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, 2005
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.) | |
| 11 Greenway Plaza, Suite 2950 Houston, Texas |
77046 | |
| (Address of principal executive offices) | (Zip Code) | |
Registrant’s telephone number, including area code:
(713) 979-9300
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $0.01 par value per share
Rights to Purchase Preferred Stock
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 of the Act. Yes ¨ 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 ¨
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. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes ¨ No þ
The registrant’s common stock was not publicly traded as of the last business day of the registrant’s most recently completed second quarter. The aggregate market value of the registrant’s common stock held by non-affiliates of the registrant as of December 31, 2005, based on the closing price on the NASDAQ Global Market on such date, was approximately $335.9 million. (The registrant’s directors and executive officers, LR Hercules Holdings, LP and its affiliates and Greenhill & Co., Inc. and its affiliates are considered affiliates of the registrant for this purpose.)
The number of shares of the registrant’s common stock outstanding on March 3, 2006 was 30,252,750.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for the Annual Meeting of Stockholders to be held in April 2006 are incorporated by reference into Part III of this report.
| Page | ||||
| PART I | ||||
| Item 1. |
1 | |||
| Item 1A. |
9 | |||
| Item 1B. |
18 | |||
| Item 2. |
18 | |||
| Item 3. |
19 | |||
| Item 4. |
19 | |||
| Executive Officers |
19 | |||
| PART II | ||||
| Item 5. |
21 | |||
| Item 6. |
23 | |||
| Item 7. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
25 | ||
| 46 | ||||
| Item 7A. |
47 | |||
| Item 8. |
48 | |||
| Item 9. |
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
70 | ||
| Item 9A. |
70 | |||
| Item 9B. |
70 | |||
| PART III | ||||
| Item 10. |
71 | |||
| Item 11. |
71 | |||
| Item 12. |
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
71 | ||
| Item 13. |
71 | |||
| Item 14. |
71 | |||
| PART IV | ||||
| Item 15. |
72 | |||
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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,” unless the context clearly indicates otherwise. Hercules Offshore, Inc. is a Delaware corporation formed in July 2004, with its principal executive offices located at 11 Greenway Plaza, Suite 2950, Houston, Texas 77046. Hercules’ telephone number at such address is (713) 979-9300.
Overview
We provide shallow-water drilling and liftboat services to the oil and natural gas exploration and production industry primarily in the U.S. Gulf of Mexico. We currently own a fleet of nine jackup rigs that are capable of drilling in maximum water depths ranging from 85 to 250 feet and a fleet of 46 liftboats with leg lengths ranging from 105 to 260 feet. We contract our jackup rigs and liftboats to major integrated energy companies and independent oil and natural gas operators.
We acquired six jackup rigs in two separate transactions completed in August 2004 and January 2005. We acquired a seventh jackup rig in January 2005 that we had previously operated under a management agreement with the rig’s prior owner. In June 2005, we acquired an eighth jackup rig located in the Middle East, Rig 16. We are currently refurbishing Rig 16 in the United Arab Emirates and expect the rig to be available in the first quarter of 2006. We acquired Rig 31 in September 2005. We are currently refurbishing the rig in Malaysia and expect the rig to be available in the third quarter of 2006. In February 2006, we acquired Rig 26, and we have started a refurbishment project for the rig that we expect to take up to one year to complete. We intend to seek work for Rig 16, Rig 31 and Rig 26 in suitable international locations. Rig 25, which we acquired in January 2005, was severely damaged in connection with Hurricane Katrina. We filed a notice of abandonment for Rig 25 with our insurance underwriters in February 2006, and expect the rig to be declared a constructive total loss under our insurance policies.
We acquired 22 of our liftboats in October 2004, 16 of our liftboats in June 2005, and one of our liftboats in August 2005. In November 2005, we acquired an additional seven liftboats, four of which are operating offshore Nigeria.
Our Fleet
Jackup Rigs
As of March 1, 2006, five of our jackup rigs were operating under contracts ranging in duration from well-to-well to six months, at an average dayrate of approximately $64,285. The following table contains information regarding our jackup rig fleet as of March 1, 2006. The table does not include Rig 25.
| Rig |
Type |
Year Built |
Maximum/Minimum |
Rated Drilling Depth (feet) (1) |
Location |
Status | |||||||
| 11 | Mat-supported, cantilever | 1980 | 200/21 | 20,000 | (2) | U.S. Gulf of Mexico | Contracted | ||||||
| 15 | Independent leg, slot | 1982 | 85/9 | 20,000 | U.S. Gulf of Mexico | Contracted | |||||||
| 16 | Independent leg, cantilever | 1981 | 170/16 | 16,000 | Middle East | Shipyard | |||||||
| 20 | Mat-supported, cantilever | 1980 | 100/20 | 25,000 | U.S. Gulf of Mexico | Contracted | |||||||
| 21 | Mat-supported, cantilever | 1980 | 120/22 | 20,000 | U.S. Gulf of Mexico | Shipyard(3) | |||||||
| 22 | Mat-supported, cantilever | 1971 | 173/22 | 15,000 | U.S. Gulf of Mexico | Contracted | |||||||
| 26 | Independent leg, cantilever | 1979 | 150/12 | 16,000 | U.S. Gulf of Mexico | Shipyard | |||||||
| 30 | Mat-supported, slot | 1979 | 250/25 | 20,000 | U.S. Gulf of Mexico | Contracted | |||||||
| 31 | Mat-supported, slot | 1979 | 250/25 | 20,000 | Asia | Shipyard |
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| (1) | 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. |
| (2) | Rated workover depth. Rig 11 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. |
| (3) | Rig 21 is undergoing refurbishment in a shipyard in Mississippi primarily for repairs of damage sustained during Hurricane Katrina. We expect to complete the repairs and other refurbishment work in the first quarter of 2006. |
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.
Our rigs are used primarily for exploration and development drilling in the shallow waters of the U.S. Gulf of Mexico. Six of our jackup rigs are mat-supported. Six 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. Three 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. However, one of our slot-type rigs has a competitive advantage in very shallow water as it is one of the few jackup rigs in the world that can drill in water depths as shallow as nine feet.
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Liftboats
The following table contains information regarding our liftboats as of March 1, 2006:
| Liftboat Name (1) |
Year Built |
Leg Length (feet) |
Deck Area (square feet) |
Maximum Deck Load (pounds) |
Location |
Gross Tonnage | ||||||
| Whale Shark |
2005 | 260 | 8,170 | 729,000 | U.S. Gulf of Mexico | 99 | ||||||
| Tigershark |
2001 | 230 | 5,300 | 1,000,000 | U.S. Gulf of Mexico | 469 | ||||||
| Kingfish |
1996 | 229 | 5,000 | 500,000 | U.S. Gulf of Mexico | 188 | ||||||
| Man-O-War |
1996 | 229 | 5,000 | 500,000 | U.S. Gulf of Mexico | 188 | ||||||
| Wahoo |
1981 | 215 | 4,525 | 500,000 | U.S. Gulf of Mexico | 491 | ||||||
| Amberjack |
1981 | 205 | 3,800 | 500,000 | U.S. Gulf of Mexico | 417 | ||||||
| Bullshark |
1998 | 200 | 5,000 | 1,000,000 | U.S. Gulf of Mexico | 859 | ||||||
| Swordfish |
2000 | 190 | 4,000 | 700,000 | U.S. Gulf of Mexico | 189 | ||||||
| Oilfish |
1996 | 170 | 3,200 | 590,000 | Nigeria | 194 | ||||||
| Manta Ray |
1981 | 150 | 2,400 | 200,000 | U.S. Gulf of Mexico | 194 | ||||||
| Seabass |
1983 | 150 | 2,600 | 200,000 | U.S. Gulf of Mexico | 186 | ||||||
| Hammerhead |
1980 | 145 | 1,648 | 150,000 | U.S. Gulf of Mexico | 178 | ||||||
| Pilotfish |
1990 | 145 | 2,400 | 175,000 | Nigeria | 190 | ||||||
| Rudderfish |
1991 | 145 | 2,600 | 200,000 | Nigeria | 183 | ||||||
| Blue Runner |
1980 | 140 | 3,400 | 300,000 | U.S. Gulf of Mexico | 174 | ||||||
| Starfish |
1978 | 140 | 2,266 | 150,000 | U.S. Gulf of Mexico | 99 | ||||||
| Pompano |
1981 | 130 | 1,864 | 100,000 | U.S. Gulf of Mexico | 196 | ||||||
| Sandshark |
1982 | 130 | 1,940 | 150,000 | U.S. Gulf of Mexico | 196 | ||||||
| Stingray |
1979 | 130 | 2,266 | 150,000 | U.S. Gulf of Mexico | 99 | ||||||
| Albacore |
1985 | 130 | 2,200 | 150,000 | U.S. Gulf of Mexico | 171 | ||||||
| Moray |
1980 | 130 | 1,824 | 130,000 | U.S. Gulf of Mexico | 178 | ||||||
| Skipfish |
1985 | 130 | 1,000 | 110,000 | U.S. Gulf of Mexico | 91 | ||||||
| Sailfish |
1982 | 130 | 1,764 | 150,000 | U.S. Gulf of Mexico | 179 | ||||||
| Mahi Mahi |
1980 | 130 | 1,500 | 142,000 | U.S. Gulf of Mexico | 97 | ||||||
| Triggerfish |
2001 | 130 | 2,400 | 150,000 | U.S. Gulf of Mexico | 195 | ||||||
| Scamp |
1984 | 130 | 2,500 | 150,000 | Nigeria | 195 | ||||||
| Rockfish |
1981 | 125 | 1,400 | 150,000 | U.S. Gulf of Mexico | 195 | ||||||
| Gar |
1978 | 120 | 2,100 | 150,000 | U.S. Gulf of Mexico | 98 | ||||||
| Grouper |
1979 | 120 | 2,100 | 150,000 | U.S. Gulf of Mexico | 97 | ||||||
| Sea Robin |
1984 | 120 | 1,534 | 110,000 | U.S. Gulf of Mexico | 98 | ||||||
| Tilapia |
1976 | 120 | 1,268 | 110,000 | U.S. Gulf of Mexico | 97 | ||||||
| Snapper |
1982 | 120 | 1,000 | 100,000 | U.S. Gulf of Mexico | 98 | ||||||
| Barracuda |
1979 | 105 | 1,648 | 110,000 | U.S. Gulf of Mexico | 93 | ||||||
| Carp |
1978 | 105 | 1,648 | 110,000 | U.S. Gulf of Mexico | 98 | ||||||
| Cobia |
1978 | 105 | 1,648 | 110,000 | U.S. Gulf of Mexico | 94 | ||||||
| Dolphin |
1980 | 105 | 1,648 | 110,000 | U.S. Gulf of Mexico | 97 | ||||||
| Herring |
1979 | 105 | 1,648 | 110,000 | U.S. Gulf of Mexico | 97 | ||||||
| Marlin |
1979 | 105 | 1,648 | 110,000 | U.S. Gulf of Mexico | 97 | ||||||
| Corina |
1974 | 105 | 953 | 100,000 | U.S. Gulf of Mexico | 98 | ||||||
| Pike |
1980 | 105 | 936 | 130,000 | U.S. Gulf of Mexico | 92 | ||||||
| Remora |
1976 | 105 | 1,479 | 100,000 | U.S. Gulf of Mexico | 94 | ||||||
| Wolffish |
1977 | 105 | 900 | 100,000 | U.S. Gulf of Mexico | 99 | ||||||
| Seabream |
1980 | 105 | 813 | 100,000 | U.S. Gulf of Mexico | 92 | ||||||
| Sea Trout |
1978 | 105 | 1,130 | 100,000 | U.S. Gulf of Mexico | 97 | ||||||
| Tarpon |
1979 | 105 | 1,648 | 110,000 | U.S. Gulf of Mexico | 97 | ||||||
| Palometa |
1972 | 105 | 1,100 | 100,000 | U.S. Gulf of Mexico | 99 |
| (1) | The Snapper, Corina and Pike are currently stacked. We have commenced the reactivation of the Corina and the Pike, and expect them to be available by the third quarter of 2006. We are evaluating the Snapper’s condition to determine whether to reactivate or scrap it. All other liftboats are either available or operating. |
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Liftboats are self-propelled, self-elevating work platforms complete with legs, cranes and living accommodations, and with a large open deck space, which provide 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 on location, a liftboat hydraulically lowers its legs to the ocean floor and then jacks up until the work platform is elevated above the anticipated wave action. Once the liftboats are positioned, their stability, open deck area, crane capacity and relatively low costs of operation make them ideal work platforms for a wide range of offshore support services, such as:
| • | production platform construction, inspection, maintenance and removal; |
| • | well intervention and workover; |
| • | well plug and abandonment; |
| • | crane lift services; |
| • | pipeline installation and maintenance; and |
| • | offshore crew accommodation. |
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. Liftboats are typically moved to a port during severe weather to avoid the winds and waves they would be exposed to in open water.
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 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. Eight 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 3,800 existing production platforms in the U.S. Gulf of Mexico. In addition, the capability to reposition at a work site or to move to another location within a short time adds to their versatility. Each of our liftboats is staffed with two full-time crews that are available to work 24 hours per day, seven days per week, and rotate based on either a seven days on and seven days off schedule or a 14 days on and seven days off schedule. Currently, we own 42 liftboats in the U.S. Gulf of Mexico and four liftboats in Nigeria.
Competition
The U.S. Gulf of Mexico shallow-water market is highly competitive. Drilling and liftboat contracts are traditionally short term in nature and are 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 U.S. Gulf of Mexico shallow-water market 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 and independent oil and natural gas operators in the U.S. Gulf of Mexico. Our largest drilling services customers for the year ended December 31, 2005
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were Chevron Corporation, Bois d’Arc Energy, Inc. and Noble Energy, Inc., which accounted for 28.6%, 16.5% and 11.0%, respectively, of our drilling services revenues for that period. Our largest drilling services customers for the period from inception (July 27, 2004) to December 31, 2004 (“period from inception to December 31, 2004”) were Chevron, Bois d’Arc Energy and Petroquest Energy, Inc., which accounted for 33.1%, 19.4% and 10.7%, respectively, of our drilling services revenues for that period. Our largest liftboat customers for the year ended December 31, 2005 were Chevron and Gulf Offshore Logistics, LLC, which accounted for 33.6% and 12.9%, respectively, of our domestic marine services revenues for that period. Our largest liftboat customers for the period from inception to December 31, 2004 were Chevron and Bois d’Arc Energy, which accounted for 40.1% and 12.5%, respectively, of our domestic marine services revenues for that period. Chevron and Bois d’Arc Energy accounted for 31% and 12%, respectively, of our consolidated revenues for the year ended December 31, 2005 and 31% and 15%, respectively, of our consolidated revenues for the period from inception to December 31, 2004. No other customer accounted for more than 10% of our consolidated revenues for either period.
Contracts
Our contracts to provide services are individually negotiated and vary in their terms and provisions. We obtain most of our contracts through competitive bidding against other contractors. In general, 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. To date, most of our contracts in the U.S. Gulf of Mexico have been on a short-term basis of less than one year.
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. In addition, customers generally have the right to terminate our contracts with little or no notice, and without penalty. The contract term in some instances may be extended by the customer’s exercising options for the drilling of additional wells or for an additional term, or by exercising a right of first refusal.
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. Our liftboat contracts in Nigeria are on a longer-term basis.
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.
In certain countries, we also may be required to post bonds or letters of credit in order to temporarily import equipment, including our drilling rigs and liftboats, into the country. These temporary importation bonds would secure the amount of the import duty that is payable if the equipment fails to leave the country within the time frame permitted by the local jurisdiction for the temporary importation of equipment. When the equipment is exported out of the local jurisdiction, the bond or letter of credit generally would be returned to us. Currently, we have arranged for a bank in Nigeria to issue a letter of credit in the amount of approximately $440,000 with respect to our liftboats in that country, and we have executed a counter-indemnity agreement with the Nigerian bank for any liability incurred by the bank under that letter of credit.
Employees
As of December 31, 2005, we had approximately 750 employees. We require skilled personnel to operate and provide technical services and support for our rigs and liftboats. As a result, we conduct extensive personnel
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recruiting, training and safety programs. We will need to hire additional rig-based employees in connection with the commencement of operations of Rig 16, Rig 26 and Rig 31. As of December 31, 2005, none of our employees was working under collective bargaining agreements. Efforts have been made from time to time, however, to unionize portions of the offshore workforce in the U.S. Gulf of Mexico. We believe that our employee relations are good.
Insurance
We maintain insurance coverage that includes physical damage, third party liability, maritime employers liability, pollution and other coverage. Our primary marine package provides for hull and machinery coverage for our rigs and liftboats up to a scheduled value for each asset. Rig coverages include a $1.0 million deductible per occurrence; liftboat deductibles vary from $150,000 to $500,000 depending on the insured value of the particular vessel. There is no deductible in the event of a total loss. The protection and indemnity coverage under the primary marine package has a $5.0 million limit per occurrence with excess liability up to $100.0 million. The primary marine package also provides coverage for cargo and charterer’s legal liability. Vessel pollution is covered under a Water Quality Insurance Syndicate policy. In addition to our marine package, we have separate policies providing coverage for general domestic liability, employer’s liability, domestic auto liability and non-owned aircraft liability, with customary deductibles and coverages. Insurance premiums under our program are approximately $8.0 million for the twelve-month policy period ending July 31, 2006.
As a result of the damage sustained by the oil and natural gas industry from Hurricanes Ivan, Katrina and Rita, we anticipate that our insurance costs will increase significantly after the end of our current policy period on July 31, 2006. Competitors with assets in the Gulf of Mexico that have already completed their renewals in 2006 are experiencing a difficult market environment with insurance underwriters, and are likely to have increased premium costs, higher levels of retention and limits on the aggregate damage they may claim in a major windstorm. To obtain access to adequate insurance coverage, we may terminate our current policy early to accelerate the renewal process.
We believe that our insurance coverage is customary for the industry and adequate for our business. However, there are risks that such insurance will not adequately protect us against or not be available to cover all the liability from all of the consequences and hazards we may encounter in our operations.
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. We are also subject to the jurisdiction of the U.S. Coast Guard, the National Transportation Safety Board, 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, 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
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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 specified substances 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 exploration activities occur. Offshore facilities must also prepare plans addressing spill prevention control and countermeasures. Violations of monitoring, reporting and permitting requirements can result in the imposition of civil and criminal penalties. A March 2005 United States district court decision could result in certain of our vessels being required to obtain Clean Water Act permits for the discharge of ballast water. Under current Clean Water Act regulations, our vessels are exempt from such permitting requirements; however, in Northwest Environmental Advocates v. EPA, the federal district court in California ordered the Environmental Protection Agency to repeal the exemption. Under the court’s ruling, owners and operators of vessels would be required to comply with the Clean Water Act permitting requirements or face penalties. The remedy phase of the proceeding is ongoing; however, we expect to incur certain costs to obtain Clean Water Act permits for certain of our vessels if the permitting exemption is repealed. Because we do not yet know how or when this matter will ultimately be resolved, we cannot estimate its potential financial impact at this time. However, we believe that any financial impacts resulting from the repeal of the permitting exemption for ballast water discharge 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 U.S. Coast Guard has implemented regulations requiring evidence of financial responsibility in the amount of $900 per gross ton. 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 Coast Guard and Maritime Transportation Act of 2004 (the “CGMTA”) amended OPA to require the owner or operator of any non-tank vessel of 400 gross tons or more that carries oil of any kind as a fuel for main propulsion to prepare and submit a response plan that covers each applicable vessel by August 8, 2005. For vessels that have International Tonnage Certificates, gross tonnage is based on the certificate, which may vary from the standard U.S. gross tonnage for the vessel reflected in our liftboat table above. The vessel response plan must include detailed information on actions to be taken by vessel personnel to prevent or mitigate any discharge or substantial threat of discharge. We submitted the required plans to the Coast Guard prior to the August 2005 deadline.
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
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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.
Recent terrorist actions have spurred a variety of initiatives intended to enhance vessel security. In October 2003, the U.S. Coast Guard finalized regulations required to implement 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.
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.
Our operations are primarily 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; |
| • | 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; and |
| • | in the case of a limited partnership, the general partner meets U.S. citizenship requirements for U.S. coastwise trade. |
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 the Jones Act 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
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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, which became effective internationally on May 19, 2005, 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 would, however, become 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.
Available Information
We file annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission. These filings, and any amendments to these filings, are available free of charge through our internet website at www.herculesoffshore.com as soon as reasonably practicable after we electronically file that material with, or furnish it 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 12 of our Notes to Consolidated Financial Statements included in Item 8 of this annual report.
| Item 1A. | Risk Factors |
Risks Related to Our Business
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 primarily in the U.S. Gulf of Mexico, 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. Oil and natural gas prices are extremely volatile. Since mid-December 2005, commodity prices have decreased, particularly natural gas prices, which have declined sharply. 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; |
| • | economic and weather conditions in the United States and elsewhere; |
| • | expectations regarding future prices; |
| • | advances in exploration, development and production technology; |
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| • | 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; |
| • | 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 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, companies exploring for oil and natural gas may cancel or curtail their drilling programs, thereby reducing demand for drilling services. 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.
Our business is concentrated 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.
