130,546
     
172,089
 
  Current assets of discontinued operations
   
     
19,215
 
          Total current assets
   
765,753
     
960,023
 
Property and equipment
   
4,239,307
     
4,742,051
 
  Less — accumulated depreciation
   
(1,382,975
)
   
(1,323,608
)
     
2,856,332
     
3,418,443
 
Other assets:
               
  Equity investments
   
191,475
     
196,660
 
  Goodwill
   
78,220
     
366,218
 
  Other assets, net
   
79,310
     
125,722
 
   
$
3,971,090
   
$
5,067,066
 
                 
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
               
  Accounts payable
 
$
177,118
   
$
344,807
 
  Accrued liabilities
   
198,876
     
231,679
 
  Income taxes payable
   
108,213
     
 
  Current maturities of long-term debt
   
13,135
     
93,540
 
  Current liabilities of discontinued operations
   
     
2,772
 
          Total current liabilities
   
497,342
     
672,798
 
Long-term debt
   
1,347,395
     
1,933,686
 
Deferred income taxes
   
456,728
     
615,504
 
Decommissioning liabilities
   
177,924
     
194,665
 
Other long-term liabilities
   
10,148
     
81,637
 
          Total liabilities
   
2,489,537
     
3,498,290
 
                 
Convertible preferred stock
   
6,000
     
55,000
 
                 
Commitments and contingencies
               
Shareholders’ equity:
               
  Common stock, no par, 240,000 shares authorized,      
     104,378 and 91,972 shares issued, respectively
   
905,455
     
806,905
 
  Retained earnings
   
575,504
     
417,940
 
  Accumulated other comprehensive loss
   
(26,931
)
   
(33,696
)
          Total controlling interest shareholders’ equity
   
1,454,028
     
1,191,149
 
  Noncontrolling interests
   
21,525
     
322,627
 
          Total equity
   
1,475,553
     
1,513,776
 
   
$
3,971,090
   
$
5,067,066
 
                 
 
The accompanying notes are an integral part of these condensed consolidated financial statements.


 
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
 (in thousands, except per share amounts)
 
     
Three Months Ended
 
     
September 30,
 
     
2009
     
2008
 
                 
Net revenues:
               
  Contracting services                                                                         
 
$
152,310
   
$
473,117
 
  Oil and gas                                                                         
   
63,715
     
134,619
 
     
216,025
     
607,736
 
                 
Cost of sales:
               
  Contracting services                                                                         
   
127,402
     
318,451
 
  Oil and gas                                                                         
   
86,006
     
90,205
 
     
213,408
     
408,656
 
                 
     Gross profit                                                                         
   
2,617
     
199,080
 
                 
Gain on oil and gas derivative commodity contracts
   
4,598
     
2,705
 
Gain on sale of assets, net                                                                         
   
     
(23
)
Selling and administrative expenses                                                                         
   
(21,884
)
   
(48,539
)
Income (loss) from operations                                                                         
   
(14,669
)
   
153,223
 
  Equity in earnings of investments                                                                         
   
13,385
     
8,751
 
  Gain on sale of Cal Dive common  stock                                                                         
   
17,901
     
 
  Net interest expense and other                                                                         
   
(10,306
)
   
(28,298
)
Income before income taxes                                                                         
   
6,311
     
133,676
 
  Provision for income taxes                                                                         
   
(4,468
)
   
(54,165
)
Income from continuing operations                                                                         
   
1,843
     
79,511
 
  Income (loss) from discontinued operations, net of tax
   
3,021
     
(93
)
Net income, including noncontrolling interests
   
4,864
     
79,418
 
  Net income applicable to noncontrolling interests
   
(844
)
   
(19,240
)
Net income applicable to Helix                                                                         
   
4,020
     
60,178
 
  Preferred stock dividends                                                                         
   
(125
)
   
(881
)
Net income applicable to Helix common shareholders
 
$
3,895
   
$
59,297
 
                 
Basic earnings per share of common stock:
               
  Continuing operations                                                                         
 
$
0.01
   
$
0.65
 
  Discontinued operations                                                                         
   
0.03
     
 
  Net income per common share                                                                         
 
$
0.04
   
$
0.65
 
                 
Diluted earnings per share of common stock:
               
  Continuing operations                                                                         
 
$
0.01
   
$
0.63
 
  Discontinued operations                                                                         
   
0.03
     
 
  Net income per common share                                                                         
 
$
0.04
   
$
0.63
 
                 
Weighted average common shares outstanding:
               
  Basic                                                                         
   
101,282
     
90,725
 
  Diluted                                                                         
   
 101,334
     
94,583
 
                 
 
 
The accompanying notes are an integral part of these condensed consolidated financial statements.


 
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
 (in thousands, except per share amounts)
 
     
Nine Months Ended
 
     
September 30,
 
     
2009
     
2008
 
                 
Net revenues:
               
  Contracting services
 
$
967,751
   
$
1,079,804
 
  Oil and gas
   
313,888
     
499,831
 
     
1,281,639
     
1,579,635
 
                 
Cost of sales:
               
  Contracting services
   
765,602
     
777,206
 
  Oil and gas
   
216,454
     
295,688
 
     
982,056
     
1,072,894
 
                 
     Gross profit
   
299,583
     
506,741
 
                 
Gain on oil and gas derivative commodity contracts
   
83,328
     
2,705
 
Gain on sale of assets, net
   
1,773
     
79,893
 
Selling and administrative expenses
   
(102,609
)
   
(136,953
)
Income from operations
   
282,075
     
452,386
 
  Equity in earnings of investments
   
27,152
     
25,722
 
  Gain on sale of Cal Dive common stock
   
77,343
     
 
  Net interest expense and other
   
(39,969
)
   
(76,914
)
Income before income taxes
   
346,601
     
401,194
 
  Provision for income taxes
   
(126,196
)
   
(151,638
)
Income from continuing operations
   
220,405
     
249,556
 
  Income from discontinued operations, net of tax
   
10,303
     
1,671
 
Net income, including noncontrolling interests
   
230,708
     
251,227
 
  Net income applicable to noncontrolling interests
   
(19,017
)
   
(26,553
)
Net income applicable to Helix
   
211,691
     
224,674
 
  Preferred stock dividends
   
(688
)
   
(2,642
)
  Preferred stock beneficial conversion charges
   
(53,439
)
   
 
Net income applicable to Helix common shareholders
 
$
157,564
   
$
222,032
 
                 
Basic earnings per share of common stock:
               
  Continuing operations
 
$
1.49
   
$
2.40
 
  Discontinued operations
   
0.10
     
0.02
 
  Net income per common share
 
$
1.59
   
$
2.42
 
                 
Diluted earnings per share of common stock:
               
  Continuing operations
 
$
1.38
   
$
2.32
 
  Discontinued operations
   
0.10
     
0.02
 
  Net income per common share
 
$
1.48
   
$
2.34
 
                 
Weighted average common shares outstanding:
               
  Basic
   
97,831
     
90,598
 
  Diluted
   
105,868
     
95,096
 
 
 
The accompanying notes are an integral part of these condensed consolidated financial statements.
 


 
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 (in thousands)
 
     
Nine Months Ended
 
     
September 30,
 
     
2009
     
2008
 
Cash flows from operating activities:
               
  Net income, including noncontrolling interests
 
$
230,708
   
$
251,227
 
  Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities —
               
         Depreciation, depletion and amortization
   
208,870
     
246,870
 
         Asset impairment charges and dry hole expense
   
64,610
     
24,156
 
         Equity in (earnings) losses of investments, net of distributions
   
(222
)
   
2,495
 
         Amortization of deferred financing costs                                                                                 
   
4,095
     
4,163
 
         Income from discontinued operations                                                                                 
   
(10,303
)
   
(1,671
)
         Stock compensation expense                                                                                 
   
9,435
     
17,933
 
         Amortization of debt discount                                                                                 
   
5,878
     
5,508
 
         Deferred income taxes                                                                                 
   
(53,012
)
   
54,925
 
         Excess tax benefit from stock-based compensation
   
2,036
     
(1,142
)
         Gain on sale of assets                                                                                 
   
(1,773
)
   
(79,893
)
         Unrealized (gain) loss on derivative contracts
   
(19,785
)
   
4,045
 
         Gain on sale of  investment in Cal Dive common stock
   
(77,343
)
   
 
         Changes in operating assets and liabilities:
               
            Accounts receivable, net                                                                                 
   
7,215
     
(48,002
)
            Other current assets                                                                                 
   
33,483
     
(4,777
)
            Income tax payable                                                                                 
   
157,931
     
742
 
            Accounts payable and accrued liabilities
   
(46,213
)
   
(78,902
)
            Other noncurrent, net                                                                                 
   
(78,349
)
   
