10-K 1 h54292e10vk.htm FORM 10-K - ANNUAL REPORT e10vk
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­ ­
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
Form 10-K
 
 
 
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2007
 
Commission file number: 0-51582
 
 
 
 
Hercules Offshore, Inc.
(Exact name of registrant as specified in its charter)
 
 
 
 
     
Delaware
  56-2542838
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)
     
9 Greenway Plaza, Suite 2200
Houston, Texas
(Address of principal executive offices)
  77046
(Zip Code)
 
Registrant’s telephone number, including area code:
(713) 350-5100
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of Each Class
 
Name of Exchange on Which Registered
 
Common Stock, $0.01 par value per share
  NASDAQ Global Select Market
Rights to Purchase Preferred Stock
  NASDAQ Global Select Market
 
Securities registered pursuant to Section 12(g) of the Act:
None
 
 
 
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 of the Act.  Yes o     No  þ
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the 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 þ     No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  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. (Check one):
 
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o
(Do not check if a smaller reporting company)
  Smaller Reporting Company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o     No þ
 
The aggregate market value of the registrant’s common stock held by non-affiliates as of June 30, 2007, based on the closing price on the Nasdaq Global Select Market on such date, was approximately $936.6 million. (As of such date, the registrant’s directors and executive officers and LR Hercules Holdings, LP and its affiliates were considered affiliates of the registrant for this purpose.)
 
As of February 20, 2008, there were 88,860,523 shares of the registrant’s common stock, par value $0.01 per share, outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the registrant’s definitive proxy statement for the Annual Meeting of Stockholders to be held on April 23, 2008 are incorporated by reference into Part III of this report.
 


 

 
TABLE OF CONTENTS
 
             
        Page
 
  Business     3  
  Risk Factors     14  
  Unresolved Staff Comments     27  
  Properties     27  
  Legal Proceedings     27  
  Submission of Matters to a Vote of Security Holders     29  
 
  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     30  
  Selected Financial Data     31  
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     32  
    Forward-Looking Statements     51  
  Quantitative and Qualitative Disclosures About Market Risk     52  
  Financial Statements and Supplementary Data     54  
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     90  
  Controls and Procedures     90  
  Other Information     90  
 
  Directors, Executive Officers and Corporate Governance     90  
  Executive Compensation     91  
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     91  
  Certain Relationships and Related Transactions, and Director Independence     91  
  Principal Accountant Fees and Services     91  
 
  Exhibits and Financial Statement Schedules     91  
 Executive Employment Agreement - Terrell L. Carr
 Schedule of Executive Officer and Director Compensation Arrangements
 Subsidiaries of Hercules
 Consent of Ernst & Young LLP
 Consent of Grant Thornton LLP
 Certification of CEO Pursuant to Section 302
 Certification of CFO Pursuant to Section 302
 Certification of CEO & CFO Pursuant to Section 906


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PART I
 
Item 1.   Business
 
In this Annual Report on Form 10-K, we refer to Hercules Offshore, Inc. and its subsidiaries as “we,” the “Company” or “Hercules Offshore,” unless the context clearly indicates otherwise. Hercules Offshore, Inc. is a Delaware corporation formed in July 2004, with its principal executive offices located at 9 Greenway Plaza, Suite 2200, Houston, Texas 77046. Hercules Offshore’s telephone number at such address is (713) 350-5100 and our Internet address is www.herculesoffshore.com.
 
Overview
 
We provide shallow-water drilling and marine services to the oil and natural gas exploration and production industry in the U.S. Gulf of Mexico and internationally. We provide these services to major integrated energy companies, independent oil and natural gas operators and national oil companies.
 
In July 2007, we furthered our strategic growth initiative by completing the acquisition of TODCO for total consideration of approximately $2,397.8 million, consisting of $925.8 million in cash and 56.6 million shares of common stock. TODCO, a provider of contract drilling and marine services, owned and operated 24 jackup rigs, 27 barge rigs, three submersible rigs, nine land rigs, one platform rig and a fleet of marine support vessels. The TODCO acquisition positioned us as a leading shallow-water drilling provider as well as expanded our international presence and diversified our fleet. In December 2007, we sold the nine land rigs for proceeds of $107.0 million.
 
We historically reported our business activities in four business segments, Domestic Contract Drilling Services, International Contract Drilling Services, Domestic Marine Services and International Marine Services. In connection with the acquisition of TODCO, we conducted a review of our segments. Our historical operating divisions have been combined with the businesses of TODCO and now operate as six divisions: (1) Domestic Offshore, (2) International Offshore, (3) Inland, (4) Domestic Liftboats, (5) International Liftboats and (6) Other. Domestic Offshore includes our legacy Domestic Contract Drilling Services business and TODCO’s domestic offshore rigs operating in the U.S. Gulf of Mexico, while International Offshore includes our legacy International Contract Drilling Services and TODCO’s offshore rigs operating internationally. Inland includes the former TODCO U.S. inland barge business. Domestic Liftboats includes our legacy Domestic Marine Services business, while International Liftboats includes our legacy International Marine Services business. Our Other segment includes Delta Towing and, prior to the December 2007 divestiture, the activities of our land rigs. The following describes our operations for each reporting segment:
 
Domestic Offshore — operates 24 jackup rigs and three submersible rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 85 to 250 feet.
 
International Offshore — operates nine jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. We have one jackup rig working offshore in each of the following international locations: Qatar, India, Angola, Cameroon and Trinidad. This segment operates two jackup rigs and one platform rig in Mexico. In addition, this segment has one jackup rig currently undergoing reactivation in Southeast Asia and one jackup rig currently undergoing contract preparation work and customer acceptance in India.
 
Inland — operates a fleet of 12 conventional and 15 posted barge rigs that operate inland in marshes, rivers, lakes and shallow bay or coastal waterways along the U.S. Gulf Coast.
 
Domestic Liftboats — operates 47 liftboats in the U.S. Gulf of Mexico.
 
International Liftboats — operates 18 liftboats offshore West Africa, including five liftboats owned by a third party and one undergoing refurbishment.
 
Other — our Delta Towing business operates a fleet of 33 inland tugs, 17 offshore tugs, 34 crew boats, 45 deck barges, 17 shale barges and four spud barges along and in the U.S. Gulf of Mexico. Our land rig operations, which were sold in December 2007, included one land rig in Trinidad, two land rigs in the United States and six land rigs in Venezuela.


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Our Fleet
 
Jackup Drilling Rigs
 
Jackup rigs are mobile, self-elevating drilling platforms equipped with legs that can be lowered to the ocean floor until a foundation is established to support the drilling platform. Once a foundation is established, the drilling platform is jacked further up the legs so that the platform is above the highest expected waves. The rig hull includes the drilling rig, jackup system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, helicopter landing deck and other related equipment.
 
Jackup rig legs may operate independently or have a lower hull referred to as a “mat” attached to the lower portion of the legs in order to provide a more stable foundation in soft bottom areas, similar to those encountered in certain of the shallow-water areas of the U.S. Gulf of Mexico. Mat rigs generally are able to more quickly position themselves on the worksite and more easily move on and off location than independent leg rigs. Twenty-six of our jackup rigs are mat-supported and seven are independent leg rigs.
 
Our rigs are used primarily for exploration and development drilling in shallow waters. Twenty-two of our rigs have a cantilever design that permits the drilling platform to be extended out from the hull to perform drilling or workover operations over some types of preexisting platforms or structures. Eleven rigs have a slot-type design, which requires drilling operations to take place through a slot in the hull. Slot-type rigs are usually used for exploratory drilling rather than development drilling, in that their configuration makes them difficult to position over existing platforms or structures. Historically, jackup rigs with a cantilever design have maintained higher levels of utilization than rigs with a slot-type design.
 
As of February 20, 2008, 17 of our jackup rigs were operating under contracts ranging in duration from well-to-well to three years, at an average contract dayrate of approximately $78,816. In the following table, “ILS” means an independent leg slot-type jackup rig, “MC” means a mat-supported cantilevered jackup rig, “ILC” means an independent leg cantilevered jackup rig and “MS” means a mat-supported slot-type jackup rig.
 
The following table contains information regarding our jackup rig fleet as of February 20, 2008.
 
                                         
            Maximum/Minimum
           
        Year
  Water Depth
  Rated Drilling
       
Rig Name
  Type   Built   Rating   Depth(a)   Location  
Status(b)
            (Feet)   (Feet)        
 
Hercules 85
    ILS       1982       85/9       20,000     U.S. GOM   Stacked Ready
Hercules 101
    MC       1980       100/20       20,000     U.S. GOM   Stacked Ready
Hercules 110
    MC       1981       100/20       20,000     Trinidad   Contracted
Hercules 120
    MC       1958       120/22       18,000     U.S. GOM   Contracted
Hercules 150
    ILC       1979       150/10       20,000     U.S. GOM   Stacked Ready
Hercules 152
    MC       1980       150/22       20,000     U.S. GOM   Contracted
Hercules 153
    MC       1980       150/22       25,000     U.S. GOM   Warm Stacked
Hercules 155
    ILC       1980       150/15       20,000     U.S. GOM   Cold Stacked
Hercules 156
    ILC       1983       150/14       20,000     Cameroon   Contracted
Hercules 170
    ILC       1981       170/16       16,000     Qatar   Contracted
Hercules 173
    MC       1971       173/22       15,000     U.S. GOM   Contracted
Hercules 185
    ILC       1982       120/20       20,000     Angola   Contracted
Hercules 191
    MS       1978       160/20       20,000     U.S. GOM   Cold Stacked
Hercules 200
    MC       1979       200/23       20,000     U.S. GOM   Contracted
Hercules 201
    MC       1981       200/23       20,000     U.S. GOM   Contracted
Hercules 202
    MC       1981       200/23       20,000     U.S. GOM   Stacked Ready
Hercules 203
    MC       1982       200/23       20,000     U.S. GOM   Shipyard
Hercules 204
    MC       1981       200/23       20,000     U.S. GOM   Contracted
Hercules 205
    MC       1979       200/23       20,000     Mexico   Contracted
Hercules 206
    MC       1980       200/23       20,000     Mexico   Contracted
Hercules 207
    MC       1981       200/23       20,000     U.S. GOM   Contracted
Hercules 208(c)
    MC       1980       200/22       20,000     Malaysia   Shipyard/Contracted
Hercules 211
    MC       1980       200/23       18,000 (d)   U.S. GOM   Contracted


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            Maximum/Minimum
           
        Year
  Water Depth
  Rated Drilling
       
Rig Name
  Type   Built   Rating   Depth(a)   Location  
Status(b)
            (Feet)   (Feet)        
 
Hercules 250
    MS       1974       250/24       20,000     U.S. GOM   Warm Stacked
Hercules 251
    MS       1978       250/24       20,000     U.S. GOM   Stacked Ready
Hercules 252
    MS       1978       250/24       20,000     U.S. GOM   Contracted
Hercules 253
    MS       1982       250/24       20,000     U.S. GOM   Contracted
Hercules 254
    MS       1977       250/24       20,000     U.S. GOM   Cold Stacked
Hercules 255
    MS       1977       250/24       20,000     U.S. GOM   Cold Stacked
Hercules 256
    MS       1977       250/24       20,000     U.S. GOM   Cold Stacked
Hercules 257
    MS       1979       250/24       20,000     U.S. GOM   Stacked Ready
Hercules 258
    MS       1979       250/24       20,000     India   Contracted
Hercules 260
    ILC       1979       250/12       20,000     India   Shipyard/Contracted
 
 
(a) Rated drilling depth means drilling depth stated by the manufacturer of the rig. Depending on deck space and other factors, a rig may not have the actual capacity to drill at the rated drilling depth.
 
(b) Rigs designated as “Contracted” are under contract while rigs described as “Stacked Ready” are not under contract but generally are ready for service. Rigs described as “Warm Stacked” may have a reduced number of crew, but only require a full crew to be ready for service. Rigs described as “Cold Stacked” are not actively marketed, normally require the hiring of an entire crew and require a maintenance review and refurbishment before they can function as a drilling rig. Rigs described as “Shipyard” are undergoing maintenance, repairs, or upgrades and may or may not be actively marketed depending on the length of stay in the shipyard.
 
(c) This rig is currently unable to operate in the U.S. Gulf of Mexico due to regulatory restrictions.
 
(d) Rated workover depth. Hercules 211 is currently configured for workover activity, which includes maintenance and repair or modification of wells that have already been drilled and completed to enhance or resume the well’s production.
 
Other Drilling Rigs
 
A submersible rig is a mobile drilling platform that is towed to the well site where it is submerged by flooding its lower hull tanks until it rests on the sea floor, with the upper hull above the water surface. After completion of the drilling operation, the rig is refloated by pumping the water out of the lower hull, so that it can be towed to another location. Submersible rigs typically operate in water depths of 14 to 85 feet. Our three submersible rigs are suitable for deep gas drilling.
 
A platform drilling rig is placed on a production platform and is similar to a modular land rig. The production platform’s crane is capable of lifting the modularized rig crane that subsequently sets the rig modules. The assembled rig has all the drilling, housing and support facilities necessary for drilling multiple production wells. Most platform drilling rig contracts are for multiple wells and extended periods of time on the same platform. Once work has been completed on a particular platform, the rig can be redeployed to another platform for further work. We have one platform drilling rig. In the following table, “Sub” means a submersible rig and “Plat” means a platform drilling rig. The following table contains information regarding our other drilling rig fleet as of February 20, 2008.
 
                                         
            Maximum/Minimum
           
        Year
  Water Depth
  Rated Drilling
       
Rig Name
  Type   Built   Rating   Depth(a)   Location  
Status(b)
            (Feet)   (Feet)        
 
Hercules 75
    Sub       1983       85/14       25,000     U.S. GOM   Warm Stacked
Hercules 77
    Sub       1982       85/14       30,000     U.S. GOM   Warm Stacked
Hercules 78
    Sub       1985       85/14       30,000     U.S. GOM   Warm Stacked
Platform 3
    Plat       1993       N/A       25,000     Mexico   Contracted

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(a) Rated drilling depth means drilling depth stated by the manufacturer of the rig. Depending on deck space and other factors, a rig may not have the actual capacity to drill at the rated drilling depth.
 
(b) Rigs designated as “Contracted” are under contract while rigs described as “Warm Stacked” may have a reduced number of crew, but only require a full crew to be ready for service.
 
Barge Drilling Rigs
 
Barge drilling rigs are mobile drilling platforms that are submersible and are built to work in seven to 20 feet of water. They are towed by tugboats to the drill site with the derrick lying down. The lower hull is then submerged by flooding compartments until it rests on the river or sea floor. The derrick is then raised and drilling operations are conducted with the barge resting on the bottom. Our barge drilling fleet consists of 27 conventional and posted barge rigs. A posted barge is identical to a conventional barge except that the hull and superstructure are separated by 10 to 14 foot columns, which increases the water depth capabilities of the rig. Most of our barge drilling rigs are suitable for deep gas drilling.
 
The following table contains information regarding our barge drilling rig fleet as of February 20, 2008.
 
                                             
        Year
  Horsepower
  Rated Drilling
       
Rig Name
  Type   Built   Rating   Depth(a)   Location  
Status(b)
                (Feet)        
 
1
    Conv.       1980       2,000       20,000       U.S. GOM     Stacked Ready
7
    Posted       1978       2,000       25,000       U.S. GOM     Cold Stacked
9
    Posted       1981       2,000       25,000       U.S. GOM     Contracted
10
    Posted       1981       2,000       25,000       U.S. GOM     Cold Stacked
11
    Conv.       1982       3,000       30,000       U.S. GOM     Contracted
15
    Conv.       1981       2,000       25,000       U.S. GOM     Contracted
17
    Posted       1981       3,000       30,000       U.S. GOM     Contracted
19
    Conv.       1974       1,000       14,000       U.S. GOM     Stacked Ready
20(c)
    Conv.       1968       1,000       14,000       U.S. GOM     Cold Stacked
21
    Conv.       1979       1,600       15,000       U.S. GOM     Cold Stacked
23
    Conv.       1995       1,000       14,000       U.S. GOM     Cold Stacked
27
    Posted       1979       3,000       30,000       U.S. GOM     Contracted
28
    Conv.       1980       3,000       30,000       U.S. GOM     Warm Stacked
29
    Conv.       1981       3,000       30,000       U.S. GOM     Contracted
30
    Conv.       1981       3,000       30,000       U.S. GOM     Cold Stacked
31
    Conv.       1982       3,000       30,000       U.S. GOM     Cold Stacked
32
    Conv.       1982       3,000       30,000       U.S. GOM     Cold Stacked
41
    Posted       1981       3,000       30,000       U.S. GOM     Contracted
46
    Posted       1979       3,000       30,000       U.S. GOM     Contracted
47
    Posted       1982       3,000       30,000       U.S. GOM     Cold Stacked
48
    Posted       1982       3,000       30,000       U.S. GOM     Shipyard
49
    Posted       1980       3,000       30,000       U.S. GOM     Shipyard
52
    Posted       1981       2,000       25,000       U.S. GOM     Contracted
55
    Posted       1981       3,000       30,000       U.S. GOM     Stacked Ready
57
    Posted       1975       2,000       25,000       U.S. GOM     Contracted
61
    Posted       1978       3,000       30,000       U.S. GOM     Cold Stacked
64
    Posted       1979       3,000       30,000       U.S. GOM     Contracted
 
 
(a) Rated drilling depth means drilling depth stated by the manufacturer of the rig. Depending on deck space and other factors, a rig may not have the actual capacity to drill at the rated drilling depth.


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(b) Rigs designated as “Contracted” are under contract while rigs described as “Stacked Ready” are not under contract but generally are ready for service. Rigs described as “Warm Stacked” may have a reduced number of crew, but only require a full crew to be ready for service. Rigs described as “Cold Stacked” are not actively marketed, normally require the hiring of an entire crew and require a maintenance review and refurbishment before they can function as a drilling rig. Rigs described as “Shipyard” are undergoing maintenance, repairs, or upgrades and may or may not be actively marketed depending on the length of stay in the shipyard.
 
(c) In 2003, this barge was severely damaged by fire. This rig is no longer operating and will require substantial refurbishment to return to service.
 
Liftboats
 
Our liftboats are self-propelled, self-elevating vessels with a large open deck space, which provides a versatile, mobile and stable platform to support a broad range of offshore maintenance and construction services throughout the life of an oil or natural gas well. Once a liftboat is in position, typically adjacent to an offshore production platform or well, third-party service providers perform:
 
  •  production platform construction, inspection, maintenance and removal;
 
  •  well intervention and workover;
 
  •  well plug and abandonment; and
 
  •  pipeline installation and maintenance.
 
Unlike larger and more costly alternatives, such as jackup rigs or construction barges, our liftboats are self-propelled and can quickly reposition at a worksite or move to another location without third-party assistance. Our liftboats are ideal working platforms to support platform and pipeline inspection and maintenance tasks because of their ability to maneuver efficiently and support multiple activities at different working heights. Diving operations may also be performed from our liftboats in connection with underwater inspections and repair. In addition, our liftboats provide an effective platform from which to perform well-servicing activities such as mechanical wireline, electrical wireline and coiled tubing operations. Technological advances, such as coiled tubing, allow more well-servicing procedures to be conducted from liftboats. Moreover, during both platform construction and removal, smaller platform components can be installed and removed more efficiently and at a lower cost using a liftboat crane and liftboat-based personnel than with a specialized construction barge or jackup rig.
 
The length of the legs is the principal measure of capability for a liftboat, as it determines the maximum water depth in which the liftboat can operate. The U.S. Coast Guard restricts the operation of liftboats to water depths less than 180 feet, so boats with longer leg lengths are useful primarily on taller platforms. Ten of our liftboats in the U.S. Gulf of Mexico have leg lengths of 190 feet or greater, which allows us to service approximately 83% of the approximately 4,000 existing production platforms in the U.S. Gulf of Mexico. Liftboats are typically moved to a port during severe weather to avoid the winds and waves they would be exposed to in open water.
 
As of February 20, 2008, we owned 47 liftboats operating in the U.S. Gulf of Mexico and 13 liftboats operating in West Africa. In addition, we operated five liftboats owned by a third party in West Africa. The following table contains information regarding the liftboats we operate as of February 20, 2008.
 
                                             
    Year
  Leg
  Deck
  Maximum
      Gross
Liftboat Name(1)
  Built   Length   Area   Deck Load   Location   Tonnage
        (Feet)   (Square feet)   (Pounds)        
 
Whale Shark
    2005       260       8,170       729,000     U.S. GOM     99  
Tigershark
    2001       230       5,300       1,000,000     U.S. GOM     469  
Kingfish
    1996       229       5,000       500,000     U.S. GOM     188  
Man-O-War
    1996       229       5,000       500,000     U.S. GOM     188  
Wahoo
    1981       215       4,525       500,000     U.S. GOM     491  


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    Year
  Leg
  Deck
  Maximum
      Gross
Liftboat Name(1)
  Built   Length   Area   Deck Load   Location   Tonnage
        (Feet)   (Square feet)   (Pounds)        
 
Blue Shark
    1981       215       3,800       400,000     Nigeria     1,182  
Amberjack
    1981       205       3,800       500,000     U.S. GOM     417  
Bullshark
    1998       200       7,000       1,000,000     U.S. GOM     859  
Creole Fish
    2001       200       5,000       798,000     U.S. GOM     192  
Cutlassfish
    2006       200       5,000       798,000     U.S. GOM     183  
Black Jack
    1997       200       4,000       480,000     Nigeria     777  
Swordfish
    2000       190       4,000       700,000     U.S. GOM     189  
Mako
    2003       175       5,074       654,000     U.S. GOM     168  
Leatherjack
    1998       175       3,215       575,850     U.S. GOM     168  
Oilfish
    1996       170       3,200       590,000     Nigeria     495  
Manta Ray
    1981       150       2,400       200,000     U.S. GOM     194  
Seabass
    1983       150       2,600       200,000     U.S. GOM     186  
F.J. Leleux(2)
    1981       150       2,600       200,000     Nigeria     407  
Black Marlin
    1984       150       2,600       200,000     Nigeria     407  
Hammerhead
    1980       145       1,648       150,000     U.S. GOM     178  
Pilotfish
    1990       145       2,400       175,000     Nigeria     292  
Rudderfish
    1991       145       3,000       100,000     Nigeria     309  
Blue Runner
    1980       140       3,400       300,000     U.S. GOM     174  
Starfish
    1978       140       2,266       150,000     U.S. GOM     99  
Rainbow Runner
    1981       140       3,400       300,000     U.S. GOM     174  
Pompano
    1981       130       1,864       100,000     U.S. GOM     196  
Sandshark
    1982       130       1,940       150,000     U.S. GOM     196  
Stingray
    1979       130       2,266       150,000     U.S. GOM     99  
Albacore
    1985       130       1,764       150,000     U.S. GOM     171  
Moray
    1980       130       1,824       130,000     U.S. GOM     178  
Skipfish
    1985       130       1,116       110,000     U.S. GOM     91  
Sailfish
    1982       130       1,764       137,500     U.S. GOM     179  
Mahi Mahi
    1980       130       1,710       142,000     U.S. GOM     99  
Triggerfish
    2001       130       2,400       150,000     U.S. GOM     195  
Scamp
    1984       130       2,400       150,000     Nigeria     195  
Rockfish
    1981       125       1,728       150,000     U.S. GOM     192  
Gar
    1978       120       2,100       150,000     U.S. GOM     98  
Grouper
    1979       120       2,100       150,000     U.S. GOM     97  
Sea Robin
    1984       120       1,507       110,000     U.S. GOM     98  
Tilapia
    1976       120       1,280       110,000     U.S. GOM     97  
Charlie Cobb(2)
    1980       120       2,000       100,000     Nigeria     229  
Durwood Speed(2)
    1979       120       2,000       100,000     Nigeria     210  
James Choat(2)
    1980       120       2,000       100,000     Nigeria     210  
Solefish
    1978       120       2,000       100,000     Nigeria     229  
Tigerfish
    1980       120       2,000       100,000     Nigeria     210  
Zoal Albrecht(2)
    1982       120       2,000       100,000     Nigeria     213  
Barracuda
    1979       105       1,648       110,000     U.S. GOM     93  
Carp
    1978       105       1,648       110,000     U.S. GOM     98  

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    Year
  Leg
  Deck
  Maximum
      Gross
Liftboat Name(1)
  Built   Length   Area   Deck Load   Location   Tonnage
        (Feet)   (Square feet)   (Pounds)        
 
Cobia
    1978       105       1,648       110,000     U.S. GOM     94  
Dolphin
    1980       105       1,648       110,000     U.S. GOM     97  
Herring
    1979       105       1,648       110,000     U.S. GOM     97  
Marlin
    1979       105       1,648       110,000     U.S. GOM     97  
Corina
    1974       105       953       100,000     U.S. GOM     98  
Pike
    1980       105       1,360       130,000     U.S. GOM     92  
Remora
    1976       105       1,179       100,000     U.S. GOM     94  
Wolffish
    1977       105       1,044       100,000     U.S. GOM     99  
Seabream
    1980       105       1,140       100,000     U.S. GOM     92  
Sea Trout
    1978       105       1,500       100,000     U.S. GOM     97  
Tarpon
    1979       105       1,648       110,000     U.S. GOM     97  
Palometa
    1972       105       780       100,000     U.S. GOM     99  
Jackfish
    1978       105       1,648       110,000     U.S. GOM     99  
Bonefish
    1978       105       1,344       90,000     Nigeria     97  
Croaker
    1976       105       1,344       72,000     Nigeria     82  
Gemfish
    1978       105       2,000       100,000     Nigeria     223  
Tapertail
    1979       105       1,392       110,000     Nigeria     100  
 
 
(1) The Black Jack, which we acquired in June 2007 and is undergoing refurbishment, is expected to be available by April 2008. The Pike is currently cold-stacked. All other liftboats are either available or operating.
 