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. Dayrates also depend on the supply of vessels. Generally, excess capacity puts downward pressure on dayrates. Excess capacity can occur when newly constructed vessels enter the market, when vessels are mobilized between market areas and when non-marketed 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. In addition, the competitive environment has intensified as recent mergers among oil and natural gas companies have reduced the number of available customers. Finally, competition among shallow-water drilling and marine service providers is also affected by each provider’s reputation for safety and quality. We may not be
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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.
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 equipment involved and injury or death to rig or liftboat personnel. 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 August 2005, two of our jackup rigs, Rig 21 and Rig 25, sustained damage during Hurricane Katrina. Rig 25 is severely damaged, and we expect it to be declared a constructive total loss under our insurance policies. Rig 21 suffered extensive damage to its mat as a result of the storm, and we expect that the rig will not be available for service until later in the first quarter of 2006. In addition, our liftboats were required to leave location during Hurricanes Katrina and Rita and did not earn any dayrate for an average of five days per vessel.
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 the terrorist attacks on September 11, 2001 and 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, we anticipate that our insurance costs will increase significantly after the end of our current policy period in July 2006. It is likely that insurers will require higher retention levels and will limit the amount of insurance proceeds that are available after a major wind storm in the event that our rigs or liftboats experience damage. If storm activity in 2006 is as severe as it was in 2005, insurance underwriters may 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.
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A single customer accounts for a significant portion of our revenues, the loss of which 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 33.1% and 28.6% of our drilling services revenues for the period from inception to December 31, 2004 and the year ended December 31, 2005, respectively. Chevron represented approximately 40.1% and 33.6% of our domestic marine services revenues for the period from inception to December 31, 2004 and the year ended December 31, 2005, respectively. 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.
Re-activation 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 continue to improve, inactive rigs and liftboats that are not currently being marketed could be reactivated to meet an increase in demand, and the recent hurricanes have resulted in the reactivation of a number of shallow-water rigs that have been cold-stacked for the past several years. 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 2006, 51 jackup rigs had been ordered by industry participants, national oil companies and financial investors for delivery through 2009. As of that date, there also were seven liftboats under construction in the United States that are targeted for use 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 governmental authority or when a unit is damaged. We are currently refurbishing Rig 16, a rig that we recently acquired and that has not worked for approximately six years. We also are refurbishing the recently acquired Rig 26 and Rig 31. We expect to spend a total of approximately $44.3 million in refurbishment costs for Rig 16, Rig 26 and Rig 31 prior to placing the rigs into service. In addition, Rig 21, which suffered extensive damage to its mat as a result of Hurricane Katrina, was moved into a shipyard to repair the damage it sustained.
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 key equipment 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 engineering problems; |
| • | unanticipated actual or purported change orders; |
| • | work stoppages; |
| • | financial or other difficulties at shipyards; |
| • | adverse weather conditions; and |
| • | inability to obtain required permits or approvals. |
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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.
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. 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 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 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.
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. In addition, 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 the U.S. Gulf of Mexico increases,
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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. In addition, our ability to expand our operations depends in part upon our ability to increase the size of our skilled labor force. We will need to hire additional rig-based employees in connection with the commencement of operations of Rig 16, Rig 26 and Rig 31. Moreover, our labor costs increased significantly in 2005, and we anticipate that this trend will continue in 2006.
Although our 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, 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 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 government 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.
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.
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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.
We will be subject to additional political, economic, and other uncertainties as we expand our international 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. We currently own four liftboats operating offshore Nigeria, and we are marketing three of our jackup rigs to work in international markets following completion of refurbishment and upgrade projects on the rigs. 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 or nationalization of assets; |
| • | damage to our equipment or violence directed at our employees; |
| • | increased operating costs; |
| • | modification or renegotiation of contracts; |
| • | limitations on insurance coverage, such as war risk coverage in certain areas; |
| • | import-export quotas; |
| • | confiscatory taxation; |
| • | restrictions on currency repatriations; |
| • | currency fluctuations and devaluations; and |
| • | other forms of government regulation and economic conditions that are beyond our control. |
As our international operations expand, 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.
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, 2005, we have total outstanding debt of approximately $94.7 million. This debt represents approximately 30.5% of our total capitalization. We have up to $25 million of available capacity under our revolving credit facility, under which we may continue to borrow to fund working capital or other needs in the near term. 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 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 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 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 additional indebtedness; |
| • | create liens; |
| • | restrict dividend or other payments by our subsidiaries to us; |
| • | sell our assets or consolidate or merge with or into other companies; |
| • | engage in transactions with affiliates; and |
| • | make capital expenditures. |
These limitations are subject to a number of important qualifications and exceptions. Our credit agreement also requires us to maintain a minimum interest coverage ratio and a maximum leverage ratio. These covenants may adversely affect our ability to finance our future operations and capital needs and to pursue available business opportunities. A breach of any of these covenants could result in a default in respect of the related debt. If a default were to occur, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, immediately due and payable and proceed against any collateral securing that debt.
Risks Related to Our Limited Operating History
Because we have a limited operating history and we have not provided three years of audited financial statements, 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.
In addition, this annual report includes audited financial statements only as of and for the year ended December 31, 2005 and as of and for the period from inception to December 31, 2004. We have acquired our fleet of jackup rigs and liftboats in a number of separate asset acquisitions since our formation in July 2004. We
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have not completed or provided in this annual report any stand-alone pre-acquisition financial statements for the assets we acquired in these transactions. As a result, and given our recent date of formation, we have not provided in this annual report three years of audited financial statements that normally would be included in an annual report on Form 10-K.
Risks Related to Our Principal Stockholders, the Securities Markets and Ownership of Our Common Stock
Our two largest stockholders and their affiliates, to the extent they vote together, will control the outcome of stockholder voting.
LR Hercules Holdings, LP (“Lime Rock”) holds 36.4% of the outstanding common stock of our company, and Greenhill Capital Partners, L.P. and its affiliates (“Greenhill”) holds 18.2% of the outstanding common stock of our company. Accordingly, to the extent Lime Rock and Greenhill vote together, they will be able to control the outcome of matters requiring a stockholder vote, including the election of directors, adoption of amendments to our certificate of incorporation or bylaws and approval of transactions involving a change of control. In addition, as a result of its ownership, Lime Rock will be able to exert significant control over us and may be able effectively to control the outcome of matters requiring a stockholder vote. Other investors, by themselves, will not be able to affect the outcome of any stockholder vote.
Our interests may conflict with those of Lime Rock, Greenhill and their affiliates with respect to our past and ongoing business relationships, and because of their ownership, we may not be able to resolve these conflicts on terms commensurate with those possible in arms-length transactions.
Our interests may conflict with those of Lime Rock, Greenhill and their affiliates in a number of areas relating to our past and ongoing relationships, including:
| • | the timing and manner of any sales or distributions by Lime Rock or Greenhill of all or any portion of their ownership interests in us; |
| • | business opportunities that may be presented to Lime Rock or Greenhill and to our directors associated with Lime Rock or Greenhill; |
| • | competition between those stockholders and us within the same lines of business; and |
| • | our dividend policy. |
We may not be able to resolve any potential conflicts with Lime Rock, Greenhill and their affiliates, and even if we do, the resolution may be less favorable than if we were dealing with an unaffiliated party.
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.-flagged 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-United States 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
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stock by one or more persons who is not a U.S. citizen 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.
Substantial sales of our common stock by Lime Rock, Greenhill or us could cause our stock price to decline and issuances by us may dilute the ownership interest in our company of our existing stockholders.
Any sales of substantial amounts of our common stock in the public market by Lime Rock, Greenhill or us, or the perception that these sales might occur, could lower the market price of our common stock. Further, if we issue additional equity securities to raise additional capital, the ownership interest in our company of our existing stockholders may be diluted and the market price of our common stock may decline.
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, a stockholder may have to sell some or all of its common stock in order to generate cash flow from its investment. A stockholder may not receive a gain on its investment when it sell our common stock and may lose the entire amount of its investment.
Provisions in our charter documents or Delaware law may inhibit a takeover, which could adversely affect the value of our common stock.
Our certificate of incorporation, bylaws 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 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 mobile offshore drilling rigs and liftboats and ancillary equipment, substantially all of which we own. Most of our rigs and liftboats are pledged to collateralize our senior secured credit agreement. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Liquidity and Financing Arrangements—Debt” in Item 7 of this annual report.
We maintain our principal executive offices in Houston, Texas, which is under lease, and have an operational office in New Iberia, Louisiana, which we own. We also lease temporary office space in Lafayette, Louisiana and a warehouse in Broussard, Louisiana.
We incorporate by reference in response to this item the information set forth in Item 1 of this annual report.
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| Item 3. | Legal Proceedings |
We and our subsidiaries are routinely involved in litigation, claims and disputes arising in the ordinary course of our business. We do not believe that ultimate liability, if any, resulting from any such pending litigation will have a material adverse effect on our financial condition or results of operations.
| 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 2005.
We have presented below information about our executive officers as of March 1, 2006. Officers are appointed annually by the Board of Directors and serve until their successors are chosen or until their resignation or removal.
| Name |
Age | Position | ||
| Randall D. Stilley |
52 | Chief Executive Officer and President | ||
| Steven A. Manz |
40 | Chief Financial Officer | ||
| John T. Rynd |
48 | Senior Vice President of Hercules Offshore and President, Hercules Drilling Company, LLC | ||
| Randal R. Reed |
49 | President, Hercules Liftboat Company, LLC | ||
| Thomas E. Hord |
53 | Vice President, Operations and Chief Operating Officer, Hercules Drilling Company, LLC | ||
| James W. Noe |
33 | Vice President, General Counsel, Chief Compliance Officer and Secretary | ||
| Renee M. Pitre |
44 | Vice President, Finance, Hercules Liftboat Company, LLC | ||
| Don P. Rodney |
58 | President, Hercules International Holdings Ltd. | ||
| Leslie K. Taylor |
46 | Vice President, Human Resources | ||
| Johnny K. Vincent |
43 | Vice President and Corporate Controller |
Randall D. Stilley has served as Chief Executive Officer and President since October 2004. Prior to joining Hercules, Mr. Stilley was Chief Executive Officer of Seitel, Inc., an oilfield services company, from January 2004 to October 2004. From 2000 until he joined Seitel, Mr. Stilley was an independent business consultant and managed private investments. From 1997 until 2000, Mr. Stilley was President of the Oilfield Services Division at Weatherford International, Inc., an oilfield services company. Prior to joining Weatherford in 1997, Mr. Stilley served in a variety of positions at Halliburton Company, an oilfield services company. Mr. Stilley is a member of the Executive Committee at the Houston Technology Center. He is a registered professional engineer in the state of Texas and a member of the Society of Petroleum Engineers.
Steven A. Manz has served as Chief Financial Officer since January 2005. Prior to joining Hercules, Mr. Manz worked at Noble Corporation, a contract drilling company, from May 1995 to January 2005 in a number of roles, including Managing Director of the Noble Technology Services Division from May 2003 to January 2005, Vice President of Strategic Planning from August 2000 to May 2003, Director of Accounting and Investor Relations from March 1997 to August 2000 and Internal Audit Manager from May 1995 to March 1997. Prior to joining Noble, Mr. Manz served as senior auditor of Cooper Industries, an electrical products manufacturer, from May 1993 to May 1995 and as a member of the Audit Group of Price Waterhouse LLP from August 1989 to May 1993.
John T. Rynd became Senior Vice President of Hercules Offshore and President of Hercules Drilling Company, LLC in October 2005. Prior to joining Hercules, Mr. Rynd worked at Noble Drilling Services Inc., a wholly owned subsidiary of Noble Corporation, a contract drilling company, as Vice President—Investor Relations from October 2000 to September 2005 and as Vice President—Marketing and Contracts from September 1994 to September 2000. From June 1990 to September 1994, Mr. Rynd worked for Chiles Offshore Corporation, a contract drilling company, including as Vice President—Marketing.
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Randal R. Reed has served as President of our subsidiary, Hercules Liftboat Company, LLC, since October 2004. From 1995 to October 2004, Mr. Reed was manager of the fleet of liftboats, diveboats and crewboats of Global Industries, Ltd., an oilfield services company.
Thomas E. Hord has served as Vice President, Operations and Chief Operating Officer of Hercules Drilling Company, LLC since August 2004. Prior to joining our company, Mr. Hord supervised rig operations and marketing for Hercules Offshore Corporation, which is not affiliated with our company (“Unrelated HOC”), and its predecessor companies since 1982.
James W. Noe has served as Vice President, General Counsel, Chief Compliance Officer and Secretary since October 2005. From July 2002 to October 2005, Mr. Noe was Corporate Counsel for BJ Services Company, a worldwide oilfield services company. He was also in private practice from October 1997 to July 2002. On several occasions during 2000 and 2001 while still in private practice, Mr. Noe served as counsel for Single Buoy Moorings, a company that designs, owns and operates floating production systems.
Renee M. Pitre has served as Vice President, Finance of Hercules Liftboat Company, LLC since November 2004. From 1997 to November 2004, she was controller over four divisions of Global Industries, Ltd. From 1992 to 1997, Ms. Pitre was controller for the Americas region for Subsea International, an offshore oilfield services company.
Don P. Rodney has served as President of Hercules International Holdings Ltd. since December 2005. From July 2004 to December 2005, Mr. Rodney served as Vice President, Finance of Hercules Drilling Company, LLC. From October 2003 to June 2004, Mr. Rodney was Chief Financial Officer of Unrelated HOC. Mr. Rodney was retired from July 2003 to October 2003. From November 2002 to July 2003, he was Treasurer of TODCO, a contract drilling company. Mr. Rodney was Controller, Inland Water Division of Transocean from February 2001 until October 2002. From November 1992 until January 2001, Mr. Rodney served as Vice President, Finance for R&B Falcon Drilling USA, Inc., a marine contract drilling company, and its predecessors. From 1976 to November 1992, Mr. Rodney worked for Atlantic Pacific Marine Corp., a marine contract drilling company, in a number of positions, including as Controller from 1983 until November 1992.
Leslie K. Taylor has served as Vice President, Human Resources since October 2005. Prior to joining Hercules, Ms. Taylor worked at Calpine Corporation, an independent power producer, as the Director of Human Resources from July 2000 to September 2005 and as Manager of Human Resources from December 1999 to July 2000. From December 1998 to December 1999, Ms. Taylor worked for Columbia Energy Services, a natural gas and power trading company, as Manager of Human Resources.
Johnny K. Vincent has served as Vice President and Corporate Controller since November 2005. Prior to joining Hercules, Mr. Vincent worked at Dell Inc., an information technology supplier, as Controller, State and Local Government Sales from October 2004 to October 2005, Senior Manager of Corporate Internal Audit from July 2002 to October 2004, and Finance Consultant roles in the U.S. Consumer and Small Business Sales segments from March 1999 to July 2002. Prior to joining Dell, Mr. Vincent served as Director of Business Development at Complete RX, Ltd., a pharmacy management firm, from April 1998 to March 1999 and Director of Operations at Cardinal Health, a pharmaceutical company, from January 1996 to April 1998. Mr. Vincent also worked at Cooper Industries, an electrical products manufacturer, from August 1990 to January 1996 in a number of audit and accounting roles.
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PART II
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Our common stock is traded on the NASDAQ Global Market under the symbol “HERO.” As of March 1, 2006, there were 28 stockholders of record. The following table sets forth, for the periods indicated, the range of high and low sales prices for our common stock:
| Price | ||||||
| High | Low | |||||
| 2005 |
||||||
| Fourth Quarter (1) |
$ | 29.26 | $ | 20.60 | ||
| 2006 |
||||||
| First Quarter (2) |
$ | 36.70 | $ | 27.68 | ||
| (1) | Reflects trading activity from October 27, 2005 through December 31, 2005. |
| (2) | Reflects trading activity through March 1, 2006. |
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.
On November 1, 2005, we completed our initial public offering of 10,580,000 shares of our common stock at an initial offering price of $20.00 per share. Each share of common stock includes a right to purchase Series A Junior Participating Preferred Stock under the Rights Agreement dated as of October 31, 2005 between us and American Stock Transfer & Trust Company, as rights agent. We sold 6,250,000 shares of common stock at an aggregate offering price of $125.0 million, while selling stockholders sold the remaining 4,330,000 shares at an aggregate offering price of $86.6 million. The offering commenced on October 27, 2005 pursuant to a Registration Statement on Form S-1 (Registration No. 333-126457) that the SEC declared effective on October 26, 2005.
The net proceeds to us from the offering, after payment by us of $8.8 million in underwriting discounts and commissions and $1.2 million in estimated offering expenses, were approximately $115.1 million. We did not receive any of the proceeds from the sale of shares of our common stock by selling stockholders. We used $45.3 million of the net proceeds to repay $45.0 million outstanding principal amount of our senior secured term loan, together with accrued and unpaid interest to the repayment date of $0.3 million, and $44.0 million to complete the acquisition of a fleet of seven liftboats and related assets in November 2005. We also used approximately $7.3 million of the net proceeds from through January 31, 2006 for the refurbishment of Rig 16 and Rig 31 and the remaining proceeds on the acquisition of Rig 26 in February 2006.
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EQUITY COMPENSATION PLAN INFORMATION
The following table sets forth information about our common stock that may be issued under all of our existing equity compensation plans as of December 31, 2005:
| Plan Category |
Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights |
Weighted Average Exercise Price of Outstanding Options, Warrants and Rights |
Number of Securities Remaining Available for Future Issuance |
|||||
| Equity compensation plans approved by security holders (1) |
1,839,500 | $ | 11.38 | 540,500 | (2) | |||
| Equity compensation plans not approved by security holders |
— | — | — | |||||
| Total |
1,839,500 | $ | 11.38 | 540,500 | ||||
| (1) | Consists of the Hercules Offshore 2004 Long-Term Incentive Plan, which was approved by the members of our company prior to our initial public offering. |
| (2) | The securities available for issuance under the 2004 Long-Term Incentive Plan could be issued in the form of stock options, stock appreciation rights, stock awards and stock units. |
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| Item 6. | Selected Financial Data |
We have derived the following consolidated financial information as of and for the period from inception to December 31, 2004 and as of and for the year ended December 31, 2005 from our audited consolidated financial statements included in Item 8 of this annual report. 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.
We were formed in July 2004 and commenced operations in August 2004. From our formation to December 31, 2005, we completed several significant asset acquisitions that impact the comparability of our historical financial results. Our financial results reflect the impact of the assets only after the date of their acquisition. This annual report does not include any financial information relating to the assets for periods prior to their acquisition date. As described under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Acquisition History and Financial Statement Presentation” in Item 7, we have concluded that we are not required to include such pre-acquisition financial statements in this annual report, and we believe that separate audited financial statements for the assets we acquired as of any date or for any period prior to our acquisition of those assets would not be meaningful to investors.
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. Prior to the conversion, our owners elected to be taxed at the member unitholder 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.
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| Year Ended December 31, 2005 |
Period from 2004 |
|||||||
| (In thousands, except share data) | ||||||||
| Income Statement Data: |
||||||||
| Revenues: |
||||||||
| Drilling Services |
$ | 103,422 | $ | 24,006 | ||||
| Marine Services |
57,912 | 7,722 | ||||||
| Total Revenues |
161,334 | 31,728 | ||||||
| Cost and Expenses: |
||||||||
| Operating expenses for drilling services, excluding depreciation and amortization |
48,330 | 12,799 | ||||||
| Operating expenses for marine services, excluding depreciation and amortization |
29,484 | 4,198 | ||||||
| Depreciation and amortization |
13,790 | 2,016 | ||||||
| General and administrative, excluding depreciation and amortization |
13,871 | 2,808 | ||||||
| Total cost and expenses |
105,475 | 21,821 | ||||||
| Operating Income |
55,859 | 9,907 | ||||||
| Other Income (Expense): |
||||||||
| Interest expense |
(9,880 | ) | (2,070 | ) | ||||
| Loss on early retirement of debt |
(4,078 | ) | — | |||||
| Other, net |
924 | 228 | ||||||
| Income Before Income Taxes |
42,825 | 8,065 | ||||||
| Income Tax Provision |
||||||||
| Current income tax |
(122 | ) | — | |||||
| Deferred income tax |
(15,247 | ) | — | |||||
| Net Income |
$ | 27,456 | $ | 8,065 | ||||
| Net Income Per Share: |
||||||||
| Basic |
$ | 1.10 | $ | 0.55 | ||||
| Diluted |
$ | 1.08 | $ | 0.55 | ||||
| Weighted Average Shares Outstanding: |
||||||||
| Basic |
24,919,273 | 14,689,724 | ||||||
| Diluted |
25,431,822 | 14,689,724 | ||||||
| Balance Sheet Data (as of end of period): |
||||||||
| Cash and cash equivalents |
$ | 47,575 | $ | 14,460 | ||||
| Working capital |
70,083 | 30,283 | ||||||
| Total assets |
354,825 | 132,156 | ||||||
| Long-term debt, net of current portion |
93,250 | 53,000 | ||||||
| Total stockholders’ equity |
215,943 | 71,087 | ||||||
| Other Financial Data: |
||||||||
| Net cash provided by (used in): |
||||||||
| Operating activities |
$ | 52,763 | $ | (6,495 | ) | |||
| Investing activities |
(172,953 | ) | (96,274 | ) | ||||
| Financing activities |
153,305 | 117,229 | ||||||
| Capital expenditures |
168,038 | 94,443 | ||||||
| Deferred drydocking expenditures |
7,369 | 601 | ||||||
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| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
The following discussion and analysis should be read in conjunction with the accompanying consolidated financial statements as of and for the year ended December 31, 2005 and as of and for the period from inception (July 27, 2004) to December 31, 2004 (“period from inception to December 31, 2004”) 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 liftboat services to the oil and natural gas exploration and production industry primarily in the U.S. Gulf of Mexico. We provide these services to major integrated energy companies and independent oil and natural gas operators. We report our business activities in three business segments, Contract Drilling Services, Domestic Marine Services and International Marine Services. Prior to the fourth quarter of 2005, during which we acquired our international liftboats, we did not report an International Marine Services segment.
| • | Contract Drilling Services. We own a fleet of nine jackup rigs that can drill in maximum water depths ranging from 85 to 250 feet, and one jackup rig that we expect to be declared a constructive total loss. Under most of our contract drilling service agreements, 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. |
| • | Marine Services. We own a fleet of 46 liftboats in our Domestic and International Marine Services segments. Our Domestic Marine Services segment includes 42 liftboats operating in the U.S. Gulf of Mexico, and our International Marine Services segment includes four liftboats operating offshore Nigeria. Our liftboats are used to provide a wide range of offshore support services, including platform maintenance, platform construction, well intervention and decommissioning services, and can be moved from location to location within a short period of time. 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 and 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 contracts in Nigeria are longer-term in nature, with the existing contracts being for a two-year term expiring in August 2006.