(60,221
)
              Cash provided by operating activities                                                                                 
   
437,261
     
337,456
 
              Cash provided by (used in) discontinued operations
   
(6,089
)
   
1,630
 
                  Net cash provided by operating activities
   
431,172
     
339,086
 
                 
Cash flows from investing activities:
               
  Capital expenditures                                                                                 
   
(306,152
)
   
(728,692
)
  Distributions from equity investments, net                                                                                 
   
4,774
     
4,636
 
  Proceeds from the sale of Cal Dive common stock
   
418,168
     
 
  Reduction in cash from deconsolidation of Cal Dive
   
(112,995
)
   
 
  Proceeds from sales of properties                                                                                 
   
23,238
     
230,261
 
  Other
   
(564
)
   
(1,261
)
              Cash provided by (used in) investing activities
   
26,469
     
(495,056
)
              Cash provided by (used in) discontinued operations
   
20,872
     
(111
)
   Net cash provided by (used in) investing activities
   
47,341
     
(495,167
)
 


 
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 (in thousands)
(Continued)
 
     
Nine Months Ended
 
     
September 30,
 
     
2009
     
2008
 
                 
Cash flows from financing activities:
               
  Repayment of Helix Term Notes                                                                                 
   
(3,245
)
   
(3,245
)
  Borrowings on Helix Revolver                                                                                 
   
     
847,000
 
  Repayments on Helix Revolver                                                                                 
   
(349,500
)
   
(690,000
)
  Repayment of MARAD borrowings                                                                                 
   
(4,214
)
   
(4,014
)
  Borrowings on CDI Revolver                                                                                 
   
100,000
     
61,100
 
  Repayments on CDI Revolver                                                                                 
   
     
(61,100
)
  Repayments on CDI Term Notes                                                                                 
   
(20,000
)
   
(40,000
)
  Deferred financing costs                                                                                 
   
(50
)
   
(1,711
)
  Capital lease payments                                                                                 
   
     
(1,505
)
  Preferred stock dividends paid                                                                                 
   
(625
)
   
(2,642
)
  Repurchase of common stock                                                                                 
   
(10,603
)
   
(3,912
)
  Excess tax benefit from stock-based compensation
   
(2,036
)
   
1,142
 
  Exercise of stock options, net                                                                                 
   
36
     
2,139
 
             Net cash provided by (used in) financing activities
   
(290,237
)
   
103,252
 
                 
Effect of exchange rate changes on cash and cash equivalents
   
(1,383
)
   
(965
)
Net increase (decrease) in cash and cash equivalents
   
186,893
     
(53,794
)
Cash and cash equivalents:
               
  Balance, beginning of year                                                                                 
   
223,613
     
89,555
 
  Balance, end of period                                                                                 
 
$
410,506
   
$
35,761
 
 
The accompanying notes are an integral part of these condensed consolidated financial statements.


HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
 
Note 1 – Basis of Presentation
 
The accompanying condensed consolidated financial statements include the accounts of Helix Energy Solutions Group, Inc. and its majority-owned subsidiaries (collectively, "Helix" or the "Company").  Unless the context indicates otherwise, the terms "we," "us" and "our" in this report refer collectively to Helix and its subsidiaries.  On June 10, 2009, our ownership in Cal Dive International Inc. (“Cal Dive” or “CDI”) was reduced to less than 50%.  Accordingly, we ceased consolidating CDI as of that date and we accounted for our remaining approximate 26% ownership interest under the equity method of accounting through September 23, 2009, at which time we sold substantially all of our remaining ownership interest in Cal Dive (Notes 3 and 4).  All material intercompany accounts and transactions have been eliminated. These condensed consolidated financial statements are unaudited, have been prepared pursuant to instructions for the Quarterly Report on Form 10-Q required to be filed with the Securities and Exchange Commission (“SEC”), and do not include all information and footnotes normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles.
 
The accompanying condensed consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles and are consistent in all material respects with those applied in our Annual Report on Form 10-K for the year ended December 31, 2008 (“2008 Form 10-K”) and those applied in our Current Report on Form 8-K as filed with the Securities and Exchange Commission (“SEC”) on June 16, 2009 (“June 2009 Form 8-K”), which among other things, reflected the effect our  adoption on January 1, 2009 of certain accounting standards that require retrospective application had on our year-end 2008 financial statements.  The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures.  Actual results may differ from our estimates.  Management has reflected all adjustments (which were normal recurring adjustments unless otherwise disclosed herein) that it believes are necessary for a fair presentation of the condensed consolidated balance sheets, results of operations, and cash flows, as applicable.  Operating results for the three month and nine month periods ended September 30, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009.  Our balance sheet as of December 31, 2008 included herein has been derived from the audited balance sheet as of December 31, 2008 included in our June 2009 Form 8-K. These condensed consolidated financial statements should be read in conjunction with the annual consolidated financial statements and notes thereto included in our June 2009 Form 8-K.
 
Certain reclassifications were made to previously reported amounts in the condensed consolidated financial statements and notes thereto to make them consistent with the current presentation format, including the adoption of certain recent accounting pronouncements that require retrospective application (Note 3) and the presentation of a former business unit as discontinued operations (Note 2).  We have conducted our subsequent events review through October 30, 2009, the date our financial statements were filed with the SEC.
 
Note 2 – Company Overview
 
We are an international offshore energy company that provides development solutions and other key life of field contracting services to the energy market as well as to our own oil and gas business unit.  Our Contracting Services segment utilizes our vessels, offshore equipment and proprietary technologies to deliver services that may reduce finding and development costs and encompass the complete lifecycle of an offshore oil and gas field. Our Contracting Services are located primarily in Gulf of Mexico, North Sea, Asia/Pacific and Middle East regions.  Our Oil and Gas segment engages in prospect generation, exploration, development and production activities.  Our oil and gas operations are almost exclusively located in the Gulf of Mexico.
 
 
Contracting Services Operations
We seek to provide services and methodologies which we believe are critical to finding and developing offshore reservoirs and maximizing production economics. Our “life of field” services are segregated into four disciplines: construction, well operations, drilling, and production facilities. We have disaggregated our contracting services operations into three reportable segments in accordance with Financial Accounting Standards Board (“FASB”) Codification Topic No. 280 Segment Reporting: Contracting Services, Production Facilities and Shelf Contracting.  Our Contracting Services business includes subsea construction, well operations, robotics and drilling.  Our Production Facilities business includes our investments in Deepwater Gateway, L.L.C. (“Deepwater Gateway”), Independence Hub, LLC (“Independence Hub”) and Kommandor LLC (“Kommandor”).  In April 2009, Kommandor LLC completed the initial conversion of the Helix Producer I (“HP I”) vessel.  The vessel is currently undergoing further modification to install top side production facilities.   The completed vessel is expected to be ready for service in the first half of 2010, and is currently scheduled to be deployed to our deepwater Phoenix oil and gas field that is being developed in parallel with the planned delivery of the HP I.  We have sold substantially all our remaining ownership interest in CDI (Note 4).  CDI’s operations represented our former Shelf Contracting business, which we deconsolidated on June 10, 2009 (Notes 3 and 4).
 
Oil and Gas Operations
In 1992, we began our oil and gas operations to provide a more efficient solution to offshore abandonment, to expand our off-season asset utilization of our contracting services business and to achieve incremental returns to our contracting services. Since 1992, we have evolved this business model to include not only mature oil and gas properties but also proved and unproved reserves yet to be developed and explored. This has led to the assembly of services that allows us to create value at key points in the life of a reservoir from exploration through development, life of field management and operating through abandonment.
 
Discontinued Operations
In April 2009, we sold Helix Energy Limited (“HEL”), our former reservoir technology consulting business, to a subsidiary of Baker Hughes Incorporated for $25 million.  As a result of the sale of HEL, which entity’s operations were conducted by its wholly owned subsidiary, Helix RDS Limited (“Helix RDS”), we have presented the results of Helix RDS as discontinued operations in the accompanying condensed consolidated financial statements.  HEL and Helix RDS were previously components of our Contracting Services segment.   We recognized an $8.8 million gain on the sale of HEL.   The operating results of HEL and Helix RDS were immaterial to our results for all periods presented.
 
