10-K 1 hero1231201210-k.htm 10-K HERO 12.31.2012 10-K
 
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, 2012
Commission file number: 0-51582
Hercules Offshore, Inc.
(Exact name of registrant as specified in its charter)
Delaware
 
56-2542838
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
9 Greenway Plaza, Suite 2200
Houston, Texas
(Address of principal executive offices)
 
77046
(Zip Code)
Registrant’s telephone number, including area code:
(713) 350-5100
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Exchange on Which Registered
Common Stock, $0.01 par value per share
 
NASDAQ Global Select Market
Rights to Purchase Preferred Stock
 
NASDAQ Global Select Market
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes   þ        No    ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) 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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer  o
 
Accelerated filer  þ
  
Non-accelerated filer  o
 
Smaller reporting company  o
 
 
(Do not check if a smaller reporting company)                
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨        No  þ
The aggregate market value of the registrant’s common stock held by non-affiliates as of June 30, 2012, based on the closing price on the NASDAQ Global Select Market on such date, was approximately $476 million. As of such date, the registrant’s directors and executive officers and Seahawk Drilling, Inc. were considered affiliates of the registrant for this purpose.
As of February 21, 2013, there were 158,755,820 shares of the registrant’s common stock, par value $0.01 per share, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for the Annual Meeting of Stockholders to be held on May 15, 2013 are incorporated by reference into Part III of this report.
 




TABLE OF CONTENTS
 
 
 
Page
 
 
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
 
 
Item 5.
Item 6.
Item 7.
 
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
 
 
Item 15.



PART I

Item 1.    Business
In this Annual Report on Form 10-K, we refer to Hercules Offshore, Inc. and its subsidiaries as “we,” the “Company” or “Hercules Offshore,” unless the context clearly indicates otherwise. Hercules Offshore, Inc. is a Delaware corporation formed in July 2004, with its principal executive offices located at 9 Greenway Plaza, Suite 2200, Houston, Texas 77046. Hercules Offshore’s telephone number at such address is (713) 350-5100 and our Internet address is www.herculesoffshore.com.
Overview
We are a leading provider of shallow-water drilling and marine services to the oil and natural gas exploration and production industry globally. We provide these services to national oil and gas companies, major integrated energy companies and independent oil and natural gas operators. As of February 21, 2013, we owned a fleet of 37 jackup rigs, thirteen barge rigs, 58 liftboat vessels and operated an additional five liftboat vessels owned by a third party. Our diverse fleet is capable of providing services such as oil and gas exploration and development drilling, well service, platform inspection, maintenance and decommissioning operations in several key shallow-water provinces around the world.
In March 2012, we acquired an offshore jackup drilling rig, Hercules 266, for $40.0 million. We entered into a three-year drilling contract with Saudi Aramco for the use of this rig with Saudi Aramco having an option to extend the term for an additional one-year period. This rig is currently undergoing upgrades and other contract specific refurbishments and we expect the rig to commence work under the contract in the second quarter of 2013.
During April 2012, the Kingfish, a 230 class liftboat, began its mobilization from the U.S. Gulf of Mexico to the Middle East, where it underwent upgrades prior to becoming reactivated. The vessel commenced work in November 2012.
During November 2012, the decision was made to reactivate one of our previously cold stacked rigs, Hercules 209. Hercules 209 is currently in the shipyard undergoing repairs and upgrades for reactivation and is expected to be available for work in the second quarter of 2013.
As of February 21, 2013, our business segments include the following:
Domestic Offshore — includes 29 jackup rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 85 to 350 feet. Nineteen of the jackup rigs are either under contract or available for contracts and ten are cold stacked.
International Offshore — includes eight jackup rigs outside of the U.S. Gulf of Mexico. We have three jackup rigs contracted offshore in Saudi Arabia, one jackup rig contracted offshore in Myanmar and one jackup rig contracted offshore in Cameroon. In addition, we have one jackup rig warm stacked and one jackup rig cold stacked in Bahrain as well as one jackup rig cold stacked in Malaysia. In addition to owning and operating our own rigs, we have the Construction Management Agreement and the Services Agreement with Discovery Offshore S.A. (“Discovery Offshore”) with respect to each of its two rigs.
Inland — includes a fleet of three conventional and ten posted barge rigs that operate inland in marshes, rivers, lakes and shallow bay or coastal waterways along the U.S. Gulf Coast. Three of our inland barges are either under contract or available and ten are cold stacked.
Domestic Liftboats — includes 39 liftboats in the U.S. Gulf of Mexico. Twenty-nine are operating or available for contracts and ten are cold stacked.
International Liftboats — includes 24 liftboats. Nineteen are operating or available for contracts offshore West Africa, including five liftboats owned by a third party, two are cold stacked offshore West Africa and three are operating or available for contracts in the Middle East region.
 
RECENT DEVELOPMENTS
In February 2013, we entered into a definitive agreement to acquire the offshore drilling rig Ben Avon from a subsidiary of KCA Deutag. The purchase price was $55.0 million in cash and we expect the acquisition to close in late March 2013. In addition, we signed a three-year rig commitment with Cabinda Gulf Oil Company Limited for use of the Ben Avon. We expect the rig to commence work in the second quarter of 2013.
In February 2013, we entered into a definitive agreement to acquire the liftboat Titan 2, a 280 class vessel, from a subsidiary of KS Energy Ltd. The purchase price was $42.0 million in cash and we expect the acquisition to close in early March 2013. The liftboat is currently located in Limbe, Cameroon. In addition, we signed a Letter of Intent for a short term commitment to use the Titan 2 and we expect the vessel to commence work shortly after the acquisition closes.


1


Our Fleet
Our jackup rigs and barge rigs are used primarily for exploration and development drilling in shallow waters. Under most of our contracts, we are paid a fixed daily rental rate called a “dayrate,” and we are required to pay all costs associated with our own crews as well as the upkeep and insurance of the rig and equipment. Dayrate drilling contracts typically provide for higher rates while the unit is operating and lower rates or a lump sum payment for periods of mobilization or when operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other factors.
Our liftboats are self-propelled, self-elevating vessels with a large open deck space, which provides a versatile, mobile and stable platform to support a broad range of offshore maintenance and construction services throughout the life of an oil or natural gas well. 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 generally are for shorter terms than are drilling contracts, although international liftboat contracts may have terms of greater than one year.
Jackup Drilling Rigs
Jackup rigs are mobile, self-elevating drilling platforms equipped with legs that can be lowered to the ocean floor until a foundation is established to support the drilling platform. Once a foundation is established, the drilling platform is jacked further up the legs so that the platform is above the highest expected waves. The rig hull includes the drilling rig, jackup system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, helicopter landing deck and other related equipment.
Jackup rig legs may operate independently or have a lower hull referred to as a “mat” attached to the lower portion of the legs in order to provide a more stable foundation in soft bottom areas, similar to those encountered in certain of the shallow-water areas of the U.S. Gulf of Mexico or “U.S. GOM”. Mat-supported rigs generally are able to position themselves more quickly on the worksite and more easily move on and off location than independent leg rigs. Twenty-eight of our jackup rigs are mat-supported and nine are independent leg rigs.
Thirty-one of our rigs have a cantilever design that permits the drilling platform to be extended out from the hull to perform drilling or workover operations over some types of pre-existing platforms or structures. Six rigs have a slot-type design, which requires drilling operations to take place through a slot in the hull. Slot-type rigs are usually used for exploratory drilling rather than development drilling, in that their configuration makes them difficult to position over existing platforms or structures. Historically, jackup rigs with a cantilever design have maintained higher levels of utilization than rigs with a slot-type design.
As of February 21, 2013, twenty-four of our jackup rigs were under contract ranging in duration from well-to-well to three years. In the following table, “ILS” means an independent leg slot-type jackup rig, “MC” means a mat-supported cantilevered jackup rig, “ILC” means an independent leg cantilevered jackup rig and “MS” means a mat-supported slot-type jackup rig.

2


The following table contains information regarding our jackup rig fleet as of February 21, 2013.
Rig Name
 
Type
 
Year
Built/
Upgraded(a)
 
Maximum/
Minimum
Water Depth
Rating
 
Rated
Drilling
Depth(b)
 
Location
 
Status(c)
 
 
 
 
 
 
(Feet)
 
(Feet)
 
 
 
 
Hercules 85
 
ILS
 
1982
 
85/9
 
20,000

 
U.S. GOM
 
Cold Stacked
Hercules 120
 
MC
 
1958
 
120/22
 
18,000

 
U.S. GOM
 
Contracted
Hercules 150
 
ILC
 
1979
 
150/10
 
20,000

 
U.S. GOM
 
Contracted
Hercules 153
 
MC
 
1980/2007
 
150/22
 
25,000

 
U.S. GOM
 
Cold Stacked
Hercules 156
 
ILC
 
1983
 
150/14
 
20,000

 
Bahrain
 
Cold Stacked
Hercules 170
 
ILC
 
1981/2006
 
170/16
 
16,000

 
Bahrain
 
Warm Stacked
Hercules 173
 
MC
 
1971
 
173/22
 
15,000

 
U.S. GOM
 
Contracted
Hercules 200
 
MC
 
1979
 
200/23
 
20,000

 
U.S. GOM
 
Contracted
Hercules 201
 
MC
 
1981
 
200/23
 
20,000

 
U.S. GOM
 
Contracted
Hercules 202
 
MC
 
1981
 
200/23
 
20,000

 
U.S. GOM
 
Contracted
Hercules 203
 
MC
 
1982
 
200/23
 
20,000

 
U.S. GOM
 
Cold Stacked
Hercules 204
 
MC
 
1981
 
200/23
 
20,000

 
U.S. GOM
 
Contracted
Hercules 205
 
MC
 
1979/2003
 
200/23
 
20,000

 
U.S. GOM
 
Contracted
Hercules 206
 
MC
 
1980/2003
 
200/23
 
20,000

 
U.S. GOM
 
Cold Stacked
Hercules 207
 
MC
 
1981
 
200/23
 
20,000

 
U.S. GOM
 
Cold Stacked
Hercules 208(d)
 
MC
 
1980/2008
 
200/22
 
20,000

 
Myanmar
 
Contracted
Hercules 209(e)
 
MC
 
1981/2013
 
200/23
 
20,000

 
U.S. GOM
 
Shipyard
Hercules 211
 
MC
 
1980
 
200/23
 
18,000(f)

 
U.S. GOM
 
Cold Stacked
Hercules 212
 
MC
 
1982
 
200/23
 
20,000

 
U.S. GOM
 
Contracted
Hercules 213
 
MC
 
1981/2002
 
200/23
 
20,000

 
U.S. GOM
 
Contracted
Hercules 214
 
MC
 
1982
 
200/23
 
20,000

 
U.S. GOM
 
Contracted
Hercules 250
 
MS
 
1974
 
250/24
 
20,000

 
U.S. GOM
 
Cold Stacked
Hercules 251
 
MS
 
1978
 
250/24
 
20,000

 
U.S. GOM
 
Contracted
Hercules 253
 
MS
 
1982
 
250/24
 
20,000

 
U.S. GOM
 
Contracted
Hercules 258
 
MS
 
1979/2008
 
250/24
 
20,000

 
Malaysia
 
Cold Stacked
Hercules 260
 
ILC
 
1979/2008
 
250/12
 
20,000

 
Cameroon
 
Shipyard
Hercules 261
 
ILC
 
1979/2008
 
250/12
 
20,000

 
Saudi Arabia
 
Contracted
Hercules 262
 
ILC
 
1982/2008
 
250/12
 
20,000

 
Saudi Arabia
 
Contracted
Hercules 263
 
MC
 
1982/2002
 
250/23
 
20,000

 
U.S. GOM
 
Contracted
Hercules 264
 
MC
 
1976/1999
 
250/23
 
25,000

 
U.S. GOM
 
Contracted
Hercules 265
 
MC
 
1982
 
250/25
 
20,000

 
U.S. GOM
 
Contracted
Hercules 266
 
ILC
 
1978/2013
 
250/12
 
20,000

 
Saudi Arabia
 
Shipyard
Hercules 300
 
MC
 
1974/1999
 
300/25
 
25,000

 
U.S. GOM
 
Contracted
Hercules 350
 
ILC
 
1982
 
350/16
 
25,000

 
U.S. GOM
 
Contracted
Hercules 2002
 
MC
 
1982
 
200/23
 
20,000

 
U.S. GOM
 
Cold Stacked
Hercules 2003
 
MC
 
1981
 
200/23
 
20,000

 
U.S. GOM
 
Cold Stacked
Hercules 2500
 
MS
 
1981/1996
 
250/24
 
20,000

 
U.S. GOM
 
Cold Stacked
 _____________________________
(a)
Dates shown are the original date the rig was built and the date of the most recent upgrade and/or major refurbishment, if any.
(b)
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.

3


(c)
Rigs designated as “Contracted” are under contract while rigs described as “Warm Stacked” are actively marketed and may have a reduced number of crew, but only require a full crew to be ready for service. Rigs described as “Cold Stacked” are not actively marketed, normally require the hiring of an entire crew and require a maintenance review and refurbishment before they can function as a drilling rig. Rigs described as “Shipyard” are undergoing maintenance, repairs or upgrades and may or may not be actively marketed depending on the length of stay in the shipyard.
(d)
This rig is currently unable to operate in the U.S. Gulf of Mexico due to United States Department of Transportation Maritime Administration (“MARAD”) restrictions.
(e)
This rig is undergoing reactivation activities.
(f)
Rated workover depth. Hercules 211 is currently configured for workover activity, which includes maintenance and repair or modification of wells that have already been drilled and completed to enhance or resume the well’s production.
Barge Drilling Rigs
Barge drilling rigs are mobile drilling platforms that are submersible and are built to work in seven to 20 feet of water. They are towed by tugboats to the drill site with the derrick lying down. The lower hull is then submerged by flooding compartments until it rests on the river or sea floor. The derrick is then raised and drilling operations are conducted with the barge resting on the bottom. Our barge drilling fleet consists of 13 conventional and posted barge rigs. A posted barge is identical to a conventional barge except that the hull and superstructure are separated by 10 to 14 foot columns, which increases the water depth capabilities of the rig.
The following table contains information regarding our barge drilling rig fleet as of February 21, 2013.
Rig Name
 
Type
 
Year
Built/
Upgraded(a)
 
Horsepower
Rating
 
Rated Drilling
Depth(b)
 
Location
 
Status(c)
 
 
 
 
 
 
 
 
(Feet)
 
 
 
 
1
 
Conv.
 
1980
 
2,000
 
20,000
 
U.S. GOM
 
Cold Stacked
11
 
Conv.
 
1982
 
3,000
 
30,000
 
U.S. GOM
 
Cold Stacked
17
 
Posted
 
1981
 
3,000
 
30,000
 
U.S. GOM
 
Ready Stacked
19
 
Conv.
 