Our operating costs are primarily a function of fleet configuration and utilization levels. The most significant direct operating costs for our Contract Drilling Services segment are wages paid to crews, maintenance and repairs to the rigs, and marine 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” 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 greatly reduced because the crew is smaller and maintenance activities are suspended. Rigs that have been cold-stacked typically require a lengthy reactivation project that can involve significant expenditures, particularly if the rig has been cold-stacked for a long period of time.
The most significant costs for our Marine Services segments are the wages paid to crews and the amortization of regulatory drydocking costs. Unlike our Contract Drilling Services segment, a significant portion
25
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 time of drydock vary depending on the condition of the vessel. All costs associated with regulatory inspections, including related drydocking costs, are deferred and amortized over a period of 12 to 24 months.
Industry Background and Trends
Market conditions improved during 2005 compared to 2004. Our jackup rigs were contracted at dayrates ranging from approximately $31,000 to $70,000 in 2005, as compared to dayrates ranging from approximately $23,000 to $37,000 for the period from inception to December 31, 2004. Our liftboats were contracted at dayrates ranging from approximately $2,200 to $20,500 in 2005, as compared to dayrates ranging from approximately $3,300 to $13,700 for the period from inception to December 31, 2004. Dayrates for our jackup rigs and liftboats have continued to increase in the first quarter of 2006, with dayrates for our jackup rigs ranging from approximately $53,000 to $75,000 for the first two months of 2006, and dayrates for our liftboats ranging from approximately $4,800 to $28,000 in the same period. As discussed under “-Outlook” below, we believe that current commodity prices support the recent increases in rig and liftboat dayrates. However, concerns over the level of oil supplies and natural gas in storage could lead to moderation or even a decline in dayrates.
The following table compares utilization rates for our jackup rigs, as operated by us or previous owners, with rates for similar units in the U.S. Gulf of Mexico for the years ended December 31, 2005, 2004, 2003, 2002 and 2001. The industry utilization rates for jackup rigs presented below are based on data provided by ODS-Petrodata and include the total number of jackup rigs of the specified type in the U.S. Gulf of Mexico. No industry data is available with respect to utilization rates of liftboats in the U.S. Gulf of Mexico or Nigeria; however, we believe that the utilization rates for our liftboats are comparable to those for similar vessels in our industry. The rates for our rigs and liftboats in the table below are presented on a pro forma basis as to the acquisitions of the rigs and liftboats currently in our fleet, excluding Rig 16 and Rig 31, which were located in international markets for all periods presented, Rig 26, which was cold-stacked in the U.S. Gulf of Mexico for all periods presented, Rig 25, which was severely damaged during Hurricane Katrina and is likely to be declared a constructive total loss, and the Whale Shark, which was acquired in August 2005 and is newly constructed. The rates therefore include utilization data for such units when owned and operated by prior owners. As a result, the utilization rates for our rigs and liftboats presented below may not be indicative of the utilization rates that we would have achieved had we owned the assets for all of the periods presented or that we will achieve in the future. In addition, because the utilization rates for our rigs and liftboats presented below are on a pro forma basis, those rates differ from the historical utilization rates for our rigs and liftboats presented elsewhere in this annual report. Utilization shown in the table below equals the total number of operating days for all rigs or liftboats of the specified type in the period as a percentage of the total number of calendar days in the period.
PRO FORMA UTILIZATION RATES
| Year Ended December 31, | |||||||||||||||
| 2001 | 2002 | 2003 | 2004 | 2005 | |||||||||||
| Jackup Rigs: |
|||||||||||||||
| U.S. Gulf of Mexico |
|||||||||||||||
| 250-foot mat slot jackup rigs |
63.1 | % | 12.9 | % | 34.6 | % | 48.5 | % | 66.4 | % | |||||
| 200-foot mat cantilever jackup rigs |
85.2 | 61.2 | 84.9 | 98.2 | 98.2 | ||||||||||
| Hercules rigs (1) |
81.9 | 78.4 | 88.6 | 87.4 | 97.5 | ||||||||||
| Liftboats: |
|||||||||||||||
| Hercules liftboats (2) |
73.2 | % | 76.4 | % | 60.7 | % | 64.1 | % | 79.7 | % | |||||
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| (1) | Excludes Rig 16 and Rig 31, which were located in international markets for all periods presented, Rig 16, which was cold-stacked in the U.S. Gulf of Mexico for all periods presented, Rig 25, which was severely damaged during Hurricane Katrina and is likely to be declared a constructive total loss. Rig 16, Rig 26 and Rig 31 were not marketed and were stacked for all periods presented. Utilization rates for Rig 25 were 83.0%, 98.1%, 100.0%, 68.0% and 100.0% for the years ended December 31, 2001, 2002, 2003 and 2004 and the period in 2005 prior to Hurricane Katrina, respectively. |
| (2) | Excludes the Whale Shark, which was acquired in August 2005 and is newly constructed. Liftboats, unlike jackup rigs, are required to undergo annual inspections as well as more thorough inspections requiring drydocking two times every five years. As a result, we believe that utilization rates of approximately 90% represent effectively full utilization of our liftboat fleet. |
Recent Developments
Initial Public Offering
We completed our initial public offering of 10,580,000 shares of common stock at $20.00 per share on November 1, 2005. We offered 6,250,000 shares of common stock, while the remaining 4,330,000 shares were offered by selling stockholders. We received approximately $115.1 million of proceeds from the offering, net of underwriting discounts and commissions and estimated expenses. We used $44.0 million of the proceeds to complete the acquisition of a fleet of seven liftboats from Danos & Curole Marine Contractors LLC, discussed below. In addition, we repaid $45.0 million of the senior secured term loan plus accrued interest of $0.3 million, discussed below. We used the remaining proceeds for the refurbishment of and upgrades to Rig 16 and Rig 31 and the acquisition of Rig 26.
On November 1, 2005, in connection with our initial public offering, we converted from a limited liability company to a corporation (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. 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.
Amendment to Credit Agreement
In December 2005, we formed Hercules International Holdings, Ltd. (“Holdings”), a Cayman Islands subsidiary, and three additional Cayman Island subsidiaries to support our international operations. We transferred ownership of Rig 16 and Rig 31 to Holdings in December 2005 and acquired Rig 26 with Holdings in February 2006.
In January 2006, we amended our credit agreement to provide for, among other things, the release of the guaranty, security agreement and vessel mortgages recently entered into by two of our Cayman subsidiaries in connection with the transfer of Rig 16 and Rig 31. In addition, we are permitted to advance up to $20.0 million to these two Cayman subsidiaries and to invest an additional $25.0 million in our foreign subsidiaries. We also amended the credit agreement to extend the termination date of the 1% prepayment premium (that is applicable to certain prepayments of the term loan) from June 29, 2006 to December 31, 2006.
Distribution to Former Members
In February 2006, in accordance with the terms of the limited liability company operating agreement governing our company prior to the Conversion, we made a distribution of $3.7 million to the former members of our company for taxes in respect of the ten-month period ended upon the Conversion. The former members did
27
not receive any other distributions prior to the Conversion, and other than this required distribution relating to taxes, the earnings generated by our company were retained by us as part of our stockholders’ equity balance upon the Conversion. We have no further obligation under the operating agreement to make any such distributions.
Acquisition of Rig 26
In February 2006, we acquired the jackup rig Rig 26 for a purchase price of $20.1 million. This rig is capable of drilling in water depths of up to 150 feet. We are currently refurbishing the rig in a shipyard in Louisiana and expect to spend approximately $20.0 million on that refurbishment. We expect the rig to be available in the first quarter of 2007. We intend to seek work for the rig under a longer-term contract in a suitable international location.
Recent Hurricanes
Two of our jackup rigs, Rig 21 and Rig 25, sustained damage during Hurricane Katrina. Rig 21 sustained substantial damage to its mat and was moved to a shipyard in Mississippi to repair the damage. We expect the rig will be available in the first quarter of 2006. We have recently completed the salvage and recovery operation of Rig 25 and filed a notice of abandonment with our insurance underwriters in February 2006. We expect the rig to be declared a constructive total loss under our insurance policies. If Rig 25 is declared a constructive total loss, we would recognize a gain equal to the excess of the insurance proceeds received over the rig’s carrying value of $20.5 million. Rig 25 is insured for $50.0 million, and insurance proceeds received would be reduced by the amount of salvage proceeds expected to be received from the sale of recovered materials. None of our rigs or liftboats sustained any material damage during Hurricane Rita.
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 property and equipment, revenue recognition, allowance for doubtful accounts, deferred charges and stock-based compensation. Inherent in such policies are certain key assumptions and estimates.
Property and Equipment
Property and equipment represents 69.7% of our total assets as of December 31, 2005. 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 non-current assets on the consolidated balance sheet and amortized on the straight-line method over a period of 12 to 24 months (see “-Deferred Charges” below). Depreciation is computed using the straight-line method 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
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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 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. 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, which are amortized over the related drilling contract.
Allowance for Doubtful Accounts
Accounts receivable represents approximately 10.8% of our total assets and 38.4% of our current assets as of December 31, 2005. 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, 2005, there was no allowance for doubtful accounts.
Deferred Charges
All of our 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 to 24 months. As of December 31, 2005, our net deferred charges related to regulatory inspection costs totaled $3.9 million. The amortization of the regulatory inspection costs was reported as part of our depreciation and amortization expense.
Stock Based Compensation
Stock-based compensation arrangements are accounted for using 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. Accordingly, compensation cost for options granted to employees is measured as the excess, if any, of the fair value of shares at the date of grant over the exercise price an employee must pay to acquire the shares. No compensation cost has been recognized in the accompanying consolidated financial statements related to stock option awards.
In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004) “Share-Based Payment” (“SFAS No. 123R”), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion 25. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on the fair values beginning with the first interim period in fiscal year 2006, with early adoption encouraged. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition.
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We adopted SFAS No. 123R on January 1, 2006 using the modified prospective method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS No. 123R for all share-based payments granted after January 1, 2006 and (b) on the requirements of SFAS No. 123 for all awards granted to employees prior to January 1, 2006 that remain unvested on January 1, 2006. We are estimating the cost relating to stock options using the Trinomial Lattice model. 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 2005 will be approximately $2.3 million for the year ended December 31, 2006 and $4.2 million over the remaining vesting period; 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.
Acquisition History and Financial Statement Presentation
Acquisitions from Parker Drilling and Assumption of Management of Rig 30
In August 2004, we acquired five jackup rigs, four platform rigs and related assets from Parker Drilling Company for $39.3 million. The four platform rigs and related assets that we acquired are not core to our business. We have sold three of the four platform rigs for net proceeds of $0.8 million, and we intend to sell the fourth, which is inactive. In January 2005, we acquired another jackup rig and related assets from Parker Drilling for $21.5 million. The jackup rigs acquired ranged in age from 22 years to 33 years, with an average expected remaining useful life of approximately 15 years.
Each of the jackup rigs we acquired from Parker Drilling was, at the time we acquired it, operating under a short-term contract with a customer. We assumed the obligation to perform these contracts and completed each of them within 90 days of our acquisition of the rigs. Thereafter, the rigs began working under contracts that we negotiated with our customers. We did not acquire any rights to the Parker Drilling name in the acquisitions, and we have not marketed the rigs under the Parker Drilling name.
Immediately following the August 2004 acquisition, we hired 248 rig-based employees who had been employed by Parker Drilling. Seven out of the 27 members of our headquarters staff following the acquisition were employed by Parker Drilling immediately prior to the acquisition; however, none of our senior management, and only one salesperson in our marketing staff, had been employed by Parker Drilling immediately prior to the acquisition. Other than this salesperson, we did not hire any financial, legal, human resources, information technology, marketing, safety, training, payroll, purchasing, warehouse, transportation or environmental employees or managers from Parker Drilling. The substantial majority of the Parker Drilling employees that we hired were rig-based, hourly compensated employees.
Concurrent with the August 2004 closing, we hired two operations management personnel and four office employees who had been employed by Hercules Offshore Corporation (“Unrelated HOC”). Unrelated HOC was formed in March 2001 by Thomas J. Seward II, the former president of our drilling company subsidiary, and Thomas E. Hord, the current vice president, operations and chief operating officer of that subsidiary, to manage a single jackup rig, Rig 30 (formerly named the Odin Victory), under a rig management contract with Porterhouse Offshore L.P., the owner of the rig. We do not own or control Unrelated HOC.
At the closing, Unrelated HOC and Porterhouse Offshore terminated the rig management contract, and Porterhouse Offshore entered into a new contract with us under which we were reimbursed for all of our expenses plus $100 per day. Aside from the rig management contract with Porterhouse Offshore, we did not acquire any other assets or liabilities of Unrelated HOC, and the rig-based crews operating Rig 30 remained employees of Unrelated HOC until we hired them in January 2005 in connection with our acquisition of the rig as described below.
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Acquisition from Global Industries
In October 2004, we acquired 22 liftboats and related assets from Global Industries, Ltd. for $53.5 million, including a property in New Iberia, Louisiana, which we use as an operational office. At the time of the acquisition, some of the liftboats were operating under short-term contracts with customers, with the remaining liftboats available for work. We assumed those contracts and completed them within 30 days of our acquisition of the units. Thereafter, the units began working under short-term contracts that we negotiated with our customers. We did not acquire any rights to the Global Industries name in the acquisition, and we have not marketed the rigs under the Global Industries name. The liftboats acquired ranged in age from four years to 26 years, with an expected average remaining useful life of approximately 15 years.
Under a transition services agreement, for six months following the acquisition, Global Industries was to perform the accounting and marketing/sales functions related to the liftboat operations on our behalf. Subsequent to closing, however, we began hiring our own accounting and administrative support personnel, some of whom were former Global Industries employees, and terminated the transition services agreement in February 2005. In connection with the closing of the acquisition, we hired 151 vessel-based employees, five mechanics, the general manager of the group and a liftboat operations manager who had been employed by Global Industries immediately prior to the acquisition. We did not hire any financial, legal, human resources, information technology, marketing, safety, training, payroll, purchasing, warehouse, transportation or environmental employees or managers from Global Industries. The substantial majority of Global Industries employees that we hired were vessel-based, hourly compensated employees.
Acquisition from Porterhouse Offshore
In January 2005, we acquired the jackup rig Rig 30 and related assets from Porterhouse Offshore for $20.0 million. At the time of acquisition, the age of the rig was 26 years, with an expected remaining useful life of approximately 15 years, and was operating under a short-term contract. As described above, we had managed the rig under the management contract entered into with Porterhouse Offshore concurrent with the closing of the August 2004 Parker Drilling acquisition. We hired the rig-based personnel operating the rig, who were employees of Unrelated HOC, at the time of the acquisition of the rig. We did not acquire any personnel from Porterhouse Offshore.
Acquisition from Superior
In June 2005, we acquired 17 liftboats and related assets from Superior Energy Services, Inc. for $19.8 million. In August 2005, we sold one of the liftboats for $0.3 million. At the time of the acquisition, ten of the liftboats were operating under short-term contracts with customers, three of the vessels were stacked, and the remaining four liftboats were available for work. We completed such contracts within 30 days of our acquisition of the units. Thereafter, any work for the units is under contracts that we negotiate with our customers. We did not acquire any rights to the Superior Energy name in the acquisition, and we have not marketed the liftboats under the Superior Energy name. The liftboats acquired ranged in age from 20 years to 33 years, with an expected remaining average useful life of approximately 15 years. Average utilization of these liftboats during the first quarter of 2005 was approximately 61%. The average utilization of the 13 actively marketed liftboats during that period was 80%.
In connection with the closing of the acquisition, we hired 35 vessel-based employees who had been employed by Superior Energy immediately prior to the acquisition. These employees were all hourly compensated employees. We did not hire any financial, legal, human resources, information technology, marketing, safety, training, payroll, purchasing, warehouse, transportation or environmental employees or managers from Superior Energy.
Acquisition from Transocean
In June 2005, we acquired the jackup rig Rig 16 from Transocean Inc. for a purchase price of $20.0 million. This rig is capable of drilling in water depths of up to 170 feet. We are currently refurbishing the rig in the
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United Arab Emirates and expect to spend approximately $9.2 million on that refurbishment. We expect the rig to be available in the first quarter of 2006. We intend to seek work for the rig under a longer-term contract in a suitable international location. At the time of acquisition, the age of the rig was 24 years, with an expected remaining useful life of approximately 15 years. We did not acquire any customer contracts from Transocean and did not hire any employees from Transocean in connection with the acquisition.
Acquisition from CS Liftboats
In August 2005, we acquired the liftboat Whale Shark from CS Liftboats, Inc. for a purchase price of $12.5 million. The liftboat has a leg length of 260 feet and was substantially complete at the time of acquisition. However, a number of design changes made by the previous owner required additional engineering to obtain operating certificates from the U.S. Coast Guard. We obtained all required certificates in the first quarter of 2006, and the liftboat was placed in service in the U.S. Gulf of Mexico. We spent approximately $0.5 million on the engineering and regulatory equipment after the acquisition. We did not acquire any customer contracts from CS Liftboats and did not hire any employees from CS Liftboats in connection with the acquisition.
Acquisition from Hydrocarbon Capital
In September 2005, we acquired the jackup rig Rig 31 from Hydrocarbon Capital II LLC for a purchase price of $12.6 million. This rig is capable of drilling in water depths of up to 250 feet. We are currently refurbishing the rig in Malaysia and expect to spend approximately $15 million on that refurbishment. We expect the rig to be available in the third quarter of 2006. We intend to seek work for the rig under a longer-term contract in a suitable international location. At the time of acquisition, the age of the rig was 26 years, with an expected remaining useful life of approximately 15 years. We did not acquire any customer contracts from Hydrocarbon Capital and did not hire any employees from Hydrocarbon Capital in connection with the acquisition.
Liftboat Acquisitions from Danos & Curole Marine Contractors LLC
In November 2005, we completed the acquisition of a fleet of seven liftboats and related assets from Danos & Curole Marine Contractors LLC for $44.0 million. Three of these liftboats, which have leg lengths ranging from 130 to 230 feet, are located in the U.S. Gulf of Mexico. At the time of the acquisition, these liftboats were operating under short-term contracts with customers. We assumed those contracts and completed them within 30 days of our acquisition of the units. Thereafter, the units began working under short-term contracts that we negotiated with our customers. Four liftboats, which have leg lengths ranging from 130 to 170 feet, are currently operating in Nigeria under longer-term contracts, which expire in August 2006. Danos & Curole continues to operate these four vessels under an operating agreement with us until we can establish our own operations in Nigeria. This operating agreement expires in September 2006 and can be terminated by us earlier upon 30 days’ notice to Danos & Curole. We did not acquire any rights to the Danos & Curole name in the acquisition, and we have not marketed the liftboats under the Danos & Curole name. The liftboats acquired ranged in age from four years to 19 years, with an expected average remaining useful life of approximately 15 years.
An additional liftboat subject to the purchase agreement, the Andre Danos, was damaged as a result of Hurricane Katrina. Danos & Curole is currently salvaging the vessel. We have agreed to reimburse Danos & Curole up to $0.5 million of the salvage costs. Danos & Curole insured the Andre Danos for $3.6 million, with a deductible of $1.5 million. Once the vessel is salvaged, Danos & Curole and its insurers will determine whether the vessel is a constructive total loss or can be repaired. If the vessel is determined to be a constructive total loss, a portion of the $44.0 million purchase price equal to the amount of insurance proceeds Danos & Curole recovers, net of the deductible, will be refunded by Danos & Curole to us. However, if the vessel can be repaired, Danos & Curole will conduct the repairs until the insurance proceeds received are completely expended, and will thereafter deliver the vessel to us in such condition without additional payment of any consideration. We believe the liftboat is likely to be declared a constructive total loss.