(2) We operate these vessels; however, they are owned by a third party.
 
Competition
 
The shallow-water businesses in which we operate are highly competitive. Domestic drilling and liftboat contracts are traditionally short term in nature whereas international drilling and liftboat contracts are longer-term in nature. The contracts are typically awarded on a competitive bid basis. Pricing is often the primary factor in determining which qualified contractor is awarded a job, although technical capability of service and equipment, unit availability, unit location, safety record and crew quality may also be considered. Many of our competitors in the shallow-water business have greater financial and other resources than we have and may be better able to make technological improvements to existing equipment or replace equipment that becomes obsolete.
 
Customers
 
Our customers primarily include major integrated energy companies, independent oil and natural gas operators and national oil companies. Chevron Corporation accounted for 21% and 35% of our consolidated revenues for the years ended December 31, 2007 and 2006. Chevron and Bois d’Arc Energy accounted for 31% and 12%, respectively, of our consolidated revenues for the year ended December 31, 2005. No other customer accounted for more than 10% of our consolidated revenues in any period.
 
Contracts
 
Our contracts to provide services are individually negotiated and vary in their terms and provisions. In general, dayrate drilling contracts provide for payment on a dayrate basis, with higher rates while the unit is operating and lower rates for periods of mobilization or when operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other factors.

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A dayrate drilling contract generally extends over a period of time covering the drilling of a single well or group of wells or covering a stated term. These contracts typically can be terminated by the customer under various circumstances such as the loss or destruction of the drilling unit or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment or due to events beyond the control of either party. In addition, customers generally have the right to terminate our contracts with little or no prior notice, and without penalty. The contract term in some instances may be extended by the customers exercising options for the drilling of additional wells or for an additional term, or by exercising a right of first refusal. To date, most of our contracts in the U.S. Gulf of Mexico have been on a short-term basis of less than six months. Our contracts in international locations have been longer-term, with contract terms of up to three years. For contracts over six months in term we may have the right to pass through certain cost escalations.
 
A liftboat contract generally is based on a flat dayrate for the vessel and crew. Our liftboat dayrates are determined by prevailing market rates, vessel availability and historical rates paid by the specific customer. Under most of our liftboat contracts, we receive a variable rate for reimbursement of costs such as catering, fuel, oil, rental equipment, crane overtime and other items. Liftboat contracts in the U.S. Gulf of Mexico generally are for shorter terms than are drilling contracts. However, most of our liftboat contracts in West Africa have initial contract terms of two years plus a renewal option, with a few others for shorter terms similar to the U.S. Gulf of Mexico contracts.
 
On larger contracts, particularly outside the United States, we may be required to arrange for the issuance of a variety of bank guarantees, performance bonds or letters of credit. The issuance of such guarantees may be a condition of the bidding process imposed by our customers for work outside the United States. The customer would have the right to call on the guarantee, bond or letter of credit in the event we default in the performance of the services. The guarantees, bonds and letters of credit would typically expire after we complete the services.
 
Contract Backlog
 
The following table reflects the amount of our contract backlog by year as of February 20, 2008. Backlog is indicative of the full contractual dayrate. The amount of actual revenue earned and the actual periods during which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors including shipyard and maintenance projects, other downtime and other factors that result in lower applicable dayrates than the full contractual operating dayrate, as well as the ability of our customers to terminate contracts under certain circumstances. Our contract backlog is calculated by multiplying the contracted operating dayrate by the number of days remaining in the firm contract period, excluding revenues for mobilization, demobilization and contract preparation.
 
                                                 
    For the years ending December 31,  
    Total     2008     2009     2010     2011     Thereafter  
    (in thousands)  
 
Domestic Offshore
  $ 46,172     $ 46,172     $     $     $     $  
International Offshore
    570,395       213,759       181,071       134,975       40,590        
Inland
    19,660       19,660                          
                                                 
Total
  $ 636,227     $ 279,591     $ 181,071     $ 134,975     $ 40,590     $  
                                                 
 
Employees
 
As of December 31, 2007, we had approximately 3,300 employees. We require skilled personnel to operate and provide technical services and support for our rigs, barges and liftboats. As a result, we conduct extensive personnel recruiting, training and safety programs. As of December 31, 2007, certain of our employees in West Africa and Venezuela were working under collective bargaining agreements. Additionally, efforts have been made from time to time to unionize portions of the offshore workforce in the U.S. Gulf of Mexico. We believe that our employee relations are good.


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Insurance
 
We maintain insurance coverage that includes coverage for physical damage, third party liability, workers’ compensation and employers’ liability, general liability, vessel pollution and other coverages.
 
In July 2007, we completed the renewal of all of our key insurance policies. Our primary marine package provides for hull and machinery coverage for our rigs and liftboats up to a scheduled value for each asset. The maximum coverage for these assets is $2.6 billion; however, coverage for U.S. Gulf of Mexico named windstorm damage is subject to an annual aggregate limit on liability of $150.0 million. The policies are subject to deductibles, self-insured retentions and other conditions. Deductibles for events that are not U.S. Gulf of Mexico named windstorm events are 10% of insured values per occurrence for drilling rigs, and range from $0.3 million to $1.0 million per occurrence for liftboats, depending on the insured value of the particular vessel. The deductibles for drilling rigs and liftboats in a U.S. Gulf of Mexico named windstorm event are the greater of $10.0 million or the applicable deductible for each U.S. Gulf of Mexico named windstorm. We are self-insured for 10% above the deductibles for removal of wreck, sue and labor, collision, protection and indemnity general liability and hull and physical damage policies. The protection and indemnity coverage under the primary marine package has a $5.0 million limit per occurrence with excess liability coverage up to $200.0 million. Vessel pollution is covered under a Water Quality Insurance Syndicate policy. In addition to the marine package, we have separate policies providing coverage for onshore general liability, employer’s liability, auto liability and non-owned aircraft liability, with customary deductibles and coverage. We intend to renew certain of our insurance policies in the first half of 2008 and we do not expect significant increases to insurance premiums and fees for coverage of our operations, assets and personnel base.
 
Regulation
 
Our operations are affected in varying degrees by governmental laws and regulations. Our industry is dependent on demand for services from the oil and natural gas industry and, accordingly, is also affected by changing tax and other laws relating to the energy business generally. In the United States, we are also subject to the jurisdiction of the U.S. Coast Guard, the National Transportation Safety Board and the U.S. Customs and Border Protection Service, as well as private industry organizations such as the American Bureau of Shipping. The Coast Guard and the National Transportation Safety Board set safety standards and are authorized to investigate vessel accidents and recommend improved safety standards, and the U.S. Customs Service is authorized to inspect vessels at will. Coast Guard regulations also require annual inspections and periodic drydock inspections or special examinations of our vessels.
 
The shorelines and shallow water areas of the U.S. Gulf of Mexico are ecologically sensitive. Heightened environmental concerns in these areas have led to higher drilling costs and a more difficult and lengthy well permitting process and, in general, have adversely affected drilling decisions of oil and natural gas companies. In the United States, regulations applicable to our operations include regulations that require us to obtain and maintain specified permits or governmental approvals, control the discharge of materials into the environment, require removal and cleanup of materials that may harm the environment or otherwise relate to the protection of the environment. For example, as an operator of mobile offshore units in navigable U.S. waters and some offshore areas, we may be liable for damages and costs incurred in connection with oil spills or other unauthorized discharges of chemicals or wastes resulting from or related to those operations. Laws and regulations protecting the environment have become more stringent and may in some cases impose strict liability, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. Some of these laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts which were in compliance with all applicable laws at the time they were performed. The application of these requirements or the adoption of new or more stringent requirements could have a material adverse effect on our financial condition and results of operations.
 
The U.S. Federal Water Pollution Control Act of 1972, commonly referred to as the Clean Water Act, prohibits the discharge of pollutants into the navigable waters of the United States without a permit. The regulations implementing the Clean Water Act require permits to be obtained by an operator before specified


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exploration activities occur. Offshore facilities must also prepare plans addressing spill prevention control and countermeasures. Challenges arising largely out of foreign invasive species contained in discharges of ballast water resulted in a 2006 court order that vacated, as of September 30, 2008, an exemption from Clean Water Act discharge permit requirements for discharges incidental to normal operation of a vessel. This decision may result in imposition of permit or other requirements on the discharges of ballast water and other vessel wastewaters. In addition to this federal development, some states have begun regulating ballast water discharges. Violations of monitoring, reporting and permitting requirements can result in the imposition of civil and criminal penalties. Because we do not yet know what ballast water requirements will be imposed, we cannot estimate the potential financial impact at this time. However, we believe that any financial impacts resulting from the vacation of the permitting exemption and the implementation of federal and possible state regulation of ballast water discharges will not be material.
 
The U.S. Oil Pollution Act of 1990 (“OPA”) and related regulations impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills. Few defenses exist to the liability imposed by OPA, and the liability could be substantial. Failure to comply with ongoing requirements or inadequate cooperation in the event of a spill could subject a responsible party to civil or criminal enforcement action. OPA also requires owners and operators of all vessels over 300 gross tons to establish and maintain with the U.S. Coast Guard evidence of financial responsibility sufficient to meet their potential liabilities under OPA. The 2006 amendments to OPA require evidence of financial responsibility for a vessel over 300 gross tons in the amount the greater of $950 per gross ton or $800,000. Under OPA, an owner or operator of a fleet of vessels is required only to demonstrate evidence of financial responsibility in an amount sufficient to cover the vessel in the fleet having the greatest maximum liability under OPA. Vessel owners and operators may evidence their financial responsibility by showing proof of insurance, surety bond, self-insurance or guarantee. We have obtained the necessary OPA financial assurance certifications for each of our vessels subject to such requirements.
 
The U.S. Outer Continental Shelf Lands Act authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the outer continental shelf. Included among these are regulations that require the preparation of spill contingency plans and establish air quality standards for certain pollutants, including particulate matter, volatile organic compounds, sulfur dioxide, carbon monoxide and nitrogen oxides. Specific design and operational standards may apply to outer continental shelf vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations related to the environment issued pursuant to the Outer Continental Shelf Lands Act can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and canceling leases. Such enforcement liabilities can result from either governmental or citizen prosecution.
 
The U.S. Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the “Superfund” law, imposes liability without regard to fault or the legality of the original conduct on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a facility where a release occurred, the owner or operator of a vessel from which there is a release, and companies that disposed or arranged for the disposal of the hazardous substances found at a particular site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the cost of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Prior owners and operators are also subject to liability under CERCLA. It is also not uncommon for third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
 
In recent years, a variety of initiatives intended to enhance vessel security were adopted to address terrorism risks, including the U.S. Coast Guard regulations implementing the Maritime Transportation and Security Act of 2002. These regulations required, among other things, the development of vessel security plans and on-board installation of automatic information systems, or AIS, to enhance vessel-to-vessel and vessel-to-shore communications. We believe that our vessels are in substantial compliance with all vessel security regulations.


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Some operations are conducted in the U.S. domestic trade, which is governed by the coastwise laws of the United States. The U.S. coastwise laws reserve marine transportation, including liftboat services, between points in the United States to vessels built in and documented under the laws of the United States and owned and manned by U.S. citizens. Generally, an entity is deemed a U.S. citizen for these purposes so long as:
 
  •  it is organized under the laws of the United States or a state;
 
  •  each of its president or other chief executive officer and the chairman of its board of directors is a U.S. citizen;
 
  •  no more than a minority of the number of its directors necessary to constitute a quorum for the transaction of business are non-U.S. citizens; and
 
  •  at least 75% of the interest and voting power in the corporation is held by U.S. citizens free of any trust, fiduciary arrangement or other agreement, arrangement or understanding whereby voting power may be exercised directly or indirectly by non-U.S. citizens.
 
Because we could lose our privilege of operating our liftboats in the U.S. coastwise trade if non-U.S. citizens were to own or control in excess of 25% of our outstanding interests, our certificate of incorporation restricts foreign ownership and control of our common stock to not more than 20% of our outstanding interests. Two of our liftboats rely on an exemption from coastwise laws in order to operate in the U.S. Gulf of Mexico. If these liftboats were to lose this exemption, we would be unable to use them in the U.S. Gulf of Mexico and would be forced to seek opportunities for them in international locations.
 
The United States is one of approximately 165 member countries to the International Maritime Organization (“IMO”), a specialized agency of the United Nations that is responsible for developing measures to improve the safety and security of international shipping and to prevent marine pollution from ships. Among the various international conventions negotiated by the IMO is the International Convention for the Prevention of Pollution from Ships (“MARPOL”). MARPOL imposes environmental standards on the shipping industry relating to oil spills, management of garbage, the handling and disposal of noxious liquids, harmful substances in packaged forms, sewage and air emissions.
 
Annex VI to MARPOL sets limits on sulfur dioxide and nitrogen oxide emissions from ship exhausts and prohibits deliberate emissions of ozone depleting substances. Annex VI also imposes a global cap on the sulfur content of fuel oil and allows for specialized areas to be established internationally with more stringent controls on sulfur emissions. For vessels over 400 gross tons, platforms and drilling rigs, Annex VI imposes various survey and certification requirements. For this purpose, gross tonnage is based on the International Tonnage Certificate for the vessel, which may vary from the standard U.S. gross tonnage for the vessel reflected in our liftboat table above. The United States has not yet ratified Annex VI. Any vessels we operate internationally are, however, subject to the requirements of Annex VI in those countries that have implemented its provisions. We believe the rigs we currently offer for international projects are generally exempt from the more costly compliance requirements of Annex VI and the liftboats we currently offer for international projects are generally exempt from or otherwise substantially comply with those requirements. Accordingly, we do not anticipate incurring significant costs to comply with Annex VI in the near term. If the United States does elect to ratify Annex VI in the future, we could be required to incur potentially significant costs to bring certain of our vessels into compliance with these requirements.
 
Our non-U.S. operations are subject to other laws and regulations in countries in which we operate, including laws and regulations relating to the importation of and operation of rigs and liftboats, currency conversions and repatriation, oil and natural gas exploration and development, environmental protection, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of rigs, liftboats and other equipment. Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and natural gas and other aspects of the oil and natural gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and natural


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gas companies and may continue to do so. Operations in less developed countries can be subject to legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.
 
Although significant capital expenditures may be required to comply with these governmental laws and regulations, such compliance has not materially adversely affected our earnings or competitive position. We believe that we are currently in compliance in all material respects with the environmental regulations to which we are subject.
 
Available Information
 
General information about us, including our corporate governance policies can be found on our website at www.herculesoffshore.com. On our website we make available, free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file or furnish them to the SEC. These filings also are available at the SEC’s Internet website at www.sec.gov. Information contained on our website is not part of this annual report.
 
Segment and Geographic Information
 
Information with respect to revenues, operating income and total assets attributable to our segments and revenues and long-lived assets by geographic areas of operations is presented in Note 15 of our Notes to Consolidated Financial Statements included in Item 8 of this annual report. Additional information about our segments, as well as information with respect to the impact of seasonal weather patterns on domestic operations, is presented in “Management’s Discussion and Financial Analysis of Financial Condition and Results of Operations” in Item 7 of this annual report.
 
Item 1A.   Risk Factors
 
Our business depends on the level of activity in the oil and natural gas industry, which is significantly affected by volatile oil and natural gas prices.
 
Our business depends on the level of activity in oil and natural gas exploration, development and production in the U.S. Gulf of Mexico and internationally, and in particular, the level of exploration, development and production expenditures of our customers. Oil and natural gas prices and our customers’ expectations of potential changes in these prices significantly affect this level of activity. In particular, changes in the price of natural gas materially affect our operations because drilling in the shallow-water U.S. Gulf of Mexico is primarily focused on developing and producing natural gas reserves. However, higher prices do not necessarily translate into increased drilling activity since our clients’ expectations about future commodity prices typically drive demand for our services. Oil and natural gas prices are extremely volatile. On December 13, 2005 natural gas prices were $15.39 per MMBtu at the Henry Hub. They subsequently declined sharply, reaching a low of $3.63 per MMBtu at the Henry Hub on September 29, 2006. As of February 15, 2008, the closing price of natural gas at the Henry Hub was $8.73 per MMBtu. Oil prices since January 1, 2007, based on the spot price for West Texas intermediate crude, have ranged from $50.48 as of January 18, 2007 to $99.62 as of January 2, 2008, with a closing price of $95.50 as of February 15, 2008. Commodity prices are affected by numerous factors, including the following:
 
  •  the demand for oil and natural gas in the United States and elsewhere;
 
  •  the cost of exploring for, producing and delivering oil and natural gas;
 
  •  political, economic and weather conditions in the United States and elsewhere;
 
  •  imports of liquefied natural gas;


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  •  expectations regarding future prices;
 
  •  advances in exploration, development and production technology;
 
  •  the ability of the Organization of Petroleum Exporting Countries, commonly called “OPEC,” to set and maintain production levels and pricing;
 
  •  the level of production in non-OPEC countries;
 
  •  domestic and international tax policies;
 
  •  the development and exploitation of alternative fuels;
 
  •  the policies of various governments regarding exploration and development of their oil and natural gas reserves; and
 
  •  the worldwide military and political environment, uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East and other significant oil and natural gas producing regions or further acts of terrorism in the United States, or elsewhere.
 
Depending on the market prices of oil and natural gas, and even during periods of high commodity prices, companies exploring for and producing oil and natural gas may cancel or curtail their drilling programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including their lack of success in exploration efforts. Any reduction in the demand for drilling and liftboat services may materially erode dayrates and utilization rates for our units, which would adversely affect our financial condition and results of operations.
 
A significant portion of our business is conducted in the shallow-water U.S. Gulf of Mexico, where market conditions are highly cyclical and subject to rapid change. The mature nature of this region could result in less drilling activity in the area, thereby reducing demand for our services.
 
Historically, the offshore service industry has been highly cyclical, with periods of high demand and high dayrates often followed by periods of low demand and low dayrates. Periods of low demand intensify the competition in the industry and often result in rigs or liftboats being idle for long periods of time. We may be required to idle rigs or liftboats or enter into lower dayrate contracts in response to market conditions in the future. In the U.S. Gulf of Mexico, contracts are generally short term, and oil and natural gas companies tend to respond quickly to upward or downward changes in prices. Due to the short-term nature of most of our contracts, changes in market conditions can quickly affect our business. In addition, customers generally have the right to terminate our contracts with little or no notice, and without penalty. As a result of the cyclicality of our industry, we expect our results of operations to be volatile.
 
In addition, the U.S. Gulf of Mexico, and in particular the shallow-water region of the U.S. Gulf of Mexico, is a mature oil and natural gas production region that has experienced substantial seismic survey and exploration activity for many years. Because a large number of oil and natural gas prospects in this region have already been drilled, additional prospects of sufficient size and quality could be more difficult to identify. According to the U.S. Energy Information Administration, the average size of the U.S. Gulf of Mexico discoveries has declined significantly since the early 1990s. In addition, the amount of natural gas production in the shallow-water U.S. Gulf of Mexico has declined over the last decade. Moreover, oil and natural gas companies may be unable to obtain financing necessary to drill prospects in this region. The decrease in the size of oil and natural gas prospects, the decrease in production or the failure to obtain such financing may result in reduced drilling activity in the U.S. Gulf of Mexico and reduced demand for our services.


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Our industry is highly competitive, with intense price competition. Our inability to compete successfully may reduce our profitability.
 
Our industry is highly competitive. Our contracts are traditionally awarded on a competitive bid basis. Pricing is often the primary factor in determining which qualified contractor is awarded a job, although rig and liftboat availability, location and technical capability and each contractor’s safety performance record and reputation for quality also can be key factors in the determination. Dayrates also depend on the supply of rigs and vessels. Generally, excess capacity puts downward pressure on dayrates. Excess capacity can occur when newly constructed rigs and vessels enter service, when rigs and vessels are mobilized between geographic areas and when non-marketed rigs and vessels are re-activated.
 
Many other companies in the drilling industry are larger than we are and have more diverse fleets, or fleets with generally higher specifications, and greater resources than we have. Some of our competitors also are incorporated in tax-haven countries outside the United States, which provides them with significant tax advantages that are not available to us as a U.S. company, which may materially impair our ability to compete with them for many projects that would be beneficial to our company. In addition, the competitive environment has intensified as recent mergers within the oil and natural gas industry have reduced the number of available customers and suppliers, resulting in increased price competition and fewer alternatives for sourcing of key supplies. Finally, competition among drilling and marine service providers is also affected by each provider’s reputation for safety and quality. We may not be able to maintain our competitive position, and we believe that competition for contracts will continue to be intense in the foreseeable future. Our inability to compete successfully may reduce our profitability.
 
The terms of some of our dayrate drilling contracts may limit our ability to benefit from increasing dayrates in an improving market.
 
Although historically our offshore drilling contracts in the U.S. Gulf of Mexico generally have been on a short-term basis, from time to time, and particularly in international locations, we may enter into longer term contracts. The duration of offshore drilling contracts is generally determined by market demand and the strategies of the offshore drilling contractors and their customers. In periods of rising demand for offshore rigs, a drilling contractor generally would prefer to enter into well-to-well or other shorter term contracts that would allow the contractor to profit from increasing dayrates, while customers with reasonably definite drilling programs would typically prefer longer term contracts in order to maintain dayrates at a consistent level. Conversely, in periods of decreasing demand for offshore rigs, a drilling contractor generally would prefer longer term contracts to preserve dayrates and utilization, while customers generally would prefer well-to-well contracts or other shorter term contracts that would allow the customer to benefit from the decreasing dayrates. Our inability to fully benefit from increasing dayrates in an improving market, due to the long-term nature of some of our contracts, may adversely affect our profitability.
 
Our drilling and liftboat contracts may be terminated due to events beyond our control.
 
Our customers may terminate some of our drilling and liftboat contracts if the unit is destroyed or lost or if operations are suspended for a specified period of time as a result of a breakdown of our equipment, or due to events beyond the control of either party. In some cases, our drilling contracts and liftboat contracts may be terminable upon specified advance notice from the customer and after some termination payment (which would not fully compensate us for the loss of the contract). The likelihood that a customer may seek to terminate a contract is increased during periods of market weakness. Early termination of a contract may result in a rig or liftboat being idle for an extended period of time, which could adversely affect our financial position, results of operations and cash flows.