1974
 
1,000
 
14,000
 
U.S. GOM
 
Cold Stacked
27
 
Posted
 
1979/2008
 
3,000
 
30,000
 
U.S. GOM
 
Cold Stacked
41
 
Posted
 
1981
 
3,000
 
30,000
 
U.S. GOM
 
Contracted
46
 
Posted
 
1979
 
3,000
 
30,000
 
U.S. GOM
 
Cold Stacked
48
 
Posted
 
1982
 
3,000
 
30,000
 
U.S. GOM
 
Cold Stacked
49
 
Posted
 
1980
 
3,000
 
30,000
 
U.S. GOM
 
Ready Stacked
52
 
Posted
 
1981
 
2,000
 
25,000
 
U.S. GOM
 
Cold Stacked
55
 
Posted
 
1981
 
3,000
 
30,000
 
U.S. GOM
 
Cold Stacked
57
 
Posted
 
1975
 
2,000
 
25,000
 
U.S. GOM
 
Cold Stacked
64
 
Posted
 
1979
 
3,000
 
30,000
 
U.S. GOM
 
Cold Stacked
  _____________________________
(a)
Dates shown are the original date the rig was built and the date of the most recent upgrade and/or major refurbishment, if any.
(b)
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.
(c)
Rigs designated as “Contracted” are under contract. Rigs described as “Ready Stacked” are not under contract but generally are ready for service. Rigs described as “Cold Stacked” are not actively marketed, normally require the hiring of an entire crew and require a maintenance review and refurbishment before they can function as a drilling rig.
Liftboats
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. Once a liftboat is in position, typically adjacent to an offshore production platform or well, third-party service providers perform:
production platform construction, inspection, maintenance and removal;
well intervention and workover;

4


well plug and abandonment; and
pipeline installation and maintenance.
Our liftboats are ideal working platforms providing support platform and pipeline inspection and maintenance tasks because of their ability to maneuver efficiently and support multiple activities at different working heights. Diving operations may also be performed from our liftboats in connection with underwater inspections and repair. In addition, our liftboats provide an effective platform from which to perform well-servicing activities such as mechanical wireline, electrical wireline and coiled tubing operations. Technological advances, such as coiled tubing, allow more well-servicing procedures to be conducted from liftboats. Moreover, during both platform construction and removal, smaller platform components can be installed and removed more efficiently and at a lower cost using a liftboat crane and liftboat-based personnel than with a specialized construction barge or jackup rig.
The length of the legs is the principal measure of capability for a liftboat, as it determines the maximum water depth in which the liftboat can operate. Our liftboats in the U.S. Gulf of Mexico range in leg lengths up to 229 feet, which allows us to service the majority of the shallow-water offshore infrastructure in the U.S. Gulf of Mexico. Liftboats are typically moved to a port during severe weather to avoid the winds and waves they would be exposed to in open water.
As of February 21, 2013, we owned 39 liftboats operating in the U.S. Gulf of Mexico, sixteen liftboats operating in West Africa, and three liftboats operating in the Middle East. In addition, we operated five liftboats owned by a third party in West Africa. The following table contains information regarding the liftboats we operate as of February 21, 2013.
Liftboat Name(1)
 
Year
Built/
Upgraded(2)
 
Leg
Length
 
Deck
Area
 
Maximum
Deck Load
 
Location
 
Gross
Tonnage
 
 
 
 
(Feet)
 
(Square feet)
 
(Pounds)
 
 
 
 
Whale Shark(3)
 
2005/2009
 
260
 
8,170

 
1,010,000

 
U.A.E.
 
1,142

Tiger Shark(4)
 
2001
 
230
 
5,300

 
1,000,000

 
Nigeria
 
469

Kingfish(3)
 
1996/2012
 
229
 
5,000

 
500,000

 
U.A.E
 
1,312

Man-O-War(4)
 
1996
 
229
 
5,000

 
500,000

 
U.S. GOM
 
188

Wahoo(4)
 
1981
 
215
 
4,525

 
500,000

 
U.S. GOM
 
491

Blue Shark(3)
 
1981
 
215
 
3,800

 
400,000

 
Nigeria
 
1,182

Amberjack(3)
 
1981
 
205
 
3,800

 
500,000

 
U.A.E.
 
417

Bullshark(4)
 
1998
 
200
 
7,000

 
1,000,000

 
U.S. GOM
 
859

Creole Fish(4)
 
2001
 
200
 
5,000

 
798,000

 
Nigeria
 
192

Cutlassfish(4)
 
2006
 
200
 
5,000

 
798,000

 
Nigeria
 
183

Black Jack(3)
 
1997/2008
 
200
 
4,000

 
480,000

 
Nigeria
 
777

Swordfish(4)
 
2000
 
190
 
4,000

 
700,000

 
U.S. GOM
 
189

Leatherjack(4)
 
1998
 
175
 
3,215

 
575,850

 
U.S. GOM
 
168

Oilfish(3)
 
1996
 
170
 
3,200

 
590,000

 
Nigeria
 
495

Manta Ray(4)
 
1981
 
150
 
2,400

 
200,000

 
U.S. GOM
 
194

Seabass(4)
 
1983
 
150
 
2,600

 
200,000

 
U.S. GOM
 
186

F.J. Leleux(5)
 
1981
 
150
 
2,600

 
200,000

 
Nigeria
 
407

Black Marlin(3)
 
1984
 
150
 
2,600

 
200,000

 
Nigeria
 
407

Hammerhead(4)
 
1980
 
145
 
1,648

 
150,000

 
U.S. GOM
 
178

Pilotfish(3)
 
1990
 
145
 
2,400

 
175,000

 
Nigeria
 
292

Rudderfish(3)
 
1991
 
145
 
3,000

 
100,000

 
Nigeria
 
309

Blue Runner(4)
 
1980
 
140
 
3,400

 
300,000

 
U.S. GOM
 
174

Rainbow Runner(4)
 
1981
 
140
 
3,400

 
300,000

 
U.S. GOM
 
174

Pompano(4)
 
1981
 
130
 
1,864

 
100,000

 
U.S. GOM
 
196

Sandshark(4)
 
1982
 
130
 
1,940

 
150,000

 
U.S. GOM
 
196

Stingray(4)
 
1979
 
130
 
2,266

 
150,000

 
U.S. GOM
 
99

Albacore(4)
 
1985
 
130
 
1,764

 
150,000

 
U.S. GOM
 
171

Moray(4)
 
1980
 
130
 
1,824

 
130,000

 
U.S. GOM
 
178


5


Liftboat Name(1)
 
Year
Built/
Upgraded(2)
 
Leg
Length
 
Deck
Area
 
Maximum
Deck Load
 
Location
 
Gross
Tonnage
 
 
 
 
(Feet)
 
(Square feet)
 
(Pounds)
 
 
 
 
Skipfish(4)
 
1985
 
130
 
1,116

 
110,000

 
U.S. GOM
 
91

Sailfish(4)
 
1982
 
130
 
1,764

 
137,500

 
U.S. GOM
 
179

Mahi Mahi(4)
 
1980
 
130
 
1,710

 
142,000

 
U.S. GOM
 
99

Triggerfish(4)
 
2001
 
130
 
2,400

 
150,000

 
U.S. GOM
 
195

Scamp(3)
 
1984
 
130
 
2,400

 
150,000

 
Nigeria
 
195

Rockfish(4)
 
1981
 
125
 
1,728

 
150,000

 
U.S. GOM
 
192

Gar(4)
 
1978
 
120
 
2,100

 
150,000

 
U.S. GOM
 
98

Grouper(4)
 
1979
 
120
 
2,100

 
150,000

 
U.S. GOM
 
97

Sea Robin(4)
 
1984
 
120
 
1,507

 
110,000

 
U.S. GOM
 
98

Tilapia(4)
 
1976
 
120
 
1,280

 
110,000

 
U.S. GOM
 
97

Charlie Cobb(5)
 
1980
 
120
 
2,000

 
100,000

 
Nigeria
 
229

Durwood Speed(5)
 
1979
 
120
 
2,000

 
100,000

 
Nigeria
 
210

James Choat(5)
 
1980
 
120
 
2,000

 
100,000

 
Nigeria
 
210

Solefish(3)
 
1978
 
120
 
2,000

 
100,000

 
Nigeria
 
229

Tigerfish(3)
 
1980
 
120
 
2,000

 
100,000

 
Nigeria
 
210

Zoal Albrecht(5)
 
1982
 
120
 
2,000

 
100,000

 
Nigeria
 
213

Barracuda(4)
 
1979
 
105
 
1,648

 
110,000

 
U.S. GOM
 
93

Carp(4)
 
1978
 
105
 
1,648

 
110,000

 
U.S. GOM
 
98

Cobia (4)
 
1978
 
105
 
1,648

 
110,000

 
U.S. GOM
 
94

Dolphin (4)
 
1980
 
105
 
1,648

 
110,000

 
U.S. GOM
 
97

Herring(4)
 
1979
 
105
 
1,648

 
110,000

 
U.S. GOM
 
97

Marlin(4)
 
1979
 
105
 
1,648

 
110,000

 
U.S. GOM
 
97

Corina(4)
 
1974
 
105
 
953

 
100,000

 
U.S. GOM
 
98

Pike(4)
 
1980
 
105
 
1,360

 
130,000

 
U.S. GOM
 
92

Remora(4)
 
1976
 
105
 
1,179

 
100,000

 
U.S. GOM
 
94

Wolffish(4)
 
1977
 
105
 
1,044

 
100,000

 
U.S. GOM
 
99

Seabream(4)
 
1980
 
105
 
1,140

 
100,000

 
U.S. GOM
 
92

Sea Trout(4)
 
1978
 
105
 
1,500

 
100,000

 
U.S. GOM
 
97

Tarpon(4)
 
1979
 
105
 
1,648

 
110,000

 
U.S. GOM
 
97

Palometa(4)
 
1972
 
105
 
780

 
100,000

 
U.S. GOM
 
99

Jackfish(4)
 
1978
 
105
 
1,648

 
110,000

 
U.S. GOM
 
99

Bonefish(3)
 
1978
 
105
 
1,344

 
90,000

 
Nigeria
 
97

Croaker(3)
 
1976
 
105
 
1,344

 
72,000

 
Nigeria
 
82

Gemfish(3)
 
1978
 
105
 
2,000

 
100,000

 
Nigeria
 
223

Tapertail(3)
 
1979
 
105
 
1,392

 
110,000

 
Nigeria
 
100

  _____________________________
(1)
The Skipfish, Mahi Mahi, Corina, Remora, Wolffish, Palometa, Bonefish, Croaker, Barracuda, Pike, Sea Trout and Seabream are currently cold stacked. All other liftboats are either available or operating.
(2)
Dates shown are the original date the vessel was built and the date of the most recent upgrade and/or major refurbishment, if any.
(3)
Pursuant to the registry documents issued by the Republic of Panama.
(4)
Pursuant to U.S. Coast Guard documentation. International regulatory bodies or non-U.S. Flag states may calculate gross tonnage differently than the U.S. Coast Guard.
(5)
We operate these vessels; however, they are owned by a third party.

6


Competition
The shallow-water businesses in which we operate are highly competitive. Domestic drilling and liftboat contracts are traditionally short term in nature, whereas international drilling and liftboat contracts are longer term in nature. The contracts are typically awarded on a competitive bid basis. Pricing is often the primary factor in determining which qualified contractor is awarded a job, although technical capability of service and equipment, unit availability, unit location, safety record and crew quality may also be considered. Certain of our competitors in the shallow-water business may have greater financial and other resources than we have. As a result, these competitors may have a better ability to withstand periods of low utilization, compete more effectively on the basis of price, build new rigs, acquire existing rigs, and make technological improvements to existing equipment or replace equipment that becomes obsolete. Competition for offshore rigs is usually on a global basis, as drilling rigs are highly mobile and may be moved, at a cost that is sometimes substantial, from one region to another in response to demand. However, our mat-supported jackup rigs are less capable than independent leg jackup rigs of managing variable sea floor conditions found in most areas outside the Gulf of Mexico. As a result, our ability to move our mat-supported jackup rigs to certain regions in response to changes in market conditions is limited. Additionally, a number of our competitors have independent leg jackup rigs with generally higher specifications and capabilities than the independent leg rigs that we currently operate in the Gulf of Mexico. Particularly during market downturns when there is decreased rig demand, higher specification rigs may be more likely to obtain contracts than lower specification rigs.
Customers
Our customers primarily include major integrated energy companies, independent oil and natural gas operators and national oil companies. Sales to customers exceeding 10 percent or more of our total revenue in any of the past three years are as follows:
 
Year Ended
December 31,
 
2012
 
2011
 
2010
Chevron Corporation(a)
17
%
 
25
%
 
17
%
Saudi Aramco(b)
6

 
13

 
14

Oil and Natural Gas Corporation Limited(b)

 
9

 
20

   _____________________________
(a)
Revenue included in our Domestic Offshore, International Offshore, Domestic Liftboats and International Liftboats segments.
(b)
Revenue included in our International Offshore segment.
Contracts
Our contracts to provide services are individually negotiated and vary in their terms and provisions. Currently, all of our drilling contracts are on a dayrate basis. Dayrate drilling contracts typically provide for payment on a dayrate basis, with higher rates while the unit is operating and lower rates or a lump sum payment for periods of mobilization or when operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other factors.
A dayrate drilling contract generally extends over a period of time covering the drilling of a single well or group of wells or covering a stated term. These contracts typically can be terminated by the customer under various circumstances such as the loss or destruction of the drilling unit or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment or due to events beyond the control of either party. In addition, customers in some instances have the right to terminate our contracts with little or no prior notice, and without penalty or early termination payments. The contract term in some instances may be extended by the customers exercising options for the drilling of additional wells or for an additional term, or by exercising a right of first refusal. To date, most of our contracts in the U.S. Gulf of Mexico have been on a short-term basis of less than six months. Our contracts in international locations have historically been longer-term, with contract terms of up to three years. For contracts over six months in term we may have the right to pass through certain cost escalations. Our customers may have the right to terminate, or may seek to renegotiate, existing contracts if we experience downtime or operational problems above a contractual limit, if the rig is a total loss, or in other specified circumstances. A customer is more likely to seek to cancel or renegotiate its contract during periods of depressed market conditions. We could be required to pay penalties if some of our contracts with our customers are canceled due to downtime or operational problems. Suspension of drilling contracts results in the reduction in or loss of dayrates for the period of the suspension.
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 generally are for shorter terms than are drilling contracts.