Economic Outlook
The economic downturn and weakness in the equity and credit capital markets continue to contribute to the uncertainty regarding the outlook of the global economy.  This uncertainty, coupled with the negative near-term outlook for global demand for oil and natural gas, resulted in commodity price declines over the second half of 2008, with significant declines occurring in the fourth quarter of 2008.  Natural gas prices continued to decline in 2009 with prices reaching near decade low levels.  A decline in oil and natural gas prices negatively impacts our operating results and cash flows.   Our stock price also significantly declined over the second half of 2008.  The declines in our stock price and the prices of oil and natural gas were considered in association with our required annual impairment assessment of goodwill and properties at year end 2008, which resulted in significant impairment charges (see Note 2 of our 2008 Form 10-K). Our stock price decreased further in the first quarter of 2009 resulting in our assessment of our goodwill amounts as of March 31, 2009; however, no further impairments were required.  Our stock price subsequently increased and no further impairment of goodwill was required through September 30, 2009.  At September 30, 2009 our remaining goodwill totaled $78.2 million, all of which is attributable to our Contracting Services segment.
 
Our Contracting Services segment may also be negatively impacted by low commodity prices as some of our customers, primarily oil and gas companies, have announced their intention to reduce capital spending.  We forecast weaker demand for our contracting services for the remainder of 2009.  With respect to our oil and gas operations, we hedged the price risk for a significant portion of our anticipated oil and gas production for 2009 when we entered into commodity hedges during 2008.  These hedge contracts enable us to minimize our near-term cash flow risks related to declining commodity prices.  Similarly, throughout the nine months ended September 30, 2009, we have entered into a number of financial derivative contracts to hedge a substantial portion of our forecasted production of both oil and natural gas for 2010.  See Note 19 for additional information regarding our oil and gas hedge contracts.
 
 
Note 3 – Recent Accounting Pronouncements
 
We have adopted the fair value accounting standards as contained in FASB Codification Topic No. 280 “Fair Value Measurements and Disclosures.”   These standards among other things, define fair value, establish a consistent framework for measuring fair value and expand disclosure for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis.  The FASB has clarified that fair value is an exit price, representing the amount that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants.  The following is the  three-tier fair value hierarchy established by the FASB, which prioritizes the inputs used in measuring fair value as follows:
 
 
 
Level 1.  Observable inputs such as quoted prices in active markets;
 
 
Level 2.  Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and
 
 
Level 3. Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.
 
Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows:
 
(a)  
Market Approach.  Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.
(b)  
Cost Approach.   Amount that would be required to replace the service capacity of an asset (replacement cost).
(c)  
Income Approach.  Techniques to convert expected future cash flows to a single present amount based on market expectations (including present value techniques, option-pricing and excess earnings models).
 
The following table provides additional information related to assets and liabilities measured at fair value on a recurring basis at September 30, 2009 (in thousands):
 
   
Level 1
   
Level 2
   
Level 3
   
Total
 
Valuation Technique
                           
Assets:
                         
    Oil and gas derivatives
   $     $ 16,711           $ 16,711  
(c)
Foreign currency forwards
          2,077             2,077  
(c)
    Investment in Cal Dive (Note 4)
    4,945                   4,945  
(a)
                                   
Liabilities:
                                 
   Gas swaps and collars
          13,890             13,890  
(c)
   Interest rate swaps                                           
          2,388             2,388  
(c)
     Total                                           
    4,945     $ 2,510           $ 7,455    
 
 
In December 2007, the FASB issued Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB 51. These standards are now included in FASB Codification Topic No. 810 Consolidation.  These standards were enacted to improve the relevance, comparability, and transparency of financial information provided to investors by requiring all entities to report noncontrolling (minority) interests in subsidiaries as equity in the consolidated financial statements.
 
 
8

 
We adopted these standards on January 1, 2009, which are required to be adopted prospectively, except the following provisions were required to  be adopted retrospectively:
 
1.  
Reclassifying noncontrolling interest from the “mezzanine” to equity, separate from the parents’ shareholders’ equity, in the statement of financial position; and
2.  
Recasting consolidated net income to include net income attributable to both the controlling and noncontrolling interests.  That is, retrospectively, the noncontrolling interests’ share of a consolidated subsidiary’s income should not be presented in the income statement as “minority interest.”
 
Effective January 1, 2009, we changed our accounting policy of recognizing a gain or loss upon any future direct sale or issuance of equity by our subsidiaries if the sales price differs from our carrying amount, in which a gain or loss will only be recognized when loss of control of a consolidated subsidiary occurs. See Note 4 for disclosure of stock sales transactions that ultimately resulted in our loss of control of CDI.
 
  On January 1, 2009 we adopted certain financial accounting standards included with FASB Codification Topic No. 815 Derivatives and Hedging. These standards apply to all derivative instruments and related hedged items and require that entities provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions.   Adoption of these standards had no impact on our results of operations, cash flows or financial condition.  See Note 19 below for the required disclosures for our derivative instruments.
 
 Effective January 1, 2009, we adopted accounting standards as required in FASB Codification Topic No. 470-20 Debt with Conversion and Other Options.    These standards  require retrospective application for all periods reported (with the cumulative effect of the change reported in retained earnings as of the beginning of the first period presented).   These standards require the proceeds from the issuance of convertible debt instruments to be allocated between a liability component (issued at a discount) and an equity component. The resulting debt discount is amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. This standard  affects the accounting treatment for our Convertible Senior Notes and increases our interest expense for our past and future reporting periods by recognizing accretion charges on the resulting debt discount.
 
Upon adoption, we recorded a discount of $60.2 million related to our Convertible Senior Notes.  To arrive at this discount amount we estimated the fair value of the liability component of the Convertible Senior Notes as of the date of their issuance (March 30, 2005) using an income approach.  To determine this estimated fair value, we used borrowing rates of similar market transactions involving comparable liabilities at the time of issuance and an expected life of 7.75 years.  In selecting the expected life, we selected the earliest date that the holder could require us to repurchase all or a portion of the Convertible Senior Notes (December 15, 2012).
 
The following table sets forth the effect of retrospective application of the adoption of new accounting standards and the effect on earnings per share (Note 14) and discontinued operations on certain previously reported line items in our accompanying condensed consolidated statements of operations (in thousands, except per share data):
 
   
Three Months Ended
September 30, 2008
 
   
Originally
 Reported
   
As Adjusted
 
             
Net interest expense and other                                                                           
  $ 23,464     $ 28,298  
Provision for Income taxes                                                                           
    54,816       54,165  
Net  income from continuing operations                                                                           
    80,708       79,511  
                 
Earnings per common share from continuing operations – Basic
  $ 0.67     $ 0.65  
Earnings per common share from continuing operations – Diluted
    0.65       0.63  
 
   
Nine Months Ended
September 30, 2008
 
   
Originally
 Reported
   
As Adjusted
 
             
Net interest expense and other                                                                           
  $ 68,178     $ 76,914  
Provision for Income taxes                                                                           
    154,373       151,638  
Net  income from continuing operations                                                                           
    255,019       249,556  
                 
Earnings per common share from continuing operations - Basic
  $ 2.49     $ 2.42  
Earnings per common share from continuing operations – Diluted
    2.40       2.34  
 
On June 30, 2009, we adopted the general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Specifically, FASB Codification Topic No. 855 Subsequent Events sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date.  The adoption of these standards had no impact on  our results, cash flow or financial position as management already followed a similar approach prior to the adoption of this standard.
 
Note 4 – Reduction in Ownership of Cal Dive
 
At December 31, 2008, we owned approximately 57.2% of Cal Dive.   During 2009, as previously noted in Notes 1, 2 and 3,  we engaged in a number of transactions that ultimately resulted in our disposal of substantially all of our remaining ownership in Cal Dive.
 
In January 2009, we sold approximately 13.6 million shares of Cal Dive common stock to Cal Dive for $86 million.  This transaction constituted a single transaction and was not part of any planned set of transactions that would result in us having a noncontrolling interest in Cal Dive, and reduced our ownership in Cal Dive to approximately 51%.  Because we retained control of CDI immediately after the transaction, the loss of approximately $2.9 million on this sale was treated as a reduction of our equity in the accompanying condensed consolidated balance sheet.
 
In June 2009, we sold 22.6 million shares of Cal Dive common stock held by us pursuant to a secondary public offering (“Offering”).  Proceeds from the Offering totaled approximately $182.9 million, net of underwriting fees.  Separately, pursuant to a Stock Repurchase Agreement with Cal Dive, simultaneously with the closing of the Offering, Cal Dive repurchased from us approximately 1.6 million shares of its common stock for net proceeds of $14 million at $8.50 per share, the Offering price. Following the closing of these two transactions, our ownership of Cal Dive common stock was reduced to approximately 26%.
 
 Because these transactions reduced our ownership in Cal Dive to less than 50%, the $59.4 million gain resulting from the sale of these shares is reflected in “Gain on sale of Cal Dive common stock” in the accompanying condensed consolidated statement of operations.  The $59.4 million amount included an approximate $27.1 million gain associated with the re-measurement of our remaining 26% ownership interest in Cal Dive at its fair value on June 10, 2009, the date of the closing of the Offering, which represented the date of deconsolidation.   Since we no longer held a controlling interest in Cal Dive, we ceased consolidating Cal Dive effective June 10, 2009, and subsequently accounted for our remaining ownership interest in Cal Dive under the equity method of accounting until September 23, 2009, as further discussed below.
 