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In connection with the closing of the acquisition, we hired 46 vessel-based employees who had been employed by Danos & Curole immediately prior to or on the date of the acquisition. These employees were all hourly compensated employees. Following the acquisition, we hired two marketing employees, one human resource manager, two Nigeria-based operational supervisors and two maintenance managers. We did not hire any financial, legal, information technology, safety, training, payroll, purchasing, warehouse, transportation or environmental employees or managers from Danos & Curole.
Acquisition from Aries Offshore Partners Ltd.
In February 2006, we acquired the jackup rig Rig 26 from Aries Offshore Partners Ltd. for a purchase price of $20.1 million. This rig is capable of drilling in water depths of up to 150 feet. We are currently refurbishing the rig in a shipyard in Louisiana and expect to spend approximately $20.0 million on that refurbishment. We expect the rig to be available in the first quarter of 2007. We intend to seek work for the rig under a longer-term contract in a suitable international location. We are contractually restricted until 2015 from using the rig for drilling operations in U.S. waters. At the time of acquisition, the age of the rig was 26 years, with an expected remaining useful life of approximately 15 years. We did not acquire any customer contracts from Aries Offshore and did not hire any employees from Aries Offshore in connection with the acquisition.
Nature of Acquisitions
We believe that the acquisitions described above represent the acquisition of assets, not of “businesses” within the meaning of applicable accounting guidance. We did not acquire separate entities, subsidiaries or divisions. Although we hired rig- and vessel-based personnel, and some shore-based staff, we did not acquire from the sellers most of the personnel who had performed management functions of overseeing and supporting the assets that were sold to us. As of December 31, 2005, we employed approximately 400 people in our drilling operations and 330 people in our liftboat operations, exclusive of headquarters staff. Approximately 60% of those employees were employees of Parker Drilling, Global Industries, Superior Energy or Danos & Curole immediately prior to our related acquisition of assets from those companies.
We have independently developed the operating rights necessary to operate the assets, including the establishment of our own operating privileges with the U.S. Coast Guard, U.S. Minerals Management Service and Nigerian authorities. We did not acquire any of our processes and systems from any of the sellers. Instead, we have independently developed the material systems we use in operating our business, including systems related to management; accounting; payroll; benefits; health, safety and environment; training; marketing and sales; maintenance; and project management. We did not acquire any intangible assets or intellectual property from any of the sellers. Without the systems we have developed, we could not successfully access our customer base to generate revenue.
Financial Statements
Since we have concluded that the acquisitions of rigs and liftboats described above do not constitute the acquisition of businesses, we have not provided audited stand-alone pre-acquisition financial statements of the assets acquired. We do not believe that separate audited financial statements for the assets acquired for any date or period prior to our acquisition of those assets would be meaningful to investors. There are significant differences between the organization, operation and overhead structures of our company, on the one hand, and of each of the sellers, on the other hand. In addition, Parker Drilling had held the assets we acquired from them for sale and accounted for their operations as discontinued operations since 2003. We believe, therefore, that for an extended period such assets did not receive the same management attention, marketing effort or maintenance as other assets operated by Parker Drilling or that we provide to the rigs and our other assets.
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Results of Operations
The following table sets forth our operating days, average utilization rates, average revenue and expenses per day, revenues and operating expenses by operating segment and other selected information for the periods indicated:
| For the Year Ended December 31, 2005 |
Period from Inception to December 31, 2004 |
|||||||
| (Dollars in thousands, except per day amounts) |
||||||||
| Contract Drilling Services Segment: |
||||||||
| Number of rigs (as of end of period) |
9 | 5 | ||||||
| Operating days |
2,192 | 748 | ||||||
| Available days |
2,309 | 751 | ||||||
| Utilization (1) |
94.9 | % | 99.6 | % | ||||
| Average revenue per rig per day (2) |
$ | 47,177 | $ | 32,098 | ||||
| Average operating expense per rig per day (3)(4) |
$ | 20,932 | $ | 17,046 | ||||
| Revenues |
$ | 103,422 | $ | 24,006 | ||||
| Operating expenses, excluding depreciation and amortization (4) |
$ | 48,330 | $ | 12,799 | ||||
| Depreciation and amortization expense |
$ | 5,547 | $ | 1,070 | ||||
| General and administrative expenses, excluding depreciation and amortization |
$ | 5,486 | $ | 1,972 | ||||
| Operating income |
$ | 44,059 | $ | 8,165 | ||||
| Domestic Marine Services Segment: |
||||||||
| Number of liftboats (as of end of period) |
42 | 22 | ||||||
| Operating days |
8,571 | 1,350 | ||||||
| Available days |
10,971 | 1,958 | ||||||
| Utilization (1) |
78.1 | % | 68.9 | % | ||||
| Average revenue per liftboat per day (2) |
$ | 6,503 | $ | 5,720 | ||||
| Average operating expense per liftboat per day (3) |
$ | 2,590 | $ | 2,144 | ||||
| Revenues |
$ | 55,740 | $ | 7,722 | ||||
| Operating expenses, excluding depreciation and amortization |
$ | 28,413 | $ | 4,198 | ||||
| Depreciation and amortization expense |
$ | 8,031 | $ | 946 | ||||
| General and administrative expenses, excluding depreciation and amortization |
$ | 1,888 | $ | 581 | ||||
| Operating income |
$ | 17,408 | $ | 1,997 | ||||
| International Marine Services Segment: |
||||||||
| Number of liftboats (as of end of period) |
4 | — | ||||||
| Operating days |
212 | — | ||||||
| Available days |
212 | — | ||||||
| Utilization (1) |
100.0 | % | — | |||||
| Average revenue per liftboat per day (2) |
$ | 10,243 | $ | — | ||||
| Average operating expense per liftboat per day (3) |
$ | 5,052 | $ | — | ||||
| Revenues |
$ | 2,172 | $ | — | ||||
| Operating expenses, excluding depreciation and amortization |
$ | 1,071 | $ | — | ||||
| Depreciation and amortization expense |
$ | 176 | $ | — | ||||
| General and administrative expenses, excluding depreciation and amortization |
$ | 336 | $ | — | ||||
| Operating income |
$ | 589 | $ | — | ||||
| Total Company: |
||||||||
| Revenues |
$ | 161,334 | $ | 31,728 | ||||
| Operating expenses, excluding depreciation and amortization (4) |
$ | 77,814 | $ | 16,997 | ||||
| Depreciation and amortization expense |
$ | 13,790 | $ | 2,016 | ||||
| General and administrative expenses, excluding depreciation and amortization |
$ | 13,871 | $ | 2,808 | ||||
| Operating income |
$ | 55,859 | $ | 9,907 | ||||
| Interest expense |
$ | 9,880 | $ | 2,070 | ||||
| Loss on early retirement of debt |
$ | 4,078 | $ | — | ||||
| Other income |
$ | 924 | $ | 228 | ||||
| Income before income taxes |
$ | 42,825 | $ | 8,065 | ||||
| Income tax provision |
$ | 15,369 | $ | — | ||||
| Net income |
$ | 27,456 | $ | 8,065 | ||||
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| (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, which included Rig 16, Rig 21, Rig 25, Rig 31 and the Whale Shark, or cold-stacked units, which included three of our liftboats, 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. |
| (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. |
| (4) | Includes a $1.0 million loss for accrual of the deductible for insurance proceeds to repair Rig 21 for the year ended December 31, 2005. |
Our operations generally are affected by the seasonal differences in weather patterns in the U.S. Gulf of Mexico. These differences 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, such as Hurricane Rita in September 2005, Hurricane Katrina in August 2005 and Hurricane Ivan in September 2004, may also affect 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. Accordingly, our operating results may vary from quarter to quarter, depending on factors outside of our control.
We have presented below a comparison of certain daily operating and financial information and utilization for the year ended December 31, 2005 and the period from inception to December 31, 2004 because we believe it provides the most meaningful comparative analysis of our results of operations for those periods and provides meaningful trend information over those periods. We have not provided a comparison of the full period results. We do not believe such a comparison would be meaningful since our results of operations for the period from inception to December 31, 2004 include only the results from five rigs and 22 liftboats for all or a portion of a five-month period as compared with the results from nine rigs and 46 liftboats for all or a portion of a full year period in 2005. We also have not provided a comparison of our International Marine Services segment, because that segment was created in the fourth quarter of 2005 in connection with our acquisition of liftboats operating offshore Nigeria in November 2005.
Year Ended December 31, 2005 Compared with the Period from Inception to December 31, 2004
Average Revenue per Day
Contract Drilling Services Segment. Average revenue per rig per day for our Contract Drilling Services segment increased to $47,177 for the year ended December 31, 2005 (the “Current Period”) compared with $32,098 for the period from inception to December 31, 2004 (the “Prior Period”), an increase of 47%. The increase resulted from higher dayrates on our rigs and the January 2005 acquisition of Rig 30, which earned dayrates during the Current Period higher than the average for the rest of our fleet.
Domestic Marine Services Segment. Average revenue per liftboat per day for our Domestic Marine Services segment increased to $6,503 for the Current Period compared with $5,720 for the Prior Period, an
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increase of 14%. This increase resulted from higher dayrates for our liftboats, partially offset by the impact of Hurricanes Katrina and Rita, where we experienced 374 days of weather, cumulative for our liftboat fleet, resulting in half dayrates.
Average Operating Expense per Day
Contract Drilling Services Segment. Average operating expense per rig per day for our Contract Drilling Services segment increased to $20,932 for the Current Period compared with $17,046 for the Prior Period, an increase of 23%. The increase resulted primarily from an increase in labor expenses, which increased $1,686 per day, an increase in insurance costs, which increased $819 per day, and an increase in rig maintenance costs, which increased $558 per day. The insurance cost was impacted by the $1.0 million loss for the accrual of the deductible for insurance proceeds to repair Rig 21. The increase in operating expense per rig per day is due in part to the inclusion of operating expenses for Rig 21 while the rig was undergoing repairs for damage sustained during Hurricane Katrina. During that time, the rig was not considered available and therefore no available days for the rig were included in the calculation of average operating expense per rig per day.
Domestic Marine Services Segment. Average operating expense per liftboat per day for our Domestic Marine Services segment increased to $2,590 for the Current Period compared with $2,144 for the Prior Period, an increase of 21%. This increase resulted primarily from an increase in labor expenses, which increased $279 per day, an increase in insurance costs, which increased $45 per day, and an increase in liftboat maintenance costs, which increased $100 per day.
Utilization and Operating Days
Contract Drilling Services Segment. Utilization for our Contract Drilling Services segment was 94.9% for the Current Period compared with 99.6% for the Prior Period. Operating days for the Current Period totaled 2,192 compared with 748 for the Prior Period. The Current Period reflects our ownership of nine jackup rigs, following the acquisitions of Rig 25 and Rig 30 in January 2005, Rig 16 in June 2005 and Rig 31 in September 2005. Rig 16 and Rig 31 were undergoing refurbishment during the Current Period. The Prior Period reflects our ownership of only five jackup rigs.
Domestic Marine Services Segment. Utilization for our Domestic Marine Services segment was 78.1% for the Current Period compared with 68.9% for the Prior Period. Operating days for the Current Period totaled 8,571 compared with 1,350 for the Prior Period. The Current Period reflects our ownership of 42 liftboats in the segment following the acquisitions 17 liftboats in June 2005, the Whale Shark in August 2005 and three liftboats in November 2005 and the sale of one liftboat in August 2005. The Prior Period reflects our ownership of 22 liftboats for approximately three months in 2004.
Rig Information
We did not own any jackup rigs at the beginning of the Prior Period. We acquired five jackup rigs and assumed the management of another jackup rig from an unrelated party in August 2004. During the Prior Period, those jackup rigs were contracted at dayrates ranging from approximately $23,000 to $37,000.
We owned five jackup rigs and managed a sixth jackup rig at the beginning of the Current Period. We acquired two jackup rigs, including the jackup rig that we had been managing since August 2004, in January 2005, and an additional jackup rig in each of June 2005 and September 2005. Our jackup rigs were contracted at dayrates ranging from approximately $32,000 to $37,900 from January 1, 2005 to the date of the acquisition of the two jackup rigs in January 2005. Following the January 2005 acquisition but prior to the June 2005 acquisition, our jackup rigs were contracted at dayrates ranging from approximately $33,000 to $46,000. Following the June 2005 acquisition but prior to the September 2005 acquisition, our jackup rigs were contracted
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at dayrates ranging from approximately $33,000 to $53,000. Our jackup rigs were contracted at dayrates ranging from approximately $48,000 to $70,000 from the date of the acquisition of our ninth jackup rig in September 2005 to the end of the Current Period.
Liftboat Information
We did not own any liftboats at the beginning of the Prior Period. We acquired 22 liftboats in October 2004. During the Prior Period, those liftboats were contracted at dayrates ranging from approximately $3,300 to $13,700.
We owned 22 liftboats at the beginning of the Current Period. We acquired 17 liftboats in June 2005, one liftboat in August 2005 and seven liftboats in November 2005, and we sold one liftboat in August 2005. Our liftboats were contracted at dayrates ranging from approximately $2,800 to $13,000 from January 1, 2005 to the date of the acquisition in June 2005. Following the June 2005 acquisition but prior to the August 2005 acquisition, our liftboats were contracted at dayrates ranging from approximately $2,900 to $12,400. Following the August 2005 acquisition but prior to the November 2005 acquisition, our liftboats were contracted at dayrates ranging from approximately $2,200 to $13,500. Our liftboats were contracted at dayrates ranging from approximately $4,000 to $20,500 from the date of the November 2005 acquisition to the end of the Current Period.
Year Ended December 31, 2005
Revenues
Consolidated. Total revenues for the Current Period were $161.3 million. Total revenues were positively impacted by increasing jackup dayrates and additional operating days in our Domestic Marine Services segment as a result of the June 2005 liftboat acquisition and higher activity levels in our Domestic Marine Services segment following Hurricane Katrina and Hurricane Rita. Total revenues included $4.6 million in reimbursements from our customers for expenses paid by us.
Contract Drilling Services Segment. Revenues for our Contract Drilling Services segment were $103.4 million for the Current Period. Average revenue per rig per day was $47,177, operating days were 2,192 and average utilization was 94.9%. Revenues for our Contract Drilling Services segment included $2.3 million in reimbursements from our customers for expenses paid by us.
Domestic Marine Services Segment. Revenues for our Domestic Marine Services segment were $55.7 million for the Current Period. Average revenue per liftboat per day was $6,503, operating days were 8,571 and average utilization was 78.1%. The liftboats in our Domestic Marine Services segment increased from 22 to 42 liftboats in the Current Period. Average revenue per liftboat per day was negatively impacted by the liftboats acquired in June 2005, which are smaller and earned lower average dayrates than the remaining fleet. Revenues for our Domestic Marine Services segment included $2.3 million in reimbursements from our customers for expenses paid by us.
International Marine Services Segment. Our International Marine Services segment comprises the four liftboats acquired in November 2005 that are operating in Nigeria. Revenues for our International Marine Services segment were $2.2 million for the Current Period. Average revenue per liftboat per day was $10,243, operating days were 212 and average utilization was 100.0%. Revenues in our International Marine Services segment do not include any reimbursements from our customers for expenses paid by us.
Operating Expenses
Consolidated. Total operating expenses, excluding depreciation and amortization, for the Current Period were $77.8 million. Operating expenses in our Contract Drilling Services segment were impacted by increasing
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labor costs attributable to wage increases paid to our crews, and increasing insurance costs, including a $1.0 million deductible accrued for the repair of Rig 21. Operating expenses in our Domestic Marine Services segment were impacted during the Current Period by expenses associated with the liftboats acquired in June 2005 and additional expenses due to higher utilization on the remaining liftboat fleet.
Contract Drilling Services Segment. Operating expenses, excluding depreciation and amortization, for our Contract Drilling Services segment were $48.3 million for the Current Period. Average operating expenses per rig per day were $20,932. Average labor costs per rig per day, which include wages and benefits paid to crews, were $11,317. Average rig maintenance expenses per rig per day, excluding capitalized costs, were $3,066. Average insurance expense per rig was $1,807 per day, which includes the $1.0 million deductible accrued for the repair of Rig 21. Other rig expenses, which include catering, rentals, communications, and mobilization costs, averaged $4,742 per rig per day.
Domestic Marine Services Segment. Operating expenses, excluding depreciation and amortization, for our Domestic Marine Services segment were $28.4 million for Current Period. Operating expenses on our liftboats averaged $2,590 per liftboat per day in the period, ranging from $1,360 per liftboat per day for the smaller vessels to $4,313 per liftboat per day for the larger vessels. Average labor costs per liftboat per day, which includes wages and benefits paid to crews, were $1,378. Average maintenance expenses per liftboat per day, excluding capitalized costs, were $356. Average insurance expense per liftboat per day was $271. Other operating expenses, which include catering, rentals and communication costs, averaged $585 per liftboat per day.
International Marine Services Segment. Following our acquisition in November 2005, the four liftboats comprising the International Marine Services segment were operated by the sellers under a vessel operating agreement that expires in September 2006. The operating agreement provides for a monthly management fee of $125,000. Costs reflected in the segment include actual operating costs for the liftboats and the management fee charged to us by the sellers. The management fee for 2005 totaled $0.2 million. Operating expenses, excluding depreciation and amortization, for our International Marine Services segment were $1.1 million for Current Period. Operating expenses on our liftboats averaged $5,052 per liftboat per day in the period. Average labor costs per liftboat per day, which includes wages and benefits paid to crews, were $945. Average maintenance expenses per liftboat per day, excluding capitalized costs, were $1,745. Average insurance expense per liftboat per day was $673. Other operating expenses, which include catering, rentals and communication costs, averaged $1,689 per liftboat per day.
Depreciation and Amortization Expenses
Total depreciation and amortization expenses were $13.8 million for the Current Period. Results for the Current Period included $5.5 million of depreciation expense for our drilling fleet, $4.3 million of depreciation expense for our liftboat fleet and $3.9 million of amortization of regulatory inspections and related drydockings.
General and Administrative Expenses
General and administrative expenses, excluding depreciation and amortization, were $13.9 million for the Current Period. Our Contract Drilling Services, Domestic Marine Services and International Marine Services segments incurred general and administrative expenses of $5.5 million, $1.9 million and $0.3 million, respectively. General and administrative expenses for our corporate office were $6.2 million. Expenses related to our initial public offering totaling $2.2 million are included in our corporate general and administrative expense.
Interest Expense
Interest expense was $9.9 million for the Current Period. Results for the period included $2.0 million of interest expense associated with the $28.0 million in borrowings incurred in the acquisition of five drilling rigs in August 2004, $1.0 million associated with the $28.0 million in borrowings incurred in the acquisition of 22
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liftboats in October 2004, $1.6 million associated with $25.0 million of borrowings incurred in the acquisitions of Rig 25 and Rig 30 in January 2005, $0.1 million associated with the $20.0 million in borrowings incurred in the acquisition of liftboats in June 2005 and $5.2 million associated with $140.0 million in borrowings incurred in refinancing our debt in June 2005.
Other Income
Other income was $0.9 million for the Current Period. Results for the period included $0.6 million of interest income associated with short-term investments of cash.
Period from Inception to December 31, 2004
Revenues
Consolidated. Total revenues were $31.7 million for the Prior Period. Revenues for the period include activity for the five jackup rigs acquired in August 2004 and for the 22 liftboats acquired in October 2004. Total revenues included $0.9 million in reimbursements from our customers for expenses paid by us.
Contract Drilling Services Segment. Revenues for our Contract Drilling Services segment were $24.0 million for the Prior Period. Segment revenues included activity for the five jackup rigs beginning on August 2, 2004. Average revenue per rig per day was $32,098, operating days were 748 and average utilization was 99.6%. Revenues for our Contract Drilling Services segment included $0.6 million in reimbursements from our customers for expenses paid by us.
Domestic Marine Services Segment. Revenues for our Domestic Marine Services segment were $7.7 million for the Prior Period. Segment revenues included activity for the 22 liftboats beginning on October 2, 2004. Average revenue per liftboat per day was $5,720, operating days were 1,350 and average utilization was 68.9%. Revenues for our Domestic Marine Services segment included $0.3 million in reimbursements from our customers for expenses paid by us. We did not have an International Marine Services segment in the Prior Period.
Operating Expenses
Consolidated. Total operating expenses, excluding depreciation and amortization, were $17.0 million for the Prior Period. Total operating expenses included expenses for five jackup rigs beginning on August 2, 2004 and for 22 liftboats beginning on October 2, 2004.
Contract Drilling Services Segment. Operating expenses, excluding depreciation and amortization, for our Contract Drilling Services segment were $12.8 million for the Prior Period. Average operating expenses per rig were $17,046 per day. Average labor costs per rig, which include wages and benefits paid to crews, were $9,631 per day. Rig maintenance expenses per rig, excluding capitalized costs, were $2,508 per day. Other rig expenses, which included catering, rentals, communications, insurance and mobilization costs, averaged $4,907 per rig per day.
Domestic Marine Services Segment. Operating expenses, excluding depreciation and amortization, for our Domestic Marine Services segment were $4.2 million for the Prior Period. Segment expenses included three months of activity from the inception of the segment on October 2, 2004 with the acquisition of 22 liftboats. Our most significant operating expenses were labor ($2.2 million), vessel maintenance, excluding capital expenditures and drydocking costs ($0.5 million), and insurance ($0.4 million). Operating expenses on our liftboats averaged $2,144 per liftboat per day in the period, ranging from $1,158 per day for the smaller vessels to $3,014 per day for the larger vessels.