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Our business involves numerous operating hazards, and our insurance may not be adequate to cover our losses.
 
Our operations are subject to the usual hazards inherent in the drilling and operation of oil and natural gas wells, such as blowouts, reservoir damage, loss of production, loss of well control, punchthroughs, craterings, fires and pollution. The occurrence of these events could result in the suspension of drilling or production operations, claims by the operator, severe damage to or destruction of the property and equipment involved, injury or death to rig or liftboat personnel, and environmental damage. We may also be subject to personal injury and other claims of rig or liftboat personnel as a result of our drilling and liftboat operations. Operations also may be suspended because of machinery breakdowns, abnormal operating conditions, failure of subcontractors to perform or supply goods or services and personnel shortages.
 
In addition, our drilling and liftboat operations are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Tropical storms, hurricanes and other severe weather prevalent in the U.S. Gulf of Mexico, such as Hurricane Rita in September 2005, Hurricane Katrina in August 2005 and Hurricane Ivan in September 2004, could have a material adverse effect on our operations. During such severe storms, our liftboats typically leave location and cease to earn a full dayrate. Under U.S. Coast Guard guidelines, the liftboats cannot return to work until the weather improves and seas are less than five feet. In addition, damage to our rigs, liftboats, shorebases and corporate infrastructure caused by high winds, turbulent seas, or unstable sea bottom conditions could potentially cause us to curtail operations for significant periods of time until the damages can be repaired.
 
Damage to the environment could result from our operations, particularly through oil spillage or extensive uncontrolled fires. We may also be subject to property, environmental and other damage claims by oil and natural gas companies and other businesses operating offshore and in coastal areas. Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we may not have insurance coverage or rights to indemnity for all risks. Moreover, pollution and environmental risks generally are not totally insurable.
 
As a result of a number of recent catastrophic events like Hurricanes Ivan, Katrina and Rita, insurance underwriters increased insurance premiums for many of the coverages historically maintained and issued general notices of cancellation and significant changes for a wide variety of insurance coverages. The oil and natural gas industry suffered extensive damage from Hurricanes Ivan, Katrina and Rita. As a result, our insurance costs increased significantly, our deductibles increased and our coverage for named windstorm damage was restricted. Any additional severe storm activity in the energy producing areas of the U.S. Gulf of Mexico in the future could cause insurance underwriters to no longer insure U.S. Gulf of Mexico assets against weather-related damage. A number of our customers that produce oil and natural gas have previously maintained business interruption insurance for their production. This insurance may cease to be available in the future, which could adversely impact our customers’ business prospects in the U.S. Gulf of Mexico and reduce demand for our services.
 
If a significant accident or other event resulting in damage to our rigs or liftboats, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a customer, it could adversely affect our financial condition and results of operations. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.
 
Our customers may be unable or unwilling to indemnify us.
 
Consistent with standard industry practice, our clients generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. These risks are those associated with the loss of control of a well, such as blowout or cratering, the cost to regain control or redrill the well and associated pollution. There can be no assurance, however, that these clients will necessarily be financially able to indemnify us against all these risks. Also, we may be effectively prevented from enforcing these indemnities because of the


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nature of our relationship with some of our larger clients. Additionally, from time to time we may not be able to obtain agreement from our customer for such damages and risks.
 
Our international operations are subject to additional political, economic, and other uncertainties not generally associated with domestic operations.
 
An element of our business strategy is to continue to expand into international oil and natural gas producing areas such as West Africa, the Middle East and the Asia-Pacific region, including India. As of February 20, 2008, we owned or operated 18 liftboats operating offshore West Africa, including Nigeria, nine jackup rigs operating offshore or located in the following locations: Mexico, Qatar, India, Angola, Malaysia and Trinidad, and one platform rig in Mexico. Our international operations are subject to a number of risks inherent in any business operating in foreign countries, including:
 
  •  political, social and economic instability, war and acts of terrorism;
 
  •  potential seizure, expropriation or nationalization of assets;
 
  •  damage to our equipment or violence directed at our employees, including kidnappings;
 
  •  piracy;
 
  •  increased operating costs;
 
  •  complications associated with repairing and replacing equipment in remote locations;
 
  •  repudiation, modification or renegotiation of contracts;
 
  •  limitations on insurance coverage, such as war risk coverage in certain areas;
 
  •  import-export quotas;
 
  •  confiscatory taxation;
 
  •  work stoppages, particularly in the Nigerian labor environment;
 
  •  unexpected changes in regulatory requirements;
 
  •  wage and price controls;
 
  •  imposition of trade barriers;
 
  •  imposition or changes in enforcement of local content laws;
 
  •  restrictions on currency or capital repatriations;
 
  •  currency fluctuations and devaluations; and
 
  •  other forms of government regulation and economic conditions that are beyond our control.
 
As a result of our international expansion, including our acquisition of jack-ups and a platform rig in the acquisition of TODCO, the exposure to these risks will increase. Our financial condition and results of operations could be susceptible to adverse events beyond our control that may occur in the particular country or region in which we are active.
 
Many governments favor or effectively require that liftboat or drilling contracts be awarded to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may result in inefficiencies or put us at a disadvantage when bidding for contracts against local competitors.


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Our non-U.S. contract drilling and liftboat operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipment and operation of drilling units and liftboats, currency conversions and repatriation, oil and natural gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of units and other equipment. Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and natural gas and other aspects of the oil and natural gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and natural gas companies and may continue to do so. Operations in less developed countries can be subject to legal systems which are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.
 
Due to our international operations, we may experience currency exchange losses where revenues are received and expenses are paid in nonconvertible currencies or where we do not hedge an exposure to a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital.
 
A small number of customers account for a significant portion of our revenues, and the loss of any of these customers could adversely affect our financial condition and results of operations.
 
We derive a significant amount of our revenue from a single major integrated energy company. Chevron Corporation represented approximately 21%, 35% and 31% of our consolidated revenues for the years ended December 31, 2007, 2006 and 2005. In addition, Chevron Corporation accounts for 85% of the revenues for our International Liftboats segment. Our financial condition and results of operations will be materially adversely affected if Chevron curtails its activities in the U.S. Gulf of Mexico or Nigeria, terminates its contracts with us, fails to renew its existing contracts or refuses to award new contracts to us and we are unable to enter into contracts with new customers at comparable dayrates. In addition, the loss of any of our other significant customers could adversely affect our financial condition and results of operations.
 
Reactivation of non-marketed rigs or liftboats, mobilization of rigs or liftboats back to the U.S. Gulf of Mexico or new construction of rigs or liftboats could result in excess supply in the region, and our dayrates and utilization could be reduced.
 
If market conditions improve, inactive rigs and liftboats that are not currently being marketed could be reactivated to meet an increase in demand. Improved market conditions, particularly relative to other markets, could also lead to jackup rigs, other mobile offshore drilling units and liftboats being moved into the U.S. Gulf of Mexico or could lead to increased construction and upgrade programs by our competitors. Some of our competitors have already announced plans to upgrade existing equipment or build additional jackup rigs with higher specifications than our rigs. According to ODS-Petrodata, as of February 8, 2008, 85 jackup rigs had been ordered by industry participants, national oil companies and financial investors for delivery through 2011. Not all of the rigs currently under construction have been contracted for future work, which may intensify price competition as scheduled delivery dates occur. In addition, as of February 20, 2008, we believe there were also ten liftboats under construction or on order in the United States that may be used in the U.S. Gulf of Mexico. A significant increase in the supply of jackup rigs, other mobile offshore drilling units or liftboats could adversely affect both our utilization and dayrates.
 
Upgrade, refurbishment and repair projects are subject to risks, including delays and cost overruns, which could have an adverse impact on our available cash resources and results of operations.
 
We make upgrade, refurbishment and repair expenditures for our fleet from time to time, including when we acquire units or when repairs or upgrades are required by law, in response to an inspection by a


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governmental authority or when a unit is damaged. We also regularly make certain upgrades or modifications to our drilling rigs to meet customer or contract specific requirements. We are currently upgrading and refurbishing Hercules 208 and Black Jack and are making or planning to make contract specific modifications to Hercules 260 and Hercules 258.
 
Upgrade, refurbishment and repair projects are subject to the risks of delay or cost overruns inherent in any large construction project, including costs or delays resulting from the following:
 
  •  unexpectedly long delivery times for, or shortages of, key equipment, parts and materials;
 
  •  shortages of skilled labor and other shipyard personnel necessary to perform the work;
 
  •  unforeseen increases in the cost of equipment, labor and raw materials, particularly steel;
 
  •  unforeseen design and engineering problems;
 
  •  unanticipated actual or purported change orders;
 
  •  work stoppages;
 
  •  latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;
 
  •  failure or delay of third-party service providers and labor disputes;
 
  •  disputes with shipyards and suppliers;
 
  •  delays and unexpected costs of incorporating parts and materials needed for the completion of projects;
 
  •  financial or other difficulties at shipyards;
 
  •  adverse weather conditions; and
 
  •  inability to obtain required permits or approvals.
 
We may experience delays and costs overruns in the refurbishment of Hercules 208 due to certain of the factors listed above. Delays could put at risk our planned arrangements to commence operations on schedule. We are exposed to penalties for failure to complete the rig and commence operations in a timely manner.
 
Significant cost overruns or delays would adversely affect our financial condition and results of operations. Additionally, capital expenditures for rig upgrade and refurbishment projects could exceed our planned capital expenditures. Failure to complete an upgrade, refurbishment or repair project on time may, in some circumstances, result in the delay, renegotiation or cancellation of a drilling or liftboat contract. Our rigs and liftboats undergoing upgrade, refurbishment or repair may not earn a dayrate during the period they are out of service.
 
Our jackup rigs are at a relative disadvantage to higher specification rigs, which may be more likely to obtain contracts than lower specification jackup rigs such as ours.
 
Many of our competitors have jackup fleets with generally higher specification rigs than those in our jackup fleet. In addition, the announced construction of new rigs includes approximately 85 higher specification jackup rigs. Particularly during market downturns when there is decreased rig demand, higher specification rigs may be more likely to obtain contracts than lower specification jackup rigs such as ours. In the past, lower specification rigs have been stacked earlier in the cycle of decreased rig demand than higher specification rigs and have been reactivated later in the cycle, which may adversely impact our business. In addition, higher specification rigs may be more adaptable to different operating conditions and therefore have greater flexibility to move to areas of demand in response to changes in market conditions. Because a majority of our rigs were designed specifically for drilling in the shallow-water U.S. Gulf of Mexico, our ability to


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move them to other regions in response to changes in market conditions is limited. Furthermore, in recent years, an increasing amount of exploration and production expenditures have been concentrated in deepwater drilling programs and deeper formations, including deep natural gas prospects, requiring higher specification jackup rigs, semisubmersible drilling rigs or drillships. This trend is expected to continue and could result in a decline in demand for lower specification jackup rigs like ours, which could have an adverse impact on our financial condition and results of operations.
 
The impact of purchase accounting associated with our acquisition of TODCO could adversely affect our results of operations and financial condition.
 
Purchase accounting required us to allocate the price paid in the acquisition of TODCO to the assets acquired on the basis of their fair values at the time of the closing of the acquisition. Those adjustments resulted in significant increases in the carrying values of acquired property, plant and equipment costs. The increased value of property, plant and equipment has increased our depreciation expense, which has reduced reported earnings but has had no effect on cash flows.
 
As a result of the acquisition, we have recorded significant goodwill on our balance sheet. We will assess the realizability of the goodwill we have on our books annually as well as whenever events or changes in circumstances indicate that the goodwill may be impaired. These events or circumstances generally include operating losses or a significant decline in earnings associated with the acquired business, which may affect one or more of our reported segments. Our ability to realize the value of the goodwill will depend on the future cash flows of our businesses. These cash flows in turn depend in part on how well we have integrated these businesses. If we are not able to realize the value of the goodwill, we may be required to incur material charges relating to the impairment of those assets. In addition, the goodwill will be tested annually to assess this amount for impairment under generally accepted accounting principles. If we conclude that the goodwill associated with the TODCO acquisition is impaired or, additionally, that the carrying value of assets acquired are impaired, the amount of the impairment would reduce the amount of earnings we would otherwise report but would have no effect on our cash flows.
 
Our business is expected to continue to be cyclical. The goodwill associated with the acquisition and the increased carrying values of TODCO’s assets on our balance sheet could, therefore, increase the potential for impairment of the goodwill and the carrying values of the assets acquired.
 
TODCO’s tax sharing agreement with Transocean may require continuing substantial payments.
 
We, as successor to TODCO, and TODCO’s former parent Transocean Inc. are parties to a tax sharing agreement that was originally entered into in connection with TODCO’s initial public offering in 2004. The tax sharing agreement was amended and restated in November 2006 in a negotiated settlement of disputes between Transocean and TODCO over the terms of the original tax sharing agreement. The tax sharing agreement required us to make an acceleration payment to Transocean upon completion of the TODCO acquisition as a result of the deemed utilization of TODCO’s pre-IPO tax benefits. Subsequent to the completion of the TODCO acquisition, we paid $116 million to Transocean in satisfaction of those obligations. The basis of determination for the change in control payment is subject to a differing interpretation by Transocean.
 
Additionally, the tax sharing agreement continues to require that additional payments be made to Transocean based on a portion of the expected tax benefit from the exercise of certain compensatory stock options to acquire Transocean common stock attributable to TODCO employees and board members. The estimated amount of payments to Transocean related to compensatory options that remain outstanding at December 31, 2007, assuming a Transocean stock price of $143.15 per share at the time of exercise of the compensatory options (the actual price of Transocean’s common stock at December 31, 2007), is approximately $25.4 million. There is no certainty that we will realize future economic benefits from TODCO’s tax benefits equal to the amount of the payments required under the tax sharing agreement.


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Our acquisition strategy may be unsuccessful if we incorrectly predict operating results, are unable to identify and complete future acquisitions, fail to successfully integrate acquired assets or businesses we acquire, or are unable to obtain financing for acquisitions on acceptable terms.
 
The acquisition of assets or businesses that are complementary to our drilling and liftboat operations is an important component of our business strategy. We believe that acquisition opportunities may arise from time to time, and any such acquisition could be significant. At any given time, discussions with one or more potential sellers may be at different stages. However, any such discussions may not result in the consummation of an acquisition transaction, and we may not be able to identify or complete any acquisitions. Any such transactions could involve the payment by us of a substantial amount of cash, the incurrence of a substantial amount of debt or the issuance of a substantial amount of equity. We cannot predict the effect, if any, that any announcement or consummation of an acquisition would have on the trading price of our common stock.
 
Any future acquisitions could present a number of risks, including:
 
  •  the risk of incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets;
 
  •  the risk of failing to integrate the operations or management of any acquired operations or assets successfully and timely; and
 
  •  the risk of diversion of management’s attention from existing operations or other priorities.
 
In addition, we may not be able to obtain, on terms we find acceptable, sufficient financing that may be required for any such acquisition or investment.
 
If we are unsuccessful in completing acquisitions of other operations or assets, our financial condition could be adversely affected and we may be unable to implement an important component of our business strategy successfully. In addition, if we are unsuccessful in integrating our acquisitions in a timely and cost-effective manner, our financial condition and results of operations could be adversely affected.
 
Failure to employ a sufficient number of skilled workers or an increase in labor costs could hurt our operations.
 
We require skilled personnel to operate and provide technical services and support for our rigs and liftboats. In periods of increasing activity and when the number of operating units in our areas of operation increases, either because of new construction, re-activation of idle units or the mobilization of units into the region, shortages of qualified personnel could arise, creating upward pressure on wages and difficulty in staffing our units. The shortages of qualified personnel or the inability to obtain and retain qualified personnel also could negatively affect the quality and timeliness of our work. In addition, our ability to expand our operations depends in part upon our ability to increase the size of our skilled labor force. Moreover, our labor costs increased significantly in 2006 and 2007, and we expect this trend to continue, but at a slower pace in 2008.
 
Although our domestic employees are not covered by a collective bargaining agreement, the marine services industry has been targeted by maritime labor unions in an effort to organize U.S. Gulf of Mexico employees. A significant increase in the wages paid by competing employers or the unionization of our U.S. Gulf of Mexico employees could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.
 
Governmental laws and regulations may add to our costs or limit drilling activity and liftboat operations.
 
Our operations are affected in varying degrees by governmental laws and regulations. The industries in which we operate are dependent on demand for services from the oil and natural gas industry and, accordingly,


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are also affected by changing tax and other laws relating to the energy business generally. We are also subject to the jurisdiction of the United States Coast Guard, the National Transportation Safety Board and the United States Customs and Border Protection Service, as well as private industry organizations such as the American Bureau of Shipping. We may be required to make significant capital expenditures to comply with laws and the applicable regulations and standards of those authorities and organizations. Moreover, the cost of compliance could be higher than anticipated. Similarly, our international operations are subject to compliance with the U.S. Foreign Corrupt Practices Act, certain international conventions and the laws, regulations and standards of other foreign countries in which we operate. It is also possible that these conventions, laws, regulations and standards may in the future add significantly to our operating costs or limit our activities.
 
In addition, as our vessels age, the costs of drydocking the vessels in order to comply with governmental laws and regulations and to maintain their class certifications are expected to increase, which could have an adverse effect on our financial condition and results of operations.
 
Compliance with or a breach of environmental laws can be costly and could limit our operations.
 
Our operations are subject to regulations that require us to obtain and maintain specified permits or other governmental approvals, control the discharge of materials into the environment, require the removal and cleanup of materials that may harm the environment or otherwise relate to the protection of the environment. For example, as an operator of mobile offshore drilling units and liftboats in navigable U.S. waters and some offshore areas, we may be liable for damages and costs incurred in connection with oil spills or other unauthorized discharges of chemicals or wastes resulting from those operations. Laws and regulations protecting the environment have become more stringent in recent years, and may in some cases impose strict liability, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. Some of these laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. The application of these requirements, the modification of existing laws or regulations or the adoption of new requirements, both in U.S. waters and internationally, could have a material adverse effect on our financial condition and results of operations.
 
We may not be able to maintain or replace our rigs and liftboats as they age.
 
The capital associated with the repair and maintenance of our fleet increases with age. We may not be able to maintain our fleet by extending the economic life of existing rigs and liftboats, and our financial resources may not be sufficient to enable us to make expenditures necessary for these purposes or to acquire or build replacement units.
 
Our operating and maintenance costs with respect to our rigs do not necessarily fluctuate in proportion to changes in operating revenues.
 
We do not expect our operating and maintenance costs with respect to our rigs to necessarily fluctuate in proportion to changes in operating revenues. Operating revenues may fluctuate as a function of changes in dayrate. But costs for operating a rig are generally fixed or only semi-variable regardless of the dayrate being earned. Additionally, if our rigs incur idle time between contracts, we typically do not de-man those rigs because we will use the crew to prepare the rig for its next contract. During times of reduced activity, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking, after which time the crew members are assigned to active rigs or dismissed. Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. In general, labor costs increase primarily due to higher salary levels and inflation. Equipment maintenance expenses fluctuate depending upon the type of activity the unit is performing and the age and condition of the equipment. Contract preparation expenses vary based on the scope and length of contract preparation required and the duration of the firm contractual period over which such expenditures are amortized.


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We are subject to litigation that could have an adverse effect on us.
 
We are from time to time involved in various litigation matters. These matters may include, among other things, contract disputes, personal injury, environmental, asbestos and other toxic tort, employment, tax and securities litigation, and other litigation that arises in the ordinary course of our business. We cannot predict with certainty the outcome or effect of any claim or other litigation matter. Litigation may have an adverse effect on us because of potential negative outcomes, the costs associated with defending the lawsuits, the diversion of our management’s resources and other factors.
 
Changes in effective tax rates or adverse outcomes resulting from examination of our tax returns could adversely affect our operating results and financial results.
 
Our future effective tax rates could be adversely affected by changes in tax laws, both domestically and internationally. They could also be adversely affected by changes in the valuation of our deferred tax assets and liabilities, or by changes in tax treaties, regulations, accounting principles or interpretations thereof in one or more countries in which we operate. In addition, we are subject to the potential examination of our income tax returns by the Internal Revenue Service and other tax authorities where we file tax returns. We regularly assess the likelihood of adverse outcomes resulting from these examinations to determine the adequacy of our provision for taxes. There can be no assurance that such examinations will not have an adverse effect on our operating results and financial condition.
 
Our business would be adversely affected if we failed to comply with the provisions of U.S. law on coastwise trade, or if those provisions were modified, repealed or waived.
 
We are subject to U.S. federal laws that restrict maritime transportation, including liftboat services, between points in the United States to vessels built and registered in the United States and owned and manned by U.S. citizens. We are responsible for monitoring the ownership of our common stock. If we do not comply with these restrictions, we would be prohibited from operating our liftboats in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our liftboats, fines or forfeiture of the liftboats.
 
During the past several years, interest groups have lobbied Congress to repeal these restrictions to facilitate foreign flag competition for trades currently reserved for U.S.-flag vessels under the federal laws. We believe that interest groups may continue efforts to modify or repeal these laws currently benefiting U.S.-flag vessels. If these efforts are successful, it could result in increased competition, which could adversely affect our results of operations.
 
Our debt could adversely affect our ability to operate our business and make it difficult to meet our debt service obligations.
 
As of December 31, 2007, we have total outstanding debt of approximately $912 million. This debt represents approximately 31% of our total capitalization. We have up to $150 million of available capacity under our revolving credit facility of which $28.1 million has been committed related to issued standby letters of credit. We may continue to borrow to fund working capital or other needs, including to fund the purchase price of three rigs from Transocean Inc., in the near term up to the remaining $121.9 million. Our debt and the limitations imposed on us by our existing or future debt agreements could have significant consequences on our business and future prospects, including the following:
 
  •  we may not be able to obtain necessary financing in the future for working capital, capital expenditures, acquisitions, debt service requirements or other purposes;


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  •  we may be exposed to risks inherent in interest rate fluctuations because our borrowings generally are at variable rates of interest, which would result in higher interest expense to the extent we have not hedged such risk in the event of increases in interest rates; and
 
  •  we could be more vulnerable in the event of a downturn in our business that would leave us less able to take advantage of significant business opportunities and to react to changes in our business and in market or industry conditions.
 
Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures will depend on our ability to generate cash in the future, which is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. Our future cash flows may be insufficient to meet all of our debt obligations and commitments, and any insufficiency could negatively impact our business. To the extent we are unable to repay our indebtedness as it becomes due or at maturity with cash on hand or from other sources, we will need to refinance our debt, sell assets or repay the debt with the proceeds from equity offerings. Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, and we may not be able to complete asset sales in a timely manner sufficient to make such repayments.
 
Our senior secured credit agreement imposes significant operating and financial restrictions, which may prevent us from capitalizing on business opportunities and taking some actions.
 
Our senior secured credit agreement imposes significant operating and financial restrictions on us. These restrictions limit our ability to:
 
  •  make investments and other restricted payments, including dividends;
 
  •  incur or guarantee additional indebtedness;
 
  •  create or incur liens;
 
  •  restrict dividend or other payments by our subsidiaries to us;
 
  •  sell our assets or consolidate or merge with or into other companies; and
 
  •  engage in transactions with affiliates.
 
These limitations are subject to a number of important qualifications and exceptions. Our credit agreement also requires us to maintain a minimum fixed charge coverage ratio and maximum leverage ratio. In addition, commencing with the year ending December 31, 2008, we are required to prepay our $900 million term loan with 50% of our excess cash flow until the outstanding principal balance of the term loan is less than $550.0 million. Our compliance with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures, finance our acquisitions, equipment purchases and development expenditures, or withstand a future downturn in our business.
 
If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there could be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed.
 