On September 23, 2009, we sold 20.6 million shares of Cal Dive common stock held by us pursuant to a second secondary public offering (“Second Offering”).    On September 24, 2009, the underwriters sold an additional 2.6 million shares of Cal Dive common stock held by us pursuant to their overallotment option under the terms of the Second Offering.   The price for the Second Offering was $10 per share, with resulting proceeds totaling approximately $221.5 million, net of underwriting fees.  We recorded an approximate $17.9 million gain associated with the Second Offering transactions.
 
Following the closing of the Second Offering transactions, we own 0.5 million shares of Cal Dive common stock, representing  less than 1% of the total outstanding shares of Cal Dive.  Accordingly we now classify our remaining interest in Cal Dive as an investment available for sale pursuant to FASB Codification Topic No.320  Investment  - Debt and Equity Securities.  As an investment available for sale, the value of our remaining interest will be marked-to-market at each period end with the corresponding change in value being reported as a component of other comprehensive income (loss) in the accompanying condensed consolidated balance sheet at September 30, 2009 (Note 3).  We intend to sell our remaining shares of Cal Dive common stock over the near term as market conditions warrant.  The value of our remaining investment in Cal Dive decreased by $0.1 million from the closing of the Second Offering to September 30, 2009.
 
Proceeds from our Cal Dive stock sale transaction have been and will continue to be used for general corporate purposes.
 
Note 5 – Insurance Matters
 
In September 2008, we sustained damage to certain of our facilities resulting from Hurricane Ike.  All of our segments were affected by the hurricane; however, the oil and gas segment suffered the substantial majority of our aggregate damages.  While we sustained damage to our own production facilities from Hurricane Ike, the larger issue in terms of our production recovery involved damage to third party pipelines and onshore processing facilities.  The timing of the repairs of these facilities was not subject to our control and some of these third party facilities remain out of service as of October 30, 2009.  Our insurance policy, which covered all of our operated and non-operated producing and non-producing properties, was subject to an approximate $6 million of aggregate deductibles.  We met our aggregate deductible in September 2008.  We record our hurricane-related repair costs as incurred in our oil and gas cost of sales.  We record insurance reimbursements when the realization of the claim for recovery of a loss is deemed probable.
 
In June 2009, we reached a settlement with the underwriters of our insurance policies related to damages from Hurricane Ike.  Insurance proceeds received in the second quarter of 2009 totaled $102.6 million.  Previously, we had received approximately $25.6 million of reimbursements under previously submitted Ike-related insurance claims.  In the second quarter of 2009, we recorded a $43.0 million net reduction  in our cost of sales in the accompanying condensed consolidated statements of operations representing the amount our insurance recoveries exceeded our costs during the second quarter of 2009.    The cost reduction reflected the net proceeds of $102.6 million partially offset by $8.1 million of hurricane-related expenses incurred in the second quarter of 2009 and $51.5 million of hurricane related impairment charges, including $43.8 million of additional estimated asset retirement costs (“ARO”) resulting from additional work performed and/or further evaluation of facilities on properties that were classified as a “total loss” following the storm.
 
We are substantially complete with our hurricane repairs; however we are still incurring costs related to our accrued asset retirement obligations.
 
The following table summarizes the claims and reimbursements by segment that affected our costs of sales accounts under various insurance claims resulting from damages sustained by Hurricane Ike, primarily those claims and reimbursements recently settled under our energy insurance policy (in thousands):


 
   
 
 
Third
Quarter
2009
   
Nine Months Ended
September 30,
2009
   
Since Inception in September 2008
 
                   
Oil and gas:
                 
   Hurricane repair costs                                           
  $ 5,060     $ 25,223     $ 47,774  
   ARO liability adjustments
    -       43,812       48,065  
   Hurricane-related impairments
    -       7,699       37,585  
   Insurance recoveries                                           
    -       (100,874 )     (118,415 )
      Net (reimbursements) costs
  $ 5,060     $ (24,140 )   $ 15,009  
                         
Contracting services:
                       
   Hurricane repair costs                                           
  $ -     $ 776     $ 6,026  
   Insurance recoveries                                           
    (159 )     (2,885 )     (5,022 )
      Net (reimbursements) costs
  $ (159 )     (2,109 )     1,004  
                         
Shelf Contracting:
                       
   Hurricane repair costs                                           
  $ 3     $ 613     $ 4,550  
   Insurance recoveries                                           
    (238 )     (2,849 )     (5,183 )
Net (reimbursements) costs
  $ (235 )   $ (2,236 )     (633 )
                         
Totals:
                       
   Hurricane repair costs                                           
  $ 5,063     $ 26,612     $ 58,350  
   ARO liability adjustments
    -       43,812       48,065  
   Hurricane-related impairments
    -       7,699       37,585  
   Insurance recoveries                                           
    (397 )     (106,608 )     (128,620 )
Net (reimbursements) costs
  $ 4,666     $ (28,485 )   $ 15,380  
 
We renewed our energy and marine insurance for the period July 1, 2009 to June 30, 2010.  However, this insurance renewal did not include wind storm coverage as the premium and deductibles would have been relatively substantial for the underlying coverage provided.  In order to mitigate potential loss with respect to our most significant oil and gas properties from hurricanes in the Gulf of Mexico, we entered into a weather derivative (Catastrophic Bond).   The Catastrophic Bond provides for payments of negotiated amounts should the eye of a Category 3 or greater hurricane pass within certain pre-defined areas encompassing our more prominent oil and gas producing fields.   The premium for this Catastrophic Bond was approximately $13.1 million.   The Catastrophic Bond is not considered a risk management instrument for accounting purposes.   Accordingly, the premium associated with the Catastrophic Bond is not charged to expense on a straight line basis as customary with insurance premiums but rather it is charged to expense on a basis to reflect the Catastrophic Bond’s intrinsic value at the end of the period.  Because our Catastrophic Bond was underwritten to mitigate the risk of hurricanes in the Gulf of Mexico, substantially all of its intrinsic value is for the period associated with “hurricane season” (typically June 1 to November 30) with a substantial majority of the intrinsic value associated with the period July 1, 2009 to September 30, 2009.  As a result, we charged to expense $10.4 million of our $13.1 premium in the third quarter of 2009 and substantially all of the remaining $2.7 million of premium will be charged to expense in the fourth quarter of 2009.    The expense associated with the Catastrophic Bond premium is recorded as a component of lease operating expense for our oil and gas operations.
 

 
 
Note 6 – Details of Certain Accounts (in thousands)
 
Other Current Assets consisted of the following as of September 30, 2009 and December 31, 2008:
 
   
September 30,
   
December 31,
 
   
2009
   
2008
 
             
Other receivables
  $ 10,486     $ 22,977  
Prepaid insurance
    16,335       18,327  
Other prepaids
    12,779       23,956  
Inventory
    26,856       32,195  
Current deferred tax assets
    25,701       3,978  
Hedging assets
    17,830       26,800  
Income tax receivable
          23,485  
Gas imbalance
    7,603       7,550  
Investments available for sale 
    4,945        
Other
    8,011       12,821  
    $ 130,546     $ 172,089  
 
Other Assets, net, consisted of the following as of September 30, 2009 and December 31, 2008:
 
   
September 30,
   
December 31,
 
   
2009
   
2008
 
             
Restricted cash
  $ 35,416     $ 35,402  
Deferred drydock expenses, net
    13,221       38,620  
Deferred financing costs
    25,641       33,431  
Intangible assets with definite lives, net
    842       7,600  
Other
    4,190       10,669  
    $ 79,310     $ 125,722  
 
Accrued Liabilities consisted of the following as of September 30, 2009 and December 31, 2008:
 
   
September 30,
   
December 31,
 
   
2009
   
2008
 
             
Accrued payroll and related benefits
  $ 36,146     $ 46,224  
Royalties payable
    4,153       10,265  
Current decommissioning liability
    73,566       31,116  
Unearned revenue
    7,925       9,353  
Billings in excess of costs
    1,307       13,256  
Accrued interest
    16,942       34,299  
Deposit
    25,542       25,542  
Hedge liability
    9,218       7,687  
Other
    24,077       53,937  
    $ 198,876     $ 231,679  
 
 

 
 