Depreciation and Amortization Expenses
Total depreciation and amortization expenses were $2.0 million for the Prior Period and included $1.1 million of depreciation expense associated with the acquisition of five jackup rigs in August 2004, $0.8 million
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of depreciation expense associated with the 22 liftboats in October 2004 and $0.1 million of amortization of regulatory inspections and related drydockings.
General and Administrative Expenses
General and administrative expenses, excluding depreciation and amortization, were $2.8 million for the Prior Period. Our Contract Drilling Services and Domestic Marine Services segments incurred general and administrative expenses of $2.0 million and $0.6 million, respectively. General and administrative expenses for our corporate office were $0.2 million.
Interest Expense
Interest expense was $2.1 million for the Prior Period, which represented interest due on a $28.0 million term loan used to fund the acquisition of five jackup rigs in August 2004 and an additional $28.0 million term loan used to fund the acquisition of 22 liftboats in October 2004.
Outlook
Our industry is cyclical and is typically driven by general economic activity and changes in actual or anticipated oil and natural gas prices. In addition, most of our rigs and liftboats are located in the shallow waters of the U.S. Gulf of Mexico, which is a market characterized by short-term contracts for our rigs and liftboats to support drilling and production primarily of natural gas. Throughout 2005, oil and natural gas prices were high relative to historical levels and, as a result, we experienced strong demand for our rigs and liftboats.
In addition to the favorable commodity price environment, two other factors positively impacted the market conditions for our rigs and liftboats during 2005. First, a number of jackup rigs have been mobilized out of the U.S. Gulf of Mexico over the past five years, and several of our competitors have announced the mobilization of a number of additional rigs from the U.S. Gulf of Mexico to international locations in 2006. Second, because of the significant damage to rigs, production platforms, pipelines and other equipment in the U.S. Gulf of Mexico caused by Hurricanes Katrina and Rita, demand for our liftboats for inspection and repair work has increased significantly compared to the beginning of 2005. We anticipate that the additional inspection and repair work will continue into 2006. We also expect increased demand for our well intervention capabilities to assist our customers in restoring production from wells damaged by the hurricanes. Plug and abandonment and platform decommissioning work is also expected to increase in 2006.
Since mid-December 2005, commodity prices have decreased, particularly natural gas prices, which have declined sharply. Commodity prices continue to remain relatively strong, however, compared to average prices over the past five years. We believe that the current favorable market conditions will continue for at least the near term and that current commodity prices support the recent increases in rig and liftboat dayrates. However, demand for our rigs and liftboats could be negatively impacted by a number of factors, including among others increases in the supply of rigs and liftboats in the U.S. Gulf of Mexico, unexpected changes in oil and natural gas prices, increases in insurance costs for both our assets and for our customers’ production assets, the cost and availability of labor and regulatory changes. In addition, concerns over the level of oil supplies and natural gas in storage could lead to moderation or even a decline in dayrates. Sensitivity to natural gas price changes varies for each of our customers, but even the expectation of weaker prices may influence their decision to contract our rigs and liftboats.
According to ODS-Petrodata, as of February 2006, 51 jackup rigs have been ordered by industry participants, national oil companies and financial investors for delivery through 2009. We do not anticipate that these rigs will compete directly with our fleet, but may indirectly impact us through competition in other markets. In addition, nine idle jackups in the U.S. Gulf of Mexico owned by our competitors have been cold stacked for all of 2005, and in some cases, several years earlier. We believe that these idle jackup rigs will require extensive capital expenditures to refurbish and bring back into service, but given the current tight market
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conditions, our competitors may begin reactivating at least some of these rigs. There are also seven liftboats under construction in the U.S. that are targeted for use in the U.S. Gulf of Mexico. Once delivered, these liftboats may impact the demand for our liftboat fleet.
Liquidity and Capital Resources
Sources and Uses of Cash
Sources and Uses of Cash for the Year Ended December 31, 2005
Net cash provided by operating activities for the year ended December 31, 2005 was $52.8 million, which was primarily attributable to net income of $27.5 million plus depreciation and amortization of $13.8 million, an increase in accounts payable and other current liabilities of $19.9 million, a deferred income tax provision of $15.2 million, $0.1 million in stock based compensation and a $4.1 million loss on the early retirement of debt, partially offset by a $27.8 million increase in accounts receivable and other current assets. The increase in accounts receivable was due to increased revenue from higher average dayrates for our Contract Drilling Services and Domestic Marine Services segments and the revenue from the liftboats acquired in 2005.
Net cash used in investing activities for the year ended December 31, 2005 was $173.0 million. The net cash investments during the period included the acquisition in January 2005 of Rig 25 and Rig 30 for an aggregate of $41.5 million, the acquisitions in June 2005 of 17 liftboats for an aggregate of $19.8 million and Rig 16 for $20.0 million, the acquisition in August 2005 of the Whale Shark liftboat for $12.5 million, the acquisition in September 2005 of Rig 31 for $12.6 million and the acquisition in November 2005 of seven liftboats for $44.0 million. The acquisition of Rig 25 was funded in part by a $2.0 million deposit paid in 2004, which was applied towards the purchase price at closing. Capital expenditures for our rigs and liftboats in 2005 included $5.7 million for the refurbishment of Rig 16, $2.9 million for the refurbishment of Rig 31 and $7.4 million for drydockings of liftboats and $4.3 million for general rig refurbishments.
Net cash provided by financing activities for the year ended December 31, 2005 totaled $153.3 million. This amount included $116.3 of net proceeds from our initial public offering in November 2005 (which amount does not take into account $1.2 million of estimated offering expenses), borrowings of $45.0 under two of our credit facilities for the acquisitions of Rig 25 and Rig 30 and the liftboats acquired in June 2005 and $140.0 million under our new senior secured term loan. In addition, we received contributions from owners prior to our initial public offering totaling $4.3 million. We repaid $101.0 million outstanding under our then-existing credit facilities with proceeds from our new term loan, and we repaid $45.0 million of our outstanding term loan with the proceeds from our initial public offering and made a $0.4 million principal payment in October 2005. We also paid $6.0 million in fees and expenses in connection with our debt agreements.
Sources and Uses of Cash for the Period from Inception to December 31, 2004
Net cash used in operating activities for the period from inception to December 31, 2004 was $6.5 million. Net income for the period totaled $8.1 million, which was offset by the adjustments to net income representing a reduction in cash of $14.6 million. The adjustments to reconcile net income to net cash used by operating activities included an increase in accounts receivable and other current assets totaling $21.7 million partially offset by depreciation of $2.0 million and an increase in accounts payable and other current liabilities of $5.1 million. The increases in both the current assets and the current liabilities were attributable to the start-up of our business activities.
Net cash used in investing activities for the period from inception to December 31, 2004 was $96.2 million. The net cash investments during the period included the acquisition of five jackup and four platform rigs in August 2004 for $39.3 million, the acquisition of a fleet of 22 liftboats in October 2004 for $53.5 million, an increase in deferred drydocking expenses of $0.6 million and a deposit of $2.0 million related to the purchase of Rig 25, which closed in January 2005. Additionally, in November 2004 we sold three of the platform rigs for $0.8 million that we had purchased in August 2004. We accounted for this sale as a reduction in the original purchase price of the assets.
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Net cash provided by financing activities for the period from inception to December 31, 2004 totaled $117.2 million. This included contributions from owners of $63.0 million and proceeds from borrowings under our term loans totaling $56.0 million, less lenders fees and expenses totaling $1.8 million.
Liquidity and Financing Arrangements
Contributions from owners and borrowings from our creditors represented our primary source of liquidity for the period from inception to December 31, 2004. For the same period, our primary uses of cash were the acquisitions of jackup and platform rigs and 22 liftboats. Proceeds from our initial public offering, borrowings from our creditors, and cash from operations represented our primary sources of liquidity for the year ended December 31, 2005. For the same period, our primary uses of cash were the acquisitions of additional rigs and liftboats for our fleet.
We believe that our current cash on hand and our cash flow from operations through December 31, 2006, together with availability under our revolving credit facility and insurance recoveries, will be adequate during such period to repay our debts as they become due, to make normal recurring capital additions and improvements, to meet working capital requirements, to refurbish Rig 16, Rig 26 and Rig 31, to repair Rig 21 and, if it is not declared a constructive total loss, Rig 25, and otherwise to operate our business. Our ability to make payments on our indebtedness and to fund planned capital expenditures in the future will depend on our ability to generate cash, 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 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.
As a result of the damage sustained by the oil and natural gas industry from Hurricanes Ivan, Katrina and Rita, we anticipate that our insurance costs will increase significantly after the end of our current policy period on July 31, 2006. Competitors with assets in the Gulf of Mexico that have already completed their renewals in 2006 are experiencing a difficult market environment with insurance underwriters, and are likely to have increased premium costs, higher levels of retention and limits on the aggregate damage they may claim in a major windstorm. To obtain access to adequate insurance coverage we may terminate our current policy early to accelerate the renewal process. If storm activity in 2006 is as severe as it was in 2005, insurance underwriters may no longer insure U.S. Gulf of Mexico assets against weather-related damage.
Cash
Cash balances as of December 31, 2005 totaled $47.6 million. This represented an increase of $33.1 million from the cash balances of $14.5 million as of December 31, 2004. The increase was due to aggregate borrowings of $185.0 million under our various term loans, net proceeds from the sale of common stock in our initial public offering of $115.1 million, contributions from owners totaling $4.3 million and cash flow generated from operations of $52.8 million. The amounts were partially offset by debt repayments of $146.4 million and the acquisition of rigs and liftboats for a total of $168.0 million.
Debt
Our current debt structure is used to fund our business operations, and our revolving credit facility is a source of liquidity. As of December 31, 2005, we had outstanding long-term debt of $94.7 million, including current maturities of $1.4 million.
In June 2005, we entered into a senior secured credit agreement with a syndicate of financial institutions. This agreement provides for a $140.0 million term loan and a $25.0 million revolving credit facility. We may
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seek commitments to increase the amount available under the credit agreement by an additional $25.0 million if the amount outstanding under the term loan is no more than $105.0 million and our leverage ratio, after giving effect to the incurrence of the additional $25.0 million of borrowings, is no greater than 2.5 to 1. We used $54.6 million of the proceeds from the term loan to repay all outstanding amounts under the credit facility of our drilling company subsidiary and $47.5 million of the proceeds to repay all outstanding amounts under the credit facility of our liftboat company subsidiary, in each case including accrued interest, fees and applicable prepayment premiums. We terminated both of those credit facilities in connection with the repayment. In addition, we used $20.0 million of the remaining proceeds from the term loan to fund the purchase price of Rig 16. In connection with the repayment of the two credit facilities, we recognized in the second quarter of 2005 pretax charges of $2.8 million, consisting of a prepayment penalty and the write-off of deferred financing costs related to the retired debt. In addition, we repaid $45.0 million of the outstanding amount under the term loan, together with the accrued and unpaid interest of $0.3 million, with proceeds from our initial public offering. We recognized a pretax charge of $1.3 million in connection with the repayment in the fourth quarter of 2005.
The revolving credit facility provides for swing line loans of up to $2.5 million and for the issuance of up to $5.0 million of letters of credit. The revolving loans bear interest at a rate equal to, at our option, either (1) the highest of (a) Comerica Bank’s base rate, (b) the three-month certificate of deposit rate plus 0.5% and (c) the Federal funds effective rate plus 0.5%, in each case plus 2.25%, or (2) LIBOR plus 3.25%. We may prepay the revolving loans at any time without premium or penalty. The revolving loans mature in June 2008. We are required to pay a commitment fee of 0.50% on the average daily amount of the unused commitment amount of the revolving credit facility and a letter of credit fee of 3.25%, plus a fronting fee of 0.13%, with respect to the undrawn amount of each issued letter of credit. As of December 31, 2005, no amounts were outstanding and no letters of credit had been issued under the revolving credit facility.
The term loan bears interest at a rate equal to, at our option, either (1) the highest of (a) Comerica Bank’s base rate, (b) the three-month certificate of deposit rate plus 0.5% and (c) the Federal funds effective rate plus 0.5%, in each case plus 2.25%, or (2) LIBOR plus 3.25%. As of December 31, 2005, $94.7 million of the principal amount of the term loan was outstanding, and the interest rate was 7.3%. In accordance with the credit agreement, in July 2005, we entered into hedge transactions with the purpose and effect of fixing the interest rate on $70.0 million of the outstanding principal amount of the term loan at 7.54% for three years. In addition, we entered into hedge transactions with the purpose and effect capping the interest rate on an additional $20.0 million of such principal amount at 8.25% for three years. Principal payments of $350,000 are due quarterly, and the outstanding principal balance of the term loan is payable in full in June 2010. We may prepay the term loan at any time without premium or penalty, except that prepayments made before December 31, 2006 with proceeds from debt issuances or in connection with a repricing of the term loan will be made at 101% of the principal repaid.
We are required to prepay the term loan with:
| • | the proceeds from sales of certain assets; |
| • | the proceeds from casualties or condemnations of assets to the extent that the net cash proceeds from any such casualty or condemnation exceed $1.0 million and are not reinvested within one year; |
| • | the net proceeds of certain debt for borrowed money; |
| • | 25% of the net proceeds of any public or private offering of our equity securities, provided that holders of the term loan may reject the mandatory prepayment; and |
| • | 50% of excess cash flow if either our leverage ratio is above 3.0 to 1.0 or the outstanding principal balance of the term loan is greater than $110.0 million. |
Our obligations under the credit agreement are secured by our liftboats, all of our domestic rigs and substantially all of our other personal property, including all the equity of our domestic subsidiaries and
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two-thirds of the equity of certain of our foreign subsidiaries. All of our domestic material subsidiaries guarantee our obligations under the agreement and have granted similar liens on substantially all of their assets.
The credit agreement contains financial covenants relating to leverage and interest coverage. Other covenants contained in the agreement restrict, among other things, repurchases of equity interests, mergers, asset dispositions, guaranties, debt, liens, acquisitions, dividends, distributions, investments, affiliate transactions, prepayments of other debt and capital expenditures. The credit agreement permits us to advance up to $20.0 million to two of our Cayman subsidiaries and permits us to invest an additional $25.0 million in our foreign subsidiaries. We are currently in compliance in all material respects with our covenants under the credit agreement. The credit agreement contains customary events of default.
Capital Expenditures
We expect to spend approximately $46.2 million in 2006 on the refurbishment and upgrade of our rigs and liftboats. Rigs or liftboats that have been idle for long periods of time will often require a substantial amount of work to restore the rig or liftboat into operating condition. This often entails replacing or rebuilding much of the operating equipment, and is often costly. We describe this process as a refurbishment, and we capitalize the costs of restoring a unit to operating condition.
We differentiate a refurbishment from an upgrade, in which we materially increase 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 size of the living quarters’ capacity, or a combination of each. As part of our acquisitions of Rig 16, Rig 31 and Rig 26, we had to undertake both a major refurbishment project and upgrade of each rig to make them competitive with rigs that are already in operation.
We expect to spend approximately $9.2 million to upgrade Rig 16 and expect to complete the upgrade in the first quarter of 2006. The commissioning of the Whale Shark was completed in the first quarter of 2006 for total expenditures of $0.5 million. We expect to spend approximately $15.0 million to refurbish and upgrade Rig 31 and to complete the project by the third quarter of 2006. We expect to spend approximately $20.0 million to refurbish and upgrade Rig 26 and to complete the project in early 2007. Additionally, we expect the cost to repair Rig 21 to be within insured values. In addition to the repairs from hurricane damage, we are performing additional maintenance to Rig 21 while it is in the shipyard totaling approximately $3.2 million. These maintenance costs will not be covered by insurance proceeds. We also expect to spend approximately $2.0 million to refurbish the Corina and the Pike, two liftboats in our fleet that are currently inactive.
Over the remainder of 2006, we will continue to incur expenditures to upgrade and refurbish our rigs and our liftboats. In addition, we are required to inspect and drydock our liftboats on a periodic basis to meet U.S. Coast Guard requirements. During 2005, we spent approximately $13.9 million on rig refurbishments and $7.4 million on liftboat drydockings. We expect these amounts to increase as we acquire additional rigs and liftboats and as our fleet ages. 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
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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 senior secured credit facility.
Contractual Obligations
The following table summarizes our contractual obligations as of December 31, 2005:
| Payments due by period ending December 31, | |||||||||||||||
| Contractual Obligations (1) |
2006 | 2007 to 2008 |
2009 to 2010 |
Thereafter | Total | ||||||||||
| (in thousands) | |||||||||||||||
| Long-term debt obligations |
$ | 1,400 | $ | 2,800 | $ | 90,450 | $ | — | $ | 94,650 | |||||
| Management compensation obligations |
1,550 | 609 | — | — | 2,159 | ||||||||||
| Obligation to former members |
3,732 | — | — | — | 3,732 | ||||||||||
| Operating lease obligations |
651 | 632 | 487 | 33 | 1,803 | ||||||||||
| Total contractual obligations |
$ | 7,333 | $ | 4,041 | $ | 90,937 | $ | 33 | $ | 102,344 | |||||
| (1) | As of December 31, 2005, we did not have any material purchase obligations for goods or services. |
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements.
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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 and repair costs; |
| • | expected repair time for Rig 21 and the declaration of Rig 25 as a constructive total loss; |
| • | amounts expected to be paid by insurance proceeds for Rig 21 and Rig 25; |
| • | expected time to complete the refurbishment of Rig 16, Rig 26 and Rig 31; |
| • | sufficiency of funds for required capital expenditures, working capital and debt service; |
| • | our plans regarding increased international operations; |
| • | our expectations regarding the availability and costs of insurance coverages for our rigs and liftboats; |
| • | 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 |
| • | expectations regarding improvements in offshore drilling activity, continuation of current market conditions, demand for our rigs and liftboats, inspection and repair work for our 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 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; |
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| • | 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 exposed to interest rate risk with respect to our variable rate debt. All of the debt under our term loan is at variable rates. As of December 31, 2005, the interest rate for the $94.7 million outstanding under the term loan was 7.3%. In accordance with the credit agreement, in July 2005, we entered into hedge transactions with the purpose and effect of fixing the interest rate on $70.0 million of the outstanding principal amount of the term loan at 7.54% for three years. In addition, we entered into hedge transactions with the purpose and effect of capping the interest rate on an additional $20.0 million of such principal amount at 8.25% for three years. We entered into these instruments other than for trading purposes. A hypothetical 100 basis point increase in the average interest rate on our variable rate debt outstanding as of December 31, 2005 would increase our annual interest expense by approximately $0.9 million.
47
| Item 8. | Financial Statements and Supplementary Data |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors
Hercules Offshore, Inc.
We have audited the accompanying consolidated balance sheets of Hercules Offshore, Inc. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, comprehensive income, stockholders’ equity and cash flows for the year ended December 31, 2005 and for the period from July 27, 2004 (inception) to December 31, 2004. 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, 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, 2005 and 2004, and the results of their operations and their cash flows for the year ended December 31, 2005 and the period from July 27, 2004 (inception) to December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.
| /s/ GRANT THORNTON LLP |
| Houston, Texas |
| February 24, 2006 |
48
HERCULES OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands)
| December 31, 2005 |
December 31, 2004 | ||||||
| ASSETS | |||||||
| CURRENT ASSETS |
|||||||
| Cash and cash equivalents |
$ | 47,575 | $ | 14,460 | |||
| Accounts receivable, net |
38,484 | 19,501 | |||||
| Deposits |
33 | 2,032 | |||||
| Assets held for sale |
2,040 | — | |||||
| Prepaid expenses and other |
12,079 | 2,359 | |||||
| Total current assets |
100,211 | 38,352 | |||||
| PROPERTY AND EQUIPMENT, net |
247,443 | 91,774 | |||||
| OTHER ASSETS, net |
7,171 | 2,030 | |||||
| Total assets |
$ | 354,825 | $ | 132,156 | |||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
| CURRENT LIABILITIES |
|||||||
| Current portion of long-term debt |
$ | 1,400 | $ | 3,000 | |||
| Accounts payable |
13,281 | 1,838 | |||||
| Accrued liabilities |
11,165 | 2,174 | |||||
| Taxes payable |
122 | — | |||||
| Interest payable |
1,759 | 374 | |||||
| Other liabilities |
2,401 | 683 | |||||
| Total current liabilities |
30,128 | 8,069 | |||||
| LONG-TERM DEBT, net of current portion |
93,250 | 53,000 | |||||
| DEFERRED INCOME TAXES |
15,504 | — | |||||
| COMMITMENTS AND CONTINGENCIES |
|||||||
| STOCKHOLDERS’ EQUITY |
|||||||
| Member units (64 units issued and outstanding) |
— | 63,022 | |||||
| Common stock, par value $0.01 per share; 200,000 shares authorized; 30,243 shares issued and outstanding |
302 | — | |||||
| Additional paid-in capital |
184,698 | — | |||||
| Restricted stock (unearned compensation) |
(1,322 | ) | — | ||||
| Accumulated other comprehensive income |
476 | — | |||||
| Retained earnings |
31,789 | 8,065 | |||||
| Total stockholders’ equity |
215,943 | 71,087 | |||||
| Total liabilities and stockholders’ equity |
$ | 354,825 | $ | 132,156 | |||
The accompanying notes are an integral part of these statements.