7


On larger contracts, particularly outside the United States, we may be required to arrange for the issuance of a variety of bank guarantees, performance bonds or letters of credit. The issuance of such guarantees may be a condition of the bidding process imposed by our customers for work outside the United States. The customer would have the right to call on the guarantee, bond or letter of credit in the event we default in the performance of the services. The guarantees, bonds and letters of credit would typically expire after we complete the services.
Contract Backlog
We calculate our contract revenue backlog, or future contracted revenue, as the contract dayrate multiplied by the number of days remaining on the contract assuming full utilization, less any penalties or reductions in dayrate for late delivery or non-compliance with contractual obligations. Backlog excludes revenue for management agreements, mobilization, demobilization, contract preparation and customer reimbursables. The amount of actual revenue earned and the actual periods during which revenue is earned will be different than the backlog disclosed or expected due to various factors. Downtime due to various operational factors, including unscheduled repairs, maintenance, operational delays, health, safety and environmental incidents, weather events in the Gulf of Mexico and elsewhere and other factors (some of which are beyond our control), may result in lower dayrates than the full contractual operating dayrate. In some of the contracts, our customer has the right to terminate the contract without penalty and in certain instances, with little or no notice. The following table reflects the amount of our contract backlog by year as of February 21, 2013, which excludes the three-year rig commitment with Cabinda Gulf Oil Company Limited for use of the Ben Avon, as this acquisition has not yet closed:
 
For the Years Ending December 31,
 
Total
 
2013
 
2014
 
2015
 
Thereafter
 
(in thousands)
Domestic Offshore
$
370,696

 
$
334,951

 
$
35,745

 
$

 
$

International Offshore
268,492

 
126,683

 
102,652

 
39,157

 

Inland
818

 
818

 

 

 

International Liftboats
42,151

 
16,157

 
24,940

 
1,054

 

Total
$
682,157

 
$
478,609

 
$
163,337

 
$
40,211

 
$

Employees
As of December 31, 2012, we had approximately 2,600 employees. We require skilled personnel to operate and provide technical services and support for our rigs, barges and liftboats. As a result, we conduct extensive personnel training and safety programs.
Certain of our employees in West Africa are working under collective bargaining agreements. Additionally, efforts have been made from time to time to unionize portions of the offshore workforce in the U.S. Gulf of Mexico. We believe that our employee relations are good.
Insurance
We maintain insurance coverage that includes coverage for physical damage, third party liability, workers’ compensation and employer’s liability, general liability, vessel pollution and other coverages.
Our primary marine package provides for hull and machinery coverage for substantially all of our rigs and liftboats up to a scheduled value of each asset. The total maximum amount of coverage for these assets is $1.6 billion. The marine package includes protection and indemnity and maritime employer’s liability coverage for marine crew personal injury and death and certain operational liabilities, with primary coverage (or self-insured retention for maritime employer’s liability coverage) of $5.0 million per occurrence with excess liability coverage up to $200.0 million. The marine package policy also includes coverage for personal injury and death of third parties with primary and excess coverage of $25.0 million per occurrence with additional excess liability coverage up to $200.0 million, subject to a $250,000 per-occurrence deductible. The marine package also provides coverage for cargo and charterer’s legal liability. The marine package includes limitations for coverage for losses caused in U.S. Gulf of Mexico named windstorms, including an annual aggregate limit of liability of $75.0 million for property damage and removal of wreck liability coverage. We also procured an additional $75.0 million excess policy for removal of wreck and certain third-party liabilities incurred in U.S. Gulf of Mexico named windstorms. Deductibles for events that are not caused by a U.S. Gulf of Mexico named windstorm are 12.5% of the insured drilling rig values per occurrence, subject to a minimum of $1.0 million, and $1.0 million per occurrence for liftboats. The deductible for drilling rigs and liftboats in a U.S. Gulf of Mexico named windstorm event is $25.0 million. Vessel pollution is covered under a Water Quality Insurance Syndicate policy (“WQIS Policy”) providing limits as required by applicable law, including the Oil Pollution Act of 1990. The WQIS Policy covers pollution emanating from our vessels and drilling rigs, with primary limits of $5.0 million (inclusive of a $3.0 million per-occurrence deductible) and excess liability coverage up to $200.0 million.

8


Control-of-well events generally include an unintended flow from the well that cannot be contained by equipment on site (e.g., a blow-out preventer), by increasing the weight of the drilling fluid, or that does not naturally close itself off through what is typically described as "bridging over". We carry a contractor’s extra expense policy with $25.0 million primary liability coverage for well control costs, expenses incurred to redrill wild or lost wells and pollution, with excess liability coverage up to $200.0 million for pollution liability that is covered in the primary policy. The policies are subject to exclusions, limitations, deductibles, self-insured retention and other conditions. In addition to the marine package, we have separate policies providing coverage for onshore foreign and domestic general liability, employer’s liability, auto liability and non-owned aircraft liability, with customary deductibles and coverage. Our policy, which we renew annually, expires in April 2013.
Our drilling contracts provide for varying levels of indemnification from our customers and in most cases, may require us to indemnify our customers for certain liabilities. Under our drilling contracts, liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property, regardless of how the loss or damage to the personnel and property may be caused. Our customers typically assume responsibility for and agree to indemnify us from any loss or liability resulting from pollution or contamination, including clean-up and removal and third-party damages arising from operations under the contract and originating below the surface of the water, including as a result of blow-outs or cratering of the well (“Blowout Liability”). The customer’s assumption for Blowout Liability may, in certain circumstances, be limited or could be determined to be unenforceable in the event of our gross negligence, willful misconduct or other egregious conduct. In addition, we may not be indemnified for statutory penalties and punitive damages relating to such pollution or contamination events. We generally indemnify the customer for the consequences of spills of industrial waste or other liquids originating solely above the surface of the water and emanating from our rigs or vessels.
We are self-insured for the deductible portion of our insurance coverage. Management believes adequate accruals have been made on known and estimated exposures up to the deductible portion of our insurance coverage. Management believes that claims and liabilities in excess of the amounts accrued are adequately insured. However, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences. In addition, there is no assurance of renewal or the ability to obtain coverage acceptable to us.
Insurance Claims Settlement
In September 2011, we were conducting a required annual spud can inspection on Hercules 185 in protected waters offshore Angola. While conducting the inspection, it was determined that the spud can on the starboard leg had detached from the leg. Subsequently, additional leg damage was identified. The rig underwent repairs related to this damage and was mobilized back to Angola. During the return mobilization from the U.S. Gulf of Mexico to Angola, Hercules 185 experienced additional damage to its legs. We conducted a survey of the rig's legs above and below the water line and discovered extensive damage to various portions of the rig's legs. In June 2012, we determined that it was unfeasible to repair the damage and return the rig to service and recorded an impairment charge to write the rig down to salvage value. We and our insurance underwriters reached a global settlement in September 2012, agreeing that Hercules 185 should be considered a constructive total loss. From this settlement, we received total insurance proceeds of $41.0 million for the rig, including $7.5 million received in June 2012 for its earlier claim relating to previous leg damage to the rig. These proceeds generated a gain on insurance settlement of $27.3 million which is included in Operating Expenses on the Consolidated Statements of Operations for the year ended December 31, 2012. As part of the settlement, we agreed to transport and attempt to sell the rig, which entitled us to the first $1.5 million in proceeds from such sale and any sale proceeds in excess of $1.5 million being split seventy-five percent to the underwriters and twenty-five percent to us.
Regulation
Our operations are affected in varying degrees by federal, state, local and foreign and/or international governmental laws and regulations regarding the discharge of materials into the environment or otherwise relating to environmental protection. Our industry is dependent on demand for services from the oil and natural gas industry and, accordingly, is also affected by changing tax and other laws relating to the energy business generally. In the United States, we are subject to the jurisdiction of the U.S. Coast Guard (“Coast Guard”), the National Transportation Safety Board ("NTSB"), the U.S. Customs and Border Protection (“CBP”), the Department of Interior, the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”), as well as classification societies such as the American Bureau of Shipping ("ABS"). The Coast Guard and the NTSB set safety standards and are authorized to investigate vessel accidents and recommend improved safety standards, and the CBP is authorized to inspect vessels at will. Coast Guard regulations also require annual inspections and periodic drydock inspections or special examinations of our vessels.

9


For instance, the Coast Guard issued a Policy Letter in July 2011 that provides for more frequent inspections of foreign flagged Mobile Offshore Drilling Units (“MODUs”) that operate on the U.S. Outer Continental Shelf (“OCS”). The Coast Guard will make determinations to conduct more frequent inspections of foreign flagged MODUs in accordance with its Mobile Offshore Drilling Unit Safety and Environmental Protection Compliance Targeting Matrix. We may be subject to increased costs and potential downtime for certain of our rigs operating on the OCS if such rigs are determined by the Coast Guard to need additional oversight and inspection under this Policy Letter.
In addition to this Coast Guard Policy Letter, in November 2011, the BSEE announced a change in its enforcement policies in the aftermath of the Macondo well blowout in April 2010, pursuant to which the agency has extended its regulatory enforcement reach to include contractors as well as offshore lease operators. Consequently, the BSEE may elect to hold contractors, including drilling contractors, liable for alleged violations of law arising in the BSEE’s jurisdictional area. In August 2012, the BSEE issued an Interim Policy Letter that established the parameters by which BSEE will issue incidents of noncompliance to drilling contractors for serious violations of BSEE regulations. Implementation of this announced change in enforcement policy by the BSEE could subject us to added liabilities, including sanctions and penalties, as well as increased costs arising from contractual arrangements in master services agreements that failed to take into account such change in enforcement policy with respect to our operations in the U.S. Gulf of Mexico, which may have an adverse effect on our business and results of operations.
The shorelines and shallow-water areas of the U.S. Gulf of Mexico are ecologically sensitive. Heightened environmental concerns in these areas have led to higher drilling costs and a more difficult and lengthy well permitting process and, in general, have adversely affected drilling decisions of oil and natural gas companies. In the United States, our operations are subject to federal and state laws and regulations that require us to obtain and maintain specified permits or governmental approvals; control the discharge of materials into the environment; remove and cleanup materials that may harm the environment; or otherwise comply with the protection of the environment. For example, as an operator of mobile offshore units in navigable U.S. waters including the OCS, 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. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions restricting some or all of our activities in the affected areas.
Laws and regulations protecting the environment have become more stringent over time 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 legal requirements or the adoption of new or more stringent legal 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, as amended, commonly referred to as the Clean Water Act, prohibits the discharge of pollutants into the navigable waters of the United States without a permit. The regulations implementing the Clean Water Act require permits to be obtained by an operator before specified discharge activities occur. Offshore facilities must also prepare plans addressing spill prevention, control and countermeasures. In addition, while operators of vessels visiting U.S. ports historically have been excluded from obtaining permits for the discharge of ballast water and other substances incidental to the normal operation of the vessels because of an exemption under the Clean Water Act, that exemption was vacated, effective February 6, 2009. In place of the former Clean Water Act exemption, the EPA adopted a Vessel General Permit, effective December 19, 2008, that required subject vessel operators, including us, to obtain a Vessel General Permit for all of our covered vessels by February 6, 2009. We have obtained the necessary Vessel General Permit for all of our vessels to which this permitting program applies. The current Vessel General Permit expires December 19, 2013 and EPA has released a new draft permit which is expected to be issued in March 2013. In addition to the EPA’s issuance of the Vessel General Permit, some states are, and other states are considering, regulating ballast water discharges. Violations of monitoring, reporting and permitting requirements associated with applicable ballast water discharge permitting programs or other regulatory initiatives may result in the imposition of civil and criminal penalties. Moreover, we have incurred added costs to comply with legal requirements under the Vessel General Permit and may continue to incur further costs as other legal requirements under federal and state ballast water discharge permit programs are adopted and implemented, but we do not believe that such compliance efforts will have a material adverse effect on our results of operations or financial position.
The U.S. Oil Pollution Act of 1990 (“OPA”), as amended, and related regulations impose a variety of requirements on “responsible parties” related to the prevention and/or reporting of oil spills and liability for damages resulting from such spills in waters off the U.S. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. Under OPA, as amended by the Coast Guard and Maritime Transportation Act of 2006, “tank vessels” of over 3,000 gross tons that carry oil or other hazardous materials in bulk as cargo, are subject to liability limits of (i) for a single-hulled vessel, the greater of $3,200 per gross ton or $23.5 million or (ii) for a

10


tank vessel other than a single-hulled vessel, the greater of $2,000 per gross ton or $17.1 million. “Tank vessels” of 3,000 gross tons or less are subject to liability limits of (i) for a single-hulled vessel, the greater of $3,200 per gross ton or $6.4 million or (ii) for a tank vessel other than a single-hulled vessel, the greater of $2,000 per gross ton or $4.3 million. For any vessels other than “tank vessels” that are subject to OPA, the liability limits are the greater of $1,000 per gross ton or $854,400. Few defenses exist to the liability imposed by OPA and the liability could be substantial. Moreover, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, the liability limits likewise do not apply and certain defenses may not be available. In addition, OPA imposes on responsible parties the need for proof of financial responsibility to cover at least some costs in a potential spill. As required, we have provided satisfactory evidence of financial responsibility to the Coast Guard for all of our vessels subject to such requirements.
The U.S. Outer Continental Shelf Lands Act, as amended, authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the OCS. 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 OCS vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations related to the environment issued pursuant to the Outer Continental Shelf Lands Act can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and canceling leases. Such enforcement liabilities can result from either governmental or citizen prosecution.
The U.S. Comprehensive Environmental Response, Compensation, and Liability Act, as amended, also known as CERCLA or the “Superfund” law, imposes liability without regard to fault or the legality of the original conduct on certain 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 entities 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. We generate wastes in the course of our routine operations that may be classified as hazardous substances.
The U.S. Resource Conservation and Recovery Act, as amended, regulates the generation, transportation, storage, treatment and disposal of onshore hazardous and non-hazardous wastes and requires states to develop programs to ensure the safe disposal of wastes. We generate nonhazardous wastes and small quantities of hazardous wastes in connection with routine operations. We believe that all of the wastes that we generate are handled in compliance in all material respects with the Resource Conservation and Recovery Act and analogous state laws.
In recent years, a variety of initiatives intended to enhance vessel security were adopted to address terrorism risks, including the Coast Guard regulations implementing the Maritime Transportation and Security Act of 2002. These regulations required, among other things, the development of vessel security plans and on-board installation of automatic information systems, or AIS, to enhance vessel-to-vessel and vessel-to-shore communications. We believe that our vessels are in substantial compliance with all vessel security regulations.
Some of our operations are conducted in the U.S. domestic trade, which is governed by the coastwise laws of the United States. The U.S. coastwise laws reserve marine transportation, including liftboat services, between points in the United States to vessels built in and documented under the laws of the United States and owned and manned by U.S. citizens. Generally, an entity is deemed a U.S. citizen for these purposes so long as:
it is organized under the laws of the United States or a state;
each of its president or other chief executive officer and the chairman of its board of directors is a U.S. citizen;
no more than a minority of the number of its directors necessary to constitute a quorum for the transaction of business are non-U.S. citizens; and
at least 75% of the interest and voting power in the corporation is held by U.S. citizens free of any trust, fiduciary arrangement or other agreement, arrangement or understanding whereby voting power may be exercised directly or indirectly by non-U.S. citizens.
Because we could lose our privilege of operating our liftboats in the U.S. coastwise trade if non-U.S. citizens were to own or control in excess of 25% of our outstanding interests, our certificate of incorporation restricts foreign ownership and control of our common stock to not more than 20% of our outstanding interests. One of our liftboats relies on an exemption from coastwise laws in order to operate in the U.S. Gulf of Mexico. If this liftboat were to lose this exemption, we would be unable to use it in the U.S. Gulf of Mexico and would be forced to seek opportunities for it in international locations.