Note 7 – Convertible Preferred Stock
 
In January 2003, we completed the private placement of $25 million of a newly designated class of cumulative convertible stock (Series A-1 Cumulative Convertible Stock, par value $0.01 per share) convertible into 1,666,668 shares of our common stock at $15 per share.  The preferred stock was issued to a private investment firm, Fletcher International, Ltd. (“Fletcher”).  Subsequently on June 2004, Fletcher exercised an existing right to purchase an additional $30 million of cumulative convertible preferred stock (Series A-2 Cumulative Convertible Preferred Stock, par value $0.01 per share) convertible into 1,964,058 shares of our common stock at $15.27 per share.  Pursuant to the agreement governing the preferred stock (the “Fletcher Agreement”), Fletcher was entitled to convert the preferred shares into common stock at any time, and to redeem the preferred shares into common stock at any time after December 31, 2004.  In January 2009, Fletcher issued a redemption notice with respect to all its shares of the Series A-2 Cumulative Convertible Preferred Stock, and, pursuant to such redemption, we issued and delivered 5,938,776 shares of our common stock to Fletcher based on a redemption price of $5.05 per share as determined by the average closing price of our common stock on the three days starting on the third day prior to holder redeeming the shares of Series A-2 Cumulative Preferred Stock.  Accordingly, in the first quarter of 2009 we recognized a $29.3 million charge to reflect the terms of this redemption, which was recorded as a reduction to our net income applicable to common shareholders.  This beneficial conversion charge reflected the value associated with the additional 3,974,718 shares delivered over the original 1,964,058 shares that were contractually required to be issued upon conversion but was limited to the $29.3 million of net proceeds we received from the issuance of the Series A-2 Cumulative Convertible Preferred Stock.
 
The Fletcher Agreement provides that if the volume weighted average price of our common stock on any date is less than a certain minimum price (calculated at $2.767 subsequent to the above described redemption), then our right to pay dividends in our common stock is extinguished, and we are required to deliver a notice to Fletcher that either (1) the conversion price will be reset to such minimum price (in which case Fletcher shall have no further right to cause the redemption of the preferred stock), or (2) in the event Fletcher exercises its redemption rights, we will satisfy our redemption obligations either in cash, or a combination of cash and common stock subject to a maximum number of shares (14,973,814) that can be delivered to Fletcher under the Fletcher Agreement.  On February 25, 2009, the volume weighted average price of our common stock was below the minimum price, and on February 27, 2009 we provided notice to Fletcher that with respect to the Series A-1 Cumulative Convertible Preferred Stock the conversion price is reset to $2.767 as of that date and that Fletcher shall have no further rights to redeem the shares, and we have no further right to pay dividends in common stock. Subsequent to this election, the conversion price is not subject to any further adjustment or reset.  As a result of the reset of the conversion price, Fletcher was entitled to receive an aggregate of 9,035,056 shares in future conversion(s) into our common stock based on the fixed $2.767 conversion price. In the event we elect to settle any future conversion in cash, Fletcher would receive cash in an amount approximately equal to the value of the shares it would receive upon a conversion, which could be substantially greater than the original face amount of the Series A-1 Cumulative Convertible Preferred Stock, and which would result in additional beneficial conversion charges in our statement of operations. Under the existing terms of our Senior Credit Facilities we are not permitted to deliver cash to the holder upon a conversion of the Convertible Preferred Stock.
 
In connection with the reset of the conversion price of the Series A-1 Cumulative Convertible Preferred Stock to $2.767, we were required to recognize a $24.1 million charge to reflect the value associated with the additional 7,368,388 shares that will be required to be delivered upon any future conversion(s) over the 1,666,668 shares that were to be delivered under the original contractual terms.  This $24.1 million charge was recorded as a beneficial conversion charge reducing our net income applicable to common shareholders.  Similar to the beneficial conversion charge associated with the redemption of Series A-2 Cumulative Convertible Preferred Stock, the beneficial conversion charge for the Series A-1 Cumulative Convertible Preferred Stock is limited to the $24.1 million of net proceeds received upon its issuance.
 
 
 
On July 23, 2009 and August 12, 2009, Fletcher provided a notice of conversion informing us of its election to convert 15,000 shares and 4,000 shares, respectively, of the Series A-1 Cumulative Convertible Preferred Stock into 5,421,033 shares and 1,445,608 shares, respectively, of our common stock. In connection with the closing of each conversion we also paid the accrued and unpaid dividends associated with these shares in cash, the amount of which was immaterial at the time of the conversion notice.   The conversions were consummated on July 27, 2009 and August 14, 2009, respectively.  
 
At September 30, 2009, we had 6,000 shares of convertible preferred stock outstanding, which are convertible into 2,168,413 shares of our common stock.  The convertible preferred stock maintains its mezzanine presentation below liabilities but is not included as component of shareholders’ equity, because we may, under certain instances, be required to settle any future conversions in cash.   
 
The common shares issuable in connection with this convertible preferred stock outstanding are included in our diluted earnings per share computations using the “if converted” method based on the applicable conversion price of $2.767 per share, meaning that for almost all future reporting periods in which we have positive earnings and our average stock price exceeds $2.767 per share we will have an assumed conversion of convertible preferred stock and the applicable number of our shares (2,168,413 shares at September 30, 2009) will be included in our diluted shares outstanding amount.  However, our earnings from continuing operations for the three month period ended September 30, 2009 resulted in the assumed conversion of the convertible preferred stock to be anti-dilutive, meaning its assumed conversion would have increased our diluted earnings per share calculation (Note 14).
 
 
Note 8 – Oil and Gas Properties
 
We follow the successful efforts method of accounting for our interests in oil and gas properties. Under the successful efforts method, the costs of successful wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred relating to unsuccessful exploratory wells are expensed in the period in which the drilling is determined to be unsuccessful.
 
Depletion expense is determined on a field-by-field basis using the units-of-production method, with depletion rates for leasehold acquisition costs based on estimated total remaining proved reserves.  Depletion rates for well and related facility costs are based on estimated total remaining proved developed reserves associated with each individual field.  The depletion rates are changed whenever there is an indication of the need for a revision but, at a minimum, are evaluated annually.  Any such revisions are accounted for prospectively as a change in accounting estimate.
 
Litigation and Claims
 
On December 2, 2005, we received an order from the U.S. Department of the Interior Minerals Management Service (“MMS”) that the price threshold for both oil and gas was exceeded for 2004 production and that royalties were due on such production notwithstanding the provisions of the Outer Continental Shelf Deep Water Royalty Relief Act of 2005 (“DWRRA”), which was intended to stimulate exploration and production of oil and natural gas in the deepwater Gulf of Mexico by providing relief from the obligation to pay royalty on certain federal leases up to certain specified production volumes. Our oil and gas leases affected by this dispute are Garden Banks Blocks 667, 668 and 669 (“Gunnison”). On May 2, 2006, the MMS issued another order that superseded the December 2005 order, and claimed that royalties on gas production are due for 2003 in addition to oil and gas production in 2004. The order also seeks interest on all royalties allegedly due. We filed a timely notice of appeal with respect to both the December 2005 Order and the May 2006 Order. We received an additional order from the MMS dated September 30, 2008 stating that the price thresholds for oil and gas were exceeded for 2005, 2006 and 2007 production and that royalties and interest are payable as well as an additional order from the MMS dated August 28, 2009 stating the price thresholds for oil and natural gas were exceeded for 2008 and that royalties and interest are payable. We appealed these orders on the same basis as the previous orders.
 
 
 
Other operators in the Deep Water Gulf of Mexico who have received notices similar to ours sought royalty relief under the DWRRA, including Kerr-McGee, the operator of Gunnison. In March of 2006, Kerr-McGee filed a lawsuit in federal district court challenging the enforceability of price thresholds in certain deepwater Gulf of Mexico leases, including ours. On October 30, 2007, the federal district court in the Kerr-McGee case entered judgment in favor of Kerr-McGee and held that the Department of the Interior exceeded its authority by including the price thresholds in the subject leases.  The government  appealed the district court’s decision.  On January 12, 2009, the United States Court of Appeals for the Fifth Circuit affirmed the decision of the district court in favor of Kerr-McGee, holding that the DWRRA unambiguously provides that royalty suspensions up to certain production volumes established by Congress apply to leases that qualify under the DWRRA.  After the appellate court denied a request by the plaintiff for rehearing, the plaintiff subsequently petitioned the United States Supreme Court for a writ of certiorari for the Supreme Court to review the Fifth Circuit Court’s decision.  In October 2009, the United States Supreme Court announced its decision to deny the plaintiff’s writ of certiorari, concluding the litigation in this dispute.
 