49
HERCULES OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share data)
| Year Ended December 31, 2005 |
Period from December 31, 2004 |
|||||||
| REVENUES |
||||||||
| Contract drilling services |
$ | 103,422 | $ | 24,006 | ||||
| Marine services |
57,912 | 7,722 | ||||||
| 161,334 | 31,728 | |||||||
| COSTS AND EXPENSES |
||||||||
| Operating expenses for contract drilling services, excluding depreciation and amortization |
48,330 | 12,799 | ||||||
| Operating expenses for marine services, excluding depreciation and amortization |
29,484 | 4,198 | ||||||
| Depreciation and amortization |
13,790 | 2,016 | ||||||
| General and administrative, excluding depreciation and amortization |
13,871 | 2,808 | ||||||
| 105,475 | 21,821 | |||||||
| OPERATING INCOME |
55,859 | 9,907 | ||||||
| OTHER INCOME (EXPENSE) |
||||||||
| Interest expense |
(9,880 | ) | (2,070 | ) | ||||
| Loss on early retirement of debt |
(4,078 | ) | — | |||||
| Other, net |
924 | 228 | ||||||
| INCOME BEFORE INCOME TAXES |
42,825 | 8,065 | ||||||
| INCOME TAX PROVISION |
||||||||
| Current income tax |
(122 | ) | — | |||||
| Deferred income tax |
(15,247 | ) | — | |||||
| NET INCOME |
$ | 27,456 | $ | 8,065 | ||||
| EARNINGS PER SHARE (SEE NOTE 3): |
||||||||
| Basic |
$ | 1.10 | $ | 0.55 | ||||
| Diluted |
$ | 1.08 | $ | 0.55 | ||||
| WEIGHTED AVERAGE SHARES OUTSTANDING: |
||||||||
| Basic |
24,919,273 | 14,689,724 | ||||||
| Diluted |
25,431,822 | 14,689,724 | ||||||
The accompanying notes are an integral part of these statements.
50
HERCULES OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
| Year Ended December 31, 2005 |
Period from inception (July 27, 2004) to December 31, 2004 |
|||||||
| CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||
| Net income |
$ | 27,456 | $ | 8,065 | ||||
| Adjustments to reconcile net income to net cash provided by (used in) operating activities |
||||||||
| Depreciation and amortization |
13,790 | 2,016 | ||||||
| Stock based compensation expense |
78 | — | ||||||
| Deferred income taxes |
15,247 | — | ||||||
| Amortization of deferred financing fees |
890 | 215 | ||||||
| (Recovery of) provision for bad debts |
(519 | ) | 519 | |||||
| Loss on early retirement of debt |
4,078 | — | ||||||
| Increase in operating assets— |
||||||||
| Increase in receivables |
(18,464 | ) | (20,020 | ) | ||||
| Increase in prepaid expenses and other |
(9,720 | ) | (2,359 | ) | ||||
| Increase in operating liabilities— |
||||||||
| Increase in accounts payable |
11,443 | 1,838 | ||||||
| Increase in other current liabilities |
6,766 | 2,548 | ||||||
| Increase in other liabilities |
1,718 | 683 | ||||||
| Net cash provided by (used in) operating activities |
52,763 | (6,495 | ) | |||||
| CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||
| Purchase of property and equipment |
(168,038 | ) | (94,443 | ) | ||||
| Proceeds from disposal of assets, net of commissions |
455 | 803 | ||||||
| Deferred drydocking expenditures |
(7,369 | ) | (601 | ) | ||||
| Decrease (increase) in deposits |
1,999 | (2,033 | ) | |||||
| Net cash used in investing activities |
(172,953 | ) | (96,274 | ) | ||||
| CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||
| Proceeds from borrowings |
185,000 | 56,000 | ||||||
| Payment of debt |
(146,350 | ) | — | |||||
| Proceeds from issuance of common stock |
116,249 | |||||||
| Payment of debt issuance costs |
(5,923 | ) | (1,793 | ) | ||||
| Contributions from members |
4,329 | 63,022 | ||||||
| Net cash provided by financing activities |
153,305 | 117,229 | ||||||
| NET INCREASE IN CASH AND CASH EQUIVALENTS |
33,115 | 14,460 | ||||||
| CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD |
14,460 | — | ||||||
| CASH AND CASH EQUIVALENTS AT END OF PERIOD |
$ | 47,575 | $ | 14,460 | ||||
The accompanying notes are an integral part of these statements.
51
HERCULES OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)
| Member Interests | Common Stock | Additional Capital |
Restricted Stock |
Accumulated Income |
Retained Earnings |
Total Equity |
||||||||||||||||||||||||
| Units | Amount | Shares | Amount | |||||||||||||||||||||||||||
| Balance at July 27, 2004 (date of inception) |
— | $ | — | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
| Net income |
— | — | — | — | — | — | — | 8,065 | 8,065 | |||||||||||||||||||||
| Contributions from members |
64 | 63,022 | — | — | — | — | — | — | 63,022 | |||||||||||||||||||||
| Balance at December 31, 2004 |
64 | 63,022 | — | — | — | — | — | 8,065 | 71,087 | |||||||||||||||||||||
| Net income |
— | — | — | — | — | — | — | 27,456 | 27,456 | |||||||||||||||||||||
| Distributions to former members |
— | — | — | — | — | — | — | (3,732 | ) | (3,732 | ) | |||||||||||||||||||
| Contributions from members |
4 | 4,329 | — | — | — | — | — | — | 4,329 | |||||||||||||||||||||
| Effect of Conversion (see Note 3) |
(68 | ) | (67,351 | ) | 23,923 | 239 | 67,112 | — | — | — | — | |||||||||||||||||||
| Issuance of common stock |
— | — | 6,250 | 62 | 116,187 | — | — | — | 116,249 | |||||||||||||||||||||
| Issuance of restricted stock |
— | — | 70 | 1 | 1,399 | (1,400 | ) | — | — | — | ||||||||||||||||||||
| Compensation expense recognized |
— | — | — | — | — | 78 | — | — | 78 | |||||||||||||||||||||
| Change in unrealized gain on hedge transaction |
— | — | — | — | — | — | 476 | — | 476 | |||||||||||||||||||||
| Balance at December 31, 2005 |
— | $ | — | 30,243 | $ | 302 | $ | 184,698 | $ | (1,322 | ) | $ | 476 | $ | 31,789 | $ | 215,943 | |||||||||||||
The accompanying notes are an integral part of these statements.
52
HERCULES OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
| Year Ended December 31, 2005 |
Period from inception December 31, 2004 | |||||
| NET INCOME |
$ | 27,456 | $ | 8,065 | ||
| OTHER COMPREHENSIVE INCOME (LOSS) |
||||||
| Unrealized gains on hedge transactions (net of tax benefit of $257) |
476 | — | ||||
| COMPREHENSIVE INCOME |
$ | 27,932 | $ | 8,065 | ||
The accompanying notes are an integral part of these statements.
53
HERCULES OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 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 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 for periods prior to the Conversion and to Hercules Offshore, Inc. for periods after the Conversion.
The Company provides shallow-water drilling and liftboat services to the oil and gas exploration and production industry in the U.S. Gulf of Mexico and international markets through its Contract Drilling Services, Domestic Marine Services and International Marine Services segments. The Company owns one platform rig, ten jackup drilling rigs and 46 liftboat vessels. One of the jackup rigs was severely damaged in a hurricane and is likely to be declared a constructive total loss. (see NOTE 13)
For the period from inception (July 27, 2004) to December 31, 2004 (“period from inception to December 31, 2004”), the Company owned five jackup drilling rigs and four platform rigs that were purchased on August 2, 2004 for $39,250,000. The consolidated results of operations for the period from inception to December 31, 2004 include the operation during such period of those five jackup rigs. Three of the four platform rigs were sold in November 2004 and the fourth was classified as an asset held for sale as of December 31, 2005 (see Assets Held for Sale). Also included in the consolidated results of operations for the period from inception to December 31, 2004 is a fleet of 22 liftboats acquired from Global Industries, Ltd. (“Global”) for $53,500,000 in addition to an operating facility in New Iberia, Louisiana. Following the purchase of the liftboats from Global, Global had performed invoicing and other administrative functions for the Company under a transition services agreement until the Company could assume these functions.
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.
Cash and Cash Equivalents
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.
Revenue Recognition
Revenue generated from the operation of the Company’s drilling rigs and liftboats is recognized under dayrate contracts as services are performed. Certain contracts include provisions for the recovery of direct costs, including mobilization and demobilization costs, extra labor and extra catering. Under most of its liftboat contracts, the Company receives a variable rate for reimbursement of costs such as catering, fuel, oil, rental equipment, crane overtime and other items. Revenue for recovery of these costs is recognized when the costs are incurred. For certain Contract Drilling Services 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.
54
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 included $4,627,525 and $892,700 for the year ended December 31, 2005 and the period from inception to December 31, 2004, respectively.
Supplemental Cash Flow Information
| Year Ended December 31, 2005 |
Period from inception to December 31, 2004 | |||||
| Dollars in thousands: |
||||||
| Cash paid during the period for: |
||||||
| Interest |
$ | 7,688 | $ | 1,484 | ||
| Income taxes |
$ | — | $ | — | ||
| Non-cash financing activity: |
||||||
| Accrued distribution |
$ | 3,732 | $ | — | ||
Stock-Based Compensation
Stock-based compensation arrangements are accounted for using 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. Accordingly, compensation cost for options granted to employees is measured as the excess, if any, of the fair value of shares at the date of grant over the exercise price an employee must pay to acquire the shares. No compensation cost has been recognized in the accompanying consolidated financial statements related to stock option awards.
In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004) “Share-Based Payment” (“SFAS No. 123R”), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion 25. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on the fair values beginning with the first interim period in fiscal year 2006, with early adoption encouraged. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition.
The Company adopted SFAS No. 123R on January 1, 2006 using the modified prospective method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS No. 123R for all share-based payments granted after January 1, 2006 and (b) on the requirements of SFAS No. 123 for all awards granted to employees prior to January 1, 2006 that remain unvested on January 1, 2006. The Company is estimating that the cost relating to stock options granted through 2005 will be $2,278,631 for the year ended December 31, 2006 and $4,177,490 over the remaining vesting period; 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.
The Company’s 2004 Long-Term Incentive Plan (the “2004 Plan”) provides for the granting of stock options, restricted stock, performance stock awards and other stock-based awards to selected employees and non-employee directors of the Company. At December 31, 2005, 540,500 shares were available for grant or award under the 2004 Plan. The Nominating, Governance and Compensation Committee of the Company’s Board of Directors selects participants from time to time and, subject to the terms and conditions of the 2004 Plan, determines all terms and conditions of awards. Options granted prior to the Company’s initial public offering on November 1, 2005 became fully vested at that date. Options issued at the time of and after the Company’s initial public offering under the 2004 Plan have a 10-year term and vest in four equal installments, one-fourth on the effective date of grant and one-fourth thereafter on the anniversary of the grant date for the next three years.
55
The following table summarizes stock option activity under the 2004 Plan:
| Year Ended December 31, 2005 |
Period from inception to December 31, 2004 | |||||||||
| Number of Shares Underlying Options |
Weighted Average Exercise Price |
Number of Shares Underlying Options |
Weighted Average Exercise Price | |||||||
| Outstanding at beginning of year |
— | $ | — | — | $ | — | ||||
| Granted |
1,839,500 | 11.38 | — | — | ||||||
| Exercised |
— | — | — | — | ||||||
| Forfeited |
— | — | — | — | ||||||
| Outstanding at end of year |
1,839,500 | $ | 11.38 | — | $ | — | ||||
| Exercisable at end of year |
1,168,625 | $ | 6.44 | — | $ | — | ||||
The following table summarizes information about stock options outstanding at December 31, 2005:
| Options Outstanding | Options Exercisable | |||||||||||
| Number Outstanding |
Weighted Average Remaining Life (Years) |
Weighted Average Exercise Price |
Number Exercisable |
Weighted Average Exercise Price | ||||||||
| Exercise Prices |
||||||||||||
| $2.86 |
822,500 | 8.83 | $ | 2.86 | 822,500 | $ | 2.86 | |||||
| 5.71 |
122,500 | 9.33 | 5.71 | 122,500 | 5.71 | |||||||
| 20.00 |
894,500 | 9.83 | 20.00 | 223,625 | 20.00 | |||||||
| 1,839,500 | 9.35 | $ | 11.38 | 1,168,625 | $ | 6.44 | ||||||
The following table reflects pro forma net income and earnings per share had we elected to adopt the fair value approach of SFAS No. 123R (dollars in thousands):
| Year Ended December 31, 2005 |
Period from December 31, 2004 | ||||||
| Net income-as reported |
$ | 27,456 | $ | 8,065 | |||
| Compensation expense, net of tax, as reported |
51 | — | |||||
| Compensation expense, net of tax, pro forma |
(1,752 | ) | — | ||||
| Net income-pro forma |
$ | 25,755 | $ | 8,065 | |||
| Earnings per share: |
|||||||
| Basic-as reported |
$ | 1.10 | $ | 0.55 | |||
| Basic-pro forma |
$ | 1.03 | $ | 0.55 | |||
| Diluted-as reported |
$ | 1.08 | $ | 0.55 | |||
| Diluted-pro forma |
$ | 1.01 | $ | 0.55 | |||
The above pro forma amounts are not indicative of future results. The fair value of the options granted under the 2004 Plan at the time of and after the Company’s initial public offering was estimated on the date of grant using the Trinomial Lattice option pricing model with the following assumptions used:
| Year Ended December 31, 2005 |
Period from December 31, 2004 | |||||
| Dividend yield |
— | — | ||||
| Expected price volatility |
35.00 | % | — | |||
| Risk-free interest rate |
4.40 | % | — | |||
| Expected life of options in years |
8.08 | — | ||||
| Weighted-average fair value of options granted |
$ | 9.45 | — | |||
56
In October 2005, we awarded an employee 70,000 restricted shares that vest one-third per year over a three-year period commencing on the first anniversary date of the award.
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. During the period from inception to December 31, 2004, the Company recorded a provision for bad debts of $519,165. During the second quarter of 2005, the Company recorded an additional provision for bad debts of $318,967. The Company received payment for the full amount of the receivable of $838,132 during September 2005, and the allowance was reversed. There was no allowance at December 31, 2005.
Deposits
Deposits at December 31, 2004 include $2,000,000 placed in escrow for the purchase of the jackup drilling rig, Rig 25. The purchase was consummated in January 2005 and the deposit was applied to the purchase price. There were no material deposits at December 31, 2005.
Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets consist of claims receivable, prepaid insurance and other. Claims receivable include amounts the Company has incurred related to insurance claims the Company will file under its insurance policies related to Hurricanes Katrina and Rita to repair damage sustained by Rig 21, the salvage costs for Rig 25 and costs related to the clean-up efforts at the Company’s New Iberia facilities. At December 31, 2005, $5,919,308 was outstanding for claims receivable related to Hurricanes Katrina and Rita. There were no claims receivable at December 31, 2004. At December 31, 2005 and December 31, 2004, prepaid insurance totaled $6,101,284 and $2,299,956, respectively.
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. Routine expenditures for repairs and maintenance are expensed as incurred, except for expenditures for drydocking the Company’s liftboats. Drydock costs are capitalized at cost in other non-current assets on the consolidated balance sheet and amortized on the straight-line method over a period of 12 to 24 months (see below). Depreciation is computed using the straight-line method over the useful lives of the assets. Amortization of leasehold improvements is computed utilizing the straight-line method over the life of the lease.
The useful lives of property and equipment for the purposes of computing depreciation are as follows:
| Years | ||
| Drilling rigs and marine equipment |
15 | |
| Drilling machinery and equipment |
3 | |
| Furniture and fixtures |
5 | |
| Computer equipment |
3 | |
| Automobiles and trucks |
3 | |
| Building |
20 |
Assets Held for Sale
Assets are classified as held for sale when the Company has a plan for disposal and those assets meet the held for sale criteria of SFAS No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets”. During
57
the first quarter of 2005, the Company’s Contract Drilling Services segment committed to a plan to sell Rig 41, a platform rig, in connection with the Company’s efforts to dispose of certain non-strategic assets. The rig has been idle since being acquired on August 2, 2004. The rig was classified as an asset held for sale in March 2005. The estimated fair value of the rig less its selling costs exceeded the rig’s carrying value of approximately $2,000,000 at December 31, 2005 and, as such, no loss has been recognized for the year ended December 31, 2005. The Company entered into a definitive agreement to sell the Rig 41 in October 2005 and received a deposit of $181,250. The buyer terminated the agreement in December 2005 and the Company recorded the deposit to other income on the consolidated statement of operations. The Company believes that Rig 41 continues to meet the criteria of SFAS No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets” and the rig continues to be classified as an asset held for sale at December 31, 2005. During the second quarter of 2005, the Company’s Domestic Marine Services segment committed to a plan to sell the Moonfish, a liftboat, in connection with the Company’s effort to dispose of certain non-strategic assets. The liftboat had been idle since being acquired on June 1, 2005. The Moonfish was sold in August 2005. No gain or loss was recognized on the transaction.
Impairment of Long-Lived Assets
The carrying value of long-lived assets, principally property and equipment, is reviewed for potential impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. 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 year ended December 31, 2005 or for the period from inception to December 31, 2004.
Other Assets
Other assets consist of drydocking costs for liftboats, financing fees and unrealized gain on hedge transactions. The drydock costs are capitalized at cost and amortized on the straight-line method over a period of 12 to 24 months. Drydocking costs, net of accumulated amortization, at December 31, 2005 and December 31, 2004 were $3,906,106 and $452,256, respectively. Accumulated amortization of drydocking costs at December 31, 2005 and December 31, 2004 was $2,967,062 and $149,228, respectively. Amortization expense for drydocking costs was $3,915,142 and $149,228 for the year ended December 31, 2005 and the period from inception to December 31, 2004, respectively.
Financing fees are deferred and amortized over the life of the applicable debt instrument. Unamortized deferred financing fees at December 31, 2005 were $2,531,966, net of accumulated amortization of $398,806. Unamortized deferred financing fees at December 31, 2004 were $1,577,793, net of accumulated amortization of $215,283. All unamortized deferred financing fees outstanding at December 31, 2004 were expensed in conjunction with the refinancing of the Company’s long-term debt in June 2005, and the portion outstanding as of the date of the refinancing, totaling $2,190,709, is included in the loss on early retirement of debt in the statement of operations for the year ended December 31, 2005. In addition, the Company repaid $45,000,000 of the outstanding balance of the term loan (see NOTE 6) in November 2005 with proceeds from its initial public offering. The portion of outstanding deferred financing fees expensed and included in loss on early retirement of debt in the statement of operations related to this repayment is $1,291,922. The amortization expense related to the deferred financing fees is included in interest expense on the statement of operations. Amortization expense for financing fees was $890,848 and $215,285 for the year ended December 31, 2005 and the period from inception to December 31, 2004, respectively. All financing fees at December 31, 2005 and December 31, 2004 relate to debt obtained through credit agreements dated July 30, 2004, October 1, 2004 and June 29, 2005 (see NOTE 6).
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 7).
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Income Taxes
The Company was a limited liability company until its conversion to a Delaware corporation on November 1, 2005. Prior to the Conversion, the Company elected to be taxed as a partnership. As such, the members of the Company were taxed on their proportionate share of net income prior to the Conversion and no provision or liability for income taxes is included in the Company’s accompanying financial statements for periods prior to the Conversion. When the Company became a taxable entity in the Conversion, a provision of $12,145,040 was made reflecting the tax effect of the difference between the book and tax basis of assets and liabilities as of November 1, 2005, the effective date of the Conversion. Following the Conversion, income taxes have been provided based upon the tax laws and rates in effect in the countries and states in which operations are conducted and income is earned.
In February 2006, in accordance with the terms of the limited liability company operating agreement governing the Company prior to the Conversion (the “Operating Agreement”), the Company made a distribution of $3,731,660 to the former members of the Company for taxes in respect of the ten-month period ended upon the Conversion. The former members did not receive any other distributions prior to the Conversion, and other than this required distribution relating to taxes, the earnings generated by the Company were retained by the Company as part of its stockholders’ equity balance upon the Conversion. The Company has no further obligation under the Operating Agreement to make any such distributions.
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 is equal to the fair market value because the debt bears interest at market rates.