11


The United States is one of approximately 170 member countries to the International Maritime Organization (“IMO”), a specialized agency of the United Nations that is responsible for developing measures to improve the safety and security of international shipping and to prevent marine pollution from ships. Among the various international conventions negotiated by the IMO is the International Convention for the Prevention of Pollution from Ships (“MARPOL”). MARPOL imposes environmental standards on the shipping industry relating to oil spills, management of garbage, the handling and disposal of noxious liquids, harmful substances in packaged forms, sewage and air emissions.
Annex VI to MARPOL sets limits on sulfur dioxide and nitrogen oxide emissions from ship exhausts and prohibits deliberate emissions of ozone depleting substances. Annex VI entered into force on May 19, 2005, and applies to all ships, fixed and floating drilling rigs and other floating platforms. 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 400 gross tons and greater, 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 previously. Annex VI came into force in the United States on January 8, 2009. Moreover, on July 1, 2010, amendments to Annex VI to the MARPOL Convention took effect requiring the imposition of progressively stricter limitations on sulfur emissions from ships. As a result, limitations imposed on sulfur emissions will require that fuels of vessels in covered Emission Control Areas (“ECAs”) contain no more than 1% sulfur. In August 2012, the North American ECA became enforceable. The North American ECA includes areas subject to the exclusive sovereignty of the United States and extends up to 200 nautical miles from the coasts of the United States, which area includes parts of the U.S. Gulf of Mexico. Consequently, beginning on January 1, 2012, limits on marine fuel used to power ships in non-ECA areas were capped at 3.5% sulfur and, in August 2012, when the North American ECA became effective, the sulfur limit in marine fuel was capped at 1%, which is the capped amount for all other ECA areas since July 1, 2010. These capped amounts will then decrease progressively until they reach 0.5% by January 1, 2020 for non-ECA areas and 0.1% by January 1, 2015 for ECA areas, including the North American ECA. The amendments also establish new tiers of stringent nitrogen oxide emissions standards for new marine engines, depending on their date of installation. Our operation of vessels in international waters, outside of the North American ECA, are 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 that compliance with MARPOL or Annex VI to MARPOL, whether within the North American ECA or beyond, will have a material adverse effect on our results of operations or financial position.
In response to the Macondo well blowout incident in April 2010, the U.S. Department of Interior, initially through the U.S. Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) and, upon dissolution of the BOEMRE effective October 1, 2011, through the BOEM and BSEE, has undertaken an aggressive overhaul of the offshore oil and natural gas regulatory process that has significantly impacted oil and gas development in the U.S. Gulf of Mexico. From time to time, new rules, regulations and requirements have been proposed and implemented by BOEM, BSEE or the United States Congress that materially limit or prohibit, and increase the cost of, offshore drilling in the U.S. Gulf of Mexico. These new rules, regulations and requirements include the moratorium on shallow-water drilling that was lifted in May 2010, but which resulted in a significant delay in permits being issued in the U.S. Gulf of Mexico, the adoption of new safety requirements and policies relating to the approval of drilling permits in the U.S. Gulf of Mexico, restrictions on oil and gas development and production activities in the U.S. Gulf of Mexico, and the promulgation of numerous Notices to Lessees that have impacted and may continue to impact our operations. In addition to these rules, regulations and requirements, the federal government is considering new legislation that could impose additional equipment and safety requirements on operators and drilling contractors in the U.S. Gulf of Mexico, as well as regulations relating to the protection of the environment, all of which could materially adversely affect our financial condition and results of operations.
Greenhouse gas emissions have increasingly become the subject of international, national, regional, state and local attention. Cap and trade initiatives to limit greenhouse gas emissions have been introduced in the European Union. Similarly, numerous bills related to climate change have been introduced in the U.S. Congress, which could adversely impact most industries. In addition, future regulation of greenhouse gas could occur pursuant to future treaty obligations, statutory or regulatory changes or new climate change legislation in the jurisdictions in which we operate. It is uncertain whether any of these initiatives will be implemented. However, based on published media reports, we believe that it is not reasonably likely that recently considered federal legislative initiatives in the U.S. will be adopted and implemented without substantial modification. Restrictions on greenhouse gas emissions or other related legislative or regulatory enactments could have an effect in those industries that use significant amounts of petroleum products, which could potentially result in a reduction in demand for petroleum products and, consequently and indirectly, our offshore support services. We are currently unable to predict the manner or extent of any such effect. Furthermore, one of the asserted long-term physical effects of climate change may be an increase in the severity and frequency of adverse weather conditions, such as hurricanes, which may increase our insurance costs or risk retention, limit insurance availability or reduce the areas in which, or the number of days during which,

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our customers would contract for our vessels in general and in the U.S. Gulf of Mexico in particular. We are currently unable to predict the manner or extent of any such effect.
Our non-U.S. operations are subject to other laws and regulations in countries in which we operate, including laws and regulations relating to the importation of and operation of rigs and liftboats, currency conversions and repatriation, oil and natural gas exploration and development, environmental protection, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of rigs, liftboats and other equipment. Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and natural gas and other aspects of the oil and natural gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and natural gas companies and may continue to do so. Operations in less developed countries can be subject to legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.
Although significant capital expenditures may be required to comply with these governmental laws and regulations, such compliance has not materially adversely affected our earnings or competitive position. We believe that we are currently in compliance in all material respects with the environmental regulations to which we are subject.
Available Information
General information about us, including our corporate governance policies, can be found on our Internet website at www.herculesoffshore.com. On our website we make available, free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file or furnish them to the SEC. These filings also are available at the SEC’s Internet website at www.sec.gov. Information contained on our website is not part of this annual report.
 Segment and Geographic Information
Information with respect to revenue, operating income and total assets attributable to our segments and revenue and long-lived assets by geographic areas of operations is presented in Note 16 of our Notes to Consolidated Financial Statements included in Item 8 of this annual report. Additional information about our segments, as well as information with respect to the impact of seasonal weather patterns on domestic operations, is presented in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this annual report.

Item 1A.    Risk Factors

Our business depends on the level of activity in the oil and natural gas industry, which is significantly affected by volatile oil and natural gas prices.
Our business depends on the level of activity of oil and natural gas exploration, development and production in the U.S. Gulf of Mexico and internationally, and in particular, the level of exploration, development and production expenditures of our customers. Demand for our drilling services is adversely affected by declines associated with depressed oil and natural gas prices. Even the perceived risk of a decline in oil or natural gas prices often causes oil and gas companies to reduce spending on exploration, development and production. However, higher prices do not necessarily translate into increased drilling activity since our clients’ expectations about future commodity prices typically drive demand for our services. Reductions in capital expenditures of our customers reduce rig utilization and day rates. Crude oil and condensates are representing a larger proportion of overall production in the U.S. GOM, however, a majority of the production remains natural gas. Oil and natural gas prices are extremely volatile and 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, developing, producing and delivering oil and natural gas, and the relative cost of onshore production or importation of natural gas;
political, economic and weather conditions in the United States and elsewhere;
advances in drilling, exploration, development and production technology;
the ability of the Organization of Petroleum Exporting Countries, commonly called “OPEC,” to set and maintain oil production levels and pricing;
the level of production in non-OPEC countries;
domestic and international tax policies and governmental regulations;

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the development and exploitation of alternative fuels, and the competitive, social and political position of natural gas as a source of energy compared with other energy sources;
the policies of various governments regarding exploration and development of their oil and natural gas reserves;
the worldwide military and political environment and uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East (including the recent tensions between the international community and Iran), North Africa, West Africa and other significant oil and natural gas producing regions; and
acts of terrorism or piracy that affect oil and natural gas producing regions, especially in Nigeria, where armed conflict, civil unrest and acts of terrorism are increasingly common occurrences.
While economic conditions continue to improve, reduced demand for drilling and liftboat services could materially erode dayrates and utilization rates for our units, which could adversely affect our financial condition and results of operations. Continued hostilities in the Middle East, North Africa, and West Africa and the occurrence or threat of terrorist attacks against the United States or other countries could negatively impact the economies of the United States and other countries where we operate. Another decline in the economy could result in a decrease in energy consumption, which in turn would cause our revenue and margins to decline and limit our future growth prospects.
The offshore service industry is highly cyclical and experiences periods of low demand and low dayrates. The volatility of the industry, coupled with our short-term contracts, has in the past resulted and could again result in sharp declines in our profitability.
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 or increasing supply intensify the competition in the industry and often result in rigs or liftboats being idle for long periods of time. As a result of the cyclicality of our industry, we expect our results of operations to be volatile and to decrease during market declines such as the recession we recently experienced.
Maintaining idle assets or the sale of assets below their then carrying value may cause us to experience losses and may result in impairment charges.
Prolonged periods of low utilization and dayrates, the cold stacking of idle assets or the sale of assets below their then carrying value may cause us to experience losses. These events may also result in the recognition of impairment charges on certain of our assets if future cash flow estimates, based upon information available to management at the time, indicate that their carrying value may not be recoverable or if we sell assets at below their then carrying value.
We have a significant level of debt, and could incur additional debt in the future. Our debt could have significant consequences for our business and future prospects.
As of December 31, 2012, we had total outstanding debt of approximately $865.1 million. This debt represented approximately 49% of our total book capitalization. As of December 31, 2012, we had $74.0 million of available capacity under our revolving credit facility, after the commitment of $1.0 million for letters of credit issued under it. We may borrow under our revolving credit facility to fund working capital or other needs in the near term up to the remaining availability, subject to our compliance with financial covenants. Our debt and the limitations imposed on us by our existing or future debt agreements could have significant consequences for 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 and we may be required under the terms of our existing credit facility or notes to use the proceeds of any financing we obtain to repay or prepay existing debt;
we will be required to dedicate a substantial portion of our cash flow to payments of interest on our debt;
we may be exposed to risks inherent in interest rate fluctuations on borrowings under our credit facility which could result in higher interest expense to the extent that we do not hedge such risk in the event of increases in interest rates;
we could be more vulnerable during downturns in our business and be less able to take advantage of significant business opportunities and to react to changes in our business and in market or industry conditions; and
we may have a competitive disadvantage relative to our competitors that have less debt.
Our ability to make payments on and to refinance our indebtedness, including the convertible notes issued by us in June 2008, the senior notes issued by us in October 2009, the senior secured notes issued by us in April 2012 and the senior notes issued by us in April 2012, and to fund planned capital expenditures will depend on our ability to generate cash in the future,

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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 other 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, we will need to refinance our debt, sell assets or repay the debt with the proceeds from equity offerings. Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, and we may not be able to complete asset sales in a timely manner sufficient to make such repayments.
Our debt instruments impose significant additional costs and operating and financial restrictions on us, which may prevent us from capitalizing on business opportunities and taking certain actions.
Our debt instruments impose significant additional costs and operating and financial restrictions on us. These restrictions limit our ability to, among other things:
make certain types of loans and investments;
pay dividends, redeem or repurchase stock, prepay, redeem or repurchase other debt or make other restricted payments;
incur or guarantee additional indebtedness;
invest in certain new joint ventures;
create or incur liens;
place restrictions on our subsidiaries’ ability to make dividends or other payments to us;
sell our assets or consolidate or merge with or into other companies;
engage in transactions with affiliates; and
enter into new lines of business.
Our compliance with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures, finance our acquisitions, equipment purchases and development expenditures, or withstand the present or any future downturn in our business.
If we are unable to comply with the restrictions and financial covenant in our debt instruments, there could be a default, which could result in an acceleration of repayment of funds that we have borrowed.
Our revolving credit facility includes a financial covenant that will be tested if borrowings or letters of credit exceed $10.0 million. If we trigger the conditions requiring testing, our ability to comply with this financial covenant and restrictions can be affected by events beyond our control. Reduced activity levels in the oil and natural gas industry could adversely impact our ability to comply with such covenants in the future. Our failure to comply with such covenant would result in an event of default under the revolving credit facility. An event of default could prevent us from borrowing under our revolving credit facility, which could in turn have a material adverse effect on our available liquidity. In addition, an event of default could result in our having to immediately repay all amounts outstanding under the revolving credit facility, the 3.375% Convertible Senior Notes due 2038, the 10.5% Senior Notes due 2017, the 7.125% Senior Secured Notes due 2017 and the 10.25% Senior Notes due 2019, and in foreclosure of liens on our assets. As of December 31, 2012, we were not required to test the financial covenant under our revolving credit facility.
Our industry is highly competitive, with intense price competition. Our inability to compete successfully may reduce our profitability.
Our industry is highly competitive. Our contracts are traditionally awarded on a competitive bid basis. Pricing is often the primary factor in determining which qualified contractor is awarded a job, although rig and liftboat availability, location and technical capability and each contractor’s safety performance record and reputation for quality also can be key factors in the determination. Dayrates also depend on the supply of rigs and vessels and excess capacity puts downward pressure on dayrates. Excess capacity can occur when newly constructed rigs and vessels enter service, when rigs and vessels are mobilized between geographic areas and when non-marketed rigs and vessels are reactivated.
Several of our competitors also are incorporated in other jurisdictions outside the United States, which provides them with significant tax advantages that are not available to us as a U.S. company and, as a result, may materially impair our ability to compete with them for many projects that would be beneficial to our company.