As a result of this dispute, we had been recording reserves for the disputed royalties (and any other royalties that may be claimed for production during 2005, 2006, 2007 and 2008) plus interest at 5% for our portion of the Gunnison related MMS claim.  The result of accruing these reserves since 2005 had reduced our oil and gas revenues.  Following the decision of the United States Court of Appeals for the Fifth Circuit Court, we reversed our previously accrued royalties ($73.5 million) to oil and gas revenues in the first quarter of 2009.  Effective in January 2009, we commenced recognizing oil and natural gas sales revenue associated with this disputed net revenue interest and are no longer accruing any additional royalty reserves as we believed it was remote that we would be liable for such amounts in future.  This belief was confirmed with United States Supreme Court decision to deny the plaintiff’s writ of certiorari in October 2009.
 
Property Sales
 
In the first quarter of 2009, we sold our interest in East Cameron Block 316 for gross proceeds of approximately $18 million.  We recorded an approximate $0.7 million gain from the sale of East Cameron Block 316 which was partially offset by the loss on the sale of the remaining 10% of our interest in the Bass Lite field at Atwater Valley Block 426 in January 2009. In the second quarter we sold three fields for gross proceeds of $0.8 million and resulting in an aggregate gain of $1.2 million, including transfer of the respective field’s asset retirement obligations.
 
In March and April 2008, we sold an aggregate 30% working interest in the Bushwood discoveries (Garden Banks Blocks 463, 506 and 507) and other Outer Continental Shelf oil and gas properties (East Cameron Blocks 371 and 381), in two separate transactions to affiliates of a private independent oil and gas company for total cash consideration of approximately $183.4 million (which included the purchasers’ share of incurred capital expenditures on these fields), and additional potential cash payments of up to $20 million based upon certain field production milestones.  The new co-owners will also pay their pro rata share of all future capital expenditures related to the exploration and development of these fields.  Decommissioning liabilities will be shared on a pro rata share basis between the new co-owners and us.  Proceeds from the sale of these properties were used to pay down our outstanding revolving loans in April 2008.  As a result of these sales, we recognized a pre-tax gain of $91.6 million (of which $30.5 million was recognized in second quarter 2008).
 
In May 2008, we sold all our interests in our onshore proved and unproved oil and gas properties located in the states of Texas, Mississippi, Louisiana, Oklahoma, New Mexico and Wyoming (“Onshore Properties”) to an unrelated investor.  We sold these Onshore Properties for cash proceeds of $47.2 million and recorded a related loss of $11.9 million in the second quarter of 2008.  Included in the cost basis of the Onshore Properties was an $8.1 million allocation of goodwill from our Oil and Gas segment.


 
Exploration and Other
 
As of September 30, 2009, we capitalized approximately $2.9 million of costs associated with ongoing exploration and/or appraisal activities.  Such capitalized costs may be charged against earnings in future periods if management determines that commercial quantities of hydrocarbons have not been discovered or that future appraisal drilling or development activities are not likely to occur.
 
Further, the following table details the components of exploration expense for the three and nine months ended September 30, 2009 and 2008 (in thousands):
 
     
Three Months Ended
     
Nine Months Ended
 
     
September 30,
     
September 30,
 
     
2009
     
2008
     
2009
     
2008
 
Delay rental and geological and geophysical costs
 
$
755
   
$
1,375
   
$
2,288
   
$
4,753
 
Dry hole expense
   
149
     
270
     
575
     
254
 
     Total exploration expense
 
$
904
   
$
1,645
   
$
2,863
   
$
5,007
 
 

    In 2009, we farmed-out our 100% leasehold interests in Green Canyon Block 490 located in the deepwater of the Gulf of Mexico.   Our farmout agreement was structured such that the operator paid 100% of the drilling costs to evaluate the prospective reservoir.  The operator has drilled the well and it was successful in finding commercial quantities of hydrocarbons.  We have elected to participate for a 25 percent working interest in setting production casing and the right to participate in all subsequent operations.  Well completion and development options are being evaluated for the new discovery
 
In the second quarter of 2009, we recorded an aggregate of approximately $63.1 million of impairment charges, which are reflected as a reduction to our cost of sales.  These charges primarily reflect the approximate $51.5 million of impairment-related charges recorded to properties that were severely damaged by Hurricane Ike (Note 5).  Separately, we also recorded $11.5 million of impairment charges to reduce the asset carrying value of four fields following reductions in their estimated proved reserves as evaluated at June 30, 2009.  We recorded an aggregate $1.5 million of additional impairment charges associated with five fields following a comprehensive impairment analysis at September 30, 2009.  Prior to the impairments charges discussed above, the aggregate net book value of the affected fields was $68.9 million.   The impairment charges reduced the fields to their then aggregate net fair value of $4.2  million.  The substantial majority of the impairments were associated with fields to which we had to increase our reclamation obligation estimates.  We have concluded that this valuation is classified with level three of the valuation hierarchy (Note 3).
 
For the nine months ended September 30, 2008 we recorded impairment charges totaling $23.9  million as a component of oil and gas cost of sales in the accompanying condensed statement of operations.  These impairments primarily reflected the $14.6 million of costs associated with the unsuccessful development well on Devil’s Island (Garden Banks Block 344) and $6.7 million related to our Tiger deepwater field that was damaged by Hurricane Ike.
 
The following table describes the changes in our asset retirement obligations (both long term and current) since December 31, 2008 (in thousands):
 
Asset retirement obligation at December 31, 2008
 
$
225,781
 
Liability transferred  to third party during the period
   
(3,506
)
Liability settled during the period                                                                               
   
(45,848
)
Revision in estimated cash flows                                                                               
   
63,462
a
Accretion expense (included in depreciation and amortization)
   
11,601
 
Asset retirement obligations at December 31,                                                                               
 
$
251,490
 
 
a.  
Increase in estimates primary associated with properties damaged during Hurricane Ike (Note 5).


Note 9 – Statement of Cash Flow Information
 
We define cash and cash equivalents as cash and all highly liquid financial instruments with original maturities of less than three months.  As of September 30, 2009 and December 31, 2008, our restricted cash totaled $35.4 million and is included in other assets, net.  All of our restricted cash relates to funds required to be escrowed to cover the future decommissioning liabilities associated with the South Marsh Island Block 130, which we acquired in 2002.  We have fully satisfied the escrow requirements under this agreement and may use the restricted cash for future decommissioning of the related field.
 
The following table provides supplemental cash flow information for the nine months ended September 30, 2009 and 2008 (in thousands):
 
     
Nine Months Ended
 
     
September 30,
 
     
2009
     
2008
 
                 
Interest paid, net of capitalized interest
 
$
51,696
   
$
46,649
 
Income taxes paid
 
$
57,412
   
$
97,059
 
 
Non-cash investing activities for the nine months ended September 30, 2009 included $63.6 million of accruals for capital expenditures.  Non-cash investing activities for the nine months ended September 30, 2008 totaled $28.6 million.  The accruals have been reflected in the condensed consolidated balance sheet as an increase in property and equipment and accounts payable.
 
Note 10 – Equity Investments
    
As of September 30, 2009, we have the following material investments, both of which are included within our Production Facilities segment and are accounted for under the equity method of accounting:
 
·  
Deepwater Gateway, L.L.C.  In June 2002, we, along with Enterprise Products Partners L.P. (”Enterprise”), formed Deepwater Gateway, L.L.C. (“Deepwater Gateway”) (each with a 50% interest) to design, construct, install, own and operate a tension leg platform (“TLP”) production hub primarily for Anadarko Petroleum Corporation's Marco Polo field in the Deepwater Gulf of Mexico. Our investment in Deepwater Gateway totaled $104.3 million and $106.3 million as of September 30, 2009 and December 31, 2008, respectively (including capitalized interest of $1.5 million and $1.6 million at September 30, 2009 and December 31, 2008, respectively).  Our equity in the earnings of Deepwater Gateway totaled $1.0 million and $2.5 million for the three month and nine month periods ended September 30, 2009 compared with $4.1 million and $14.4 million during the respective prior year periods.  Distributions from Deepwater Gateway, net to our interest, totaled $4.5 million for the nine months ended September 30, 2009.
 
·  
Independence Hub, LLC.  In December 2004, we acquired a 20% interest in Independence Hub, LLC (“Independence”), an affiliate of Enterprise.  Independence owns the "Independence Hub" platform located in Mississippi Canyon Block 920 in a water depth of 8,000 feet.  First production began in July 2007.  Our investment in Independence was $87.2 million and $90.2 million as of September 30, 2009 and December 31, 2008, respectively (including capitalized interest of $5.6 million and $5.9 million at September 30, 2009 and December 31, 2008, respectively).  Our equity in the earnings of Independence Hub totaled $5.3 million and $17.2 million for the three month and nine month periods ended September 30, 2009 compared with $4.8 million and  $13.9 million during the respective prior year periods.  Distributions from Independence, net to our interest, totaled $20.0 million for the nine months ended September 30, 2009.
 