If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness or in current or future debt financing agreements, there could be a default under the terms of these agreements. Our ability to comply with these restrictions and covenants, including meeting financial ratios and tests, may be affected by events beyond our control. If a default occurs under these agreements, lenders could terminate their commitments to lend or accelerate the outstanding loans and declare all amounts borrowed due and payable. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable. If any of these events occur, our


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assets might not be sufficient to repay in full all of our outstanding indebtedness, and we may be unable to find alternative financing. Even if we could obtain alternative financing, that financing might not be on terms that are favorable or acceptable. If we were unable to repay amounts borrowed, the holders of the debt could initiate a bankruptcy proceeding or liquidation proceeding against collateral.
 
Because we have a limited operating history, you may not be able to evaluate our current business and future earnings prospects accurately.
 
We were formed in July 2004 to provide drilling and liftboat services to the oil and natural gas exploration and production industry. As a result, we have limited operating history upon which you can base an evaluation of our current business and our future earnings prospects.
 
We limit foreign ownership of our company, which could reduce the price of our common stock.
 
Our certificate of incorporation limits the percentage of outstanding common stock and other classes of capital stock that can be owned by non-United States citizens within the meaning of statutes relating to the ownership of U.S.-flag vessels. Applying the statutory requirements applicable today, our certificate of incorporation provides that no more than 20% of our outstanding common stock may be owned by non-U.S. citizens and establishes mechanisms to maintain compliance with these requirements. These restrictions may have an adverse impact on the liquidity or market value of our common stock because holders may be unable to transfer our common stock to non-United States citizens. Any attempted or purported transfer of our common stock in violation of these restrictions will be ineffective to transfer such common stock or any voting, dividend or other rights in respect of such common stock.
 
Restrictions on the percentage ownership of our outstanding capital stock by non-U.S. citizens may subject the shares held by such non-U.S. citizens to restrictions, limitations and redemption.
 
Our certificate of incorporation provides that any transfer, or attempted or purported transfer, of any shares of our capital stock that would result in the ownership or control of in excess of 20% of our outstanding capital stock by one or more persons who are not U.S. citizens for purposes of U.S. coastwise shipping will be void and ineffective as against us. In addition, if at any time persons other than U.S. citizens own shares of our capital stock or possess voting power over any shares of our capital stock in excess of 20%, we may withhold payment of dividends, suspend the voting rights attributable to such shares and redeem such shares.
 
We have no plans to pay regular dividends on our common stock, so investors in our common stock may not receive funds without selling their shares.
 
We do not intend to declare or pay regular dividends on our common stock in the foreseeable future. Instead, we generally intend to invest any future earnings in our business. Subject to Delaware law, our board of directors will determine the payment of future dividends on our common stock, if any, and the amount of any dividends in light of any applicable contractual restrictions limiting our ability to pay dividends, our earnings and cash flows, our capital requirements, our financial condition, and other factors our board of directors deems relevant. Our senior secured credit agreement restricts our ability to pay dividends or other distributions on our equity securities. Accordingly, stockholders may have to sell some or all of their common stock in order to generate cash flow from their investment. Stockholders may not receive a gain on their investment when they sell our common stock and may lose the entire amount of their investment.
 
Provisions in our charter documents, stockholder rights plan or Delaware law may inhibit a takeover, which could adversely affect the value of our common stock.
 
Our certificate of incorporation, bylaws, stockholder rights plan and Delaware corporate law contain provisions that could delay or prevent a change of control or changes in our management that a stockholder might consider favorable. These provisions will apply even if the offer may be considered beneficial by some


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of our stockholders. If a change of control or change in management is delayed or prevented, the market price of our common stock could decline.
 
Item 1B.   Unresolved Staff Comments
 
None.
 
Item 2.   Properties
 
Our property consists primarily of jackup rigs, barge rigs, submersible rigs, a platform rig, marine support vessels, liftboats and ancillary equipment, substantially all of which we own. Several of our vessels and substantially all of our other personal property, are pledged to collateralize our senior secured credit agreement.
 
We maintain our principal executive office in Houston, Texas, which is under lease. We lease office space in Lafayette, Louisiana; Houma, Louisiana; La Romaine, Trinidad; Luanda, Angola; and Ciudad del Carmen, Mexico. We also lease warehouses and yard facilities in Houma, Louisiana; Broussard, Louisiana and La Romaine, Trinidad. We lease warehouses, office space and residential premises in Qatar, India, Nigeria and Cayman Islands. In addition, we lease a waterfront dock and maintenance facility in Nigeria.
 
We incorporate by reference in response to this item the information set forth in Item 1 of this annual report.
 
Item 3.   Legal Proceedings
 
In March 2007, two TODCO stockholder lawsuits were filed in the District Court of Harris County, Texas, both alleging that the TODCO board of directors (which includes three of our current directors) breached their fiduciary duties in approving the merger with a subsidiary of our company. The first lawsuit, Frank Donio v. Jan Rask, et al , then pending in the 269th Judicial District Court of Harris County, Texas, Cause No. 2007-16357, is a purported stockholder class action suit against the TODCO directors and contains claims for breach of fiduciary duty. The second lawsuit, Robert Foster v. Jan Rask, et al., then pending in the 333rd Judicial District Court of Harris County, Texas, Cause No. 2007-16397, is a stockholder derivative action purportedly filed on behalf of TODCO against the TODCO directors (which includes three of our current directors) and us, and contains claims for breach of fiduciary duties of loyalty, due care, candor, good faith and/or fair dealing; corporate waste; unlawful self dealing; and claims that the defendants conspired, aided and abetted and/or assisted one another in a common plan to breach these fiduciary duties. Both lawsuits allege, among other things, that the TODCO directors engaged in self-dealing in approving the merger with us by advancing their own personal interests or those of TODCO’s senior management at the expense of the TODCO stockholders, utilized a defective sales process not designed to maximize TODCO stockholder value, and failed to consider any value maximizing alternatives, thus causing TODCO stockholders to receive an unfair price for their shares of TODCO common stock. The second lawsuit also alleges that we conspired, aided and abetted or assisted in these violations. In addition, the second suit alleges that TODCO’s directors breached their fiduciary duties by allegedly improperly awarding stock options to certain officers at a time when they allegedly knew the merger was “imminent” and the stock options would vest immediately upon consummation of the merger. The second suit also names the officers who received these stock option awards as defendants and alleges three causes of action against them: (1) a breach of fiduciary duty claim for having received allegedly improperly awarded stock options, (2) an unjust enrichment claim seeking a constructive trust, and (3) rescission of the stock option awards.
 
Both lawsuits seek, among other things, rescission of the merger, imposition of a constructive trust in favor of plaintiffs upon any benefits improperly received by the defendants, attorneys’ fees and expenses associated with the lawsuits and any other equitable relief the courts deem just and proper. On August 29, 2007, the two lawsuits were consolidated and transferred to the 270th Judicial District Court of Harris County,


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Texas. We, the TODCO directors, and the officers named as defendants believe the asserted claims are without merit, and each intends to defend them vigorously.
 
In connection with our acquisition of TODCO, we also assumed certain other material legal proceedings from TODCO and its subsidiaries.
 
In October 2001, TODCO was notified by the U.S. Environmental Protection Agency (“EPA”) that the EPA had identified a subsidiary of TODCO as a potentially responsible party under CERCLA in connection with the Palmer Barge Line superfund site located in Port Arthur, Jefferson County, Texas. Based upon the information provided by the EPA and our review of our internal records to date, we dispute our designation as a potentially responsible party and do not expect that the ultimate outcome of this case will have a material adverse effect on our consolidated results of operations, financial position or cash flows. We continue to monitor this matter.
 
Robert E. Aaron et al. vs. Phillips 66 Company et al. Circuit Court, Second Judicial District, Jones County, Mississippi.  This is the case name used to refer to several cases that have been filed in the Circuit Courts of the State of Mississippi involving 768 persons that allege personal injury or whose heirs claim their deaths arose out of asbestos exposure in the course of their employment by the defendants between 1965 and 2002. The complaints name as defendants, among others, certain of TODCO’s subsidiaries and certain of subsidiaries of TODCO’s former parent to whom TODCO may owe indemnity and other unaffiliated defendant companies, including companies that allegedly manufactured drilling related products containing asbestos that are the subject of the complaints. The number of unaffiliated defendant companies involved in each complaint ranges from approximately 20 to 70. The complaints allege that the defendant drilling contractors used asbestos-containing products in offshore drilling operations, land based drilling operations and in drilling structures, drilling rigs, vessels and other equipment and assert claims based on, among other things, negligence and strict liability, and claims authorized under the Jones Act. The plaintiffs seek, among other things, awards of unspecified compensatory and punitive damages. All of these cases were assigned to a special master who has approved a form of questionnaire to be completed by plaintiffs so that claims made would be properly served against specific defendants. As of the date of this report, approximately 700 questionnaires were returned and the remaining plaintiffs, who did not submit a questionnaire reply, have had their suits dismissed without prejudice. Of the respondents, approximately 100 shared periods of employment by TODCO and its former parent which could lead to claims against either company, even though many of these plaintiffs did not state in their questionnaire answers that the employment actually involved exposure to asbestos. After providing the questionnaire, each plaintiff was further required to file a separate and individual amended complaint naming only those defendants against whom they had a direct claim as identified in the questionnaire answers. Defendants not identified in the amended complaints were dismissed from the plaintiffs’ litigation. To date, three plaintiffs named TODCO as a defendant in their amended complaints. It is possible that some of the plaintiffs who have filed amended complaints and have not named TODCO as a defendant may attempt to add TODCO as a defendant in the future when case discovery begins and greater attention is given to each individual plaintiff’s employment background. We continue to monitor a small group of these other cases. We have not determined which entity would be responsible for such claims under the Master Separation Agreement between TODCO and its former parent. We intend to defend ourselves vigorously and, based on the limited information available at this time, do not expect the ultimate outcome of these lawsuits to have a material adverse effect on our consolidated results of operations, financial position or cash flows.
 
In December 2002, TODCO received an assessment for corporate income taxes from SENIAT, the national Venezuelan tax authority, of approximately $20.7 million (based on the current exchange rates at the time of the assessment and inclusive of penalties) relating to calendar years 1998 through 2000. In March 2003, TODCO paid approximately $2.6 million of the assessment, plus approximately $0.3 million in interest, and we are contesting the remainder of the assessment with the Venezuelan Tax Court. After TODCO made the partial assessment payment, it received a revised assessment in September 2003 of approximately $16.7 million (based on the current exchange rates at the time of the assessment and inclusive of penalties). Thereafter, TODCO filed an administrative tax appeal with SENIAT and the tax authority rendered a decision


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that reduced the tax assessment to $8.1 million (based on the current exchange rates at the time of the decision). TODCO then initiated a judicial tax court appeal with the Venezuelan Tax Court to set aside the $8.1 million administrative tax assessment. We do not expect the ultimate resolution of this assessment to have a material impact on our consolidated results of operations, financial condition or cash flows. In January 2008, SENIAT commenced an audit for the 2003 calendar year. We have not yet received any proposed adjustments from SENIAT arising from this audit. We believe we are owed indemnity from TODCO’s former parent under the tax sharing agreement for any losses we incur as a result of these legal proceedings.
 
We and our subsidiaries are involved in a number of other lawsuits, all of which have arisen in the ordinary course of our business. We do not believe that ultimate liability, if any, resulting from any such other pending litigation will have a material adverse effect on our business or consolidated financial position.
 
We cannot predict with certainty the outcome or effect of any of the litigation matters specifically described above or of any such other pending litigation. There can be no assurance that our belief or expectations as to the outcome or effect of any lawsuit or other litigation matter will prove correct, and the eventual outcome of these matters could materially differ from management’s current estimates.
 
Item 4.   Submission of Matters to a Vote of Security Holders
 
There were no matters submitted to a vote of security holders during the fourth quarter of 2007.


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PART II
 
Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
Quarterly Common Stock Prices and Dividend Policy
 
Our common stock is traded on the NASDAQ Global Select Market under the symbol “HERO.” As of February 20, 2008, there were 79 stockholders of record. On February 20, 2008, the closing price of our common stock as reported by NASDAQ was $26.75 per share. The following table sets forth, for the periods indicated, the range of high and low sales prices for our common stock:
 
                 
    Price  
    High     Low  
 
2007
               
Fourth Quarter
  $ 28.43     $ 22.93  
Third Quarter
    34.98       24.88  
Second Quarter
    36.97       25.45  
First Quarter
    29.24       23.80  
 
                 
    Price  
    High     Low  
 
2006
               
Fourth Quarter
  $ 36.97     $ 28.14  
Third Quarter
    36.23       28.72  
Second Quarter
    43.89       29.14  
First Quarter
    36.70       27.68  
 
We have not paid any cash dividends on our common stock since becoming a publicly held corporation in October 2005, and we do not intend to declare or pay regular dividends on our common stock in the foreseeable future. Instead, we generally intend to invest any future earnings in our business. Subject to Delaware law, our board of directors will determine the payment of future dividends on our common stock, if any, and the amount of any dividends in light of any applicable contractual restrictions limiting our ability to pay dividends, our earnings and cash flows, our capital requirements, our financial condition, and other factors our board of directors deems relevant. Our senior secured credit agreement restricts our ability to pay dividends or other distributions on our equity securities.
 
Issuer Purchases of Equity Securities
 
The following table sets forth for the periods indicated certain information with respect to our purchases of our common stock:
 
                                 
                Total
       
                Number of
    Maximum
 
                Shares
    Number
 
                Purchased
    of Shares
 
                as Part of a
    that may yet be
 
    Total Number
    Average
    Publicly
    Purchased
 
    of Shares
    Price Paid
    Announced
    Under the
 
Period
  Purchased(1)     per Share     Plan(2)     Plan(2)  
 
October 1 – 31, 2007
                N/A       N/A  
November 1 – 30, 2007
    6,172     $ 26.95       N/A       N/A  
December 1 – 31, 2007
                N/A       N/A  
                                 
Total
    6,172       26.95       N/A       N/A  
                                 
 
 
(1) Represents the surrender of shares of common stock to satisfy tax withholding obligations in connection with the vesting of restricted stock issued to employees under our stockholder-approved long-term incentive plan.
 
(2) We did not have at any time during 2007 or 2006, and currently do not have, a share repurchase program in place.


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Item 6.   Selected Financial Data
 
We have derived the following condensed consolidated financial information as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005 from our audited consolidated financial statements included in Item 8 of this annual report. The condensed consolidated financial information as of December 31, 2005 and 2004 and for the period from inception (July 27, 2004) to December 31, 2004 was derived from our audited consolidated financial statements included in Item 8 of our annual report on Form 10-K, as amended, for the year ended December 31, 2006.
 
We were formed in July 2004 and commenced operations in August 2004. From our formation to December 31, 2007, we completed the acquisition of TODCO and several significant asset acquisitions that impact the comparability of our historical financial results. Our financial results reflect the impact of the TODCO business and the asset acquisitions from the date of closing. We have included pro forma information related to the TODCO acquisition in Note 4 to the Consolidated Financial Statements included in Item 8 of this annual report.
 
In addition, in connection with our initial public offering, we converted from a Delaware limited liability company to a Delaware corporation on November 1, 2005. Upon the conversion, each outstanding membership interest of the limited liability company was converted to 350 shares of common stock of the corporation. Share-based information contained herein assumes that we had effected the conversion of each outstanding membership interest into 350 shares of common stock for all periods prior to the conversion. Prior to the conversion, our owners elected to be taxed at the member unit holder level rather than at the company level. As a result, we did not recognize any tax provision on our income prior to the conversion. Upon completion of the conversion, we recorded a tax provision of $12.1 million related to the recognition of deferred taxes equal to the tax effect of the difference between the book and tax basis of our assets and liabilities as of the effective date of the conversion.
 
The selected consolidated financial information below should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this annual report and our consolidated financial statements and related notes included in Item 8 of this annual report. In addition, the following information may not be deemed indicative of our future operations.
 
                                 
                      Period from
 
    Year Ended
    Year Ended
    Year Ended
    Inception
 
    December 31,
    December 31,
    December 31,
    to December 31,
 
    2007     2006     2005     2004  
    (In thousands, except per share data)  
 
Statement of Operations Data:
                               
Revenues
  $ 766,793     $ 344,312     $ 161,334     $ 31,728  
Operating income
    231,459       158,057       55,859       9,907  
Net income
    136,522       119,050       27,456       8,065  
Earnings per share:
                               
Basic
  $ 2.32     $ 3.80     $ 1.10     $ 0.55  
Diluted
    2.29       3.70       1.08       0.55  
Balance Sheet Data (as of end of period):
                               
Cash and cash equivalents
  $ 212,452     $ 72,772     $ 47,575     $ 14,460  
Working capital
    327,684       110,897       70,083       30,283  
Total assets
    3,642,539       605,581       354,825       132,156  
Long-term debt, net of current portion
    890,013       91,850       93,250       53,000  
Total stockholders’ equity
    2,011,433       394,851       215,943       71,087  
Cash dividends per share
                       


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                      Period from
 
    Year Ended
    Year Ended
    Year Ended
    Inception
 
    December 31,
    December 31,
    December 31,
    to December 31,
 
    2007     2006     2005     2004  
    (In thousands, except per share data)  
 
Other Financial Data:
                               
Net cash provided by (used in):
                               
Operating activities
  $ 178,319     $ 124,241     $ 54,762     $ (8,528 )
Investing activities
    (825,007 )     (149,983 )     (174,952 )     (94,241 )
Financing activities
    786,368       50,939       153,305       117,229  
Capital expenditures
    155,390       204,456       168,038       94,443  
Deferred drydocking expenditures
    20,772       12,544       7,369       601  
 
Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying consolidated financial statements as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005 included in Item 8 of this annual report. The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth under “Risk Factors” in Item 1A and elsewhere in this annual report. See “Forward-Looking Statements”.
 
OVERVIEW
 
We provide shallow-water drilling and marine services to the oil and natural gas exploration and production industry in the U.S. Gulf of Mexico and internationally. We provide these services to major integrated energy companies, independent oil and natural gas operators and national oil companies.
 
In July 2007, we furthered our strategic growth initiative by completing the acquisition of TODCO for total consideration of approximately $2,397.8 million, consisting of $925.8 million in cash and 56.6 million shares of common stock. TODCO, a provider of contract drilling and marine services in the U.S. Gulf of Mexico and international markets, owned and operated 24 jackup rigs, 27 barge rigs, three submersible rigs, nine land rigs, one platform rig and a fleet of marine support vessels. The TODCO acquisition positioned us as a leading shallow-water drilling provider as well as expanded our international presence and diversified our fleet. In December 2007, we sold our land rigs for proceeds of $107.0 million.
 
We historically reported our business activities in four business segments, Domestic Contract Drilling Services, International Contract Drilling Services, Domestic Marine Services and International Marine Services. In connection with the acquisition of TODCO, we conducted a review of our segments. Our historical operating divisions have been combined with the acquired businesses and now operate as six divisions: (1) Domestic Offshore, (2) International Offshore, (3) Inland, (4) Domestic Liftboats, (5) International Liftboats and (6) Other. Domestic Offshore includes our legacy Domestic Contract Drilling Services businesses and TODCO’s domestic offshore rigs operating in the U.S. Gulf of Mexico, while International Offshore includes our legacy International Contract Drilling Services and TODCO’s offshore rigs operating internationally. Inland includes the acquired U.S. inland barge business. Domestic Liftboats includes our legacy Domestic Marine Services business, while International Liftboats includes our legacy International Marine Services business. Our Other segment includes Delta Towing and the activities of our land rigs. We sold the land rigs in December 2007. The following describes our operations for each reporting segment:
 
Domestic Offshore — operates 24 jackup rigs and three submersible rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 85 to 250 feet.
 
International Offshore — operates nine jackup rigs and one platform rig outside of the U.S. Gulf of Mexico. We have one jackup rig working offshore in each of the following international locations: Qatar, India, Angola, Cameroon and Trinidad. This segment operates two jackup rigs and one platform rig in

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Mexico. In addition, this segment has one jackup rig currently undergoing reactivation in Southeast Asia and one jackup rig currently undergoing contract preparation work and customer acceptance in India.
 
Inland — operates a fleet of 12 conventional and 15 posted barge rigs that operate inland in marshes, rivers, lakes and shallow bay or coastal waterways along the U.S. Gulf Coast.
 
Domestic Liftboats — operates 47 liftboats in the U.S. Gulf of Mexico.
 
International Liftboats — operates 18 liftboats offshore West Africa, including five liftboats owned by a third party and one undergoing refurbishment.
 
Other — our Delta Towing business operates a fleet of 33 inland tugs, 17 offshore tugs, 34 crew boats, 45 deck barges, 17 shale barges and four spud barges along and in the U.S. Gulf of Mexico. In December 2007, we sold our land rig operations which included one land rig in Trinidad, two land rigs in the United States and six land rigs in Venezuela.
 
Our jackup and submersible rigs and our barge rigs are used primarily for exploration and development drilling in shallow waters. Under most of our contracts, we are paid a fixed daily rental rate called a “dayrate,” and we are required to pay all costs associated with our own crews as well as the upkeep and insurance of the rig and equipment.
 
Our liftboats are self-propelled, self-elevating vessels that support a broad range of offshore support services, including platform maintenance, platform construction, well intervention and decommissioning services throughout the life of an oil or natural gas well. Under most of our liftboat contracts, we are paid a fixed dayrate for the rental of the vessel, which typically includes the costs of a small crew of four to eight employees, and we also receive a variable rate for reimbursement of other operating costs such as catering, fuel, rental equipment and other items.
 
Our revenues are affected primarily by dayrates, fleet utilization and the number and type of units in our fleet. Utilization and dayrates, in turn, are influenced principally by the demand for rig and liftboat services from the exploration and production sectors of the oil and natural gas industry. Our contracts in the U.S. Gulf of Mexico tend to be short-term in nature and are heavily influenced by changes in the supply of units relative to the fluctuating expenditures for both drilling and production activity. Our international drilling contracts and some of our liftboat contracts in West Africa are longer term in nature.
 
Our operating costs are primarily a function of fleet configuration and utilization levels. The most significant direct operating costs for our Domestic Offshore, International Offshore and Inland segments are wages paid to crews, maintenance and repairs to the rigs, and insurance. These costs do not vary significantly whether the rig is operating under contract or idle, unless we believe that the rig is unlikely to work for a prolonged period of time, in which case we may decide to “cold-stack” or “warm-stack” the rig. Cold-stacking is a common term used to describe a rig that is expected to be idle for a protracted period and typically for which routine maintenance is suspended and the crews are either redeployed or laid-off. When a rig is cold-stacked, operating expenses for the rig are significantly reduced because the crew is smaller and maintenance activities are suspended. Placing rigs in service that have been cold-stacked typically requires a lengthy reactivation project that can involve significant expenditures and potentially additional regulatory review, particularly if the rig has been cold-stacked for a long period of time. Warm-stacking is a term used for a rig expected to be idle for a period of time that is not as prolonged as is the case with a cold-stacked rig. Maintenance is continued for warm-stacked rigs. Crews are reduced through attrition and redeployment, but a small crew is retained. Warm-stacked rigs generally can be reactivated in one to two weeks.
 
The most significant costs for our Domestic Liftboats and International Liftboats segments are the wages paid to crews and the amortization of regulatory drydocking costs. Unlike our Domestic Offshore; International Offshore and Inland segments, a significant portion of the expenses incurred with operating each liftboat are paid for or reimbursed by the customer under contractual terms and prices. This includes catering, fuel, oil, rental equipment, crane overtime and other items. We record reimbursements from customers as revenues and the related expenses as operating costs. Our liftboats are required to undergo regulatory inspections every year and to be drydocked two times every five years; the drydocking expenses and length of time in drydock vary depending on the condition of the vessel.


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RESULTS OF OPERATIONS
 
On July 11, 2007, we completed the acquisition of TODCO for total consideration of approximately $2,397.8 million, consisting of $925.8 million in cash and 56.6 million shares of common stock. Our 2007 results include activity from this acquired business from the date of acquisition. The acquisition significantly impacts the comparability of the 2007 period with the other periods presented.
 