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Global financial and economic circumstances may have impacts on our business and financial condition that we cannot predict, and may limit our ability to finance our business and refinance our debt at a reasonable cost of capital.
We may face challenges if conditions in the financial markets are inadequate to finance our activities and pay or refinance our debt as it comes due at a reasonable cost. Continuing concerns over the worldwide economic outlook, the availability and costs of credit, and the sovereign debt crisis have contributed to increased volatility in the global financial markets and commodity prices and diminished expectations for the global economy. These conditions could make it more difficult for us to access capital on reasonable terms and to refinance our debt at reasonable costs.
We may require additional capital in the future, which may not be available to us or may be at a cost which reduces our cash flow and profitability.
Our business is capital intensive and, to the extent we do not generate sufficient cash from operations, we may need to raise additional funds through public or private debt (which would increase our interest costs) or equity financings to execute our business strategy, to fund capital expenditures or to meet the covenant under our revolving credit facility. Adequate sources of capital funding may not be available when needed or may not be available on acceptable terms. In addition, under the terms of our revolving credit facility, we may be required to use the proceeds of any capital that we raise to repay existing indebtedness. If we raise additional funds by issuing additional equity securities, existing stockholders may experience dilution. If funding is insufficient at any time in the future, we may be unable to fund maintenance of our assets, take advantage of business opportunities or respond to competitive pressures, any of which could harm our business.
Asset sales are currently an important component of our business strategy in reducing our debt. We may be unable to identify appropriate buyers with access to financing or to complete any sales on acceptable terms.
We are currently considering sales or other dispositions of certain of our assets, and any such disposition could be significant and could significantly affect the results of operations of one or more of our business segments. In the current economic environment, asset sales may occur on less favorable terms than terms that might be available at other times in the business cycle. At any given time, discussions with one or more potential buyers may be at different stages. However, any such discussions may or may not result in the consummation of an asset sale. We may not be able to identify buyers with access to financing or complete sales on acceptable terms.
Our customer contracts are generally short term, and we will experience reduced profitability if our customers reduce activity levels, terminate or seek to renegotiate contracts, or if we experience downtime, operational difficulties, or safety-related issues.
Currently, all of our drilling contracts with major customers are dayrate contracts, where we charge a fixed charge per day regardless of the number of days needed to drill the well. Likewise, under our current liftboat contracts, we charge a fixed fee per day regardless of the success of the operations that are being conducted by our customer utilizing our liftboat. During depressed market conditions, a customer may no longer need a rig or liftboat that is currently under contract or may be able to obtain a comparable rig or liftboat at a lower daily rate. As a result, customers may seek to renegotiate the terms of their existing drilling contracts or avoid their obligations under those contracts. In addition, our customers may have the right to terminate, or may seek to renegotiate, existing contracts if we experience downtime, operational problems above the contractual limit or safety-related issues, if the rig or liftboat is a total loss, if the rig or liftboat is not delivered to the customer within the period specified in the contract or in other specified circumstances, which include events beyond the control of either party.
In the U.S. Gulf of Mexico, contracts are generally short term, and oil and natural gas companies tend to reduce activity levels quickly in response to downward changes in oil and natural gas prices. Due to the short-term nature of most of our contracts, a decline in market conditions can quickly affect our business if customers reduce their levels of operations.
Some of our contracts with our customers include terms allowing them to terminate the contracts without cause, with little or no prior notice and without penalty or early termination payments. In addition, we could be required to pay penalties if some of our contracts with our customers are terminated due to downtime, operational problems or failure to deliver. Some of our other contracts with customers may be cancelable at the option of the customer upon payment of a penalty, which may not fully compensate us for the loss of the contract. Early termination of a contract may result in a rig or liftboat being idle for an extended period of time. The likelihood that a customer may seek to terminate a contract is increased during periods of market weakness. If our customers cancel or require us to renegotiate some of our significant contracts, if we are unable to secure new contracts on substantially similar terms, especially those contracts in our International Offshore segment, or if contracts are suspended for an extended period of time, our revenue and profitability would be materially reduced.
An increase in supply of rigs or liftboats could adversely affect our financial condition and results of operations.
Reactivation of non-marketed rigs or liftboats, mobilization of rigs or liftboats back to the U.S. Gulf of Mexico or new construction of rigs or liftboats could result in excess supply in the region, and our dayrates and utilization could be reduced.

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Construction of rigs could result in excess supply in international regions, which could reduce our ability to secure new contracts for our stacked rigs and could reduce our ability to renew, extend or obtain new contracts for working rigs at the end of such contract term. The excess supply would also impact the dayrates on future contracts.
If market conditions improve, inactive rigs and liftboats that are not currently being marketed could be reactivated to meet an increase in demand. Improved market conditions in the U.S. Gulf of Mexico, particularly relative to other regions, could also lead to the movement of jackup rigs, other mobile offshore drilling units and liftboats into the U.S. Gulf of Mexico. Improved market conditions in any region worldwide could lead to increased construction and upgraded 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 20, 2013, 86 jackup rigs were under construction or on order globally by industry participants, national oil companies and financial investors for delivery through 2015. Many of the rigs currently under construction have not been contracted for future work, which may intensify price competition as scheduled delivery dates occur. A significant increase in the supply of jackup rigs, other mobile offshore drilling units or liftboats could adversely affect both our utilization and dayrates.
Our business involves numerous operating hazards and exposure to extreme weather and climate risks, and our insurance may not be adequate to cover our losses.
Our operations are subject to the usual hazards inherent in the drilling and operation of oil and natural gas wells, such as blowouts, reservoir damage, loss of production, loss of well control, punchthroughs, craterings, fires and pollution. The occurrence of these events could result in the suspension of drilling or production operations, claims by the operator, severe damage to or destruction of the property and equipment involved, injury or death to rig or liftboat personnel, and environmental damage. We may also be subject to personal injury and other claims of rig or liftboat personnel as a result of our drilling and liftboat operations. Operations also may be suspended because of machinery breakdowns, abnormal operating conditions, failure of subcontractors to perform or supply goods or services and personnel shortages.
In addition, our drilling and liftboat operations are subject to perils of 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 could have a material adverse effect on our operations. During such severe weather conditions, our liftboats typically leave their location and cease to earn a full dayrate. The liftboats cannot return to the location until the weather improves and the seas are within U.S. Coast Guard approved limits. In addition, damage to our rigs, liftboats, shorebases and corporate infrastructure caused by high winds, turbulent seas, or unstable sea bottom conditions could potentially cause us to curtail operations for significant periods of time until the damages can be repaired. In addition, we cold stack a number of rigs in certain locations offshore. This concentration of rigs in specific locations could expose us to increased liability from a catastrophic event and could cause an increase in our insurance costs.
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 subject to significant deductibles and are not totally insurable. Risks from extreme weather and marine hazards may increase in the event of ongoing patterns of adverse changes in weather or climate.
A significant portion of our business is conducted in shallow-water areas of the U.S. Gulf of Mexico. The mature nature of this region could result in less drilling activity in the area, thereby reducing demand for our services.
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.
We can provide no assurance that our current backlog of contract drilling revenue will be ultimately realized.
As of February 21, 2013, our total contract drilling backlog for our Domestic Offshore, International Offshore, International Liftboats and Inland segments was approximately $682.2 million, which excludes the three-year rig commitment with Cabinda Gulf Oil Company Limited for use of the Ben Avon, as this acquisition has not yet closed. We calculate our contract revenue backlog, or future contracted revenue, as the contract dayrate multiplied by the number of days remaining on the contract assuming full utilization, less any penalties or reductions in dayrate for late delivery or non-compliance with

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contractual obligations. Backlog excludes revenue for management agreements, mobilization, demobilization, contract preparation and customer reimbursables. We may not be able to perform under our drilling contracts due to various operational factors, including unscheduled repairs, maintenance, operational delays, health, safety and environmental incidents, weather events in the Gulf of Mexico and elsewhere and other factors (some of which are beyond our control), and our customers may seek to cancel or renegotiate our contracts for various reasons. In some of the contracts, our customer has the right to terminate the contract without penalty and in certain instances, with little or no notice. Our inability or the inability of our customers to perform under our or their contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.
Our insurance coverage has become more expensive, may become unavailable in the future, and may be inadequate to cover our losses.
Our insurance coverage is subject to certain significant deductibles and levels of self-insurance, does not cover all types of losses and, in some situations, may not provide full coverage for losses or liabilities resulting from our operations. In addition, due to the losses sustained by us and the offshore drilling industry in recent years, we are likely to continue experiencing increased costs for available insurance coverage, which may impose higher deductibles and limit maximum aggregated recoveries, including for hurricane-related windstorm damage or loss and for pollution and blowout events. Insurance costs may increase in the event of ongoing patterns of adverse changes in weather or climate.
Further, we may elect not to obtain or we may be unable to obtain windstorm coverage in the future, thus putting us at a greater risk of loss due to severe weather conditions and other hazards. If a significant accident or other event resulting in damage to our rigs or liftboats, including severe weather, equipment breakdowns, terrorist acts, piracy, war, civil disturbances, blowouts, 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.
As a result of a number of recent catastrophic weather related and other events, 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 has suffered extensive damage from several hurricanes since 2005. As a result, our insurance costs have increased significantly, our deductibles have increased and our coverage for named windstorm damage was restricted. Any additional severe storm activity in the energy producing areas of the U.S. Gulf of Mexico in the future could cause insurance underwriters to no longer insure U.S. Gulf of Mexico assets against weather-related damage. Further, due to the escalating costs for weather-related damage in the U.S. Gulf of Mexico, in the future we may elect to forgo purchasing such coverage. A number of our customers that produce oil and natural gas have previously maintained business interruption insurance for their production. This insurance is less available and 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.
Our customers may be unable or unwilling to indemnify us.
Consistent with standard industry practice, our clients generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. These risks are those associated with the loss of control of a well, such as blowout or cratering, the cost to regain control or redrill the well and associated pollution. There can be no assurance, however, that these clients will necessarily be financially able to indemnify us against all these risks. Also, we may be effectively prevented from enforcing these indemnities because of the nature of our relationship with some of our larger clients. Additionally, from time to time we may not be able to obtain agreement from our customers to indemnify us for such damages and risks.
Any violation of the Foreign Corrupt Practices Act ("FCPA") or similar laws and regulations could result in significant expenses, divert management attention, and otherwise have a negative impact on us.
We are subject to the FCPA, which generally prohibits U.S. companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or retaining business, and the anti-bribery laws of other jurisdictions. On April 4, 2011, we received a subpoena from the Securities and Exchange Commission ("SEC") requesting that we produce documents relating to our compliance with the FCPA. We were also advised by the Department of Justice ("DOJ") on April 5, 2011, that it was conducting a similar investigation. Under the direction of the audit committee, we conducted an internal investigation regarding these matters. On April 24, 2012 and August 7, 2012, we received letters notifying us that the DOJ and SEC, respectively, had completed their investigations and did not intend to pursue enforcement action against us. Despite the favorable termination of these investigations, we remain subject to the FCPA and similar laws and regulations, and any determination that we have violated the FCPA or laws of any other jurisdiction could have a material adverse effect on our financial condition.

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Our international operations may subject us to political and regulatory risks and uncertainties.
In connection with our international contracts, the transportation of rigs, services and technology across international borders subjects us to extensive trade laws and regulations. Our import and export activities are governed by unique customs laws and regulations in each of the countries where we operate. In each jurisdiction, laws and regulations concerning importation, recordkeeping and reporting, import and export control and financial or economic sanctions are complex and constantly changing. Our business and financial condition may be materially affected by enactment, amendment, enforcement or changing interpretations of these laws and regulations. Rigs and other shipments can be delayed and denied import or export for a variety of reasons, some of which are outside our control and some of which may result in failure to comply with existing laws and regulations and contractual requirements. Shipping delays or denials could cause operational downtime or increased costs, duties, taxes and fees. Any failure to comply with applicable legal and regulatory obligations also could result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of goods and loss of import and export privileges.
Our international operations are subject to additional political, economic, and other uncertainties not generally associated with domestic operations.
An element of our business strategy is to continue to expand into international oil and natural gas producing areas such as West Africa, the Middle East and the Asia-Pacific region. We operate liftboats in West Africa, including Nigeria, and in the Middle East. We also operate drilling rigs in Southeast Asia, Saudi Arabia and West Africa. Our international operations are subject to a number of risks inherent in any business operating in foreign countries, including:
political, social and economic instability, war and acts of terrorism;
potential seizure, expropriation or nationalization of assets;
damage to our equipment or violence directed at our employees, including kidnappings and piracy;
increased operating costs;
complications associated with repairing and replacing equipment in remote locations;
repudiation, modification or renegotiation of contracts, disputes and legal proceedings in international jurisdictions;
limitations on insurance coverage, such as war risk coverage in certain areas;
import-export quotas;
confiscatory taxation;
work stoppages or strikes, particularly in the West African labor environments;
unexpected changes in regulatory requirements;
wage and price controls;
imposition of trade barriers;
imposition or changes in enforcement of local content laws, particularly in West Africa and Southeast Asia, where the legislatures are active in developing new legislation;
restrictions on currency or capital repatriations;
currency fluctuations and devaluations; and
other forms of government regulation and economic conditions that are beyond our control.
Many governments favor or effectively require that liftboat or drilling contracts be awarded to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may result in inefficiencies or put us at a disadvantage when bidding for contracts against local competitors.
Our non-U.S. contract drilling and liftboat operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipment and operation of drilling rigs and liftboats, currency conversions and repatriation, oil and natural gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors, the ownership of assets by local citizens and companies, and duties on the importation and exportation of units and other equipment. Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and natural gas and other aspects of the oil and natural gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work

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done by major oil and natural gas companies and may continue to do so. Operations in developing countries can be subject to legal systems which are not as predictable as those in more developed countries, which can lead to greater risk and uncertainty in legal matters and proceedings.
Due to our international operations, we may experience currency exchange losses when revenue is received and expenses are paid in nonconvertible currencies or when we do not hedge an exposure to a foreign currency. We may also incur losses as a result of our inability to collect revenue because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital.

A small number of customers account for a significant portion of our revenue, and the loss of one or more of these customers could adversely affect our financial condition and results of operations.
In recent years there has been a significant consolidation in our customer base. Therefore, we derive a significant amount of our revenue from a few energy companies. Chevron Corporation and Saudi Aramco accounted for 17% and 6% of our revenue for the year ended December 31, 2012, respectively. Our financial condition and results of operations will be materially adversely affected if these customers interrupt or curtail their activities, terminate their contracts with us, fail to renew their existing contracts or refuse to award new contracts to us and we are unable to enter into contracts with new customers at comparable dayrates. The loss of either of these or any other significant customer could adversely affect our financial condition and results of operations.