Also included within our Production Facilities segment is our investment in Kommandor LLC, the results of which we consolidate in our financial statements.
 
 
 
 
As disclosed in Note 4, in June 2009 we sold shares of Cal Dive common stock that reduced our ownership in Cal Dive to less than 50%. Accordingly we deconsolidated Cal Dive from our financial statements effective June 11, 2009.  We accounted for our remaining approximate 26% ownership interest in Cal Dive using the equity method until September 23, 2009, at which time we sold substantially all our remaining ownership interest in Cal Dive.   The fair value of our  remaining investment in Cal Dive was approximately $4.9 million at September 30, 2009 (Note 3).
 
Note 11 – Long-Term Debt
 
Scheduled maturities of long-term debt and capital lease obligations outstanding as of September 30, 2009 were as follows (in thousands):
 
     
Helix Term Loan
   
Helix Revolving Loans
     
Senior Unsecured Notes
   
Convertible Senior Notes
   
MARAD Debt
   
Other(1)
   
Total
 
                                               
Less than one year
 
$
4,326
 
$
   
$
 
$
 
$
4,424
 
$
4,385
 
$
13,135
 
One to two years
   
4,326
   
     
   
   
4,645
   
   
8,971
 
Two to three years
   
4,326
   
     
   
   
4,877
   
   
9,203
 
Three to four years
   
402,870
   
     
   
   
5,120
   
   
407,990
 
Four to five years
   
   
     
   
   
5,376
   
   
5,376
 
Over five years
   
   
     
550,000
   
300,000
   
94,793
   
   
944,793
 
Total debt
   
415,848
   
     
550,000
   
300,000
   
119,235
   
4,385
   
1,389,468
 
Current maturities
   
(4,326
)
 
     
   
   
(4,424
)
 
(4,385
)
 
(13,135
)
Long-term debt, less
   current maturities
 
$
411,522
 
$
   
$
550,000
 
$
300,000
 
$
114,811
 
 
$
 
 
$
1,376,333
 
Unamortized debt discount (2)
   
   
     
   
(28,938
)
 
   
   
(28,938
)
Long-term debt
 
$
411,522
 
$
   
$
550,000
 
$
271,062
 
$
114,811
 
 
$
 
 
$
1,347,395
 
                                               
Fair Value (3), (4), (5)
 
$
399,734
 
$
   
$
552,750
 
$
265,725
 
$
123,325
 
$
4,385
 
$
1,345,919
 
                                               
(1)  
Reflects loan provided by Kommandor RØMØ to Kommandor LLC.
(2)  
Reflects debt discount resulting from adoption of APB 14-1 on January 1, 2009.  The notes will increase to $300 million face amount through accretion of non-cash interest charges through 2012.
(3)  
The fair value of the term loan, senior unsecured notes and convertible notes were based on quoted market prices as of September 30, 2009 using level 1 inputs as defined in FASB Codification Topic No 280 using the market approach (Note 3).
(4)  
The fair value of the MARAD debt was determined using a third-party evaluation of the remaining average life and outstanding principal balance of the MARAD indebtedness as compared to other government guaranteed obligations in the market with similar terms.   The fair value of the MARAD debt was estimated using level 2 inputs using the cost approach (Note 3).
(5)  
The loan notes representing other in the table approximate fair value.
 
We had unsecured letters of credit outstanding at September 30, 2009 totaling approximately $49.7 million. These letters of credit primarily guarantee various contract bids, contractual performance, insurance activities and shipyard commitments.  The following table details our interest expense and capitalized interest for the three and nine months ended September 30, 2009 and 2008 (in thousands):
 
     
Three Months Ended
     
Nine Months Ended
 
     
September 30,
     
September 30,
 
     
2009
     
2008
     
2009
     
2008
 
                                 
Interest expense
 
$
23,582
   
$
32,453
   
$
81,094
   
$
100,877
 
Interest income
   
(282
)
   
(593
)
   
(694
)
   
(2,149
)
Capitalized interest
   
(16,050
)
   
(10,045
)
   
(35,540
)
   
(30,618
)
     Interest expense, net
 
$
7,250
   
$
21,815
   
$
44,860
   
$
68,110
 
 
 
 
 
Included below is a summary of certain components of our indebtedness.  At September 30, 2009 and December 31, 2008, we were in compliance with all debt covenants.  For additional information regarding our debt see Note 11 of our 2008 Form 10-K.
 
Senior Unsecured Notes
 
In December 2007, we issued $550 million of 9.5% Senior Unsecured Notes due January 15, 2016 (“Senior Unsecured Notes”).  Interest on the Senior Unsecured Notes is payable semiannually in arrears on each January 15 and July 15, commencing July 15, 2008.  The Senior Unsecured Notes are fully and unconditionally guaranteed by substantially all of our existing restricted domestic subsidiaries, except for Cal Dive I-Title XI, Inc.  In addition, any future restricted domestic subsidiaries that guarantee any of our indebtedness and/or our restricted subsidiaries’ indebtedness are required to guarantee the Senior Unsecured Notes.   Cal Dive I -Title XI, Inc. and our foreign subsidiaries are not guarantors.  CDI and its subsidiaries were not guarantors of the Senior Unsecured Notes prior to deconsolidation of CDI in June 2009 (Note 4).  We used the proceeds from the Senior Unsecured Notes to repay outstanding indebtedness under our senior secured credit facilities (see below).
 
Senior Credit Facilities
 
In July 2006, we entered into a credit agreement (the “Senior Credit Facilities”) under which we borrowed $835 million in a term loan (the “Term Loan”) and were initially able to borrow up to $300 million (the “Revolving Loans”) under a revolving credit facility (the “Revolving Credit Facility”).  The proceeds from the Term Loan were used to fund the cash portion of the Remington acquisition (see Note 4 of our 2008 Form 10-K).  Total borrowing capacity under the Revolving Credit Facility at September 30, 2009 totaled $420 million.  The full amount of the Revolving Credit Facility may be used for issuances of letters of credit.  At September 30, 2009 we had no amounts drawn on the Revolving Credit Facility and our availability under the Facility totaled $370.3 million net of $49.7 million of unsecured letters of credit issued.
 
The Term Loan currently bears interest either at the one-, three- or six-month LIBOR at our current election plus a 2.00% margin.  Our average interest rate on the Term Loan for the nine months ended September 30, 2009 and 2008 was approximately 2.9% and 5.4%, respectively, including the effects of our interest rate swaps (see below).  The Revolving Loans bear interest based on one-, three- or six-month LIBOR rates or on Base Rates at our current election plus an applicable margin as discussed below.  Margins on the Revolving Loans will fluctuate in relation to the consolidated leverage ratio as provided in the Credit Agreement.  The average interest rate on the Revolving Loans was approximately 3.4% through date of their repayment in the second quarter of 2009.   We have no amounts outstanding under the revolver at September 30, 2009.
 
In October 2009, we amended our Senior Credit Facility.  Among other things, the amendment:
 
·  
extends the maturity of the revolving line of credit under the Credit Agreement from July 1, 2011 to November 30, 2012;
 
·  
permits the disposition of certain oil and gas properties without a limit as to value, provided that we use 60% of the proceeds from such sales to make certain mandatory prepayments of the existing term loan (40% of the proceeds can be reinvested into collateral);
 
·  
relaxes limitations on our right to dispose of the Caesar vessel, by permitting the disposition of the Caesar provided that we use 60% of the proceeds from such sale to make certain mandatory prepayments of the existing term loans and permits us to contribute the Caesar to a joint venture or similar arrangement (40% of the proceeds can be reinvested into collateral);
 
·  
increases the maximum amount of all investments permitted in subsidiaries that are neither loan parties nor whose equity interests are pledged from $100 million to $150 million;
 
·  
increases the amount of restricted payments in the form of stock repurchases or redemptions such that we are permitted to repurchase or redeem up to $50 million  of our common stock in the event we prepay an aggregate amount on the term loan greater than $200 million (up to $25 million if we prepay at least $100 million);
 
 
 
 
·  
amends the applicable margins under the revolving lines of credit under the Credit Agreement (ranging from 3.0% to 4.0% on LIBOR loans and 2.0% to 3.0% on Base Rate loans); and
 
·  
increases the accordion feature that allows Helix to increase the revolving line of credit by $100 million (to $550 million) at any time in future periods with lender approval.
 
Simultaneously with entering into the amendment, we  completed an increase in the revolving line of credit  from $420 million to $435 million (decreasing to $407 million from July 1, 2011 through November 30, 2012) utilizing the accordion feature included in the Credit Agreement through an increase in the commitment from an existing lender.
 
Convertible Senior Notes
 
In March 2005, we issued $300 million of our Convertible Senior Notes at 100% of the principal amount to certain qualified institutional buyers.  The Convertible Senior Notes are convertible into cash and, if applicable, shares of our common stock based on the specified conversion rate, subject to adjustment.
 