NOTE 2—PROPERTY AND EQUIPMENT
The following is a summary of property and equipment—at cost, less accumulated depreciation (in thousands):
| December 31, 2005 |
December 31, 2004 |
|||||||
| Drilling rigs and marine equipment |
$ | 252,892 | $ | 89,432 | ||||
| Drilling machinery and equipment |
1,546 | 667 | ||||||
| Building |
2,400 | 2,400 | ||||||
| Land |
600 | 600 | ||||||
| Automobiles and trucks |
601 | 353 | ||||||
| Computer equipment |
128 | 139 | ||||||
| Furniture and fixtures |
991 | 33 | ||||||
| Total property and equipment |
259,158 | 93,624 | ||||||
| Less accumulated depreciation |
(11,715 | ) | (1,850 | ) | ||||
| Total property and equipment, net |
$ | 247,443 | $ | 91,774 | ||||
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NOTE 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 (net income in thousands):
| Year Ended December 31, 2005 |
Period from Inception to December 31, 2004 | |||||
| Numerator: |
||||||
| Net income |
$ | 27,456 | $ | 8,065 | ||
| Denominator: |
||||||
| Weighted average basic shares |
24,919,273 | 14,689,724 | ||||
| Add effect of stock options |
512,549 | — | ||||
| Weighted average diluted shares |
25,431,822 | 14,689,724 | ||||
| Basic earnings per share |
$ | 1.10 | $ | 0.55 | ||
| Diluted earnings per share |
$ | 1.08 | $ | 0.55 | ||
The Company calculates earnings per share by dividing net income by the weighted average number of shares outstanding. On November 1, 2005, in connection with our initial public offering, we 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. Share-based information contained herein assumes that the Company had effected the conversion of each outstanding member unit into 350 shares of common stock for all periods prior to the Conversion. Diluted earnings per share include the dilutive effects of any outstanding stock options calculated under the treasury method. Options with an exercise price equal to or in excess of the average market price of the Company’s shares are excluded from the calculation of the dilutive effect of stock options for diluted earnings per share calculations.
NOTE 4—ASSET ACQUISITIONS
During January 2005, the Company completed the purchase of two jackup drilling rigs, Rig 25 and Rig 30, for $21,500,000 and $20,000,000, respectively. These purchases were partially funded by a $25,000,000 term loan under the Lehman Credit Agreement (as defined in NOTE 6 below). In connection with this new term loan, the Lehman Credit Agreement was amended in January 2005 to increase the amount of credit available to the Company from $28,000,000 to $53,000,000 (see NOTE 6).
In June 2005, the Company purchased 17 liftboats for $19,725,000. One of these liftboats was being held for sale and was sold in August 2005 (see NOTE 1). The transaction was funded by an increase in the Company’s term loan under the Comerica Credit Agreement (as defined in NOTE 6), which was amended to increase the amount of credit available to the Company under the term loan to $47,000,000. In June 2005, the Company purchased a jackup rig, Rig 16, for $20,000,000. A $2,000,000 refundable escrow account was funded by the Company in May 2005. The Company funded the purchase price with proceeds from its new term loan under the Company’s senior secured credit agreement (see NOTE 6).
In August 2005, the Company purchased the liftboat Whale Shark for $12,500,000. The Company funded the purchase with available cash.
In September 2005, the Company purchased Rig 31 for $12,600,000. The Company funded the purchase with available cash.
In November 2005, the Company purchased seven liftboats and related assets for $44,000,000. Three of the acquired liftboats are located in the U.S. Gulf of Mexico and are included in the Domestic Marine Services segment. The remaining four liftboats are currently operating in Nigeria and are included in the International
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Marine Services segment. The sellers will continue to operate these four vessels under an operating agreement until the Company has established its own operations in Nigeria. This operating agreement expires in September 2006, and can be terminated earlier by the Company upon 30 days’ notice to the sellers.
In February 2006, the Company purchased Rig 26 for $20,100,000. Rig 26 has been cold stacked for the past six years. The Company will begin a reactivation project that it expects will take up to one year and cost approximately $20,000,0000. Upon completion of the reactivation, the Company plans to deploy the rig in a suitable international market.
NOTE 5—BENEFIT PLANS
The Company has established a 401(k) plan for its employees. Participation is available to all employees beginning two months from the date of hire. Participants can contribute up to a maximum of $14,000 each year, and the Company matches participant contributions equal to 100% of the first 3% and 50% of the next 2% of a participant’s salary. The Company made matching contributions of $917,733 and $167,858 for the year ended December 31, 2005 and for the period from inception to December 31, 2004, respectively.
NOTE 6—LONG-TERM DEBT
Long-term debt is comprised of the following (dollars in thousands):
| December 31, 2005 |
December 31, 2004 | |||||
| Senior secured term loan due June 2010 |
$ | 94,650 | $ | — | ||
| 12.5% senior secured term loan (Lehman) due December 2006 |
— | 28,000 | ||||
| Senior secured term loan (Comerica) due October 2009 |
— | 28,000 | ||||
| Total debt |
94,650 | 56,000 | ||||
| Less debt due within one year |
1,400 | 3,000 | ||||
| Total long-term debt |
$ | 93,250 | $ | 53,000 | ||
Aggregate principal repayments of long-term debt for the next five years and thereafter are as follows (in thousands):
| 2006 | 2007 | 2008 | 2009 | 2010 | Thereafter | |||||||||||||
| Senior secured term loan due June 2010 |
$ | 1,400 | $ | 1,400 | $ | 1,400 | $ | 1,400 | $ | 89,050 | $ | — | ||||||
Lehman Commercial Paper Inc. term loan
On July 30, 2004, one of the Company’s subsidiaries entered into a credit agreement with Lehman Commercial Paper Inc. (the “Lehman Credit Agreement”) providing for a $28,000,000 term loan. On January 4, 2005, the Lehman Credit Agreement was amended, providing for an additional $25,000,000 term loan, which increased the total amount outstanding under the Lehman Credit Agreement to $53,000,000. The term loan bore interest at 12.5% per annum with interest payable monthly. The term loan was repaid in full in June 2005.
Comerica Bank term loan
On October 1, 2004, one of the Company’s subsidiaries entered into a credit agreement with Comerica Bank providing for a $28,000,000 term loan and a $4,000,000 revolving credit line (the “Comerica Credit Agreement”). At December 31, 2004, the entire balance of the term loan was outstanding and no amount was drawn on the revolving credit line. The term loan and the revolving credit line bore interest at a prime rate determined by the agent to the Comerica Credit Agreement plus a margin derived from the ratio of funded debt
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to EBITDA. The average interest rates for the period ended December 31, 2004 were approximately 5.7 percent under the term loan and 6.1 percent under the revolving credit line. The Comerica Credit Agreement was amended on June 1, 2005 to increase the amount of credit available to the subsidiary by $20,000,000, of which $19,725,000 was used to fund the liftboat acquisition in June 2005 (see NOTE 4). The term loan was repaid in full in June 2005.
Senior secured credit agreement
In June 2005, the Company entered into a senior secured credit agreement with a syndicate of financial institutions. This agreement provides for a $140,000,000 term loan and a $25,000,000 revolving credit facility. The Company may seek commitments to increase the amount available under the credit agreement by an additional $25,000,000 if the amount outstanding under the term loan is no more than $105,000,000 and the Company’s leverage ratio, after giving effect to the incurrence of the additional $25,000,000 of borrowings, is no greater than 2.5 to 1.
The revolving credit facility provides for swing line loans of up to $2,500,000 and for the issuance of up to $5,000,000 of letters of credit. The revolving loans bear interest at a rate equal to, at the option of the Company, either (1) the highest of (a) Comerica Bank’s base rate, (b) the three-month certificate of deposit rate plus 0.5% and (c) the Federal funds effective rate plus 0.5%, in each case plus 2.25%, or (2) LIBOR plus 3.25%. The Company may repay the revolving loans at any time without premium or penalty. The revolving loans mature in June 2008. The Company is required to pay a commitment fee of 0.50% on the average daily amount of the unused commitment amount of the revolving credit facility and a letter of credit fee of 3.25%, plus a fronting fee of 0.13% with respect to the undrawn amount of each issued letter of credit. As of December 31, 2005, no amounts were outstanding and no letters of credit had been issued under the revolving credit facility.
The term loan bears interest at a rate equal to, at the option of the Company, either (1) the highest of (a) Comerica Bank’s base rate, (b) the three-month certificate of deposit rate plus 0.5% and (c) the Federal funds effective rate plus 0.5%, in each case plus 2.25%, or (2) LIBOR plus 3.25%. Principal payments of $350,000 are due quarterly, and the outstanding principal balance of the term loan is payable in full in June 2010. The Company may prepay the term loan at any time without premium or penalty, except that any prepayments made before December 31, 2006 with proceeds from debt issuances or in connection with a repricing of the term loan will be made at 101% of the principal repaid. The Company is required to make prepayments on the term loan in certain cases. As of December 31, 2005, $94,650,000 of the principal amount of the term loan was outstanding, and the interest rate was 7.3%. In accordance with the credit agreement, in July 2005, the Company entered into hedge transactions with the purpose and effect of fixing the interest rate on $70,000,000 of the outstanding principal amount of the term loan at 7.54% for three years. In addition, the Company entered into hedge transactions with the purpose and effect of capping the interest rate on an additional $20,000,000 of such principal amount at 8.25% for three years. (See NOTE 7). In November 2005, the Company repaid $45,000,000 of the outstanding amount under the term loan, together with the accrued and unpaid interest of $273,750, with proceeds from the Company’s initial public offering. The Company recognized a pretax charge of $1,291,921 related to the write off of deferred financing fees in connection with the repayment in the fourth quarter of 2005.
The Company’s obligations under the credit agreement are secured by its liftboats, all of its domestic rigs and substantially all of its other personal property, including all the equity of its domestic subsidiaries and two-thirds of the equity of certain foreign subsidiaries. All of the Company’s material domestic subsidiaries guarantee the Company’s obligations under the agreement and have granted similar liens on substantially all of their assets.
The credit agreement contains financial covenants relating to leverage and interest coverage. Other covenants contained in the agreement restrict, among other things, repurchases of equity interests, mergers, asset dispositions, guaranties, debt, liens, acquisitions, dividends, distributions, investments, affiliate transactions,
62
prepayments of other debt and capital expenditures. The credit agreement permits the Company to advance up to $20,000,000 to two of its Cayman subsidiaries and permits the Company to invest an additional $25,000,000 in its foreign subsidiaries. Management believes that the Company is in compliance in all material respects with its covenants under the credit agreement. The credit agreement contains customary events of default.
Amounts outstanding under the Lehman Credit Agreement and Comerica Credit Agreement were repaid with proceeds from the new senior secured term loan, and the Company terminated the credit agreements upon the repayment. All unamortized deferred financing fees outstanding at December 31, 2004 were expensed in conjunction with the refinancing of the Company’s long-term debt in June 2005, and the portion outstanding as of the date of the refinancing is included in loss on early retirement of debt in the consolidated statements of operations.
NOTE 7—DERIVATIVE INSTRUMENTS AND HEDGING
In July 2005, 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. The Company entered into two floating-to-fixed interest rate swaps on a total of $70,000,000 of the term loan principal under which the Company receives an interest rate of three-month LIBOR and pays a fixed coupon over three years, with the terms of the swaps matching those of the term loan. The Company also entered into two purchased interest rate caps hedging interest payments made on a total of $20,000,000 of the term loan principal at a strike price of 5.0% over three years. The counterparty is obligated to pay the Company in any quarter that actual LIBOR resets above the strike price, with the terms of the caps matching those of the term loan. All hedge transactions have payment dates of October 1, January 1, April 1 and July 1. These hedging arrangements effectively fix the interest rate on $70,000,000 of the principal amount at 7.54% for three years and cap the interest rate on $20,000,000 of the principal amount at 8.25% for three years.
These hedge transactions are being accounted for as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities (an amendment of FASB Statement no. 133)”, and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. The cumulative net unrealized gain on these hedging instruments was $732,903 at December 31, 2005 and is included in other assets in the consolidated balance sheet at December 31, 2005 and in accumulated other comprehensive income, net of tax of $256,516. The Company expects to realize $208,414 of unrealized gain in the consolidated statements of operations for the year ended December 31, 2006. The Company did not recognize a gain or loss due to hedge ineffectiveness in its consolidated statements of operations for the year ended December 31, 2005 related to these hedging instruments. The Company recognized losses of $112,966 in interest expense in the consolidated statements of operations for the year ended December 31, 2005 related to the interest rate swaps.
NOTE 8—CONCENTRATION OF CREDIT RISK
The Company maintains its cash in bank deposit accounts at high credit quality financial institutions as permitted by its credit agreement. The balances, at times, may exceed federally insured limits.
The Company provides services to a diversified group of customers in the oil and natural gas exploration and production industry. Credit is extended based on an evaluation of each customer’s financial condition. The Company maintains an allowance for doubtful accounts receivable based on expected collectability and establishes a reserve when required payment is unlikely to occur. In addition, Chevron Corporation accounts for 100% of the revenue for the Company’s International Marine Services segment.
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NOTE 9—SALES TO MAJOR CUSTOMERS
The customer base for the Company is primarily concentrated in the oil and natural gas exploration and production industry. Sales to customers exceeding 10 percent or more of the Company’s total revenue are as follows:
| Year Ended December 31, 2005 |
Period from Inception to December 31, 2004 |
|||||
| Chevron Corporation |
31 | % | 31 | % | ||
| Bois d’Arc Energy, Inc. |
12 | % | 15 | % |
NOTE 10—COMPREHENSIVE INCOME
The components of accumulated other comprehensive income at December 31, 2005 and December 31, 2004, net of tax, are as follows (in thousands):
| Balance at July 27, 2004 (Inception) |
$ | — | |
| Other comprehensive gain |
— | ||
| Balance at December 31, 2004 |
— | ||
| Reclassification of losses included in net income |
73 | ||
| Other comprehensive gain |
403 | ||
| Balance at December 31, 2005 |
$ | 476 | |
NOTE 11—INCOME TAXES
The Company was a limited liability company until its conversion to a Delaware corporation on November 1, 2005. Prior to the Conversion, the Company elected to be taxed as a partnership. As such, the members of the Company were taxed on their proportionate share of net income prior to the Conversion and no provision or liability of income taxes was included in the Company’s financial statements for periods prior to the Conversion. When the Company became a taxable entity in the Conversion, a provision of approximately $12,145,000 was made reflecting the tax effect of the difference between the book and tax basis of assets and liabilities as of November 1, 2005, the effective date of the Conversion.
Income before income taxes consisted of the following (in thousands):
| Year Ended December 31, 2005 |
Period from Inception to December 31, 2004 | |||||
| United States |
$ | 42,236 | $ | 8,065 | ||
| Foreign |
589 | — | ||||
| Total |
$ | 42,825 | $ | 8,065 | ||
The income tax provision consisted of the following (in thousands):
| Year Ended December 31, 2005 |
Period from Inception to December 31, 2004 | |||||
| Current-United States |
$ | — | $ | — | ||
| Current-foreign |
100 | — | ||||
| Current-state |
22 | — | ||||
| Subtotal-current |
$ | 122 | $ | — | ||
| Deferred-United States |
$ | 14,423 | $ | — | ||
| Deferred-foreign |
— | — | ||||
| Deferred-state |
824 | — | ||||
| Subtotal-deferred |
$ | 15,247 | $ | — | ||
| Total income tax provision |
$ | 15,369 | $ | — | ||
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The components of and changes in the net deferred taxes were as follows (in thousands):
| Year Ended December 31, 2005 |
Period from Inception to December 31, 2004 | |||||
| Deferred tax assets |
||||||
| Net operating loss carryforward |
||||||
| United States |
$ | 773 | $ | — | ||
| State |
44 | — | ||||
| Deferred tax assets |
$ | 817 | $ | — | ||
| Deferred tax liabilities |
||||||
| Excess of net book over remaining tax basis |
||||||
| Depreciation |
$ | 11,993 | $ | — | ||
| Prepaid insurance |
2,135 | — | ||||
| Deferred drydocking and other |
1,325 | — | ||||
| Total United States |
$ | 15,453 | $ | — | ||
| State |
868 | — | ||||
| Deferred tax liabilities |
$ | 16,321 | $ | — | ||
| Net deferred tax liabilities |
$ | 15,504 | $ | — | ||
A reconciliation of statutory and effective income tax rates is as shown below:
| Year Ended December 31, 2005 |
Period from Inception to December 31, 2004 |
|||||
| Statutory rate |
35.0 | % | 0.0 | % | ||
| Effect of : |
||||||
| Income of LLP prior to conversion |
(27.5 | ) | — | |||
| Change in tax status and other |
28.4 | — | ||||
| Total |
35.9 | % | 0.0 | % | ||
During 2005, the Company generated a net operating loss of $2,200,000 for United States income tax purposes. This loss can be carried forward 20 years. The Company currently does not have significant unremitted earnings of foreign subsidiaries.
NOTE 12—SEGMENTS
The Company’s operations are aggregated into three reportable segments: (i) Contract Drilling Services, (ii) Domestic Marine Services and (iii) International Marine Services. The Contract Drilling Services segment consists of jackup rigs used in support of offshore drilling activities. The Marine Services segments consist of liftboats used in offshore support services. The Domestic Marine Services segment consists of liftboats operated in the U.S. Gulf of Mexico while the International Marine Services Segment consists of liftboats operated outside of the U.S. Gulf of Mexico (which currently consists of the Company’s liftboats operating in Nigeria). Accounting policies of the segments are the same as those described under “Nature of Business and Significant Accounting Policies” in NOTE 1. The Company eliminates intersegment revenue and expenses, if any.
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Operating results, total assets and capital expenditures by segment were as follows (in thousands):
Year Ended December 31, 2005
| Contract Drilling Services |
Domestic Marine Services |
International Marine Services |
Corporate and Other |
Total | ||||||||||||||||
| Revenues |
$ | 103,422 | $ | 55,740 | $ | 2,172 | $ | — | $ | 161,334 | ||||||||||
| Operating expenses, excluding depreciation and amortization |
48,330 | 28,413 | 1,071 | — | 77,814 | |||||||||||||||
| Depreciation and amortization |
5,547 | 8,031 | 176 | 36 | 13,790 | |||||||||||||||
| General and administrative, excluding depreciation and amortization |
5,486 | 1,888 | 336 | 6,161 | 13,871 | |||||||||||||||
| Operating income (loss) |
44,059 | 17,408 | 589 | (6,197 | ) | 55,859 | ||||||||||||||
| Interest expense |
(6,980 | ) | (2,825 | ) | — | (75 | ) | (9,880 | ) | |||||||||||
| Loss on early retirement of debt |
(2,683 | ) | (1,395 | ) | — | — | (4,078 | ) | ||||||||||||
| Other, net |
541 | 96 | — | 287 | 924 | |||||||||||||||
| Income before income taxes |
34,937 | 13,284 | 589 | (5,985 | ) | 42,825 | ||||||||||||||
| Income tax expense |
(6,900 | ) | (8,828 | ) | (100 | ) | 459 | (15,369 | ) | |||||||||||
| Net income (loss) |
$ | 28,037 | $ | 4,456 | $ | 489 | $ | (5,526 | ) | $ | 27,456 | |||||||||
| Total assets (at end of period) |
$ | 157,756 | $ | 137,865 | $ | 19,682 | $ | 39,522 | $ | 354,825 | ||||||||||
| Capital expenditures and deferred drydocking expenditures |
$ | 90,347 | $ | 67,460 | $ | 17,600 | $ | — | $ | 175,407 | ||||||||||
Period From Inception to December 31, 2004
| Contract Drilling Services |
Domestic Marine Services |
International Marine Services |
Corporate and Other |
Total | |||||||||||||||
| Revenues |
$ | 24,006 | $ | 7,722 | $ | — | $ | — | $ | 31,728 | |||||||||
| Operating expenses, excluding depreciation and amortization |
12,799 | 4,198 | — | — | 16,997 | ||||||||||||||
| Depreciation and amortization |
1,070 | 946 | — | — | 2,016 | ||||||||||||||
| General and administrative, excluding depreciation and amortization |
1,972 | 581 | — | 255 | 2,808 | ||||||||||||||
| Operating income (loss) |
8,165 | 1,997 | — | (255 | ) | 9,907 | |||||||||||||
| Interest expense |
(1,648 | ) | (422 | ) | — | — | (2,070 | ) | |||||||||||
| Other, net |
158 | 64 | — | 6 | 228 | ||||||||||||||
| Net income (loss) |
$ | 6,675 | $ | 1,639 | $ | — | $ | (249 | ) | $ | 8,065 | ||||||||
| Total assets (at end of period) |
$ | 60,399 | $ | 61,094 | $ | — | $ | 10,663 | $ | 132,156 | |||||||||
| Capital and deferred drydocking expenditures |
$ | 40,728 | $ | 54,316 | $ | — | $ | — | $ | 95,044 | |||||||||
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The following tables present revenues and long-lived assets by country based on the location of the service provided (in thousands):
| Revenue | Long-Lived Assets | |||||||||||
| Year Ended December 31, 2005 |
Period From Inception to December 31, 2004 |
Year Ended December 31, 2005 |
Period From Inception to December 31, 2004 | |||||||||
| United States |
$ | 159,162 | $ | 31,728 | $ | 187,897 | $ | 91,774 | ||||
| International: |
||||||||||||
| Nigeria |
2,172 | — | 17,424 | — | ||||||||
| United Arab Emirates |
— | — | 26,588 | — | ||||||||
| Malaysia |
— | — | 15,534 | — | ||||||||
| Total |
2,172 | — | $ | 59,546 | $ | — | ||||||
| Total |
$ | 161,334 | $ | 31,728 | $ | 247,443 | $ | 91,774 | ||||
NOTE 13—COMMITMENTS AND CONTINGENCIES
Operating Leases
The Company has operating lease commitments for real estate and office space that expire at various dates through 2011. As of December 31, 2005, future minimum lease payments related to operating leases were as follows (in thousands):
| Years ended December 31, |
|||
| 2006 |
$ | 651 | |
| 2007 |
326 | ||
| 2008 |
306 | ||
| 2009 |
288 | ||
| 2010 |
199 | ||
| Thereafter |
33 | ||
| Total |
$ | 1,803 | |
Legal Proceedings
The Company is involved in various claims and lawsuits in the normal course of business. Management does not believe any accruals are necessary in accordance with SFAS No. 5, “Accounting for Contingencies”.