Domestic industry conditions were generally weaker for jackup rigs during 2007 compared to 2006, as evidenced by our lower dayrates and utilization. Despite a continued reduction in supply, jackup dayrates in the U.S. Gulf of Mexico generally peaked in early summer of 2006 and have since declined due to a decline in drilling activity. Demand for jackup rigs reached a low of 47 rigs in October 2007. International industry conditions remained strong throughout 2006 and 2007. Liftboat dayrates increased throughout 2007 in the United States and West Africa.
 
The following table sets forth financial information by operating segment and other selected information for the periods indicated:
 
                         
    Year Ended December 31,  
    2007     2006     2005  
    (Dollars in thousands)  
 
Domestic Offshore:
                       
Number of rigs (as of end of period)
    27       6       9  
Revenues
  $ 241,452     $ 160,761     $ 103,422  
Operating Expenses
    122,131       51,862       48,330  
Depreciation and amortization expense
    35,143       8,882       5,547  
General and administrative expenses
    6,105       6,980       5,486  
                         
Operating income
  $ 78,073     $ 93,037     $ 44,059  
                         
International Offshore:
                       
Number of rigs (as of end of period)
    10       3        
Revenues
  $ 144,778     $ 30,460     $  
Operating expenses
    59,593       13,377        
Depreciation and amortization expense
    15,513       2,547        
General and administrative expenses
    1,863       1,606        
                         
Operating income
  $ 67,809     $ 12,930     $  
                         
Inland:
                       
Number of rigs (as of end of period)
    27              
Revenues
  $ 107,100     $     $  
Operating expenses
    56,636              
Depreciation and amortization expense
    16,264              
General and administrative expenses
    533              
                         
Operating income
  $ 33,667     $     $  
                         
Domestic Liftboats:
                       
Number of liftboats (as of end of period)
    47       47       42  
Revenues
  $ 137,745     $ 133,929     $ 55,740  
Operating expenses
    59,902       49,025       28,413  
Depreciation and amortization expense
    24,969       18,854       8,031  
General and administrative expenses
    2,190       2,259       1,888  
                         
Operating income
  $ 50,684     $ 63,791     $ 17,408  
                         
International Liftboats:
                       
Number of liftboats (as of end of period)
    18       17       4  
Revenues
  $ 63,282     $ 19,162     $ 2,172  
Operating expenses
    31,879       9,874       1,071  
Depreciation and amortization expense
    7,619       1,923       176  
General and administrative expenses
    3,888       3,056       336  
                         
Operating income
  $ 19,896     $ 4,309     $ 589  
                         


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    Year Ended December 31,  
    2007     2006     2005  
    (Dollars in thousands)  
 
Other:
                       
Revenues
  $ 72,436     $     $  
Operating expenses
    46,318              
Depreciation and amortization expense
    9,028              
General and administrative expenses
    1,011              
                         
Operating income
  $ 16,079     $     $  
                         
Total Company:
                       
Revenues
  $ 766,793     $ 344,312     $ 161,334  
Operating expenses
    376,459       124,138       77,814  
Depreciation and amortization expense
    109,064       32,310       13,790  
General and administrative expenses
    49,811       29,807       13,871  
                         
Operating income
    231,459       158,057       55,859  
Interest expense
    (36,055 )     (9,278 )     (9,880 )
Gain on disposal of assets
          30,690        
Loss on early retirement of debt
    (2,182 )           (4,078 )
Other income
    6,291       4,038       924  
                         
Income before income taxes
    199,513       183,507       42,825  
Income tax provision
    (62,991 )     (64,457 )     (15,369 )
                         
Net income
  $ 136,522     $ 119,050     $ 27,456  
                         
 
The following table sets forth selected operational data by operating segment, excluding our Other segment, for the periods indicated:
 
                                         
    Year Ended December 31, 2007  
                            Average
 
                      Average
    Operating
 
    Operating
    Available
          Revenue
    Expense per
 
    Days     Days     Utilization(1)     per Day(2)     Day(3)  
 
Domestic Offshore
    3,265       4,958       65.9 %   $ 73,952     $ 24,633  
International Offshore
    1,549       1,625       95.3 %     93,465       36,673  
Inland
    2,279       2,941       77.5 %     46,994       19,257  
Domestic Liftboats
    11,265       16,749       67.3 %     12,228       3,576  
International Liftboats
    5,077       6,149       82.6 %     12,464       5,184  
 
                                         
    Year Ended December 31, 2006  
                            Average
 
                      Average
    Operating
 
    Operating
    Available
          Revenue
    Expense
 
    Days     Days     Utilization(1)     per Day(2)     per Day(3)  
 
Domestic Offshore
    1,973       2,078       94.9 %   $ 81,480     $ 24,957  
International Offshore
    305       321       95.0 %     99,868       41,673  
Inland
    n/a       n/a       n/a       n/a       n/a  
Domestic Liftboats
    11,895       15,416       77.2 %     11,259       3,180  
International Liftboats
    1,765       2,009       87.9 %     10,857       4,915  
 


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    Year Ended December 31, 2005  
                            Average
 
                      Average
    Operating
 
    Operating
    Available
          Revenue
    Expense
 
    Days     Days     Utilization(1)     per Day(2)     per Day(3)  
 
Domestic Offshore
    2,192       2,309       94.9 %   $ 47,177     $ 20,932  
International Offshore
    n/a       n/a       n/a       n/a       n/a  
Inland
    n/a       n/a       n/a       n/a       n/a  
Domestic Liftboats
    8,571       10,971       78.1 %     6,503       2,590  
International Liftboats
    212       212       100.0 %     10,243       5,052  
 
 
(1) Utilization is defined as the total number of days our rigs or liftboats, as applicable, were under contract, known as operating days, in the period as a percentage of the total number of available days in the period. Days during which our rigs and liftboats were undergoing major refurbishments, upgrades or construction, and days during which our rigs and liftboats are cold-stacked, are not counted as available days. Days during which our liftboats are in the shipyard undergoing drydocking or inspection are considered available days for the purposes of calculating utilization.
 
(2) Average revenue per rig or liftboat per day is defined as revenue earned by our rigs or liftboats, as applicable, in the period divided by the total number of operating days for our rigs or liftboats, as applicable, in the period. Included in Domestic Offshore revenue is a total of $0.4 million related to amortization of contract specific capital expenditures reimbursed by the customer for the twelve months ended December 31, 2007. There was no such revenue in the twelve months ended December 31, 2006 and 2005. Included in International Offshore revenue is a total of $3.2 million and $2.6 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer for the twelve months ended December 31, 2007 and 2006, respectively. There was no revenue recognized in 2005 related to the amortization of deferred mobilization revenue and contract specific capital expenditures. Included in revenue for our International Offshore segment for the twelve months ended December 31, 2006 is $2.0 million earned for a timely departure of Hercules 170 from the shipyard in the second quarter of 2006.
 
(3) Average operating expense per rig or liftboat per day is defined as operating expenses, excluding depreciation and amortization, incurred by our rigs or liftboats, as applicable, in the period divided by the total number of available days in the period. We use available days to calculate average operating expense per rig or liftboat per day rather than operating days, which are used to calculate average revenue per rig or liftboat per day, because we incur operating expenses on our rigs and liftboats even when they are not under contract and earning a dayrate. In addition, the operating expenses we incur on our rigs and liftboats per day when they are not under contract are typically lower than the per-day expenses we incur when they are under contract. Included in International Offshore operating expense is a total of $2.8 million and $1.6 million related to amortization of deferred mobilization expenses for the twelve months ended December 31, 2007 and 2006, respectively. There was no expense recognized in 2005 related to the amortization of deferred mobilization expenses.
 
Our domestic liftboat operations generally are affected by the seasonal weather patterns in the U.S. Gulf of Mexico. These seasonal patterns may result in increased operations in the spring, summer and fall periods and a decrease in the winter months. The rainy weather, tropical storms, hurricanes and other storms prevalent in the U.S. Gulf of Mexico during the year affect our domestic liftboat operations. During such severe storms, our liftboats typically leave location and cease to earn a full dayrate. Under U.S. Coast Guard guidelines, the liftboats cannot return to work until the weather improves and seas are less than five feet. Demand for our domestic rigs may decline during hurricane season as our customers may reduce drilling activity. Accordingly, our operating results may vary from quarter to quarter, depending on factors outside of our control.

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2007 Compared to 2006
 
Revenues
 
Consolidated.  Total revenues for 2007 were $766.8 million compared with $344.3 million for 2006, an increase of $422.5 million, or 123%. This increase resulted primarily from revenues generated from TODCO acquired in July 2007. Total revenues included $15.4 million in reimbursements from our customers for expenses paid by us in 2007 compared with $7.5 million in 2006.
 
Domestic Offshore.  Revenues for our Domestic Offshore segment were $241.5 million for 2007 compared with $160.8 million for 2006, an increase of $80.7 million, or 50%. Revenues for 2007 include approximately $119.4 million from TODCO. Excluding the revenue from TODCO, revenue decreased by $38.7 million, of which $23.7 million was due to fewer operating days and $15.0 million was due to lower average dayrates for our fleet. Average utilization was 65.9% in 2007 compared with 94.9% in 2006 primarily due to the stacking of rigs in 2007 and our customers’ lower drilling activity. Average revenue per rig per day was $73,952 in 2007 compared with $81,480 in 2006. Lower revenue per day also reflects our customers’ lower drilling activity. Revenues for our Domestic Offshore segment included $2.4 million and $1.1 million in reimbursements from our customers for expenses paid by us in 2007 and 2006, respectively.
 
International Offshore.  Revenues for our International Offshore segment were $144.8 million for 2007 compared with $30.5 million for 2006, an increase of $114.3 million, or 375%. Revenues for 2007 include approximately $65.1 million from TODCO. Excluding the impact of the acquisition, revenue increased by $49.2 million, of which $46.2 million was due primarily to additional operating days resulting from Hercules 258 being in service the entire period in 2007. Included in our revenues for the International Offshore segment is a total of $3.2 million and $2.6 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer for the year ended December 31, 2007 and 2006, respectively. In addition, revenues for our International Offshore segment included $1.5 million and $0.2 million in reimbursements from our customers for expenses paid by us in 2007 and 2006, respectively.
 
Inland.  Revenues for our Inland segment were $107.1 million in 2007, with 2,279 operating days and average revenue per rig per day of $46,994. Revenues for our Inland segment included $0.7 million in reimbursements from our customers for expenses paid by us in 2007. Prior to our acquisition of TODCO in July 2007, we did not have an Inland segment.
 
Domestic Liftboats.  Revenues for our Domestic Liftboats segment were $137.7 million for 2007 compared with $133.9 million in 2006, an increase of $3.8 million, or 3%. This increase resulted primarily from higher average dayrates, which contributed $11.5 million of the increase, and partially offset by fewer operating days, which contributed $7.7 million of a decrease. Operating days decreased to 11,265 in 2007 from 11,895 in 2006 due primarily to 264 days of severe weather in 2007 as compared to 2006. Average utilization also declined to 67.3% in 2007 from 77.2% in 2006 as customers’ repair and maintenance activities declined. Average revenue per vessel per day was $12,228 in 2007 compared with $11,259 in 2006. Revenues for our Domestic Liftboats segment included $5.6 million and $4.8 million in reimbursements from our customers for expenses paid by us in 2007 and 2006, respectively.
 
International Liftboats.  Revenues for our International Liftboats segment were $63.3 million for 2007 compared with $19.1 million in 2006, an increase of $44.1 million, or 230%. This increase is primarily due to an acquisition in the fourth quarter 2006 which resulted in an increase in operating days from 1,765 days in 2006 to 5,077 days in 2007. Average revenue per liftboat per day was $12,464 in 2007 compared with $10,857 in 2006, with average utilization of 82.6% in 2007 compared with 87.9% in 2006. Revenues for our International Liftboats segment included $4.7 million and $1.4 million in reimbursements from our customers for expenses paid by us in 2007 and 2006, respectively.
 
Other.  Revenues for our Other segment were $72.4 million in 2007 and included $0.5 million in reimbursements from our customers for expenses paid by us in 2006. Prior to our acquisition of TODCO in July 2007, we did not have an Other segment.


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Operating Expenses
 
Consolidated.  Total operating expenses for 2007 were $376.5 million compared with $124.1 million in 2006, an increase of $252.3 million, or 203%. This increase is further described below.
 
Domestic Offshore.  Operating expenses for our Domestic Offshore segment were $122.1 million in 2007 compared with $51.8 million in 2006, an increase of $70.3 million, or 135%. Operating expenses for 2007 include approximately $67.9 million associated with the TODCO acquisition. Available days increased to 4,958 in 2007 from 2,078 in 2006. Average operating expenses per rig per day were slightly lower; $24,633 in 2007 compared with $24,957 in 2006. On a per day basis, average operating expenses per rig decreased primarily due to lower labor and insurance costs; partially offset by higher repairs and maintenance costs.
 
International Offshore.  Operating expenses for our International Offshore segment were $59.6 million in 2007 compared with $13.4 million in 2006, an increase of $46.2 million, or 345%. Operating expenses for 2007 include approximately $30.2 million associated with the TODCO acquisition. Available days increased to 1,625 in 2007 from 321 in 2006. Average operating expenses per rig per day were $36,673 in 2007 compared with $41,673 in 2006. Included in operating expense is $2.8 million and $1.6 million in amortization of deferred mobilization expense for 2007 and 2006, respectively.
 
Inland.  Operating expenses for our Inland segment were $56.6 million in 2007, with 2,941 available days and average operating expenses per rig per day of $19,257. Prior to our acquisition of TODCO in July 2007, we did not have an Inland segment.
 
Domestic Liftboats.  Operating expenses for our Domestic Liftboats segment were $59.9 million in 2007 compared with $49.0 million in 2006, an increase of $10.9 million, or 22%. Available days increased to 16,749 in 2007 from 15,416 in 2006. Average operating expenses per vessel per day increased to $3,576 in 2007 compared with $3,180 in 2006, primarily from an increase in labor costs.
 
International Liftboats.  Operating expenses for our International Liftboats segment were $31.9 million for 2007 compared with $9.9 million in 2006, an increase of $22.0 million, or 223%. The increase is primarily due to additional liftboats acquired in the fourth quarter of 2006. Average operating expenses per liftboat per day were $5,184 in 2007 compared with $4,915 in 2006. This increase was driven primarily by higher repairs and maintenance, fuel and travel costs.
 
Other.  Operating expenses for our Other segment were $46.3 million in 2007. Prior to our acquisition of TODCO in July 2007, we did not have an Other segment.
 
Depreciation and Amortization
 
Depreciation and amortization expense in 2007 was $109.1 million compared with $32.3 million in 2006, an increase of $76.8 million, or 238%. This increase resulted primarily from additional depreciation of approximately $57.0 million related to assets acquired in the TODCO acquisition.
 
General and Administrative Expenses
 
General and administrative expenses in 2007 were $49.8 million compared with $29.8 million in 2006, an increase of $20.0 million, or 67%. The increase is primarily related to incremental general and administrative costs associated with TODCO, as well as a $10.9 million increase in corporate labor related costs, which includes $3.1 million in acquisition and severance related costs.
 
Interest Expense
 
Interest expense in 2007 was $36.1 million compared with $9.3 million in 2006, an increase of $26.8 million, or 289%. The increase was primarily due to interest on our borrowings under our new senior secured term loan.


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Loss on Early Retirement of Debt
 
The loss on early retirement of debt in the amount of $2.2 million related to the write off of deferred financing fees in connection with repayment of term loan principal in April and July 2007.
 
Other Income
 
Other income in 2007 was $6.3 million compared with $4.0 million in 2006, an increase of $2.3 million. This increase primarily related to additional interest income earned in 2007.
 
Income Tax Provision
 
Income tax expense was $63.0 million on pre-tax income of $199.5 million during 2007, compared to $64.5 million on pre-tax income of $183.5 million for 2006. The effective tax rate decreased to 31.6% in 2007 from 35.1% in 2006. The decrease in the effective tax rate results from a higher percentage of pretax income being derived from our international operations where a portion of such earnings are permanently reinvested. The decrease also reflects a lower overall state income tax rate.
 
2006 Compared to 2005
 
Revenues
 
Consolidated.  Total revenues for 2006 were $344.3 million compared with $161.3 million for 2005, an increase of $183.0 million, or 113%. This increase resulted primarily from higher average dayrates in our Domestic Offshore and Domestic Liftboats segments, additional operating days in our Domestic and International Liftboats segments, due primarily to the acquisition of liftboats since June 2005, and the commencement of operations in our International Offshore segment in 2006. Total revenues included $7.5 million in reimbursements from our customers for expenses paid by us in 2006 compared with $4.6 million in 2005.
 
Domestic Offshore.  Revenues for our Domestic Offshore segment were $160.8 million for 2006 compared with $103.4 million for 2005, an increase of $57.4 million, or 56%. This increase resulted primarily from higher average dayrates for our fleet, which accounted for $75.2 million partially offset by $17.8 million related to reduced utilization on four of our rigs, two of which sustained damage during Hurricane Katrina in August 2005. Operating days decreased to 1,973 in 2006 from 2,192 in 2005. Rig 25 did not operate in 2006 and was scrapped due to damage sustained in Hurricane Katrina, and operated 235 days in 2005. Three of our rigs were in the shipyard for repairs, upgrades and refurbishments during 2006, including Hercules 120, which sustained damage during Hurricane Katrina. Average revenue per rig per day was $81,480 in 2006 compared with $47,177 in 2005, with average utilization of 94.9% in both 2006 and 2005. Revenues for our Domestic Offshore segment included $1.1 million in reimbursements from our customers for expenses paid by us in 2006 compared with $2.3 million in 2005.
 
International Offshore.  As of December 31, 2006, our International Offshore segment comprised one jackup rig working offshore Qatar, one jackup rig working offshore India and a third jackup rig undergoing upgrade and refurbishment. Revenues for our International Offshore segment were $30.5 million for 2006. Average revenue per rig per day was $99,868, operating days were 305 and average utilization was 95.0% in 2006. Included in revenue for 2006 is $2.6 million related to amortization of deferred mobilization revenue and contract specific capital expenditures reimbursed by the customer. Revenues in our International Offshore segment include reimbursements from our customers of $0.2 million for expenses paid by us. We did not have an International Offshore segment in 2005.
 
Domestic Liftboats.  Revenues for our Domestic Liftboats segment were $133.9 million for 2006 compared with $55.7 million in 2005, an increase of $78.2 million, or 140%. This increase resulted primarily from additional operating days, which contributed $37.4 million, and higher average dayrates, which contributed $40.8 million. Operating days in 2006 were 11,895 compared with 8,571 operating days in 2005, with the increase due primarily to acquisitions. Average revenue per liftboat per day was $11,259 in 2006 compared with $6,503 in 2005, with average utilization of 77.2% in 2006 compared with 78.1% in 2005. The increase in average dayrates was attributable primarily to increased demand in the aftermath of Hurricane


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Katrina and Hurricane Rita. Revenues for our Domestic Liftboats segment included $4.8 million in reimbursements from our customers for expenses paid by us in 2006 compared with $2.3 million in 2005.
 
International Liftboats.  Revenues for our International Liftboats segment were $19.1 million for 2006 compared with $2.2 million in 2005, an increase of $16.9 million, or 768%. This increase is due to acquisition activity which resulted in an increase in operating days from 212 days in 2005 to 1,765 days in 2006. Average revenue per liftboat per day was $10,857 in 2006 compared with $10,243 in 2005, with average utilization of 87.9% in 2006 compared with 100.0% in 2005. Revenues for our International Liftboats segment included $1.4 million in reimbursements from our customers for expenses paid by us in 2006. There was no reimbursable income in our International Liftboats segment in 2005.
 
Operating Expenses
 
Consolidated.  Total operating expenses for 2006 were $124.1 million compared with $77.8 million in 2005, an increase of $46.3 million, or 60%. This increase resulted primarily from the increase in rig and liftboat operating expenses described below.
 
Domestic Offshore.  Operating expenses for our Domestic Offshore segment were $51.8 million in 2006 and $48.3 million in 2005, an increase of $3.5 million or 7%. A $1.0 million deductible was recorded in 2005 for damage sustained by one of our rigs during Hurricane Katrina. Available days decreased to 2,078 in 2006 from 2,309 in 2005. Average operating expenses per rig per day were $24,957 in 2006 compared with $20,932 in 2005. The increase in operating expense per rig per day is due in part to the inclusion of operating expenses for Hercules 120 during 2006 while the rig was undergoing repairs for damage sustained during Hurricane Katrina partially offset by a $1.0 million insurance deductible in 2005. Hercules 120 was in the shipyard for 112 days in 2006. On a per day basis, average operating expenses per rig increased $4,025. The increase resulted primarily from an increase in labor expenses, which increased $2,412 per day, an increase in insurance costs, which increased $1,854 per day, and an increase in rig maintenance costs, which increased $763 per day.
 
International Offshore.  Operating expenses for our International Offshore segment were $13.4 million for 2006, and averaged $41,673 per rig per day. Included in operating expense is $1.6 million related to amortization of deferred mobilization expense. We did not have an International Offshore segment in 2005.
 
Domestic Liftboats.  Operating expenses for our Domestic Liftboats segment were $49.0 million for 2006 compared with $28.4 million in 2005, an increase of $20.6 million, or 73%. The increase is primarily due to liftboat acquisitions and additional operating days. Average operating expenses per liftboat per day were $3,180 in 2006 compared with $2,590 in 2005. This increase resulted primarily from an increase in labor expenses, which increased $366 per day, an increase in insurance costs, which increased $97 per day, and an increase in liftboat maintenance costs, which increased $92 per day.
 
International Liftboats.  Operating expenses for our International Liftboats segment were $9.9 million for 2006 compared with $1.1 million in 2005, an increase of $8.8 million, or 800%. The increase is due to additional liftboats acquired. Average operating expenses per liftboat per day were $4,915 in 2006 compared with $5,052 in 2005.
 
Depreciation and Amortization
 
Depreciation and amortization expense in 2006 was $32.3 million compared with $13.8 million in 2005, an increase of $18.5 million, or 134%. This increase resulted primarily from an additional $3.3 million in depreciation expense for our Domestic Offshore segment, $4.1 million for our Domestic Liftboats segment and $1.8 million for our International Liftboats segment. This increase in depreciation expense for these segments is related primarily to acquisition activity during 2005 and 2006. Depreciation expense for our International Offshore segment was $2.5 million. Additionally, amortization of regulatory inspections and related drydockings increased $6.8 million.


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General and Administrative Expenses
 
General and administrative expenses in 2006 were $29.8 million compared with $13.9 million in 2005, an increase of $15.9 million, or 114%. General and administrative expenses for our corporate office increased from $6.2 million in 2005 to $15.9 million in 2006, an increase of $9.7 million. This increase is due to increased headcount, additional professional fees related to increased regulatory requirements as a public company and additional stock-based compensation expense of $3.0 million. General and administrative expenses related to our segments increased $6.2 million primarily associated with our international expansion.
 
Gain on Disposal of Assets
 
The gain on disposal of assets in 2006 of $30.7 million consisted of $29.6 million related to the insurance settlement on the loss of Rig 25 in Hurricane Katrina and $1.1 million related to the gain on the sale of Rig 41. There was no gain on disposal of assets in 2005.
 
Income Tax Provision
 
Income tax expense was $64.5 million on pre-tax income of $183.5 million during 2006, compared to $15.4 million on pre-tax income of $42.8 million for 2005. On November 1, 2005, in connection with our initial public offering, we converted from a limited liability company to a corporation. Prior to the conversion, we elected to be taxed as a partnership. As such, the members of our company were taxed on their proportionate share of net income prior to the conversion and no provision or liability for income taxes was included in our consolidated financial statements. When we became a taxable entity in the conversion, a provision of approximately $12.1 million was made reflecting the tax effect of the difference between the book and tax basis of our assets and liabilities as of November 1, 2005, the effective date of the conversion. The tax rate was 35.1% in 2006 and 35.9% in 2005.
 