The Convertible Senior Notes can be converted prior to the stated maturity (March 2025) under certain triggering events specified in the indenture governing the Convertible Senior Notes.  To the extent we do not have long-term financing secured to cover the conversion, the Convertible Senior Notes would be classified as a current liability in the accompanying balance sheet.  No conversion triggers were met during the nine month period ended September 30, 2009. The first dates for early redemption of the Convertible Senior Notes are in December 2012, with the holders of the Convertible Senior Notes being able to put them to us on December 15, 2012 and our being able to call the Convertible Senior Notes at any time after December 20, 2012 (see Note 11 of our 2008 Form 10-K).   As a result of adopting FSP APB 14-1 (Note 3), the effective interest is 6.6%.
 
Approximately 0.6 million  shares underlying the Convertible Senior Notes were included in the calculation of diluted earnings per share for the nine month period ended September 30, 2008 because our average share price for the period was above the conversion price of approximately $32.14 per share.  Our average share price was below the $32.14 per share conversion price for the three month period ended September 30, 2008 and the three and nine month periods ended September 30, 2009.  As a result of our share price being lower than the $32.14 per share conversion price for these periods there are no shares included in our diluted earnings per share calculation associated with the assumed conversion of our Convertible Senior Notes.  In the event our average share price exceeds the conversion price, there would be a premium, payable in shares of common stock, in addition to the principal amount, which is paid in cash, and such shares would be issued on conversion.  The Convertible Senior Notes are convertible into a maximum 13,303,770 shares of our common stock.
 
MARAD Debt
 
This U.S. government guaranteed financing ("MARAD Debt") is pursuant to Title XI of the Merchant Marine Act of 1936 which is administered by the Maritime Administration and was used to finance the  construction of the Q4000. The MARAD Debt is payable in equal semi-annual installments which began in August 2002 and matures 25 years from such date. The MARAD Debt is collateralized by the Q4000, with us guaranteeing 50% of the debt, and initially bore interest at a floating rate which approximated AAA Commercial Paper yields plus 20 basis points.  As provided for in the MARAD Debt agreements, in September 2005, we fixed the interest rate on the debt through the issuance of a 4.93% fixed-rate note with the same maturity date (February 2027).
 
In accordance with the Senior Unsecured Notes, amended Senior Credit Facilities, Convertible Senior Notes and the MARAD Debt agreements, we are required to comply with certain covenants and restrictions, including the maintenance of minimum net worth, working capital and debt-to-equity requirements.  As of
 
 
 
 
September 30, 2009, we were in compliance with these covenants and restrictions.  The Senior Unsecured Notes and Senior Credit Facilities contain provisions that limit our ability to incur certain types of additional indebtedness.
 
Other
Deferred financing costs of $25.6 million and $33.4 million are included in other assets, net as of September 30, 2009 and December 31, 2008, respectively, and are being amortized over the life of the respective loan agreements.
 
Note 12 – Income Taxes
 
The effective tax rate for the three month and nine month periods ended September 30, 2009 was 70.8% and 36.4%, respectively, compared with 40.5% and 37.8% for the three month and nine month periods ended September 30, 2008.  The effective tax rate for the three months ended September 30, 2009 increased as a result of decreased profitability  and the reduced benefit derived from the Internal Revenue Code §199 manufacturing deduction as it primarily related to oil and gas production.  The decrease in the effective rate for the nine month period ended September 30, 2009 resulted from  the deconsolidation of Cal Dive.  This benefit was partially offset by  reduced Internal Revenue Code §199 manufacturing deductions as it primarily related to oil and gas production.
     
We believe our recorded assets and liabilities are reasonable; however, tax laws and regulations are subject to interpretation and tax litigation is inherently uncertain; therefore our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.
 
 
Note 13 – Comprehensive Income (Loss)
 
The components of total comprehensive income (loss) for the three and nine month periods ended September 30, 2009 and 2008 were as follows (in thousands):
 
     
Three Months Ended
     
Nine Months Ended
 
     
September 30,
     
September 30,
 
     
2009
     
2008
     
2009
     
2008
 
                                 
Net income, including noncontrolling interests
 
$
4,864
   
$
79,418
   
$
230,708
   
$
251,227
 
Other comprehensive income (loss), net of tax
                               
     Foreign currency translation gain
   
(3,343
)
   
(26,322
)
   
23,689
     
(23,929
)
     Unrealized loss on hedges, net
   
(2,883
)
   
14,073
     
(16,221
)
   
7,769
 
     Unrealized loss on investment available for sale
   
(130
)
   
     
(130
)
   
 
Total other accumulated comprehensive income (loss)
   
(6,356
)
   
(12,249
)
   
7,338
     
(16,160
)
Less: Other accumulated comprehensive loss applicable to noncontrolling interest
   
(844
)
   
(19,347
)
   
(19,590
)
   
(26,811
)
Total other accumulated comprehensive loss applicable to Helix
 
 
(7,200
)
 
 
(31,596
)
 
 
(12,252
)
 
(42,971
)
Total other comprehensive income (loss) applicable to Helix    $ (2,336  )    $ 47,882      218,456      $ 208,256   
 
The components of accumulated other comprehensive loss was as follows (in thousands):
 
   
September 30,
 
December 31,
   
2009
 
2008
                 
Cumulative foreign currency translation adjustment
 
$
(19,278
)
 
$
(42,874
)
Unrealized gain (loss) on hedges, net
   
(7,523
)
   
9,178
 
Unrealized loss on investment available for sale
   
(130
)
   
 
     Accumulated other comprehensive loss
 
$
(26,931
)
 
$
(33,696
)
 


 
Note 14 – Earnings Per Share
 
On January 1, 2009, we adopted FSP No. EITF 03-06-1, “Determining Whether Instruments Granted in Share Based Payment Transactions Are Participating Securities.”  We have shares of restricted stock issued and outstanding, some of which remain subject to certain vesting requirements.   Holders of such shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our outstanding common stock and are thus considered participating securities.   Under FSP 03-06-1, the undistributed earnings for each period are allocated based on the contractual participation rights of both the common shareholders and holders of any participating securities as if earnings for the respective periods had been distributed.  Because both the liquidation and dividend rights are identical, the undistributed earnings are allocated on a proportionate basis.  Under FSP 03-06-1, we are required to compute EPS amounts under the two class method.  We have revised the prior period EPS amounts to reflect the current year adoption of FSP 03-06-1 (see table below).
 
Basic earnings per share ("EPS") is computed by dividing the net income available to common shareholders by the weighted average shares of outstanding common stock.  The calculation of diluted EPS is similar to basic EPS, except that the denominator includes dilutive common stock equivalents and the income included in the numerator excludes the effects of the impact of dilutive common stock equivalents, if any.  The computation of basic and diluted EPS amounts for the three month and nine month periods ended September 30, 2009 and 2008 are as follows (in thousands):
 
     
Three Months Ended
     
Three Months Ended
 
     
September 30, 2009
     
September 30, 2008
 
     
Income
     
Shares
     
Income
     
Shares
 
Basic:
                               
Net income applicable to common shareholders
 
$
3,895
           
$
59,297
         
Less: Undistributed net income allocable to participating securities
   
(53
)
           
(724
)
       
Undistributed net income applicable to common shareholders
   
3,842
             
58,573
         
(Income) loss from discontinued operations
   
(3,021
)
           
93
         
Add: Undistributed net income from discontinued operations allocable to participating securities
   
41
             
(1
)
       
Income per common share – continuing operations
 
$
862
     
101,282
   
$
58,665
     
90,725
 
 
 
     
Three Months Ended
September 30, 2009
     
Three Months Ended
September 30, 2008
 
             
     
Income
     
Shares
     
Income
     
Shares
 
Diluted:
                               
Net  income per common share –
continuing operations – Basic                                                      
 
$
862
     
101,282
   
$
58,665
     
90,725
 
Effect of dilutive securities:
                               
Stock options
   
     
52
     
     
227
 
Undistributed earnings reallocated to participating securities
   
     
     
29
     
 
Convertible Senior Notes
   
     
     
     
 
Convertible preferred stock (a)
   
     
     
881
     
3,631
 
Income  per common share ─
continuing operations
   
862
             
59,575
         
Income (loss) per common share ─ discontinued operations
   
3,021
             
(93
)
       
Net income  per common share
 
$
3,883
     
101,334
   
$
59,482
     
94,583
 
                                 
 
(a)  
The 2009 period excludes approximately 4.4 million equivalent common  shares related to the assumed conversion of convertible preferred stock because such assumed conversion would be anti-dilutive (Note 7).

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