Insurance
The Company is self-insured for the deductible portion of its insurance coverage. Management believes adequate accruals have been made on known and estimated exposures up to the deductible portion of the Company’s insurance coverage. Management believes that claims and liabilities in excess of the amounts accrued are adequately insured.
The Company maintains insurance coverage that includes physical damage, third party liability, maritime employers liability, pollution and other coverage. The primary marine package provides for hull and machinery coverage for the Company’s rigs and liftboats up to a scheduled value for each asset. Rig coverages include a $1,000,000 deductible per occurrence; liftboat deductibles vary from $150,000 to $500,000 per occurrence, depending on the insured value of the particular vessel. There is no deductible in the event of a total loss of the vessel. The protection and indemnity coverage under the primary marine package has a $5,000,000 limit per occurrence with excess liability up to $100,000,000. The primary marine package also provides coverage for cargo and charterer’s legal liability. Vessel pollution is covered under a Water Quality Insurance Syndicate
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policy. In addition to the marine package, the Company has separate policies providing coverage for general domestic liability, employer’s liability, domestic auto liability and non-owned aircraft liability, with customary deductibles and coverage. Insurance premiums under the Company’s program are approximately $8,000,000 for the twelve-month policy period ending July 31, 2006.
In connection with the renewal of certain of the Company’s insurance policies, the Company entered into an agreement to finance annual insurance premiums. A total of $5,953,264 was financed through this arrangement. The interest rate is 5.047% and the note matures in May 2006. The outstanding balance was $2,400,580 at December 31, 2005 and is recorded in other liabilities on the consolidated balance sheets. The corresponding prepaid insurance has been recorded in prepaid expenses and other current assets.
Recent Hurricanes
In August 2005, two of the Company’s jackup rigs, Rig 21 and Rig 25, sustained damage during Hurricane Katrina. The Company believes that Rig 25 is likely to be declared a constructive total loss under its insurance policies. Salvage efforts are complete on Rig 25 and the Company filed a notice of abandonment with its insurance underwriter in February 2006. If Rig 25 is declared a constructive total loss, the Company would recognize a gain equal to the excess of the insurance proceeds received over the rig’s carrying value of $20,451,923. Rig 25 is insured for $50,000,000, and insurance proceeds received would be reduced for salvage proceeds. Rig 21 suffered extensive damage to its mat as a result of the storm. The rig is currently in drydock in a shipyard in Pascagoula, Mississippi undergoing repairs to a section of the mat. The rig is expected be ready for service in the first quarter of 2006 and all repairs are expected to be within insured values. As a result of the damage to Rig 21, the Company recognized a $1,000,000 loss in the year ended December 31, 2005 representing its insurance deductible. The loss is included in operating expenses for drilling services in the consolidated statements of operations.
NOTE 14—UNAUDITED INTERIM FINANCIAL DATA
Unaudited interim financial information for the year ended December 31, 2005 and the period from inception to December 31, 2004 is as follows (dollars in thousands, except per share amounts):
| Quarter Ended | |||||||||||||
| March 31 | June 30 | September 30 | December 31 | ||||||||||
| 2005 |
|||||||||||||
| Operating revenues |
$ | 34,055 | $ | 37,075 | $ | 42,185 | $ | 48,019 | |||||
| Operating income |
13,571 | 13,369 | 12,601 | 16,318 | |||||||||
| Net income |
11,402 | 8,150 | 10,110 | (2,206 | ) | ||||||||
| Net income per share: |
|||||||||||||
| Basic |
$ | 0.48 | $ | 0.34 | $ | 0.42 | $ | (0.08 | ) | ||||
| Diluted |
$ | 0.48 | $ | 0.34 | $ | 0.41 | $ | (0.08 | ) | ||||
| Quarter Ended | |||||||||||||
| March 31 | June 30 | September 30 | December 31 | ||||||||||
| 2004 |
|||||||||||||
| Operating revenues |
$ | — | $ | — | $ | 8,405 | $ | 23,323 | |||||
| Operating income |
— | — | 2,726 | 7,181 | |||||||||
| Net income |
— | — | 2,141 | 5,924 | |||||||||
| Net income per share: |
|||||||||||||
| Basic |
$ | — | $ | — | $ | 0.29 | $ | 0.40 | |||||
| Diluted |
$ | — | $ | — | $ | 0.29 | $ | 0.40 | |||||
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NOTE 15—RELATED PARTIES
A former manager of the Company is a principal in Bassoe Offshore USA. The Company paid $200,000 in the year ended December 31, 2005 to Bassoe Offshore USA for rig brokerage fees in connection the acquisition by the Company of a jackup rig. The Company paid $442,250 in the period from inception to December 31, 2004 for such rig brokerage fees. The services were bid under competitive marketplace conditions. The Company believes that these transactions were on terms that were reasonable and in the best interest of the Company.
In January 2005, the Company purchased Rig 30 from Porterhouse Offshore, LP (“Porterhouse”). Two of the Company’s officers and a manager of the Company at the time of acquisition were partners in Porterhouse, which owned and sold Rig 30 to the Company. The Company believes that this transaction was on terms that were reasonable and in the best interest of the Company. In the transaction, these individuals received membership interests in the Company valued at $211,209, $211,209 and $422,338, respectively.
During 2005, a subsidiary of the Company purchased an aggregate of approximately $167,000 in rig equipment monitoring products and services from MBH Datasource, Inc. Thomas E. Hord, Vice President, Operations and Chief Operating Officer of the subsidiary, holds a 50% ownership interest in MBH Datasource, Inc. The Company believes that the transactions were on terms that were reasonable and in its best interest, although the transactions may not have been on or have terms as favorable to the Company as it could have obtained from unaffiliated third-parties in arms-length transactions.
69
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
There have been no changes in or disagreements with our independent auditors regarding accounting and financial disclosure matters.
| Item 9A. | Controls and Procedures |
Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and President and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of the end of the period covered by this annual report. Based upon that evaluation, our Chief Executive Officer and President and our Chief Financial Officer concluded that , as of December 31, 2005, our disclosure controls and procedures were effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, for information required to be disclosed by us in the reports that we file or submit under the Exchange Act.
There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
| Item 9B. | Other Information |
None.
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PART III
| Item 10. | Directors and Executive Officers of the Registrant |
The information required by this item, to the extent not set forth in “Executive Officers” in Item 4, is incorporated by reference to our definitive proxy statement, which is to be filed with the SEC pursuant to the Securities Exchange Act of 1934 within 120 days of the end of our fiscal year on December 31, 2005.
Code of Business Conduct and Ethical Practices
We have adopted a Code of Business Conduct and Ethics, which applies to, among others, our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. We have posted a copy of the code under “Corporate Governance” in the “Investor Relations” section of our internet website at www.herculesoffshore.com. Copies of the code may be obtained free of charge on our website or by requesting a copy in writing from our Corporate Secretary at 11 Greenway Plaza, Suite 2950, Houston, Texas 77046. Any waivers of the code must be approved by our board of directors or a designated board committee. Any amendments to, or waivers from, the code that apply to our executive officers and directors will be posted under “Corporate Governance” in the “Investor Relations” section of our internet website at www.herculesoffshore.com.
| Item 11. | Executive Compensation |
The information required by this item is incorporated by reference to our definitive proxy statement, which is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2005.
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The information required by this item is incorporated by reference to our definitive proxy statement, which is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2005.
| Item 13. | Certain Relationships and Related Transactions |
The information required by this item is incorporated by reference to our definitive proxy statement, which is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2005.
| Item 14. | Principal Accountant Fees and Services |
The information required by this item is incorporated by reference to our definitive proxy statement, which is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2005.
71
PART IV
| Item 15. | Exhibits and Financial Statement Schedules |
(a) The following documents are included as part of this report:
| (1) | Financial Statements: |
| Page | ||
| 48 | ||
| 49 | ||
| 50 | ||
| 51 | ||
| 52 | ||
| 53 | ||
| 54 |
| (2) | Consolidated Financial Statement Schedules: |
All financial statement schedules have been omitted because they are not applicable or not required, or the information required thereby is included in the consolidated financial statements or the notes thereto included in this annual report.
| (3) | Exhibits: |
| Exhibit Number |
Description | |||
| 2.1 | — | Plan of Conversion (incorporated by reference to Exhibit 2.1 to Hercules’ Registration Statement on Form S-1 (Registration No. 333-126457), as amended (the “Registration Statement”), originally filed on July 8, 2005). | ||
| 3.1 | — | Certificate of Incorporation of Hercules Offshore, Inc. (incorporated by reference to Exhibit 3.1 to Hercules’ Current Report on Form 8-K dated November 1, 2005 (File No. 0-51582) (the “Form 8-K”)). | ||
| 3.2 | — | Bylaws of Hercules Offshore, Inc. (incorporated by reference to Exhibit 3.2 to the Form 8-K). | ||
| 4.1 | — | Form of specimen common stock certificate (incorporated by reference to Exhibit 4.1 to the Registration Statement). | ||
| 4.2 | — | Rights Agreement, dated as of October 31, 2005, between Hercules and American Stock Transfer & Trust Company, as rights agent (incorporated by reference to Exhibit 4.1 to the Form 8-K). | ||
| 4.3 | — | Certificate of Designations of Series A Junior Participating Preferred Stock (incorporated by reference to Exhibit 4.2 to the Form 8-K). | ||
| 4.4 | — | Credit Agreement dated as of June 30, 2005 (the “Credit Agreement”) among Hercules Offshore, LLC, as Borrower, Comerica Bank, as Administrative Agent, Citicorp North America, Inc., as Syndication Agent, Credit Suisse, as Documentation Agent, and the Lenders party thereto (incorporated by reference to Exhibit 4.2 to the Registration Statement). | ||
72
| Exhibit Number |
Description | |||
| 4.5 | — | Consent, Release, Waiver and Amendment to the Credit Agreement, dated as of January 25, 2006, among Hercules, as Borrower, Comerica Bank, as Administrative Agent, Citicorp North America, Inc., as Syndication Agent, Credit Suisse, Cayman Islands Branch, as Documentation Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to Hercules’ Current Report on Form 8-K dated January 25, 2006 (File No. 0-51582)). | ||
| 4.6 | — | Second Amendment to the Credit Agreement, dated as of January 25, 2006, among Hercules, as Borrower, Comerica Bank, as Administrative Agent, Citicorp North America, Inc., as Syndication Agent, Credit Suisse, Cayman Islands Branch, as Documentation Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.2 to Hercules’ Current Report on Form 8-K dated January 25, 2006 (File No. 0-51582)). | ||
| †10.1 | — | Employment Agreement, dated effective as of October 11, 2004, by and between the Company and Randall D. Stilley (incorporated by reference to Exhibit 10.1 to the Registration Statement). | ||
| †10.2 | — | Employment Agreement, dated effective as of January 10, 2005, by and between the Company and Steven A. Manz (incorporated by reference to Exhibit 10.2 to the Registration Statement). | ||
| †10.3 | — | Employment Agreement, dated effective as of January 1, 2005, by and between Hercules Drilling Company, LLC and Thomas J. Seward II (incorporated by reference to Exhibit 10.3 to the Registration Statement). | ||
| †10.4 | — | Employment Agreement, dated effective as of January 1, 2005, by and between Hercules Drilling Company, LLC and Thomas E. Hord (incorporated by reference to Exhibit 10.4 to the Registration Statement). | ||
| †10.5 | — | Hercules Offshore 2004 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 to the Registration Statement). | ||
| †10.6 | — | Form of Stock Option Agreement (incorporated by reference to Exhibit 10.6 to the Registration Statement). | ||
| *†10.7 | — | Form of Restricted Stock Agreement for Executive Officers | ||
| *†10.8 | — | Form of Restricted Stock Agreement for Directors | ||
| *10.9 | — | Registration Rights Agreement, dated as of July 8, 2005, between the Company and the holders listed on the signature page thereto. | ||
| 10.10 | — | Asset and Securities Purchase Agreement dated as of January 13, 2005 among Hercules Drilling, the Company, Porterhouse Offshore, LP and Filet Ltd. (incorporated by reference to Exhibit 10.11 to the Registration Statement). | ||
| 10.11 | — | Rig Sale Agreement dated as of May 13, 2005 among Transocean Offshore Deepwater Drilling Inc. and the Company (incorporated by reference to Exhibit 10.12 to the Registration Statement). | ||
| 10.12 | — | Vessel Purchase Agreement dated as of May 19, 2005 among Superior Energy Services, L.L.C. and the Company (incorporated by reference to Exhibit 10.13 to the Registration Statement). | ||
| 10.13 | — | Vessel Purchase Agreement dated as of August 4, 2005 between C.S. Liftboats, Inc. and the Company (incorporated by reference to Exhibit 10.14 to the Registration Statement). | ||
| 10.14 | — | Rig Sale Agreement dated as of August 8, 2005 between Hydrocarbon Capital II LLC and the Company (incorporated by reference to Exhibit 10.15 to the Registration Statement). | ||
| 10.15 | — | Asset Purchase Agreement dated as of September 16, 2005 by and among Hercules Liftboat Company, LLC, Danos Marine, Inc. and Danos & Curole Marine Contractors, LLC. (incorporated by reference to Exhibit 10.16 to the Registration Statement). | ||
73
| Exhibit Number |
Description | |||
| †10.16 | — | Employment Agreement dated as of October 3, 2005 by and between the Company and John T. Rynd (incorporated by reference to Exhibit 10.17 to the Registration Statement). | ||
| †10.17 | — | Separation Agreement dated October 4, 2005 by and between the Company and Thomas J. Seward II (incorporated by reference to Exhibit 10.18 to the Registration Statement). | ||
| *†10.18 | — | Schedule of executive officer and director compensation arrangements. | ||
| *21 | — | Subsidiaries of Hercules. | ||
| *23 | — | Consent of Grant Thornton LLP. | ||
| *31.1 | — | Certification of Chief Executive Officer of Hercules pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
| *31.2 | — | Certification of Chief Financial Officer of Hercules pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
| *32 | — | Certification of the Chief Executive Officer and the Chief Financial Officer of Hercules pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
| * | Filed herewith. |
| † | Compensatory plan, contract or arrangement. |
74
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on March 8, 2006.
| HERCULES OFFSHORE, INC. | ||
| By: |
/s/ RANDALL D. STILLEY | |
| Randall D. Stilley | ||
| President and Chief Executive Officer | ||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on March 8, 2006.
| Signatures |
Title | |
| /s/ RANDALL D. STILLEY Randall D. Stilley |
President, Chief Executive Officer and Director (Principal Executive Officer) | |
| /s/ STEVEN A. MANZ Steven A. Manz |
Chief Financial Officer and Director (Principal Financial Officer) | |
| /s/ JOHN T. REYNOLDS John T. Reynolds |
Chairman of the Board | |
| /s/ THOMAS R. BATES, JR. Thomas R. Bates, Jr. |
Director | |
| /s/ THOMAS J. MADONNA Thomas J. Madonna |
Director | |
| /s/ F. GARDNER PARKER F. Gardner Parker |
Director | |
| /s/ V. FRANK POTTOW V. Frank Pottow |
Director | |
| /s/ STEVEN A. WEBSTER Steven A. Webster |
Director | |
INDEX TO EXHIBITS
| Exhibit Number |
Description | |||
| 2.1 | — | Plan of Conversion (incorporated by reference to Exhibit 2.1 to Hercules’ Registration Statement on Form S-1 (Registration No. 333-126457), as amended (the “Registration Statement”), originally filed on July 8, 2005). | ||
| 3.1 | — | Certificate of Incorporation of Hercules Offshore, Inc. (incorporated by reference to Exhibit 3.1 to Hercules’ Current Report on Form 8-K dated November 1, 2005 (File No. 0-51582) (the “Form 8-K”)). | ||
| 3.2 | — | Bylaws of Hercules Offshore, Inc. (incorporated by reference to Exhibit 3.2 to the Form 8-K). | ||
| 4.1 | — | Form of specimen common stock certificate (incorporated by reference to Exhibit 4.1 to the Registration Statement). | ||
| 4.2 | — | Rights Agreement, dated as of October 31, 2005, between Hercules and American Stock Transfer & Trust Company, as rights agent (incorporated by reference to Exhibit 4.1 to the Form 8-K). | ||
| 4.3 | — | Certificate of Designations of Series A Junior Participating Preferred Stock (incorporated by reference to Exhibit 4.2 to the Form 8-K). | ||
| 4.4 | — | Credit Agreement dated as of June 30, 2005 (the “Credit Agreement”) among Hercules Offshore, LLC, as Borrower, Comerica Bank, as Administrative Agent, Citicorp North America, Inc., as Syndication Agent, Credit Suisse, as Documentation Agent, and the Lenders party thereto (incorporated by reference to Exhibit 4.2 to the Registration Statement). | ||
| 4.5 | — | Consent, Release, Waiver and Amendment to the Credit Agreement, dated as of January 25, 2006, among Hercules, as Borrower, Comerica Bank, as Administrative Agent, Citicorp North America, Inc., as Syndication Agent, Credit Suisse, Cayman Islands Branch, as Documentation Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to Hercules’ Current Report on Form 8-K dated January 25, 2006 (File No. 0-51582)). | ||
| 4.6 | — | Second Amendment to the Credit Agreement, dated as of January 25, 2006, among Hercules, as Borrower, Comerica Bank, as Administrative Agent, Citicorp North America, Inc., as Syndication Agent, Credit Suisse, Cayman Islands Branch, as Documentation Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.2 to Hercules’ Current Report on Form 8-K dated January 25, 2006 (File No. 0-51582)). | ||
| †10.1 | — | Employment Agreement, dated effective as of October 11, 2004, by and between the Company and Randall D. Stilley (incorporated by reference to Exhibit 10.1 to the Registration Statement). | ||
| †10.2 | — | Employment Agreement, dated effective as of January 10, 2005, by and between the Company and Steven A. Manz (incorporated by reference to Exhibit 10.2 to the Registration Statement). | ||
| †10.3 | — | Employment Agreement, dated effective as of January 1, 2005, by and between Hercules Drilling Company, LLC and Thomas J. Seward II (incorporated by reference to Exhibit 10.3 to the Registration Statement). | ||
| †10.4 | — | Employment Agreement, dated effective as of January 1, 2005, by and between Hercules Drilling Company, LLC and Thomas E. Hord (incorporated by reference to Exhibit 10.4 to the Registration Statement). | ||
| †10.5 | — | Hercules Offshore 2004 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 to the Registration Statement). | ||
| †10.6 | — | Form of Stock Option Agreement (incorporated by reference to Exhibit 10.6 to the Registration Statement). | ||
| *†10.7 | — | Form of Restricted Stock Agreement for Executive Officers | ||
| Exhibit Number |
Description | |||
| *†10.8 | — | Form of Restricted Stock Agreement for Directors | ||
| *10.9 | — | Registration Rights Agreement, dated as of July 8, 2005, between the Company and the holders listed on the signature page thereto. | ||
| 10.10 | — | Asset and Securities Purchase Agreement dated as of January 13, 2005 among Hercules Drilling, the Company, Porterhouse Offshore, LP and Filet Ltd. (incorporated by reference to Exhibit 10.11 to the Registration Statement). | ||
| 10.11 | — | Rig Sale Agreement dated as of May 13, 2005 among Transocean Offshore Deepwater Drilling Inc. and the Company (incorporated by reference to Exhibit 10.12 to the Registration Statement). | ||
| 10.12 | — | Vessel Purchase Agreement dated as of May 19, 2005 among Superior Energy Services, L.L.C. and the Company (incorporated by reference to Exhibit 10.13 to the Registration Statement). | ||
| 10.13 | — | Vessel Purchase Agreement dated as of August 4, 2005 between C.S. Liftboats, Inc. and the Company (incorporated by reference to Exhibit 10.14 to the Registration Statement). | ||
| 10.14 | — | Rig Sale Agreement dated as of August 8, 2005 between Hydrocarbon Capital II LLC and the Company (incorporated by reference to Exhibit 10.15 to the Registration Statement). | ||
| 10.15 | — | Asset Purchase Agreement dated as of September 16, 2005 by and among Hercules Liftboat Company, LLC, Danos Marine, Inc. and Danos & Curole Marine Contractors, LLC. (incorporated by reference to Exhibit 10.16 to the Registration Statement). | ||
| †10.16 | — | Employment Agreement dated as of October 3, 2005 by and between the Company and John T. Rynd (incorporated by reference to Exhibit 10.17 to the Registration Statement). | ||
| †10.17 | — | Separation Agreement dated October 4, 2005 by and between the Company and Thomas J. Seward II (incorporated by reference to Exhibit 10.18 to the Registration Statement). | ||
| *†10.18 | — | Schedule of executive officer and director compensation arrangements. | ||
| *21 | — | Subsidiaries of Hercules. | ||
| *23 | — | Consent of Grant Thornton LLP. | ||
| *31.1 | — | Certification of Chief Executive Officer of Hercules pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
| *31.2 | — | Certification of Chief Financial Officer of Hercules pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
| *32 | — | Certification of the Chief Executive Officer and the Chief Financial Officer of Hercules pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
| * | Filed herewith. |
| † | Compensatory plan, contract or arrangement. |