We have contractual commitments related  to our investment in Discovery Offshore and may not realize the anticipated benefits from our investment.
We have committed substantial management time to our investment in Discovery Offshore S.A., a development-stage publicly traded Luxembourg limited liability company, and may not realize anticipated benefits of our investment.  Discovery Offshore was formed in 2011 for the purpose of owning two new-build ultra high specification harsh environment jackup drilling rigs, which are expected to be delivered in the second and fourth quarters of 2013.  The delivery of the rigs is dependent on Discovery Offshore's ability to raise additional capital for payment of the balance of the construction price. Pursuant to the Services Agreements with respect to each rig, after delivery we will provide marketing, management, crew and operational services in exchange for a fixed daily fee of $6,000 per rig plus five percent of rig-based EBITDA generated per day per rig.  If Discovery Offshore fails to obtain contracts for its rigs at favorable day rates, or experiences construction delays or cost increases, we may not realize anticipated fees under the Services Agreements. In addition to these risks, our investment in Discovery Offshore is subject to other risks associated with our business described herein, many of which are unpredictable and fluctuate based on events outside our control.
Our existing jackup rigs are at a relative disadvantage to higher specification rigs, which may be more likely to obtain contracts than lower specification jackup rigs such as ours.
Many of our competitors have jackup fleets with generally higher specification rigs than those in our jackup fleet. In addition, all of the new rigs under construction are of higher specification than our existing fleet. While Hercules has signed agreements to manage the construction and operations of the two ultra high specification harsh environment jackup drilling rigs on order for Discovery Offshore, 28 of our 37 jackup rigs are mat-supported, which are generally limited to geographic areas with soft bottom conditions like much of the Gulf of Mexico. Most of the rigs under construction are currently without contracts, which may intensify price competition as scheduled delivery dates occur. Particularly in periods in which there is decreased rig demand, higher specification rigs may be more likely to obtain contracts than lower specification jackup rigs such as ours. In the past, lower specification rigs have been stacked earlier in the cycle of decreased rig demand than higher specification rigs and have been reactivated later in the cycle, which may adversely impact our business. In addition, higher specification rigs may be more adaptable to different operating conditions and therefore have greater flexibility to move to areas of demand in response to changes in market conditions. Because a majority of our rigs were designed specifically for drilling in the shallow-water U.S. Gulf of Mexico, our ability to 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.
Acquisitions and integrating such acquisitions create certain risk and may affect our operating results.
We have completed acquisitions and will consider pursuing acquisitions (including the acquisition of individual rigs and liftboats) in order to continue to grow and increase profitability. However, acquisitions involve numerous risks and

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uncertainties, including intense competition for suitable acquisition targets, the potential unavailability of financial resources necessary to consummate acquisitions, difficulties in identifying suitable acquisition targets or in completing any transactions identified on sufficiently favorable terms.
In addition to the risks involved in identifying and completing acquisitions described above, even when acquisitions are completed, integration of acquired entities can involve significant difficulties, such as:
failure to achieve cost savings or other financial or operating objectives with respect to an acquisition;
uncertainties and delays relating to upgrades and refurbishments of newly-acquired rigs and liftboats;
inability to perform under drilling contracts due to various operational factors, including unscheduled repairs, maintenance, operational delays, health, safety and environmental incidents, weather events and our new customers seeking to cancel or renegotiate our contracts for various reasons;
strain on the operational and managerial controls of our business;
managing geographically separated organization, systems and facilities;
difficulties in the integration and retention of customers or personnel and the integration and effective deployment of operations or technologies;
assumption of unknown material liabilities or regulatory non-compliance issues;
possible adverse short-term effects on our cash flows or operating results; and
diversion of management's attention from the ongoing operations of our business.
Failure to manage these acquisition risks could have a material adverse effect on our results of operations, financial condition and cash flows. There can be no assurance that we will be able to consummate any acquisitions or expansions, successfully integrate acquired entities or assets, or generate positive cash flow at any acquired company or expansion project.
We may consider future acquisitions and may be unable to complete and finance future acquisitions on acceptable terms. In addition, we may fail to successfully integrate acquired assets or businesses we acquire or incorrectly predict operating results.
We may consider future acquisitions which could involve the payment by us of a substantial amount of cash, the incurrence of a substantial amount of debt or the issuance of a substantial amount of equity. Unless we have achieved specified financial covenant levels, our revolving credit facility restricts our ability to make acquisitions involving the payment of cash or the incurrence of debt. If we are restricted from using cash or incurring debt to fund a potential acquisition, we may not be able to issue, on terms we find acceptable, sufficient equity that may be required for any such permitted acquisition or investment. In addition, barring any restrictions under the revolving credit facility, we still may not be able to obtain, on terms we find acceptable, sufficient financing or funding that may be required for any such acquisition or investment.
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.
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 retain or attract skilled workers could hurt our operations.
We require skilled personnel to operate and provide technical services and support for our rigs and liftboats. The shortages of qualified personnel or the inability to obtain and retain qualified personnel could negatively affect the quality and timeliness of our work. In periods of economic crisis or during a recession, we may have difficulty attracting and retaining our skilled workers as these workers may seek employment in less cyclical or volatile industries or employers. In periods of recovery or increasing activity, we may have to increase the wages of our skilled workers, which could negatively impact our operations and financial results.

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Although our domestic employees are not covered by a collective bargaining agreement, the marine services industry has been targeted by maritime labor unions in an effort to organize U.S. Gulf of Mexico employees. A significant increase in the wages paid by competing employers or the unionization of our U.S. Gulf of Mexico employees could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.
Governmental laws and regulations, including those arising out of the Macondo well incident and those related to climate change and emissions of greenhouse gases, may add to our costs or limit drilling activity and liftboat operations.
Our operations are affected in varying degrees by governmental laws and regulations. We are also subject to the jurisdiction of the Coast Guard, the NTSB, the CBP, the Department of Interior, the BOEM and the BSEE, as well as private industry organizations such as the ABS. New laws, regulations and requirements imposed after the Macondo well incident may delay our operations and cause us to incur additional expenses in order for our rigs and operations in the U.S. Gulf of Mexico to be compliant with these new laws, regulations and requirements. These new laws, regulations and requirements and other potential changes in laws and regulations applicable to the offshore drilling industry in the U.S. Gulf of Mexico may also continue to prevent our customers from obtaining new drilling permits and approvals in a timely manner, if at all, which could materially adversely impact our business, financial position or results of operations. In addition, we may be required to make significant capital expenditures to comply with laws and the applicable regulations and standards of governmental authorities and organizations. Moreover, the cost of compliance could be higher than anticipated. Similarly, our international operations are subject to compliance with the FCPA, certain international conventions and the laws, regulations and standards of other foreign countries in which we operate. It is also possible that existing and proposed governmental conventions, laws, regulations and standards, including those related to climate change and emissions of greenhouse gases, may in the future add significantly to our operating costs or limit our activities or the activities and levels of capital spending by our customers.
In addition to the laws, regulations and requirements implemented since the Macondo incident, the federal government has considered additional new laws, regulations and requirements, including those that would have imposed additional equipment requirements and that relate to the protection of the environment, which would be applicable to the offshore drilling industry in the U.S. Gulf of Mexico. The federal government may again consider implementing new laws, regulations and requirements. The implementation of new, more restrictive laws and regulations could lead to substantially increased potential liability and operating costs for us and our customers, which could cause our customers to discontinue or delay operating in the U.S. Gulf of Mexico and/or redeploy capital to international locations. These actions, if taken by any of our customers, could result in underutilization of our U.S. Gulf of Mexico assets and have an adverse impact on our revenue, profitability and financial position.
In addition, as our vessels age, the costs of drydocking the vessels in order to comply with governmental laws and regulations and to maintain their class certifications are expected to increase, which could adversely affect our financial condition and results of operations.
Compliance with or a breach of environmental laws and regulations can be costly and could limit our operations.
Our operations are subject to federal, state, local and foreign and/or international laws and 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. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions restricting some or all of our activities in the affected areas. Laws and regulations protecting the environment have become more stringent in recent years, and may in some cases impose strict liability, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. Some of these laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. The application of these requirements, the modification of existing laws or regulations or the adoption of new requirements, both in U.S. waters and internationally, could have a material adverse effect on our financial condition and results of operations.
We may not be able to maintain or replace our rigs and liftboats as they age.
The capital associated with the repair and maintenance of our fleet increases with age. We may not be able to maintain our fleet by extending the economic life of existing rigs and liftboats, and our financial resources may not be sufficient to enable us to make expenditures necessary for these purposes or to acquire or build replacement units.

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Our operating and maintenance costs with respect to our rigs include fixed costs that will not decline in proportion to decreases in dayrates.
We do not expect our operating and maintenance costs with respect to our rigs to necessarily fluctuate in proportion to changes in operating revenue. Operating revenue may fluctuate as a function of changes in dayrate, but costs for operating a rig are generally fixed or only semi-variable regardless of the dayrate being earned. Additionally, if our rigs incur idle time between contracts, we typically do not de-man those rigs because we will use the crew to prepare the rig for its next contract. During times of reduced activity, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking, after which time the crew members are assigned to active rigs or dismissed. Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. In general, labor costs increase primarily due to higher salary levels and inflation. Equipment maintenance expenses fluctuate depending upon the type of activity the unit is performing and the age and condition of the equipment. Contract preparation expenses vary based on the scope and length of contract preparation required and the duration of the firm contractual period over which such expenditures are amortized.
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 also regularly make certain upgrades or modifications to our drilling rigs to meet customer or contract specific requirements. Upgrade, refurbishment and repair projects are subject to the risks of delay or cost overruns inherent in any large construction project, including costs or delays resulting from the following:
unexpectedly long delivery times for, or shortages of, key equipment, parts and materials;
shortages of skilled labor and other shipyard personnel necessary to perform the work;
unforeseen increases in the cost of equipment, labor and raw materials used for our rigs, particularly steel;
unforeseen design and engineering problems;
latent damages to or deterioration of hull, equipment and machinery in excess of engineering estimates and assumptions;
unanticipated actual or purported change orders;
work stoppages;
failure or delay of third-party service providers and labor disputes;
disputes with shipyards and suppliers;
delays and unexpected costs of incorporating parts and materials needed for the completion of projects;
failure or delay in obtaining acceptance of the rig from our customer;
financial or other difficulties at shipyards, including shipyard incidents that could increase the cost and delay the timing of projects;
adverse weather conditions; and
inability or delay in obtaining customer acceptance or flag-state, classification society, certificate of inspection, or regulatory approvals.
Significant cost overruns or delays would adversely affect our financial condition and results of operations. Additionally, capital expenditures for rig upgrade, reactivation and refurbishment projects could exceed our planned capital expenditures. Failure to complete an upgrade, reactivation, refurbishment or repair project on time may, in some circumstances, result in the delay, renegotiation or cancellation of a drilling or liftboat contract and could put at risk our planned arrangements to commence operations on schedule. We also could be exposed to penalties for failure to complete an upgrade, refurbishment or repair project and commence operations in a timely manner. Our rigs and liftboats undergoing upgrade, reactivation, refurbishment or repair generally do not earn a dayrate during the period they are out of service.
We are subject to litigation that could have an adverse effect on us.
We are from time to time involved in various litigation matters. The numerous operating hazards inherent in our business increase our exposure to litigation, including personal injury litigation brought against us by our employees that are injured operating our rigs and liftboats. These matters may include, among other things, contract dispute, personal injury,

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environmental, asbestos and other toxic tort, employment, tax and securities litigation, and litigation that arises in the ordinary course of our business. We have extensive litigation brought against us in federal and state courts located in Louisiana, Mississippi and South Texas, areas that were significantly impacted by hurricanes during the last several years and by the Macondo well blowout incident. The jury pools in these areas have become increasingly more hostile to defendants, particularly corporate defendants in the oil and gas industry. We cannot predict with certainty the outcome or effect of any claim or other litigation matter. Litigation may have an adverse effect on us because of potential negative outcomes, the costs associated with defending the lawsuits, the diversion of our management’s resources and other factors.
Our operations present hazards and risks that require significant and continuous oversight, and we depend upon the security and reliability of our technologies, systems and networks in numerous locations where we conduct business.
We continue to increase our dependence on digital technologies to conduct our operations, to collect monies from customers and to pay vendors and employees. In addition, we have outsourced certain information technology development, maintenance and support functions. As a result, we are exposed to cybersecurity risks at both our internal locations and outside vendor locations that could disrupt our operations for an extended period of time and result in the loss of critical data and in higher costs to correct and remedy the effects of such incidents, although no such material incidents have occurred to date. If our systems for protecting against information technology and cybersecurity risks prove to be insufficient, we could be adversely affected by having our business and financial systems compromised, our proprietary information altered, lost or stolen, or our business operations and safety procedures disrupted.
Changes in effective tax rates, taxation of our foreign subsidiaries, limitations on utilization of our net operating losses or adverse outcomes resulting from examination of our tax returns could adversely affect our operating results and financial results.
Our future effective tax rates could be adversely affected by changes in tax laws, both domestically and internationally. From time to time, Congress and foreign, state and local governments consider legislation that could increase our effective tax rates. We cannot determine whether, or in what form, legislation will ultimately be enacted or what the impact of any such legislation would be on our profitability. If these or other changes to tax laws are enacted, our profitability could be negatively impacted.
Our future effective tax rates could also be adversely affected by changes in the valuation of our deferred tax assets and liabilities, the ultimate repatriation of earnings from foreign subsidiaries to the United States, or by changes in tax treaties, regulations, accounting principles or interpretations thereof in one or more countries in which we operate. In addition, we are subject to the potential examination of our tax returns by the Internal Revenue Service and other tax authorities where we file tax returns. We regularly assess the likelihood of adverse outcomes resulting from these examinations to determine the adequacy of our provision for taxes. There can be no assurance that such examinations will not have an adverse effect on our operating results and financial condition.
Our business would be adversely affected if we failed to comply with the provisions of U.S. law on coastwise trade, or if those provisions were modified, repealed or waived.
We are subject to U.S. federal laws that restrict maritime transportation, including liftboat services, between points in the United States to vessels built and registered in the United States and owned and manned by U.S. citizens. We are responsible for monitoring the ownership of our common stock. If we do not comply with these restrictions, we would be prohibited from operating our liftboats in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our liftboats, fines or forfeiture of the liftboats.
During the past several years, interest groups have lobbied Congress to repeal these restrictions to facilitate foreign flag competition for trades currently reserved for U.S.-flag vessels under the federal laws. We believe that interest groups may continue efforts to modify or repeal these laws currently benefiting U.S.-flag vessels. If these efforts are successful, it could result in increased competition, which could adversely affect our results of operations.
Our liquidity depends upon cash on hand, cash from operations and availability under our revolving credit facility.
Our liquidity depends upon cash on hand, cash from operations and availability under our revolving credit facility. The availability under the $75 million revolving credit facility is to be used for working capital, capital expenditures and other general corporate purposes. All borrowings under the revolving credit facility mature on April 3, 2017. Except under certain conditions, the revolving credit facility requires interest-only payments on a quarterly basis until the maturity date. We intend to refinance the revolving credit facility before the revolving credit facility matures. No amounts were outstanding under the revolving credit facility as of December 31, 2012, although $1.0 million in letters of credit had been issued under it. The remaining availability under the revolving credit facility is $74.0 million at December 31, 2012.