Critical Accounting Policies
 
Critical accounting policies are those that are important to our results of operations, financial condition and cash flows and require management’s most difficult, subjective or complex judgments. Different amounts would be reported under alternative assumptions. We have evaluated the accounting policies used in the preparation of the consolidated financial statements and related notes appearing elsewhere in this annual report. We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with accounting principles generally accepted in the United States. We believe that our policies are generally consistent with those used by other companies in our industry.
 
We periodically update the estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. Our significant accounting policies are summarized in Note 1 to our consolidated financial statements. We believe that our more critical accounting policies include those related to cash and cash equivalents and marketable securities, goodwill, other intangible assets, property and equipment, revenue recognition, income tax, allowance for doubtful accounts, deferred charges and stock-based compensation. Inherent in such policies are certain key assumptions and estimates.
 
Cash and Cash Equivalents and Marketable Securities
 
Beginning in March 2007, we began investing a portion of our available cash in marketable securities. Marketable securities are classified as available for sale and are stated at fair value on the Consolidated Balance Sheets. At December 31, 2007, we had marketable securities with a fair value and cost basis of $39.3 million. Proceeds of $112.4 million were received from sales and maturities of marketable securities for the year ended December 31, 2007. There were no realized or unrealized gains or losses related to these securities.
 
Cash and cash equivalents include cash on hand, demand deposits with banks and all highly liquid investments with original maturities of three months or less. Realized and unrealized gains and losses related


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to marketable securities are calculated using the specific identification method. Unrealized gains or losses, net of taxes, are included in Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheets until realized. Realized gains or losses are included in Other, Net in the Consolidated Statements of Operations.
 
Goodwill
 
As of December 31, 2007, we had $940.2 million of goodwill. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”), we are required to test for the impairment of goodwill and other intangible assets with indefinite lives on at least an annual basis. Our goodwill impairment test involves a comparison of the fair value of each of our reporting units, as defined under SFAS No. 142, with its carrying amount. Fair value is estimated using discounted cash flows and other market-related valuation models, including earnings multiples and comparable asset market values. If the fair value is determined to be less than the carrying value, the asset is considered impaired. The amount of the impairment, if any, is determined based on an allocation of the reporting unit fair values. We will test goodwill for impairment as of October 1 and will test it annually on that date unless changes occur between annual test dates that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Our 2007 impairment test indicated that goodwill was not impaired.
 
Other Intangible Assets
 
In connection with the acquisition of TODCO, we allocated $17.6 million in value to certain international customer contracts within the International Offshore segment. The estimated fair value of these acquired contracts is based on preliminary valuations and is subject to change when final valuations are obtained. These contracts are being amortized over the life of the contracts. As of December 31, 2007, the customer contracts had a carrying value of $14.8 million, net of accumulated amortization of $2.8 million, and are included in Other Assets, Net on the Consolidated Balance Sheet.
 
Amortization expense was $2.8 million for the year ended December 31, 2007. Future estimated amortization expense for the carrying amount of intangible assets as of December 31, 2007 is expected to be as follows (in thousands):
 
         
2008
  $ 8,088  
2009
    4,658  
2010
    1,466  
2011
    607  
2012
     
 
Property and Equipment
 
Property and equipment represents 56.6% of our total assets as of December 31, 2007. Property and equipment is stated at cost, less accumulated depreciation. Expenditures that substantially increase the useful lives of our assets are capitalized and depreciated, while routine expenditures for maintenance items are expensed as incurred, except for expenditures for drydocking our liftboats. Drydock costs are capitalized at cost as Other Assets, Net on the Consolidated Balance Sheets and amortized on the straight-line method over a period of 12 months (see “Deferred Charges” below). Depreciation is computed using the straight-line method, after allowing for salvage value where applicable, over the useful life of the asset, which is typically 15 years for our rigs and liftboats. We review our property and equipment for potential impairment when events or changes in circumstances indicate that the carrying value of any asset may not be recoverable. For property and equipment, the determination of recoverability is made based on the estimated undiscounted future net cash flows of the assets being reviewed. Any actual impairment charge would be recorded using the estimated discounted value of future cash flows. Our estimates, assumptions and judgments used in the application of our property and equipment accounting policies reflect both historical experience and expectations regarding future industry conditions and operations. Using different estimates, assumptions and judgments, especially those involving the useful lives of our rigs and liftboats and expectations regarding


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future industry conditions and operations, would result in different carrying values of assets and results of operations. For example, a prolonged downturn in the drilling industry in which utilization and dayrates were significantly reduced could result in an impairment of the carrying value of our jackup rigs.
 
Revenue Recognition
 
Revenues are generated from our rigs and liftboats working under dayrate contracts as the services are provided. Some of our contracts also allow us to recover additional direct costs, including mobilization and demobilization costs, additional labor and additional catering costs. Additionally, some of our contracts allow us to receive fees for contract specific capital improvements to a rig. Under most of our liftboat contracts, we receive a variable rate for reimbursement of costs such as catering, fuel, oil, rental equipment, crane overtime and other items. Revenue for the recovery or reimbursement of these costs is recognized when the costs are incurred except for mobilization revenues and reimbursement for contract specific capital expenditures, which are amortized over the related drilling contract.
 
Income Taxes
 
We provide for income taxes in accordance with SFAS No. 109, Accounting for Income Taxes. This standard takes into account the differences between the financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date.
 
Our net income tax expense or benefit is determined based on the mix of domestic and international pre-tax earnings or losses, respectively, as well as the tax jurisdictions in which we operate. We currently operate in nine countries through various legal entities. As a result, we are subject to numerous domestic and foreign tax jurisdictions and are taxed on various bases: income before tax, deemed profits (which is generally determined using a percentage of revenue rather than profits), and withholding taxes based on revenue. The calculation of our tax liabilities involves consideration of uncertainties in the application and interpretation of complex tax regulations in our operating jurisdictions. Changes in tax laws, regulations, agreements and treaties, or our level of operations or profitability in each taxing jurisdiction could have an impact upon the amount of income taxes that we provide during any given year.
 
Certain of our international rigs are owned or operated, directly or indirectly, by our wholly owned Cayman Islands subsidiaries. Most of the earnings from these subsidiaries are reinvested internationally and remittance to the United States is indefinitely postponed. We recognized $0.9 million of deferred U.S. tax expense on foreign earnings which management expects to repatriate in the future.
 
Allowance for Doubtful Accounts
 
Accounts receivable represents approximately 6.1% of our total assets and 37.5% of our current assets as of December 31, 2007. We continuously monitor our accounts receivable from our customers to identify any collectability issues. An allowance for doubtful accounts is established when a review of customer accounts indicates that a specific amount will not be collected. We establish an allowance for doubtful accounts based on the actual amount we believe is not collectable. As of December 31, 2007, there was $0.6 million in allowance for doubtful accounts.
 
Deferred Charges
 
All of our U.S. flagged liftboats are required to undergo regulatory inspections on an annual basis and to be drydocked two times every five years to ensure compliance with U.S. Coast Guard regulations for vessel safety and vessel maintenance standards. Costs associated with these inspections, which generally involve setting the vessels on a drydock, are deferred, and the costs are amortized over a period of 12 months. As of


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December 31, 2007, our net deferred charges related to regulatory inspection costs totaled $6.8 million. The amortization of the regulatory inspection costs was reported as part of our depreciation and amortization expense.
 
Stock-Based Compensation
 
On January 1, 2006, we adopted the modified prospective provisions of SFAS No. 123 (revised 2004) “Share-Based Payment” (“SFAS No. 123R”). Prior to the adoptions of SFAS No. 123R, we followed the intrinsic value method as prescribed in Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees” (“APB Opinion 25”) and related interpretations. SFAS No. 123R requires that compensation cost for stock options is recognized beginning with the effective date based on the requirements of (a) SFAS No. 123R for all share-based payments granted after January 1, 2006 and (b) SFAS No. 123 for all share-based payments granted to employees prior to January 1, 2006 that remain unvested on January 1, 2006. SFAS No. 123R requires that any unearned compensation related to share-based payments awarded prior to adoption be eliminated against the appropriate equity account. Under the new standard, our estimate of compensation expense will require a number of complex and subjective assumptions including our stock price volatility, employee exercise patterns (expected life of the options), future forfeitures and related tax effects.
 
We are estimating that the cost relating to stock options granted through December 31, 2007 will be $5.8 million over the remaining vesting period of 1.4 years and the cost relating to restricted shares granted through December 31, 2007 will be $6.0 million over the remaining vesting period of 1.8 years; however, due to the uncertainty of the level of share-based payments to be granted in the future, these amounts are estimates and subject to change.
 
Outlook
 
Offshore
 
In general, demand for our drilling rigs is a function of our customers’ capital spending plans, which are largely driven by their cash flow generated from commodity production and their expectations of future commodity prices. Demand in the U.S. Gulf of Mexico is particularly driven by natural gas prices, with demand internationally typically driven by oil prices. Both natural gas and oil prices are higher than historical levels and are generally supportive of increased capital spending for exploration and production activities.
 
As of February 15, 2008, the spot price for Henry Hub natural gas was $8.73 per MMBtu and the twelve month strip, or the average of the next twelve month’s futures contract was $9.06 per MMBtu. Declining reservoir sizes and increasing initial decline rates in North America have been supportive of natural gas prices, while increased onshore drilling activity, growing deepwater production and increasing liquefied natural gas deliveries have played a role in driving natural gas storage higher. These factors, together with weather and industrial demand, will likely remain key drivers in the natural gas market for the foreseeable future.
 
Oil prices have remained at high levels relative to historical prices for the past several years with the spot price for West Texas intermediate crude ranging from $50.48 to $99.62 per bbl since the beginning of 2006. As of February 15, 2008, the price of WTI was $95.50 with a twelve month strip of $94.23. Stronger oil prices have largely been driven by extremely strong demand growth in China and India, continued economic growth in OECD countries, and the ongoing weakness in the U.S. dollar.
 
Global demand for jackup rigs has increased significantly over the last several years with international regions such as the Middle East, India and Mexico being particularly strong. Demand for jackups worldwide, excluding the U.S. Gulf of Mexico, increased from 200 in 2001 to 319 in February 2008. This international demand has drawn available rigs from the U.S. Gulf of Mexico. As a result, the supply of jackup rigs in the U.S. Gulf of Mexico has declined considerably over the last several years from a high of 157 jackups in 2001 to only 80 currently, according to published industry sources. With several of these rigs either in the shipyard or cold stacked, the marketed supply of jackups in the U.S. Gulf of Mexico is currently approximately 65.
 
Demand for jackup rigs in the U.S. Gulf of Mexico has also declined considerably over the last two years to 51 as of February 2008 from 88 in January 2006. A combination of factors has resulted in this decline from


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the levels experienced over the previous several years, including high levels of natural gas storage during late 2006 and 2007, combined with declining target reservoir sizes, increasing finding, development and lifting costs and the significant amount of property transfers. Subsequent to the 2005 hurricanes, the seasonal decline in activity during hurricane season has been more pronounced as our customers have curtailed activity in response to their risk profiles. We believe that the further reduction in supply in the U.S. Gulf of Mexico due to rigs mobilizing to international locations could mitigate the impact of recent reduced drilling demand.
 
In addition to spurring migration of rigs out of the U.S., strong global demand for jackups over the past few years has encouraged newbuilds. According to ODS-Petrodata, as of February 8, 2008, 85 jackup rigs have been ordered by industry participants, national oil companies and financial investors for delivery through 2011. We anticipate that these rigs will compete directly with our fleet in international regions. As a result of higher dayrates, longer duration contracts and lower insurance costs, which are prevalent internationally, among other factors, we believe the vast majority of the new build jackup rigs will target international regions and not the U.S. Gulf of Mexico. Our ability to expand our international drilling fleet may be limited, however, by the increased supply of newbuild jackup rigs.
 
The offshore drilling market remains highly competitive and cyclical, and it has historically been difficult to forecast future market conditions. While future commodity price expectations have historically been a key driver for demand for drilling rigs, other factors also affect our customers’ drilling programs, including the quality of drilling prospects, exploration success, relative production costs, availability of insurance and political and regulatory environments. Additionally, the offshore drilling business has historically been cyclical, marked by periods of low demand, excess rig supply and low dayrates, followed by periods of high demand, short rig supply and increasing dayrates. These cycles have been volatile and are subject to rapid change.
 
Inland
 
The market for inland barge drilling in the U.S. generally follows the same drivers as drilling in the U.S. Gulf of Mexico with demand following operators’ expectations of prices for natural gas and, to a lesser degree, crude oil. However, given the lengthy permitting process that operators must go through prior to drilling a well in Louisiana, where the majority of our inland drilling takes place, activity for inland barges sometimes lags activity in the U.S. Gulf of Mexico.
 
Inland barge drilling activity has slowed over the past year and dayrates have also softened. However, based on recent discoveries and discussion with our customers, we remain optimistic about deeper targets in the inland barge area and believe this may generate growth opportunities as the trend toward deeper drilling in shallow water expands.
 
Liftboats
 
Although activity levels for liftboats in the U.S. Gulf of Mexico are not as closely correlated to movement in commodity prices as for offshore drilling rigs, a weakening in commodity prices could result in lower utilization of our liftboat fleet. Lower commodity prices tend to result in lower cash flows for our customers and, despite the production maintenance related nature of the majority of the work, some of the work may be deferred.
 
As of February 20, 2008, we believe that there were ten liftboats under construction or on order in the U.S. that may be used in the U.S. Gulf of Mexico, with anticipated delivery dates during 2008. Once delivered, these liftboats may impact the demand and utilization of our domestic liftboat fleet.
 
Our customers’ growth in international capital spending, coupled with an aging infrastructure and significant increases in the cost of alternatives for servicing this infrastructure, has generally resulted in strong demand for our liftboats in West Africa. We anticipate that demand for liftboats will likely increase in West Africa and other international locations as these markets mature and the focus shifts from exploration to development and new platforms and other infrastructure is installed. We anticipate that there will be longer term contract opportunities in international locations for liftboats currently working in the U.S. Gulf of Mexico and for newly constructed liftboats. While we believe that international demand for liftboats will continue to


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increase, the political instability in certain regions may negatively impact our customers’ capital spending plans. We are actively marketing a number of our liftboats currently operating in the U.S. Gulf of Mexico for projects in international locations, which have long-term contract opportunities.
 
Labor Markets
 
We require highly skilled personnel to operate our rigs, barges and liftboats and to support our business. Competition for skilled rig personnel could intensify as 164 new offshore rigs are under construction and 57 are scheduled to enter the global fleet during 2008. If competition for personnel intensifies, our labor costs will likewise increase, although we do not believe at this time that our operations will be limited. We respond to competition though retention programs, including increases in base compensation and bonuses tied to retention and utilization goals.
 
We have also experienced a tightening in the labor market for liftboat and marine personnel. We have instituted retention programs, along with additional programs that may become necessary to retain skilled personnel, to continue for the foreseeable future.
 
LIQUIDITY AND CAPITAL RESOURCES
 
Sources and Uses of Cash
 
Sources and uses of cash for 2007 and 2006 is as follows:
 
                 
    2007     2006  
 
Net Cash Provided by Operating Activities
  $ 178.3     $ 124.2  
Net Cash Provided by (Used in) Investing Activities
               
Acquisition of Business, Net of Cash Acquired
    (728.4 )      
Investment in Marketable Securities, Net
    (39.3 )      
Additions to Property and Equipment
    (155.4 )     (204.5 )
Deferred Drydocking Expenditures
    (20.8 )     (12.5 )
Proceeds from Sale of Assets, Net
    109.7       6.0  
Insurance Proceeds Received
    4.3       61.3  
Other
    4.9       (0.2 )
                 
Total
    (825.0 )     (149.9 )
                 
Net Cash Provided by (Used in) Financing Activities
               
Long-term and Short-term Debt Borrowings, Net of Repayments
    800.9       (1.4 )
Proceed from Issuance of Common Stock
          54.2  
Payment of Debt Issuance Costs
    (17.8 )     (0.6 )
Other
    3.3       (1.3 )
                 
Total
    786.4       50.9  
                 
Net Increase in Cash and Cash Equivalents
  $ 139.7     $ 25.2  
                 
 
Sources of Liquidity and Financing Arrangements
 
Our sources of liquidity include current cash and cash equivalent balances, marketable securities, cash generated from operations and committed availability under our revolving credit facility. We also maintain a shelf registration statement covering the future issuance of various types of securities, including debt and equity; however, our senior secured credit facility restricts issuance of additional debt.
 
Additional capital in either the form of debt or equity may be required in 2008 if we generate less than expected cash due to a deterioration of market conditions or other factors beyond our control, or if other acquisitions necessitate additional liquidity. Our future cash flows may be insufficient to meet all of our debt


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obligations and commitments, and any insufficiency could negatively impact our business. To the extent we are unable to repay our indebtedness as it becomes due at maturity with cash on hand or from other sources, we will need to refinance our debt, sell assets or repay the debt with the proceeds from further equity offerings. Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, and we can provide no assurance as to the timing of any asset sales or the proceeds that could be realized by us from any such asset sale.
 
Cash Requirements and Contractual Obligations
 
Pending Asset Acquisition
 
In February 2008, we entered into a definitive agreement to purchase three jackup drilling rigs and related equipment for approximately $320.0 million. Closing of the transaction is subject to regulatory approvals and other customary conditions. We plan to fund the acquisition with cash on hand and borrowings under our revolving credit facility.
 
TODCO Acquisition
 
In connection with the acquisition of TODCO in July 2007, we issued approximately 56.6 million of our shares of common stock and borrowed $900.0 million under a new senior secured term loan. Additionally, upon closing of the acquisition, we terminated our former credit facility and entered into a new $150.0 million revolving credit facility. In connection with the acquisition of TODCO, we assumed senior notes, an unsecured line of credit with a bank in Venezuela and surety bonds. The proceeds of the borrowings under the senior secured term loan were used, together with cash on hand, to finance the cash portion of our acquisition of TODCO, to repay amounts under TODCO’s senior secured credit facility outstanding at the closing of the facility and to make certain other payments in connection with the acquisition.
 
Debt
 
Our current debt structure is used to fund our business operations.
 
In July 2007, we terminated all prior facilities and we entered into a new $1,050.0 million credit facility, consisting of a $900.0 million term loan and a $150.0 million revolving credit facility. All borrowings under the revolving credit facility mature on July 11, 2012, and the revolving credit facility requires interest-only payments on a quarterly basis until the maturity date. Amounts outstanding under the revolving credit facility bear interest at either the eurodollar rate or the base prime rate plus a margin. The applicable margin under the revolving credit facility varies depending on our leverage ratio, with the applicable margin for revolving loans bearing interest at the eurodollar rate ranging between 1.25% and 1.75% per annum and the applicable margin for revolving loans bearing interest at the base prime rate ranging between 0.25% and 0.75% per annum. We pay a commitment fee on the unused portion of the revolving credit facility, which ranges between 0.25% and 0.375% depending on our leverage ratio. We pay a letter of credit fee of between 1.25% and 1.75% per annum with respect to the undrawn amount of each letter of credit issued under the revolving credit facility. No amounts were outstanding and $28.1 million in stand-by letters of credit had been issued under the revolving credit facility as of December 31, 2007. The remaining availability under this revolving credit facility was $121.9 million at December 31, 2007.
 
The principal amount of the term loan amortizes in equal quarterly installments of $2.25 million, with the balance due on July 11, 2013. In addition, we are required to prepay the term loan with:
 
  •  the net proceeds from sales of certain assets to the extent that we do not reinvest the proceeds in our business within one year;
 
  •  the net proceeds from casualties or condemnations of assets to the extent that we do not reinvest the proceeds in our business within one year;
 
  •  the net proceeds of debt that we incur to the extent that such debt is not permitted by the credit agreement;


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  •  50% of the net proceeds that we receive from any issuance of preferred stock; and
 
  •  commencing with the fiscal year ending December 31, 2008, 50% of our excess cash flow until the outstanding principal balance of the term loan is less than $550.0 million.
 
Other than the quarterly payments referred to above and these mandatory prepayments, the term loan facility requires interest-only payments on a quarterly basis until maturity. We are permitted to prepay amounts outstanding under the term loan facility at any time without penalty. Amounts outstanding under the term loan facility bear interest at either the eurodollar rate or the base prime rate plus a margin. The applicable margin under the term loan facility varies depending on our leverage ratio, with the applicable margin for term loans bearing interest at the eurodollar rate ranging between 1.50% and 1.75% per annum and the applicable margin for term loans bearing interest at the base prime rate ranging between 0.50% and 0.75% per annum. As of December 31, 2007, $895.5 million was outstanding on the term loan facility and the interest rate was 6.58%. The annualized effective interest rate was 7.06% at December 31, 2007 after giving consideration to derivative activity.
 
Our obligations under the credit agreement are secured by liens on several of our vessels and substantially all of our other personal property. Substantially all of our domestic subsidiaries guarantee our obligations under the credit agreement and have granted similar liens on several of their vessels and substantially all of their other personal property.
 
The credit agreement contains financial covenants that are tested quarterly relating to leverage and fixed charge coverage. Other covenants contained in the credit agreement restrict, among other things, asset dispositions, mergers and acquisitions, dividends, stock repurchases and redemptions, other restricted payments, debt, liens, investments and affiliate transactions. The credit agreement contains customary events of default. We were in compliance with these financial covenants at December 31, 2007.
 
In July 2007, we entered into derivative instruments with the purpose of hedging future interest payments on our new term loan facility. We entered into a floating to fixed interest rate swap with decreasing notional amounts beginning with $400.0 million with a settlement date of December 31, 2007 and ending with $50.0 million with a settlement date of April 1, 2009. We receive an interest rate of three-month LIBOR and pay a fixed coupon of 5.307% over six quarters. The terms and settlement dates of the swap match those of the term loan. We also entered into a zero cost LIBOR collar on $300.0 million of term loan principal over three years, with a ceiling of 5.75% and a floor of 4.99%. The counterparty is obligated to pay us in any quarter that actual LIBOR resets above 5.75% and we pay the counterparty in any quarter that actual LIBOR resets below 4.99%. The terms and settlement dates of the collar match those of the term loan. The effective interest rate is determined after giving consideration to amortization of original issue discount premium and fair value adjustments. The following table provides the scheduled reduction in notional amounts related to the interest rate swap (in thousands):
 
         
December 31, 2007-March 31, 2008
  $ 350,000  
April 1, 2008-June 30, 2008
    300,000  
July 1, 2008-September 30, 2008
    200,000  
October 1, 2008-December 31, 2008
    100,000  
January 1, 2009-March 31, 2009
    50,000  
 
In connection with the TODCO acquisition in July 2007, we assumed senior notes and an unsecured line of credit with a bank in Venezuela. The senior notes include 6.95% Senior Notes due in April 2008, 7.375% Senior Notes due in April 2018 and 9.5% Senior Notes due in December 2008. The fair market value of these notes at December 31, 2007 was approximately $2.2 million, $3.7 million and $10.6 million, respectively. The line of credit is designed to manage local currency liquidity in Venezuela. The maximum amount available to be drawn is 6.0 billion Bolivars ($2.8 million at the exchange rate at December 31, 2007). There were no outstanding borrowings under the foreign line of credit at December 31, 2007. The weighted average interest rate on borrowings outstanding on the line of credit during the year ended December 31, 2007 was 17.7%.


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In July 2007, in connection with the renewal of certain of our insurance policies, we entered into agreements to finance a portion of our annual insurance premiums. Approximately $36.2 million was financed through these arrangements, and $16.9 million was outstanding at December 31, 2007. The interest rate on these notes is 5.75% and each note matures in June 2008.
 
Capital Expenditures
 
We expect to spend a total of $176 million on capital expenditures excluding acquisitions. We expect to spend approximately $110 million in 2008 on the refurbishment and upgrade of our rigs and liftboats, excluding amounts allocated to Hercules 185, Hercules 208, Hercules 258, Hercules 260, the Black Jack and our planned equipment standardization for top-drives and cranes. Costs associated with refurbishment or upgrade activities which substantially extend the useful life or operating capabilities of the asset are capitalized. Refurbishment entails replacing or rebuilding the operating equipment. An upgrade entails increasing the operating capabilities of a rig or liftboat. This can be accomplished by a number of means, including adding new or higher specification equipment to the unit, increasing the water depth capabilities or increasing the capacity of the living quarters, or a combination of each.
 