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We currently maintain a shelf registration statement covering the future issuance from time to time of various types of securities, including debt and equity securities. We currently believe we will have adequate liquidity to fund our operations for the foreseeable future. However, to the extent we do not generate sufficient cash from operations, we may need to raise additional funds through public or private debt or equity offerings to fund operations and under the terms of our credit facility, we may be required to use the proceeds of any capital that we raise to repay existing indebtedness. Furthermore, we may need to raise additional funds through public or private debt or equity offerings or asset sales to avoid a breach of our financial covenants in our Credit Facility to refinance our indebtedness, to fund capital expenditures or for general corporate purposes.
We are a holding company, and we are dependent upon cash flow from subsidiaries to meet our obligations.
We currently conduct our operations through, and most of our assets are owned by, both U.S. and foreign subsidiaries, and our operating income and cash flow are generated by our subsidiaries. As a result, cash we obtain from our subsidiaries is the principal source of funds necessary to meet our debt service obligations. Contractual provisions or laws, as well as our subsidiaries’ financial condition and operating requirements, may limit our ability to obtain cash from our subsidiaries that we require to pay our debt service obligations. Applicable tax laws may also subject such payments to us by our subsidiaries to further taxation.
The inability of our subsidiaries to transfer cash to us may mean that, even though we may have sufficient resources on a consolidated basis to meet our obligations, we may not be permitted to make the necessary transfers from subsidiaries to the parent company in order to provide funds for the payment of the parent company’s obligations.
We limit foreign ownership of our company, which may restrict investment in our common stock and 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.
Our certificate of incorporation also provides that any transfer, or attempted or purported transfer, of any shares of our capital stock that would result in the ownership or control of in excess of 20% of our outstanding capital stock by one or more persons who are not United States citizens for purposes of U.S. coastwise shipping will be void and ineffective as against us. In addition, if at any time persons other than United States citizens own shares of our capital stock or possess voting power over any shares of our capital stock in excess of 20%, we may withhold payment of dividends, suspend the voting rights attributable to such shares and redeem such shares.
We have no plans to pay regular dividends on our common stock, so investors in our common stock may not receive funds without selling their shares.
We do not intend to declare or pay regular dividends on our common stock in the foreseeable future. Instead, we generally intend to invest any future earnings in our business. Subject to Delaware law, our board of directors will determine the payment of future dividends on our common stock, if any, and the amount of any dividends in light of any applicable contractual restrictions limiting our ability to pay dividends, our earnings and cash flows, our capital requirements, our financial condition, and other factors our board of directors deems relevant. Our Credit Agreement restricts our ability to pay dividends or other distributions on our equity securities. Accordingly, stockholders may have to sell some or all of their common stock in order to generate cash flow from their investment. Stockholders may not receive a gain on their investment when they sell our common stock and may lose the entire amount of their investment.
Provisions in our charter documents 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.


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Item 1B.    Unresolved Staff Comments
None.

Item 2.    Properties
Our property consists primarily of jackup rigs, barge rigs, liftboats and ancillary equipment, substantially all of which we own. The majority of our vessels and substantially all of our other personal property, are pledged to collateralize our credit facility and 7.125% Senior Secured Notes.
We maintain offices, maintenance facilities, yard facilities, warehouses, waterfront docks as well as residential premises in various countries, including the United States, Nigeria, Singapore, Saudi Arabia, United Arab Emirates, Indonesia and Bahrain. Almost all of these properties are leased. Our leased principal executive offices are located in Houston, Texas.
We incorporate by reference in response to this item the information set forth in Item 1 of this annual report.

Item 3.    Legal Proceedings

The Company is involved in various claims and lawsuits in the normal course of business. As of December 31, 2012, management did not believe any accruals were necessary in accordance with FASB ASC 450-20, Contingencies - Loss Contingencies.
Termination of FCPA Investigations
On April 4, 2011, we received a subpoena issued by the SEC requesting the delivery of certain documents to the SEC in connection with its investigation into possible violations of the securities laws, including possible violations of the FCPA in certain international jurisdictions where we conduct operations. We were also notified by the DOJ on April 5, 2011, that certain of our activities were under review by the DOJ.
On April 24, 2012, we received a letter from the DOJ notifying us that the DOJ had closed its inquiry into us regarding possible violations of the FCPA and did not intend to pursue enforcement action against us or impose any fines or penalties against us. Additionally, on August 7, 2012, we received a letter from the SEC notifying us that the SEC staff had completed its investigation into us regarding possible violations of the FCPA and did not intend to pursue enforcement action against us or impose any fines or penalties against us. As a result of these terminations by the SEC and the DOJ, there are no open FCPA investigations against us.
Shareholder Derivative Suits
Say-on-Pay Litigation
In June 2011, two separate shareholder derivative actions were filed purportedly on our behalf in response to our failure to receive a majority advisory “say-on-pay” vote in favor of our 2010 executive compensation. On June 8, 2011, the first action was filed in the District Court of Harris County, Texas, and on June 23, 2011, the second action was filed in the United States Court for the District of Delaware. Subsequently, on July 21, 2011, the plaintiff in the Harris County action filed a concurrent action in the United States District Court for the Southern District of Texas. Each action named us as a nominal defendant and certain of our officers and directors, as well as our Compensation Committee’s consultant, as defendants. Plaintiffs allege that our directors breached their fiduciary duty by approving excessive executive compensation for 2010, that the Compensation Committee consultant aided and abetted that breach of fiduciary duty, that the officer defendants were unjustly enriched by receiving the allegedly excessive compensation, and that the directors violated the federal securities laws by disseminating a materially false and misleading proxy. The plaintiffs seek damages in an unspecified amount on our behalf from the officer and director defendants, certain corporate governance actions, and an award of their costs and attorney’s fees. We and the other defendants have filed motions to dismiss these cases for failure to make demand upon our board and for failing to state a claim. Those motions are pending. On June 11, 2012, the plaintiff in the Harris County action voluntarily dismissed his action.
We do not expect the ultimate outcome of any of these shareholder derivative lawsuits to have a material adverse effect on our consolidated results of operations, financial position or cash flows.
We and our subsidiaries are involved in a number of other lawsuits, all of which have arisen in the ordinary course of our business. We do not believe that ultimate liability, if any, resulting from any such other pending litigation will have a material adverse effect on our business or consolidated financial statements.

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We cannot predict with certainty the outcome or effect of any of the litigation matters specifically described above or of any other pending litigation. There can be no assurance that our belief or expectations as to the outcome or effect of any lawsuit or other litigation matter will prove correct, and the eventual outcome of these matters could materially differ from our current estimates.

Item 4.    Mine Safety Disclosures
Not applicable.


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PART II
 
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Quarterly Common Stock Prices and Dividend Policy
Our common stock is traded on the NASDAQ Global Select Market under the symbol “HERO.” As of February 21, 2013, there were 130 stockholders of record. On February 21, 2013, the closing price of our common stock as reported by NASDAQ was $6.58 per share. The following table sets forth, for the periods indicated, the range of high and low sales prices for our common stock:
 
Price
 
High
 
Low
2012
 
 
 
Fourth Quarter
$6.30
 
$4.36
Third Quarter
5.03

 
3.22

Second Quarter
5.25

 
2.91

First Quarter
5.57

 
3.77

 
Price
 
High
 
Low
2011
 
 
 
Fourth Quarter
$4.58
 
$2.25
Third Quarter
5.60

 
2.90

Second Quarter
6.99

 
4.97

First Quarter
6.72

 
3.04


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 Credit Agreement as well as indentures governing the 7.125% Senior Secured Notes, 10.25% Senior Notes and 10.5% Senior Notes restrict our ability to pay dividends or other distributions on our equity securities.
Issuer Purchases of Equity Securities
During the three months ended December 31, 2012, we did not repurchase any shares of our securities.
Item 6.
Selected Financial Data
We have derived the following condensed consolidated financial information as of December 31, 2012 and 2011 and for the years ended December 31, 2012, 2011 and 2010 from our audited consolidated financial statements included in Item 8 of this report. The condensed consolidated financial information as of December 31, 2010 and for the year ended December 31, 2009 was derived from our audited consolidated financial statements included in Item 8 of our annual report on Form 10-K for the year ended December 31, 2011. The condensed consolidated financial information as of December 31, 2009 and for the year ended December 31, 2008 was derived from our audited consolidated financial statements included in Item 8 of our annual report on Form 10-K for the year ended December 31, 2010, as amended by our current report on Form 8-K filed on July 8, 2011. The condensed consolidated financial information as of December 31, 2008 was derived from our audited consolidated financial statements included in Item 8 of our annual report on Form 10-K for the year ended December 31, 2009.
We were formed in July 2004 and commenced operations in August 2004. From our formation to December 31, 2012, we completed our i) acquisition of 20 jackup rigs and related assets, accounts receivable, accounts payable and certain contractual rights from Seahawk Drilling, Inc. and certain of its subsidiaries ("Seahawk") ("Seahawk Transaction") on April 27, 2011; ii) acquisition of TODCO and iii) acquisition of several significant asset acquisitions. Our financial results reflect the impact of the Seahawk Transaction and various asset acquisitions from their respective dates of closing which impacts the comparability of our historical financial results presented in the tables below.

28


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 audited consolidated financial statements and related notes included in Item 8 of this annual report. In addition, the following information may not be deemed indicative of our future operations.
 
Year
Ended
December  31,
2012(a)
 
Year
Ended
December  31,
2011
 
Year
Ended
December  31,
2010(b)
 
Year
Ended
December  31,
2009(c)
 
Year
Ended
December  31,
2008(d)
 
(In thousands, except per share data)
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Revenue
$
709,792

 
$
655,358

 
$
624,827

 
$
718,601

 
$
1,053,479

Operating loss
(63,577
)
 
(18,749
)
 
(143,427
)
 
(79,469
)
 
(1,040,848
)
Loss from continuing operations
(127,004
)
 
(66,520
)
 
(132,093
)
 
(81,047
)
 
(997,893
)
Loss per share from continuing operations:
 
 
 
 
 
 
 
 
 
Basic and Diluted
$
(0.83
)
 
$
(0.51
)
 
$
(1.15
)
 
$
(0.83
)
 
$
(11.29
)
Balance Sheet Data (as of end of period):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
259,193

 
$
134,351

 
$
136,666

 
$
140,828

 
$
106,455

Working capital
217,184

 
174,598

 
182,276

 
144,813

 
224,785

Total assets
2,016,630

 
2,006,704

 
1,995,309

 
2,277,476

 
2,590,895

Long-term debt, net of current portion
798,013

 
818,146

 
853,166

 
856,755

 
1,015,764

Total stockholders’ equity
882,762

 
908,553

 
853,132

 
978,512

 
925,315

Cash dividends per share

 

 

 

 

 _____________________________
(a)
Includes $108.2 million ($82.7 million, net of taxes or $0.54 per diluted share) in asset impairment charges. In addition, 2012 includes an $18.4 million gain ($11.9 million, net of taxes or $0.08 per diluted share) on the sale of Platform Rig 3 as well as a $27.3 million gain ($17.7 million, net of taxes or $0.12 per diluted share) for the Hercules 185 insurance settlement.
(b)
Includes $122.7 million ($79.8 million, net of taxes or $0.69 per diluted share) in impairment of property and equipment charges.
(c)
Includes $26.9 million ($13.1 million, net of taxes or $0.13 per diluted share) of asset impairment charges. In addition, 2009 includes $31.6 million ($20.5 million, net of taxes or $0.21 per diluted share) related to an allowance for doubtful accounts receivable of approximately $26.8 million, associated with a customer in our International Offshore segment, a non-cash charge of approximately $7.3 million to fully impair the related deferred mobilization and contract preparation costs, partially offset by a $2.5 million reduction in previously accrued contract related operating costs that are not expected to be settled if the receivable is not collected.
(d)
Includes $863.6 million ($863.6 million, net of taxes or $9.77 per diluted share) and $376.7 million ($236.7 million, net of taxes or $2.68 per diluted share) in impairment of goodwill and impairment of property and equipment charges, respectively.
 
Year
Ended
December 31,
2012(a)
 
Year
Ended
December 31,
2011
 
Year
Ended
December 31,
2010
 
Year
Ended
December 31,
2009
 
Year
Ended
December 31,
2008(b)
 
(In thousands)
Other Financial Data:
 
 
 
 
 
 
 
 
 
Net cash provided by (used in):
 
 
 
 
 
 
 
 
 
Operating activities
$
68,363

 
$
52,025

 
$
24,420

 
$
137,861

 
$
269,727

Investing activities
(52,269
)
 
(32,520
)
 
(21,306
)
 
(60,510
)
 
(515,787
)
Financing activities
108,748

 
(21,820
)
 
(7,276
)
 
(42,978
)
 
140,063

Capital expenditures
167,180

 
39,483

 
22,018

 
76,141

 
585,084

Deferred drydocking expenditures
11,425

 
15,739

 
15,040

 
15,646

 
17,269

 

29


 _____________________________
(a)
2012 Capital expenditures includes the purchase of Hercules 266 as well as related equipment.
(b)
2008 Capital expenditures includes the purchase of Hercules 350, Hercules 262 and Hercules 261 as well as related equipment.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying consolidated financial statements as of December 31, 2012 and 2011 and for the years ended December 31, 2012, 2011 and 2010 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 are a leading provider of shallow-water drilling and marine services to the oil and natural gas exploration and production industry globally. We provide these services to national oil and gas companies, major integrated energy companies and independent oil and natural gas operators. As of February 21, 2013, we owned a fleet of 37 jackup rigs, thirteen barge rigs, 58 liftboat vessels and operated an additional five liftboat vessels owned by a third party. Our diverse fleet is capable of providing services such as oil and gas exploration and development drilling, well service, platform inspection, maintenance and decommissioning operations in several key shallow-water provinces around the world.
In March 2012, we acquired an offshore jackup drilling rig, Hercules 266, for $40.0 million. We entered into a three-year drilling contract with Saudi Aramco for the use of this rig with Saudi Aramco having an option to extend the term for an additional one-year period. This rig is currently undergoing upgrades and other contract specific refurbishments and we expect the rig to commence work under the contract in the second quarter of 2013.
During April 2012, the Kingfish, a 230 class liftboat, began its mobilization from the U.S. Gulf of Mexico to the Middle East, where it underwent upgrades prior to becoming reactivated. The vessel commenced work in November 2012.
During November 2012, the decision was made to reactivate one of our previously cold stacked rigs, Hercules 209. Hercules 209 is currently in the shipyard undergoing repairs and upgrades for reactivation and is expected to be available for work in the second quarter of 2013.
As of February 21, 2013, our business segments include the following:
Domestic Offshore — includes 29 jackup rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 85 to 350 feet. Nineteen of the jackup rigs are either under contract or available for contracts and ten are cold stacked.
International Offshore — includes eight jackup rigs outside of the U.S. Gulf of Mexico. We have three jackup rigs contracted offshore in Saudi Arabia, one jackup rig contracted offshore in Myanmar and one jackup rig contracted offshore in Cameroon. In addition, we have one jackup rig warm stacked and one jackup rig cold stacked in Bahrain as well as one jackup rig cold stacked in Malaysia. In addition to owning and operating our own rigs, we have the Construction Management Agreement and the Services Agreement with Discovery Offshore with respect to each of its two rigs.
Inland — includes a fleet of three conventional and ten posted barge rigs that operate inland in marshes, rivers, lakes and shallow bay or coastal waterways along the U.S. Gulf Coast. Three of our inland barges are either under contract or available and ten are cold stacked.
Domestic Liftboats — includes 39 liftboats in the U.S. Gulf of Mexico. Twenty-nine are operating or available for contracts and ten are cold stacked.
International Liftboats — includes 24 liftboats. Nineteen are operating or available for contracts offshore West Africa, including five liftboats owned by a third party, two are cold stacked offshore West Africa and three are operating or available for contracts in the Middle East region.
Our drilling rigs are used primarily for exploration and development drilling in shallow waters. Under most of our contracts, we are paid a fixed daily rental rate called a “dayrate,” and we are required to pay all costs associated with our own crews as well as the upkeep and insurance of the rig and equipment.
Our liftboats are self-propelled, self-elevating vessels with a large open deck space, which provides a versatile, mobile and stable platform to support a broad range of offshore maintenance and construction services throughout the life of an oil or natural gas well. Under most of our liftboat contracts, we are paid a fixed dayrate for the rental of the vessel, which typically