We expect to spend $66 million relating to the continuing contract preparation work for Hercules 258 and Hercules 260, the completion of the refurbishment of the Hercules 208 and the Black Jack, the repairs and leg extension on Hercules 185 and the planned standardization of certain core equipment. We expect to spend approximately $15 million in 2008 to repair and complete the leg extension on Hercules 185, approximately $10 million to complete the refurbishment of the Hercules 208 and approximately $12 million and $9 million to complete the contract preparation work for Hercules 258 and Hercules 260, respectively, as well as $3 million to complete the refurbishment of the Black Jack. In addition, we expect to spend approximately $17 million to standardize our fleet’s top-drive and crane equipment in order to maximize the number of available drilling days by reducing our fleet’s unplanned downtime.
 
We are required to inspect and drydock our liftboats on a periodic basis to meet U.S. Coast Guard requirements. The amount of expenditures is impacted by a number of factors, including, among others, our ongoing maintenance expenditures, adverse weather, changes in regulatory requirements and operating conditions. In addition, from time to time we agree to perform modifications to our rigs and liftboats as part of a contract with a customer. When market conditions allow, we attempt to recover these costs as part of the contract cash flow.
 
The timing and amounts we actually spend in connection with our plans to upgrade and refurbish other selected rigs and liftboats are subject to our discretion and will depend on our view of market conditions and our cash flows. From time to time, we may review possible acquisitions of rigs, liftboats or businesses, joint ventures, mergers or other business combinations, and we may have outstanding from time to time bids to acquire certain assets from other companies. We may not, however, be successful in our acquisition efforts. If we do complete any such acquisitions, we may make significant capital commitments for such purposes. Any such transactions could involve the payment by us of a substantial amount of cash. We would likely fund the cash portion of such transactions, if any, through cash balances on hand, the incurrence of additional debt, or sales of assets, equity interests or other securities or a combination thereof. If we acquire additional assets, we would expect that the ongoing capital expenditures for our company as a whole would increase in order to maintain our equipment in a competitive condition.
 
Our ability to fund capital expenditures would be adversely affected if conditions deteriorate in our business, we experience poor results in our operations or we fail to meet covenants under our term loan facility.
 
Contractual Obligations
 
Our contractual obligations and commitments principally include obligations associated with our outstanding indebtedness, surety bonds, letters of credit, future minimum operating lease obligations, purchase commitments and management compensation obligations. During 2007, there were no material changes outside the ordinary course of business in the specified contractual obligations, except in connection with our acquisition of TODCO on July 11, 2007.


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The following table summarizes our contractual obligations and contingent commitments by period as of December 31, 2007:
 
                                         
    Payments due by Period  
Contractual Obligations and
  Less than
    1-3
    4-5
    After 5
       
Contingent Commitments
  1 Year     Years     Years     Years     Total  
                (In thousands)              
 
Recorded Obligations:
                                       
Long-term debt obligations
  $ 21,427     $ 18,000     $ 18,000     $ 854,008     $ 911,435  
Insurance note payable
    16,931                         16,931  
Other
    408                         408  
Unrecorded Obligations:
                                       
Letters of credit
    1,494       17,000       9,961             28,455  
Surety Bonds
    46,401       19,456                   65,857  
Management compensation obligations
    3,578       1,989                   5,567  
Purchase obligations (a)
    46,212                         46,212  
Operating lease obligations
    2,230       2,108       2,118       5,971       12,427  
                                         
Total contractual obligations
  $ 138,681     $ 58,553     $ 30,079     $ 859,979     $ 1,087,292  
                                         
 
 
(a) A “purchase obligation” is defined as an agreement to purchase goods or services that is enforceable and legally binding on the company and that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. These amounts are primarily comprised of open purchase order commitments to vendors and subcontractors.
 
Off-Balance Sheet Arrangements
 
Guarantees
 
Our obligations under the credit agreement are secured by liens on several of our vessels and substantially all of our other personal property. Substantially all of our domestic subsidiaries guarantee the obligations under the credit agreement and have granted similar liens on several of their vessels and substantially all of their other personal property.
 
Letters of Credit and Surety Bonds
 
We execute letters of credit and surety bonds in the normal course of business. While these obligations are not normally called, these obligations could be called by the beneficiaries at any time before the expiration date should we breach certain contractual or payment obligations. As of December 31, 2007, we had $94.4 million of letters of credit and surety bonds outstanding, consisting of $0.4 million in unsecured outstanding letters of credit, $28.1 million letters of credit outstanding under our revolver and $65.9 million outstanding in surety bonds that guarantee our performance as it relates to TODCO’s drilling contracts, insurance, tax and other obligations in various jurisdictions. If the beneficiaries called these letters of credit and surety bonds, the called amount would become an on-balance sheet liability, and our available liquidity would be reduced by the amount called.
 
Accounting Pronouncements
 
In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141(R), Business Combinations (“SFAS No. 141R”). SFAS No. 141R replaces SFAS No. 141, Business Combinations, and applies to all transactions and other events in which one entity obtains control over one or more other businesses. SFAS No. 141R requires an acquirer, upon initially obtaining control of another entity, to recognize the assets, liabilities and any non-controlling interest in the acquiree at fair value as of the acquisition date. Contingent consideration is required to be recognized and measured at fair value on the date of acquisition


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rather than at a later date when the amount of that consideration may be determinable beyond a reasonable doubt. This fair value approach replaces the cost-allocation process required under SFAS No. 141 whereby the cost of an acquisition was allocated to the individual assets acquired and liabilities assumed based on their estimated fair value. SFAS No. 141R requires acquirers to expense acquisition-related costs as incurred rather than allocating such costs to the assets acquired and liabilities assumed, as was previously the case under SFAS No. 141. Under SFAS No. 141R, the requirements of SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities would have to be met in order to accrue for a restructuring plan in purchase accounting. Pre-acquisition contingencies are to be recognized at fair value, unless it is a non-contractual contingency that is not likely to materialize, in which case, nothing should be recognized in purchase accounting and, instead, that contingency would be subject to the probable and estimable recognition criteria of SFAS No. 5, Accounting for Contingencies. SFAS No. 141R may have a significant impact on our accounting for business combinations closing on or after January 1, 2009.
 
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”). SFAS No. 159 permits companies to choose to measure certain financial instruments and certain other items at fair value. The standard requires that unrealized gains and losses on items for which the fair value option has been elected be reported in earnings. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We are evaluating the impact, if any, that SFAS No. 159 will have on our financial position, results of operations and cash flows.
 
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements, rather, its application will be made pursuant to other accounting pronouncements that require or permit fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The provisions of SFAS No. 157 are to be applied prospectively upon adoption, except for limited specified exceptions. We are evaluating the requirements of SFAS No. 157 and do not expect the adoption to have a material impact on our financial position, results of operations and cash flows.
 
FORWARD-LOOKING STATEMENTS
 
This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this annual report that address activities, events or developments that we expect, project, believe or anticipate will or may occur in the future are forward-looking statements. These include such matters as:
 
  •  our ability to enter into new contracts for our rigs and liftboats and future utilization rates for the units;
 
  •  the correlation between demand for our rigs and our liftboats and our earnings and customers’ expectations of energy prices;
 
  •  future capital expenditures and refurbishment, repair and upgrade costs;
 
  •  expected completion times for our refurbishment and upgrade projects;
 
  •  sufficiency of funds for required capital expenditures, working capital and debt service;
 
  •  our plans regarding increased international operations;
 
  •  expected useful lives of our rigs and liftboats;
 
  •  liabilities under laws and regulations protecting the environment;
 
  •  expected outcomes of litigation, claims and disputes and their expected effects on our financial condition and results of operations; and


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  •  expectations regarding improvements in offshore drilling activity and dayrates, continuation of current market conditions, demand for our rigs and liftboats, operating revenues, operating and maintenance expense, insurance expense and deductibles, interest expense, debt levels and other matters with regard to outlook.
 
We have based these statements on our assumptions and analyses in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Forward-looking statements by their nature involve substantial risks and uncertainties that could significantly affect expected results, and actual future results could differ materially from those described in such statements. Although it is not possible to identify all factors, we continue to face many risks and uncertainties. Among the factors that could cause actual future results to differ materially are the risks and uncertainties described under “Risk Factors” in Item 1A of this annual report and the following:
 
  •  oil and natural gas prices and industry expectations about future prices;
 
  •  demand for offshore jackup rigs and liftboats;
 
  •  our ability to enter into and the terms of future contracts;
 
  •  the worldwide military and political environment, uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East and other oil and natural gas producing regions or further acts of terrorism in the United States, or elsewhere;
 
  •  the impact of governmental laws and regulations;
 
  •  the adequacy of sources of liquidity;
 
  •  uncertainties relating to the level of activity in offshore oil and natural gas exploration, development and production;
 
  •  competition and market conditions in the contract drilling and liftboat industries;
 
  •  the availability of skilled personnel;
 
  •  labor relations and work stoppages, particularly in the West African and Venezuelan labor environments;
 
  •  operating hazards such as severe weather and seas, fires, cratering, blowouts, war, terrorism and cancellation or unavailability of insurance coverage;
 
  •  the effect of litigation and contingencies; and
 
  •  our inability to achieve our plans or carry out our strategy.
 
Many of these factors are beyond our ability to control or predict. Any of these factors, or a combination of these factors, could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. These forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements or present or prior earnings levels. In addition, each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward-looking statements.
 
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk
 
We are currently exposed to market risk from changes in interest rates. From time to time, we may enter into derivative financial instrument transactions to manage or reduce our market risk, but we do not enter into derivative transactions for speculative purposes. A discussion of our market risk exposure in financial instruments follows.


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Interest Rate Exposure
 
We are subject to interest rate risk on our fixed-interest and variable-interest rate borrowings. Variable rate debt, where the interest rate fluctuates periodically, exposes us to short-term changes in market interest rates. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in market interest rates reflected in the fair value of the debt and to the risk that we may need to refinance maturing debt with new debt at a higher rate.
 
As of December 31, 2007, the long-term borrowings that were outstanding subject to fixed interest rate risk consist of the 7.375% Senior Notes due April 2018. The carrying amount and fair value of the 7.375% Senior Notes was $3.5 million and $3.7 million, respectively.
 
As of December 31, 2007 the interest rate for the $895.5 million outstanding under the term loan was 6.58%. If the interest rate averaged 1% more for 2008 than the rates as of December 31, 2007, annual interest expense would increase by approximately $9.0 million. This sensitivity analysis assumes there are no changes in our financial structure.
 
We believe our other debt instruments, which are short-term in nature, totaling $12.7 million as of December 31, 2007 approximate fair value.
 
Interest Rate Swaps and Derivatives
 
We manage our debt portfolio to achieve an overall desired position of fixed and floating rates and may employ hedge transactions such as interest rate swaps and zero cost LIBOR collars as tools to achieve that goal. The major risks from interest rate derivatives include changes in the interest rates affecting the fair value of such instruments, potential increases in interest expense due to market decreases in floating interest rates and the creditworthiness of the counterparties in such transactions. The counterparties to our interest rate swap and zero cost LIBOR collar are creditworthy multinational commercial banks. We believe that the risk of counterparty nonperformance is immaterial. Our interest expense was reduced by $0.2 million in 2007 as a result of our interest rate derivative transactions and we realized a net gain of $0.7 million related to the termination of certain derivative instruments. (See the information set forth under the caption “Debt” in Part 1, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.)
 
In connection with the credit facility, in July 2007, we entered into hedge transactions with the purpose of fixing the interest rate on decreasing notional amounts beginning with $400.0 million with a settlement date of December 31, 2007 and ending with $50.0 million with a settlement date of April 1, 2009. We also entered into a zero cost LIBOR collar on $300.0 million of term loan principal over three years, with a ceiling of 5.75% and a floor of 4.99%. The table below provides the scheduled reduction in notional amounts related to the interest rate swap (in thousands):
 
         
December 31, 2007-March 31, 2008
  $ 350,000  
April 1, 2008-June 30, 2008
    300,000  
July 1, 2008-September 30, 2008
    200,000  
October 1, 2008-December 31, 2008
    100,000  
January 1, 2009-March 31, 2009
    50,000  


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Item 8.   Financial Statements and Supplementary Data
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors and
Stockholders of Hercules Offshore, Inc.:
 
We have audited the accompanying consolidated balance sheet of Hercules Offshore, Inc. and subsidiaries as of December 31, 2007, and the related consolidated statements of operations, stockholders’ equity, cash flows and comprehensive income for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Hercules Offshore, Inc. and subsidiaries at December 31, 2007, and the consolidated results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.
 
As discussed in Note 1 to the consolidated financial statements, in 2006 the Company adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payments.” In addition, as described in Note 14 to the consolidated financial statements, in 2007 the Company adopted the provisions of Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes.”
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Hercules Offshore, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2008, expressed an unqualified opinion thereon.
 
/s/ ERNST & YOUNG LLP
 
Houston, Texas
February 25, 2008


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors and
Stockholders of Hercules Offshore, Inc.:
 
We have audited Hercules Offshore, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Hercules Offshore, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, Hercules Offshore, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Hercules Offshore, Inc. and subsidiaries as of December 31, 2007, and the related consolidated statements of operations, stockholders’ equity, cash flows and comprehensive income for the year then ended, and our report dated February 25, 2008, expressed an unqualified opinion thereon.
 
/s/ ERNST & YOUNG LLP
 
Houston, Texas
February 25, 2008


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
Board of Directors and Stockholders
Hercules Offshore, Inc.
 
We have audited the accompanying consolidated balance sheet of Hercules Offshore, Inc. and subsidiaries as of December 31, 2006, and the related consolidated statements of operations, cash flows, stockholders’ equity and comprehensive income for the years ended December 31, 2006 and 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hercules Offshore, Inc. and subsidiaries as of December 31, 2006 and the results of their operations and their cash flows for the years ended December 31, 2006 and 2005, in conformity with accounting principles generally accepted in the United States of America.
 
As discussed in Note 1 to the consolidated financial statements, effective January 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payments.”
 
/s/  GRANT THORNTON LLP
 
Houston, Texas
February 23, 2007


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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
 
                 
    December 31,  
    2007     2006  
    (In thousands, except par value)  
 
ASSETS
Current Assets:
               
Cash and Cash Equivalents
  $ 212,452     $ 72,772  
Restricted Cash
          250  
Marketable Securities
    39,300        
Accounts Receivable, Net
    221,663       89,136  
Insurance Claims Receivable
    43,342        
Supplies
    2,494        
Prepaids
    31,417       14,438  
Current Deferred Tax Asset
    17,551        
Other
    23,565       3,627  
                 
      591,784       180,223  
Property and Equipment, Net
    2,060,224       415,864  
Goodwill
    940,241        
Other Assets, Net
    50,290       9,494  
                 
    $ 3,642,539     $ 605,581  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
               
Short-term Debt and Current Portion of Long-term Debt
  $ 21,653     $ 1,400  
Insurance Note Payable
    16,931       6,058  
Accounts Payable
    105,527       29,123  
Accrued Liabilities
    80,138       16,262  
Taxes Payable
    23,006       8,745  
Other Current Liabilities
    16,845       7,738  
                 
      264,100       69,326  
Long-term Debt, Net of Current Portion
    890,013       91,850  
Other Liabilities
    19,518       6,700  
Deferred Income Taxes
    457,475       42,854  
Commitments and Contingencies
               
Stockholders’ Equity:
               
Common Stock, $0.01 par value; 200,000 Shares Authorized; 88,876 and 32,008 Shares Issued, Respectively; 88,857 and 32,002 Shares Outstanding, Respectively
    889       320  
Capital in Excess of Par Value
    1,731,882       243,157  
Treasury stock, at Cost, 19 Shares and 6 shares, Respectively
    (582 )     (220 )
Accumulated Other Comprehensive Income (Loss)
    (8,117 )     755  
Retained Earnings
    287,361       150,839  
                 
      2,011,433       394,851  
                 
    $ 3,642,539     $ 605,581  
                 
 
The accompanying notes are an integral part of these financial statements.


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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF OPERATIONS
 
                         
    Year Ended December 31,  
    2007     2006     2005  
    (In thousands, except per share data)  
 
Revenues
  $ 766,793     $ 344,312     $ 161,334  
Costs and Expenses:
                       
Operating Expenses
    376,459       124,138       77,814  
Depreciation and Amortization
    109,064       32,310       13,790  
General and Administrative
    49,811       29,807       13,871  
                         
      535,334       186,255       105,475  
                         
Operating Income
    231,459       158,057       55,859  
Other Income (Expense):
                       
Interest Expense
    (36,055 )     (9,278 )     (9,880 )
Gain on Disposal of Assets
          30,690        
Loss on Early Retirement of Debt
    (2,182 )           (4,078 )
Other, Net
    6,291       4,038       924  
                         
Income Before Income Taxes
    199,513       183,507       42,825  
Income Tax Provision
    (62,991 )     (64,457 )     (15,369 )
                         
Net Income
  $ 136,522     $ 119,050     $ 27,456  
                         
Earnings Per Share:
                       
Basic
  $ 2.32     $ 3.80     $ 1.10  
Diluted
  $ 2.29     $ 3.70     $ 1.08  
Weighted Average Shares Outstanding:
                       
Basic
    58,897       31,327       24,919  
Diluted
    59,563       32,203       25,432  
 
The accompanying notes are an integral part of these financial statements.


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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
 
                                                 
    December 31, 2007     December 31, 2006     December 31, 2005  
    Shares     Amount     Shares     Amount     Shares     Amount  
    (In thousands)  
Member Interests:
                                               
Balance at Beginning of Period
        $           $       64     $ 63,022  
Contributions from Members
                            4       4,329  
Effect of Conversion
                            (68 )     (67,351 )
                                                 
Balance at End of Period
                                   
                                                 
Common Stock:
                                               
Balance at Beginning of Period
    32,008       320       30,243       302              
Effect of Conversion
                            23,923       239  
Exercise of Stock Options
    250       3       129       2              
Issuance of Common Stock
                1,600       16       6,250       62  
Issuance of Common Stock, Net
    56,618       566                          
Issuance of Restricted Stock
                36             70       1  
                                                 
Balance at End of Period
    88,876       889       32,008       320       30,243       302  
                                                 
Capital in Excess of Par Value:
                                               
Balance at Beginning of Period
          243,157             184,698              
Effect of Conversion
                                  67,112  
Exercise of Stock Options
          2,052             1,230              
Issuance of Common Stock, Net
          1,471,379             54,182             116,187  
Issuance of Restricted Stock
                                  1,399  
Reclass of Restricted Stock
                      (1,322 )            
Compensation Expense Recognized
          7,680             3,098              
Compensation Capitalized as part of the Purchase Price Allocation
          3,778                          
Tax Sharing Agreement with Transocean
          2,578                          
Excess of Tax Benefit From Stock-Based Arrangements
          1,258             1,271              
                                                 
Balance at End of Period
          1,731,882             243,157             184,698  
                                                 
Treasury Stock:
                                               
Balance at Beginning of Period
    (6 )     (220 )                        
Repurchase of Common Stock
    (13 )     (362 )     (6 )     (220 )            
                                                 
Balance at End of Period
    (19 )     (582 )     (6 )     (220 )            
                                                 
Restricted Stock:
                                               
Balance at Beginning of Period
                      (1,322 )            
Issuance of Restricted Stock
                                  (1,400 )
Compensation Expense Recognized
                                  78  
Reclass of Restricted Stock
                      1,322              
                                                 
Balance at End of Period
                                  (1,322 )
                                                 
Accumulated Comprehensive Income (Loss):
                                               
Balance at Beginning of Period
          755             476              
Change in Unrealized Gain (Loss) on Hedge Transactions, Net of Tax of $4,778, $(150) and $(257), Respectively
          (8,872 )           279             476  
                                                 
Balance at End of Period, net of tax of $4,371, $(407) and $(257), Respectively
          (8,117 )           755             476  
                                                 
Retained Earnings:
                                               
Balance at Beginning of Period
          150,839             31,789             8,065  
Net Income
          136,522             119,050             27,456  
Distribution to Former Members
                                  (3,732 )
                                                 
Balance at End of Period
          287,361             150,839             31,789  
                                                 
Total Stockholders’ Equity
    88,857     $ 2,011,433       32,002     $ 394,851       30,243     $ 215,943  
                                                 
 
The accompanying notes are an integral part of these financial statements.


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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
                         
    Years Ended December 31,  
    2007     2006     2005  
    (In thousands)  
 
Net Income
  $ 136,522     $ 119,050     $ 27,456  
Other Comprehensive Income (Loss):
                       
Reclassification of (gains) losses, net included in net income
    (897 )     (382 )     73  
Other comprehensive gains (losses), net
    (7,975 )     661       403  
                         
Comprehensive Income
  $ 127,650     $ 119,329     $ 27,932  
                         
 
The accompanying notes are an integral part of these financial statements.


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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
                         
    Year Ended December 31,  
    2007     2006     2005  
    (In thousands)  
 
Cash Flows from Operating Activities:
                       
Net Income
  $ 136,522     $ 119,050     $ 27,456  
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
                       
Depreciation and Amortization
    109,064       32,310       13,790  
Stock-Based Compensation Expense
    7,680       3,098       78  
Deferred Income Taxes
    2,841       27,200       15,247  
Amortization of Deferred Financing Fees
    1,805       686       890  
Recovery of Bad Debts
                (519 )
Loss on Early Retirement of Debt
    2,182             4,078  
Gain on Disposal of Assets
    (4,491 )     (30,779 )      
Excess Tax Benefit from Stock-Based Arrangements
    (1,258 )     (1,271 )      
(Increase) Decrease in Operating Assets —
                       
Accounts Receivable
    58,827       (50,653 )     (12,545 )
Insurance Claims Receivable
    (13,565 )     5,919       (5,919 )
Prepaid Expenses and Other
    9,263       (12,617 )     (7,721 )
Increase (Decrease) in Operating Liabilities —
Accounts Payable
    (6,794 )     15,842       11,443  
Insurance Note Payable
    (25,301 )     3,657       1,718  
Other Current Liabilities
    15,239       11,499       6,766  
Tax Sharing Agreement Payment
    (116,003 )            
Other Liabilities
    2,308       300        
                         
Net Cash Provided by Operating Activities
    178,319       124,241       54,762  
Cash Flows from Investing Activities:
                       
Acquisition of Business, Net of Cash Acquired
    (728,396 )            
Investment in Marketable Securities
    (151,675 )            
Proceeds from Sale of Marketable Securities
    112,375              
Additions of Property and Equipment
    (155,390 )     (204,456 )     (168,038 )
Deferred Drydocking Expenditures
    (20,772 )     (12,544 )     (7,369 )
Insurance Proceeds Received
    4,285       61,278        
Proceeds from Sale of Assets, Net
    109,745       5,989       455  
(Increase) Decrease in Restricted Cash
    4,821       (250 )      
                         
Net Cash Used in Investing Activities
    (825,007 )     (149,983 )     (174,952 )
Cash Flows from Financing Activities:
                       
Short-term Debt Borrowings (Repayments), Net
    (1,395 )            
Long-term Debt Borrowings
    900,000             185,000  
Long-term Debt Repayments
    (97,750 )     (1,400 )     (146,350 )
Proceeds from Issuance of Common Stock, Net
          54,198       116,249  
Proceeds from Exercise of Stock Options
    2,054       1,232        
Excess Tax Benefit from Stock-Based Arrangements
    1,258       1,271        
Payment of Debt Issuance Costs
    (17,753 )     (630 )     (5,923 )
(Distributions to) Contributions from Members
          (3,732 )     4,329  
Other
    (46 )            
                         
Net Cash Provided by Financing Activities
    786,368       50,939       153,305  
                         
Net Increase in Cash and Cash Equivalents
    139,680       25,197       33,115  
Cash and Cash Equivalents at Beginning of Period
    72,772       47,575       14,460  
                         
Cash and Cash Equivalents at End of Period
  $ 212,452     $ 72,772     $ 47,575  
                         
 
The accompanying notes are an integral part of these financial statements.


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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1.   Nature of Business and Significant Accounting Policies
 
Organization
 
Hercules Offshore, LLC was formed in July 2004 as a Delaware limited liability company. On November 1, 2005 in connection with its initial public offering, Hercules Offshore, LLC and its subsidiaries was converted to a Delaware corporation named Hercules Offshore, Inc. (the “Conversion”). Upon the Conversion, each outstanding membership unit of the limited liability company was converted into 350 shares of common stock of the corporation. Unless the context indicates otherwise, references to the “Company” are to Hercules Offshore, LLC and its subsidiaries for periods prior to the Conversion and to Hercules Offshore, Inc. and its subsidiaries for periods after the Conversion.
 
The Company provides shallow-water drilling and marine services to the oil and natural gas exploration and production industry in the U.S. Gulf of Mexico and international locations through its Domestic Offshore, International Offshore, Inland, Domestic Liftboats, International Liftboats and Other segments (See Note 15). On July 11, 2007, the Company completed the acquisition of TODCO (See Note 4), a provider of contract oil and gas drilling services in the U.S. Gulf of Mexico and international locations. TODCO owned and operated 24 jackup rigs, 27 barge rigs, three submersible rigs, nine land rigs, one platform rig and a fleet of marine support vessels. During the fourth quarter of 2007, the Company sold the nine land rigs and related assets (See Note 5). At December 31, 2007, the Company owned a fleet of 33 jackup rigs, 27 barge rigs, three submersible rigs, one platform rig, a fleet of marine support vessels operated through Delta Towing, a wholly owned subsidiary, and 60 liftboat vessels and operated an additional five liftboat vessels owned by third parties. The Company operates in nine countries on four continents.
 
Principles of Consolidation
 
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All intercompany account balances and transactions have been eliminated.
 
Reclassifications
 
Certain reclassifications have been made to conform prior year financial information to the current period presentation.
 
Cash and Cash Equivalents and Marketable Securities
 
Beginning in March 2007, the Company began investing a portion of its available cash in marketable securities. Marketable securities are classified as available for sale and are stated at fair value on the Consolidated Balance Sheets. At December 31, 2007, the Company had marketable securities with a fair value and cost basis of $39.3 million. Proceeds of $112.4 million were received from sales and maturities of marketable securities for the year ended December 31, 2007. There were no realized or unrealized gains or losses related to these securities.
 
Cash and cash equivalents include cash on hand, demand deposits with banks and all highly liquid investments with original maturities of three months or less. Realized and unrealized gains and losses related to marketable securities are calculated using the specific identification method. Unrealized gains or losses, net of taxes, are included in Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheets until realized. Realized gains or losses are included in Other, Net in the Consolidated Statements of Operations.


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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Restricted Cash
 
In connection with the acquisition of TODCO (See Note 4), the Company acquired restricted cash to support surety bonds (See Note 16) issued in relation to contracts TODCO had with Pemex Exploration and Production. As of December 31, 2007, the Company had no restricted cash balances outstanding.
 
Revenue Recognition
 
Revenues generated from our contracts are recognized as services are performed. For certain contracts, the Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one market to another under contracts longer than one month are recognized over the term of the related drilling contract. Amounts related to mobilization fees are summarized below (in thousands):
 
                         
    Year Ended December 31,  
    2007     2006     2005  
 
Mobilization revenue deferred
  $ 6,517     $ 5,680     $  
Mobilization expense deferred
    3,340       3,287        
Mobilization revenue recognized
    3,060       2,590        
Mobilization expense recognized
    2,839       1,600        
 
For certain contracts, the Company may receive fees from its customers for capital improvements to its rigs. Such fees are deferred and recognized over the term of the related contract. The Company capitalizes such capital improvements and depreciates them over the useful life of the asset.
 
The Company records reimbursements from customers for “out-of-pocket” expenses as revenues and the related cost as direct operating expenses. Total revenues from such reimbursements were $15.4 million, $7.5 million and $4.6 million for the years ended December 31, 2007, 2006 and 2005, respectively.
 
Stock-Based Compensation
 
On January 1, 2006, the Company adopted the modified prospective provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004) “Share-Based Payment” (“SFAS No. 123R”). Prior to the adoptions of SFAS No. 123R, the Company followed the intrinsic value method as prescribed in Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees” (“APB Opinion 25”) and related interpretations. SFAS No. 123R requires that compensation cost for stock options is recognized beginning with the effective date based on the requirements of (a) SFAS No. 123R for all share-based payments granted after January 1, 2006 and (b) SFAS No. 123 for all share-based payments granted to employees prior to January 1, 2006 that remain unvested on January 1, 2006. SFAS No. 123R requires that any unearned compensation related to share-based payments awarded prior to adoption be eliminated against the appropriate equity account. Under the new standard, the Company’s estimate of compensation expense will require a number of complex and subjective assumptions including its stock price volatility, employee exercise patterns (expected life of the options), future forfeitures and related tax effects.
 
The Company estimates the cost relating to stock options granted through December 31, 2007 will be $5.8 million over the remaining vesting period of 1.4 years and the cost relating to restricted shares granted through December 31, 2007 will be $6.0 million over the remaining vesting period of 1.8 years; however, due to the uncertainty of the level of share-based payments to be granted in the future, these amounts are estimates and subject to change.


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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Accounts Receivable and Allowance for Doubtful Accounts
 
Accounts receivable are stated at the historical carrying amount net of write-offs and allowance for doubtful accounts. Management of the Company monitors the accounts receivable from its customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Accounts deemed uncollectable are charged to the allowance. The Company had an allowance of $0.6 million at December 31, 2007 and no allowance for doubtful accounts recorded at December 31, 2006.
 
Insurance Claims Receivable
 
Insurance claims receivable include amounts the Company incurred related to insurance claims the Company filed under its insurance policies. At December 31, 2007, $43.3 million was outstanding for insurance claims receivable primarily related to collision damage to Hercules 205 and hurricane damage to several rigs caused by Hurricanes Rita and Katrina. There were no claims receivable at December 31, 2006.
 
Prepaid Expenses
 
Prepaid expenses consist of prepaid insurance, prepaid income tax and other prepayments. At December 31, 2007 and December 31, 2006, prepaid insurance totaled $21.6 million and $13.9 million, respectively. At December 31, 2007, prepaid taxes totaled $6.2 million. There were no prepaid taxes at December 31, 2006.
 
Property and Equipment
 
Property and equipment are stated at cost, less accumulated depreciation. Expenditures for property and equipment and items that substantially increase the useful lives of existing assets are capitalized at cost and depreciated. Expenditures for drydocking the Company’s liftboats are capitalized at cost in Other Assets, Net on the Consolidated Balance Sheets and amortized on the straight-line method over a period of 12 months. Routine expenditures for repairs and maintenance are expensed as incurred. Depreciation is computed using the straight-line method, after allowing for salvage value where applicable, over the useful lives of the assets.
 
Amortization of leasehold improvements is computed utilizing the straight-line method over the lease term or life of the asset, whichever is shorter.
 
The useful lives of property and equipment for the purposes of computing depreciation are as follows:
 
         
    Years  
 
Drilling rigs and marine equipment (salvage value of 10%)
    15  
Drilling machinery and equipment
    3-12  
Furniture and fixtures
    3  
Computer equipment
    3-7  
Automobiles and trucks
    3  
 
Goodwill
 
As of December 31, 2007, the Company had $940.2 million of goodwill. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”), the Company is required to test for the impairment of goodwill and other intangible assets with indefinite lives on at least an annual basis. The Company’s goodwill impairment test involves a comparison of the fair value of each of the Company’s reporting units, as defined under SFAS No. 142, with its carrying amount. Fair value is estimated using discounted cash flows and other market-related valuation models, including earnings multiples and comparable asset market values. If the fair value is determined to be less than the carrying value, the asset is considered impaired. The amount of the impairment, if any, is determined based on an allocation of the reporting unit fair


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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
values. The Company will test goodwill for impairment as of October 1 and will test it annually on that date unless changes occur between annual test dates that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The Company’s 2007 impairment test indicated that goodwill was not impaired.
 
The changes in the carrying amount of goodwill for the year ended December 31, 2007 are as follows (in thousands):
 
                                         
    Domestic
    International
                   
    Offshore     Offshore     Inland     Other     Total  
 
As of January 1, 2007
  $     $     $     $     $  
Goodwill acquired during the period
    513,602       133,046       206,264       87,329       940,241  
                                         
As of December 31, 2007
  $ 513,602     $ 133,046     $ 206,264     $ 87,329     $ 940,241  
                                         
 
As of December 31, 2007, there was no goodwill associated with the Domestic Liftboats and International Liftboats segments.
 
Other Intangible Assets
 
In connection with the acquisition of TODCO (See Note 4), the Company allocated $17.6 million in value to certain International customer contracts within the International Offshore segment. The estimated fair value of these acquired contracts is based on preliminary valuations and is subject to change when final valuations are obtained. These contracts are being amortized over the life of the contracts. As of December 31, 2007, the customer contracts had a carrying value of $14.8 million, net of accumulated amortization of $2.8 million, and are included in Other Assets, Net on the Consolidated Balance Sheet.
 
Amortization expense was $2.8 million for the year ended December 31, 2007. Future estimated amortization expense for the carrying amount of intangible assets as of December 31, 2007 is expected to be as follows (in thousands):
 
         
2008
  $ 8,088  
2009
    4,658  
2010
    1,466  
2011
    607  
2012
     
 
Impairment of Long-Lived Assets
 
The carrying value of long-lived assets, principally property and equipment and excluding goodwill, is reviewed for potential impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Factors that might indicate a potential impairment may include, but are not limited to, significant decreases in the market value of the long-lived asset, a significant change in the long-lived asset’s physical condition, a change in industry conditions or a reduction in cash flows associated with the use of the long-lived asset. For property and equipment held for use, the determination of recoverability is made based upon the estimated undiscounted future net cash flows of the related asset or group of assets being evaluated. Actual impairment charges are recorded using an estimate of discounted future cash flows. There were no impairment charges for the periods ended December 31, 2007, 2006, and 2005.


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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Other Assets, Net
 
Other assets consist of drydocking costs for marine vessels, other intangible assets, deferred mobilization costs, financing fees, unrealized gains (losses) on hedge transactions, investments and other. Drydock costs are capitalized at cost and amortized on the straight-line method over a period of 12 months. Drydocking costs, net of accumulated amortization, at December 31, 2007 and 2006 were $8.2 million and $5.8 million, respectively. Amortization expense for drydocking costs was $18.4 million, $10.7 million and $3.9 million for the years ended December 31, 2007, 2006 and 2005, respectively.
 
Financing fees are deferred and amortized over the life of the applicable debt instrument. Unamortized deferred financing fees at December 31, 2007 and 2006 were $16.2 million and $2.5 million, respectively. The amortization expense related to the deferred financing fees is included in interest expense on the Consolidated Statements of Operations. Amortization expense for financing fees was $1.8 million, $0.7 million and $0.9 million for the years ended December 31, 2007, 2006 and 2005, respectively. The Company recognized a pretax charge of $2.2 million related to the write off of deferred financing fees in connection with the early debt repayment (See Note 9).
 
The Company entered into several transactions to hedge its variable rate debt with the purpose and effect of fixing the interest rate on a portion of the outstanding principal of the term loan (See Note 10).
 
Income Taxes
 
The Company’s income tax provision is based upon the tax laws and rates in effect in the countries in which the Company’s operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these jurisdictions vary substantially. The Company’s effective tax rate is expected to fluctuate from year to year as operations are conducted in different taxing jurisdictions and the amount of pre-tax income fluctuates. Current income tax expense reflects an estimate of the Company’s income tax liability for the current year, withholding taxes, changes in prior year tax estimates as returns are filed, or from tax audit adjustments, while the net deferred tax expense or benefit represents the changes in the balance of deferred tax assets and liabilities as reported on the balance sheet.
 
Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized in the future. While the Company has considered estimated future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for the valuation allowances, changes in these estimates and assumptions, as well as changes in tax laws, could require the Company to adjust the valuation allowances for deferred tax assets. These adjustments to the valuation allowance would impact the Company’s income tax provision in the period in which such adjustments are identified and recorded, except to the extent that the valuation allowance relates to deferred tax assets accounted for in purchase accounting, in which case, the future reduction of any such valuation allowance would reduce goodwill.
 
Certain of the Company’s international rigs and liftboats are owned or operated, directly or indirectly, by the Company’s wholly owned Cayman Islands subsidiaries. Most of the earnings from these subsidiaries are reinvested internationally and remittance to the United States is indefinitely postponed. The Company recognized $0.9 million of deferred U.S. tax expense on foreign earnings which management expects to repatriate in the future. In certain circumstances, management expects that, due to the changing demands of the offshore drilling and liftboat markets and the ability to redeploy the Company’s offshore units, certain of such units will not reside in a location long enough to give rise to future tax consequences in that location. As a result, no deferred tax asset or liability has been recognized in these circumstances. Should management’s expectations change regarding the length of time an offshore drilling unit will be used in a given location, the Company would adjust deferred taxes accordingly. (See Note 14).


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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Use of Estimates
 
In preparing financial statements in conformity with accounting principles generally accepted in the United States, management makes estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
 
Fair Value of Financial Instruments
 
The carrying amounts of the Company’s financial instruments, which include cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, approximate fair values because of the short-term nature of the instruments.
 
The carrying amount of long-term debt, excluding the acquired Senior Notes (See Note 9) is equal to the fair market value because the debt bears interest at market rates. The fair value of the Company’s acquired Senior Notes is estimated based on the current rates offered to the Company for debt of the same remaining maturities. The Company believes its other debt instruments, which are short-term in nature, totaling $12.7 million as of December 31, 2007, approximate fair value.
 
Accounting Pronouncements
 
In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141(R), Business Combinations (“SFAS No. 141R”). SFAS No. 141R replaces SFAS No. 141, Business Combinations, and applies to all transactions and other events in which one entity obtains control over one or more other businesses. SFAS No. 141R requires an acquirer, upon initially obtaining control of another entity, to recognize the assets, liabilities and any non-controlling interest in the acquiree at fair value as of the acquisition date. Contingent consideration is required to be recognized and measured at fair value on the date of acquisition rather than at a later date when the amount of that consideration may be determinable beyond a reasonable doubt. This fair value approach replaces the cost-allocation process required under SFAS No. 141 whereby the cost of an acquisition was allocated to the individual assets acquired and liabilities assumed based on their estimated fair value. SFAS No. 141R requires acquirers to expense acquisition-related costs as incurred rather than allocating such costs to the assets acquired and liabilities assumed, as was previously the case under SFAS No. 141. Under SFAS No. 141R, the requirements of SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities would have to be met in order to accrue for a restructuring plan in purchase accounting. Pre-acquisition contingencies are to be recognized at fair value, unless it is a non-contractual contingency that is not likely to materialize, in which case, nothing should be recognized in purchase accounting and, instead, that contingency would be subject to the probable and estimable recognition criteria of SFAS No. 5, Accounting for Contingencies. SFAS No. 141R may have a significant impact on the Company’s accounting for business combinations closing on or after January 1, 2009.
 
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”). SFAS No. 159 permits companies to choose to measure certain financial instruments and certain other items at fair value. The standard requires that unrealized gains and losses on items for which the fair value option has been elected be reported in earnings. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is evaluating the impact, if any, that SFAS No. 159 will have on its financial position, results of operations and cash flows.
 
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require


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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
any new fair value measurements, rather, its application will be made pursuant to other accounting pronouncements that require or permit fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The provisions of SFAS No. 157 are to be applied prospectively upon adoption, except for limited specified exceptions. The Company is evaluating the requirements of SFAS No. 157 and does not expect the adoption to have a material impact on its financial position, results of operations and cash flows.
 
2.   Property and Equipment, net
 
The following is a summary of property and equipment — at cost, less accumulated depreciation (in thousands):
 
                 
    December 31,  
    2007     2006  
 
Drilling rigs and marine equipment
  $ 1,914,018     $ 420,961  
Drilling machinery and equipment
    235,680       23,329  
Leasehold improvements
    9,722       267  
Automobiles and trucks
    2,470       915  
Computer equipment
    10,505       1,040  
Furniture and fixtures
    962       779  
                 
Total property and equipment, at cost
    2,173,357       447,291  
Less accumulated depreciation
    (113,133 )     (31,427 )
                 
Total property and equipment, net
  $ 2,060,224     $ 415,864  
                 
 
3.   Earnings per Share
 
The reconciliation of the numerator and denominator used for the computation of basic and diluted earnings per share is as follows (in thousands, except earnings per share):
 
                         
    Year Ended December 31,  
    2007     2006     2005  
 
Numerator:
                       
Net income
  $ 136,522     $ 119,050     $ 27,456  
Denominator:
                       
Weighted average basic shares
    58,897       31,327       24,919  
Add effect of stock equivalents
    666       876       513  
                         
Weighted average diluted shares
    59,563       32,203       25,432  
                         
Basic earnings per share
  $ 2.32     $ 3.80     $ 1.10  
Diluted earnings per share
    2.29       3.70       1.08  
 
The Company calculates basic earnings per share by dividing net income by the weighted average number of shares outstanding. On November 1, 2005, in connection with its initial public offering, the Company converted from a limited liability company to a corporation. Upon the Conversion, each outstanding membership unit of the limited liability company was converted into 350 shares of common stock of the corporation. Diluted earnings per share is computed by dividing net income by the weighted average number of shares outstanding during the period as adjusted for the dilutive effect of the Company’s stock option and restricted stock awards. Stock equivalents of 350,080 were anti-dilutive and are excluded from the calculation of the dilutive effect of stock equivalents for the diluted earnings per share calculation for the year ended


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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
December 31, 2007. There were no anti-dilutive stock equivalents for the years ended December 31, 2006 and 2005, respectively.
 
4.   Asset Acquisitions and Business Combination
 
On July 11, 2007, the Company acquired TODCO for total consideration of approximately $2,397.8 million, consisting of $925.8 million in cash and 56.6 million shares of common stock. The fair value of the shares issued was determined for accounting purposes using an average price of $25.99, which represented the average closing price of the Company’s stock for a period before and after the date of the merger agreement with TODCO. In addition, the Company incurred additional consideration in the amount of $41.6 million related primarily to transaction related costs, cash payments to non-continuing employees and the conversion of certain employee equity awards. The results of TODCO are included in the Company’s results from the date of acquisition. The acquisition expanded the Company’s international presence and diversified the Company’s fleet.
 
The total consideration was allocated to TODCO’s net tangible and identifiable intangible assets based on their estimated fair values. The excess of the purchase price over the net assets was recorded as goodwill (See Note 1). The preliminary allocation of the purchase price was based on preliminary valuations and estimates, and assumptions are subject to change upon the receipt and management’s review of the final valuations. The final valuation of net assets is expected to be completed no later than one year from the acquisition date.
 
The preliminary allocation of the consideration is as follows:
 
         
    July 11, 2007  
    (In thousands)
 
    (Unaudited)  
 
Cash and Cash Equivalents
  $ 235,163  
Accounts Receivable
    191,369  
Insurance Claims Receivable
    34,060  
Current Deferred Tax Asset
    14,320  
Prepaid Expenses and Other
    16,811  
Property and Equipment, Net
    1,685,477  
Goodwill
    940,241  
Other Assets, Net
    32,049  
         
Total Assets
    3,149,490  
Short-Term Debt
    (3,618 )
Accounts Payable
    (83,199 )
Income Taxes Payable
    (5,448 )
Other Current Liabilities
    (69,773 )
Long-Term Debt
    (14,062 )
Deferred Tax Liabilities
    (530,086 )
Other Liabilities
    (3,982 )
         
Total Preliminary Purchase Price
  $ 2,439,322  
         
 
The following presents the consolidated financial information for the Company on a pro forma basis assuming the acquisition of TODCO had occurred as of the beginning of the periods presented. The historical financial information has been adjusted to give effect to pro forma items that are directly attributable to the acquisition and expected to have a continuing impact on consolidated results. These items include adjustments


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
to record the incremental depreciation expense related to the increase in fair value of the acquired assets, to record the additional interest expense related to the incremental borrowings and to reclassify certain items to conform to the Company’s financial reporting presentation.
 
The unaudited financial information set forth below has been compiled from historical financial statements and other information, but is not necessarily indicative of the results that actually would have been achieved had the transaction occurred on the dates indicated or that may be achieved in the future:
 
                 
    Year Ended
 
    December 31,  
    2007     2006  
    (In millions, except
 
    per share amounts)  
 
Revenues
  $ 1,268.1     $ 1,256.4  
Net Income
    198.5       230.7  
Basic earnings per share
    2.24       2.62  
Diluted earnings per share
    2.21       2.58  
 
In June 2007, the Company purchased a liftboat vessel for $7.4 million. The vessel is undergoing refurbishment and upgrades and is being marketed in West Africa.
 
In November 2006, the Company purchased from Halliburton West Africa Limited and Halliburton Energy Services Nigeria Limited (collectively “Halliburton”) eight liftboats owned by Halliburton and was assigned the contractual rights to operate five liftboats which are currently owned by a third party, and the lease of a shore-based facility and certain contracts and other assets related to the liftboats. The purchase price for the acquisition was $51.6 million, plus up to $10.0 million payable under a three-year earnout agreement. In order to secure the Company’s obligations under the earnout agreement, the Company granted Halliburton a lien in the amount of $3.0 million on one of the liftboats acquired. The Company operates the five liftboats owned by the third party under a management agreement that applies while the liftboats are under contract with Chevron Nigeria Limited. The total purchase price was allocated to the liftboats based on their estimated fair values.
 
In June 2006, the Company acquired five liftboats from Laborde Marine Lifts, Inc. (“Laborde”). In addition, the Company assumed the construction of an additional liftboat pursuant to a construction agreement assigned to the Company by Laborde at the closing. Pursuant to the terms of the purchase agreement, the original purchase price of $52.0 million was reduced by $2.7 million which represented the total amount remaining due under the construction contract for the sixth liftboat as of closing. Construction of the additional liftboat was completed in July 2006 and the remaining amount due was paid to the shipyard.
 
In February 2006, the Company purchased Hercules 260 for $20.1 million. The Company has completed a reactivation and upgrade project to enhance the rig’s drilling capabilities and to increase the marketability of the rig in international regions. Hercules 260 is currently undergoing contract preparation work and customer acceptance in India.
 
In November 2005, the Company purchased seven liftboats and related assets for $44.0 million. Three of the acquired liftboats are located in the U.S. Gulf of Mexico and are included in the Domestic Liftboats segment. The remaining four liftboats are currently operating in Nigeria and are included in the International Liftboats segment.
 
In September 2005, the Company purchased Hercules 258 for $12.6 million.
 
In August 2005, the Company purchased the liftboat Whale Shark for $12.5 million.
 
In June 2005, the Company purchased 17 liftboats for $19.7 million. One of these liftboats was sold in August 2005. In June 2005, the Company purchased a jackup rig, Hercules 170, for $20.0 million.


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HERCULES OFFSHORE, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
During January 2005, the Company completed the purchase of two jackup drilling rigs, Rig 25 and Hercules 257, for $21.5 million and $20.0 million, respectively.
 
5.   Dispositions
 
During the fourth quarter of 2007, the Company sold the nine land rigs and related assets purchased in the TODCO acquisition for gross proceeds of $107.0 million, which approximated the carrying value of these assets. In addition, during 2007, the Company sold several marine support vessels purchased in the TODCO acquisition for gross proceeds of $3.2 million.
 
In September 2006, the Company sold its New Iberia facility for $2.8 million, net of commissions. The Company recognized a gain of approximately $0.1 million on the sale.