30


includes the costs of a small crew of four to eight employees, and we also receive a variable rate for reimbursement of other operating costs such as catering, fuel, rental equipment, crane overtime and other items.
Our revenue is affected primarily by dayrates, fleet utilization, the number and type of units in our fleet and mobilization fees received from our customers. 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. Most of our international drilling contracts and some of our international liftboat contracts are longer term in nature.
Our operating costs are primarily a function of fleet configuration and utilization levels. The most significant direct operating costs for our Domestic Offshore, International Offshore and Inland segments are wages paid to crews, maintenance and repairs to the rigs, and insurance. These costs do not vary significantly whether the rig is operating under contract or idle, unless we believe that the rig is unlikely to work for a prolonged period of time, in which case we may decide to “cold stack” or “warm stack” the rig. Cold stacking is a common term used to describe a rig that is expected to be idle for a protracted period and typically for which routine maintenance is suspended and the crews are either redeployed or laid-off. When a rig is cold stacked, operating expenses for the rig are significantly reduced because the crew is smaller and maintenance activities are suspended. Placing rigs in service that have been cold stacked typically requires a lengthy reactivation project that can involve significant expenditures and potentially additional regulatory review, particularly if the rig has been cold stacked for a long period of time. Warm stacking is a term used for a rig expected to be idle for a period of time that is not as prolonged as is the case with a cold stacked rig. Maintenance is continued for warm stacked rigs. Crews are reduced but a small crew is retained. Warm stacked rigs generally can be reactivated in three to four weeks.
The most significant costs for our Domestic Liftboats and International Liftboats segments are the wages paid to crews and the amortization of regulatory drydocking costs. Unlike our Domestic Offshore, International Offshore and Inland segments, a significant portion of the expenses incurred with operating each liftboat are paid for or reimbursed by the customer under contractual terms and prices. This includes catering, fuel, oil, rental equipment, crane overtime and other items. We record reimbursements from customers as revenue and the related expenses as operating costs. Our liftboats are required to undergo regulatory inspections every year and to be drydocked two times every five years; the drydocking expenses and length of time in drydock vary depending on the condition of the vessel. All costs associated with regulatory inspections, including related drydocking costs, are deferred and amortized over a period of twelve months.
Insurance Claims Settlement
In September 2011, we were conducting a required annual spud can inspection on Hercules 185 in protected waters offshore Angola. While conducting the inspection, it was determined that the spud can on the starboard leg had detached from the leg. Subsequently, additional leg damage was identified. The rig underwent repairs related to this damage and was mobilized back to Angola. During the return mobilization from the U.S. Gulf of Mexico to Angola, Hercules 185 experienced additional damage to its legs. We conducted a survey of the rig's legs above and below the water line and discovered extensive damage to various portions of the rig's legs. In June 2012, we determined that it was unfeasible to repair the damage and return the rig to service and recorded an impairment charge to write the rig down to salvage value. We and our insurance underwriters reached a global settlement in September 2012, agreeing that Hercules 185 should be considered a constructive total loss. From this settlement, we received total insurance proceeds of $41.0 million for the rig, including $7.5 million received in June 2012 for its earlier claim relating to previous leg damage to the rig. These proceeds generated a gain on insurance settlement of $27.3 million which is included in Operating Expenses on the Consolidated Statements of Operations for the year ended December 31, 2012. As part of the settlement, we agreed to transport and attempt to sell the rig, which entitled us to the first $1.5 million in proceeds from such sale and any sale proceeds in excess of $1.5 million being split seventy-five percent to the underwriters and twenty-five percent to us.
Dispositions and Impairment
In April 2012, during the return mobilization from the U.S. Gulf of Mexico to Angola, Hercules 185 experienced extensive damage to various portions of the rig's legs. We believed it was unfeasible to repair the damage and return the rig to service and recorded an impairment charge of $42.9 million ($27.9 million, net of tax) which is included in Asset Impairment on the Consolidated Statements of Operations for the year ended December 31, 2012 to write the rig down to salvage value.
In August 2012, we sold the Platform Rig 3 and related legal entities for aggregate consideration of approximately $36 million, consisting of a base purchase price of $28 million, as adjusted for net working capital and recorded a gain of $18.4 million which is included in Operating Expenses on the Consolidated Statements of Operations for the year ended December 31, 2012.

31


In October 2012, we sold Hercules 252 for gross proceeds of $8.0 million. The Consolidated Statements of Operations for the year ended December 31, 2012 include an impairment charge of approximately $25.5 million ($16.6 million, net of tax), related to the write-down of Hercules 252 to fair value less estimated cost to sell.
In September 2012, we made the decision to cold stack Hercules 258 effective October 1, 2012 and removed it from our marketable assets into our non-marketable assets as we do not reasonably expect to market this rig in the foreseeable future. This decision resulted in an impairment charge of approximately $35.2 million ($35.2 million, net of tax), which is included in Asset Impairment on the Consolidated Statements of Operations for the year ended December 31, 2012, to write the rig down to salvage value based on a third party estimate. The financial information for Hercules 258 has been reported as part of the International Offshore segment.
Termination of Foreign Corrupt Practices Act Investigations
On April 4, 2011, we received a subpoena issued by the Securities and Exchange Commission (“SEC”) requesting the delivery of certain documents to the SEC in connection with its investigation into possible violations of the securities laws, including possible violations of the Foreign Corrupt Practices Act (“FCPA”) in certain international jurisdictions where we conduct operations. We were also notified by the Department of Justice (“DOJ”) on April 5, 2011, that certain of our activities were under review by the DOJ.
On April 24, 2012, we received a letter from the DOJ notifying us that the DOJ had closed its inquiry into us regarding possible violations of the FCPA and did not intend to pursue enforcement action against us or impose any fines or penalties against us. Additionally, on August 7, 2012, we received a letter from the SEC notifying us that the SEC staff had completed its investigation into us regarding possible violations of the FCPA and did not intend to pursue enforcement action against us or impose any fines or penalties against us. As a result of these terminations by the SEC and the DOJ, there are no open FCPA investigations against us.
Common Stock Offering
In March 2012, we raised approximately $96.7 million in net proceeds, after adjusting for underwriting discounts and offering expenses, from an underwritten public offering of 20.0 million shares of common stock, par value $0.01 per share at a price to the public of $5.10 per share ($4.86, net of underwriting discounts). We used a portion of the net proceeds from the share offering to fund a portion of the purchase price for the acquisition of Hercules 266 and will use the remaining net proceeds for general corporate purposes as well as the costs associated with the upgrade and mobilization of Hercules 266.

RECENT DEVELOPMENTS
Effective April 27, 2011 we completed the Seahawk Transaction. Our financial statements accounted for the Seahawk Transaction as a business combination and accordingly, the total consideration was allocated to Seahawk's net tangible assets based on their estimated fair values. Our financial statements have been prepared assuming the same characterization applies for income tax purposes, based on the facts in existence through December 31, 2012. Seahawk is in a Chapter 11 proceeding in the U.S. Bankruptcy Court. In February 2013, at the direction of the Court, Seahawk made certain distributions to its equity holders. These distributions, taken together with other aspects of the acquisition, will change the tax treatment and will cause the Seahawk Transaction to be characterized as a reorganization pursuant to IRC §368(a)(1)(G). Therefore, for tax purposes we will record a carryover basis in the Seahawk assets and other tax attributes. Because of the ownership change certain of these carryovers may be subject to specific and in some cases an annual limitation on their utilization. In these instances, we will recognize valuation allowances as appropriate. These carryover attributes include net operating losses of $187 million, tax credits of $17 million, and tax basis in assets of $70 million. Based on our current tax position, these will produce additional deferred tax assets of approximately $35 million (gross additional deferred tax assets of $56 million offset by valuation allowances of $21 million). These tax attributes will be recorded in our financial statements in the first quarter of 2013 based on the effective date of the equity distribution. There can be no assurance that these deferred tax assets will be realized.
In February 2013, we entered into a definitive agreement to acquire the offshore drilling rig Ben Avon from a subsidiary of KCA Deutag. The purchase price was $55.0 million in cash and we expect the acquisition to close in late March 2013. In addition, we signed a three-year rig commitment with Cabinda Gulf Oil Company Limited for use of the Ben Avon. We expect the rig to commence work in the second quarter of 2013.
In February 2013, we entered into a definitive agreement to acquire the liftboat Titan 2, a 280 class vessel, from a subsidiary of KS Energy Ltd. The purchase price was $42.0 million in cash and we expect the acquisition to close in early March 2013. The liftboat is currently located in Limbe, Cameroon. In addition, we signed a Letter of Intent for a short term commitment to use the Titan 2 and we expect the vessel to commence work shortly after the acquisition closes.


32


RESULTS OF OPERATIONS
Generally, domestic drilling industry conditions improved in 2012, as the marketed supply of jackup rigs was further diminished and demand increased for our jackup rigs. Factors that led to the increase in demand included the relatively high price of crude oil and the shift by operators to liquids-rich drilling activities. Furthermore, during 2012 our Domestic Offshore segment benefited from the full-year addition of the rigs acquired in the Seahawk Transaction, which we completed on April 27, 2011. The results of the Seahawk Transaction are included in our results from the date of acquisition which impacts the comparability of the 2012 period with the corresponding 2011 and 2010 periods.
Our International Offshore segment experienced weaker results due primarily to contract expiration on the international rig fleet during the prior year. While the majority of our international rigs were recontracted, market dayrates were significantly below prior contract dayrates.
Our Domestic Liftboat performance strengthened in 2012, primarily due to our efforts to negotiate higher dayrates across each vessel class. Our domestic liftboat operations are generally affected by the seasonal weather patterns in the U.S. Gulf of Mexico. These seasonal patterns may result in increased activity in the spring, summer and fall periods and a decrease in the winter months. High winds, significant rain, tropical storms, hurricanes and other inclement weather conditions prevalent in the U.S. Gulf of Mexico during the year affect our domestic liftboat operations, as these conditions typically require our liftboats to leave work locations and cease to earn a full dayrate. The liftboats cannot return to the location until the weather improves and the seas are less than U.S. Coast Guard approved limits. Demand for our domestic rigs may decline during hurricane season, which is generally considered June 1 through November 30, as our customers may reduce drilling activity. Accordingly, our operating results may vary from quarter to quarter, depending on factors outside of our control.
Our International Liftboat performance strengthened in 2012, primarily due to increases in dayrates, partially offset by higher repairs and maintenance and labor costs.



33


The following table sets forth financial information by operating segment and other selected information for the periods indicated:
 
Year Ended December 31,
 
 
 
 
 
2012
 
2011
 
Change
 
% Change
 
(Dollars in thousands)
Domestic Offshore:
 
 
 
 
 
 
 
Number of rigs (as of end of period)
29

 
38

 
 
 
 
Revenue
$
355,762

 
$
217,450

 
$
138,312

 
63.6
 %
Operating expenses
238,674

 
186,132

 
52,542

 
28.2
 %
Asset impairment
25,502

 

 
25,502

 
n/m

Depreciation and amortization expense
72,938

 
68,146

 
4,792

 
7.0
 %
General and administrative expenses
8,130

 
9,275

 
(1,145
)
 
(12.3
)%
Operating income (loss)
$
10,518

 
$
(46,103
)
 
56,621

 
n/m

International Offshore:
 
 
 
 
 
 
 
Number of rigs (as of end of period)
8

 
9

 
 
 
 
Revenue
$
135,047

 
$
237,047

 
$
(102,000
)
 
(43.0
)%
Operating expenses
66,144

 
134,439

 
(68,295
)
 
(50.8
)%
Asset impairment
82,714

 

 
82,714

 
n/m

Depreciation and amortization expense
45,577

 
52,278

 
(6,701
)
 
(12.8
)%
General and administrative expenses
(183
)
 
(7,512
)
 
7,329

 
(97.6
)%
Operating income (loss)
$
(59,205
)
 
$
57,842

 
(117,047
)
 
n/m

Inland:
 
 
 
 
 
 
 
Number of barges (as of end of period)
14

 
17

 
 
 
 
Revenue
$
28,015

 
$
28,180

 
$
(165
)
 
(0.6
)%
Operating expenses
26,175

 
22,973

 
3,202

 
13.9
 %
Depreciation and amortization expense
12,842

 
14,589

 
(1,747
)
 
(12.0
)%
General and administrative expenses
652

 
1,388

 
(736
)
 
(53.0
)%
Operating loss
$
(11,654
)
 
$
(10,770
)
 
(884
)
 
8.2
 %
Domestic Liftboats:
 
 
 
 
 
 
 
Number of liftboats (as of end of period)
39

 
40

 


 


Revenue
$
63,832

 
$
56,575

 
7,257

 
12.8
 %
Operating expenses
40,050

 
42,381

 
(2,331
)
 
(5.5
)%
Depreciation and amortization expense
15,524

 
15,329

 
195

 
1.3
 %
General and administrative expenses
2,680

 
2,190

 
490

 
22.4
 %
Operating income (loss)
$
5,578

 
$
(3,325
)
 
8,903

 
n/m


34


 
Year Ended December 31,
 
 
 
 
 
2012
 
2011
 
Change
 
% Change
 
(Dollars in thousands)
International Liftboats:
 
 
 
 
 
 
 
Number of liftboats (as of end of period)
24

 
24

 
 
 
 
Revenue
$
127,136

 
$
116,106

 
$
11,030

 
9.5
 %
Operating expenses
67,041

 
58,407

 
8,634

 
14.8
 %
Depreciation and amortization expense
16,896

 
19,624

 
(2,728
)
 
(13.9
)%
General and administrative expenses
4,588

 
7,166

 
(2,578
)
 
(36.0
)%
Operating income
$
38,611

 
$
30,909

 
7,702

 
24.9
 %
Total Company:
 
 
 
 
 
 
 
Revenue
$
709,792

 
$
655,358

 
$
54,434

 
8.3
 %
Operating expenses
438,084

 
444,332

 
(6,248
)
 
(1.4
)%
Asset impairment
108,216

 

 
108,216

 
n/m

Depreciation and amortization expense
166,426

 
172,571

 
(6,145
)
 
(3.6
)%
General and administrative expenses
60,643

 
57,204

 
3,439

 
6.0
 %
Operating loss
(63,577
)
 
(18,749
)
 
(44,828
)
 
239.1
 %
Interest expense
(79,172
)
 
(79,178
)
 
6

 
 %
Loss on extinguishment of debt
(9,156
)
 

 
(9,156
)
 
n/m

Other, net
1,896

 
(3,934
)
 
5,830

 
n/m

Loss before income taxes
(150,009
)
 
(101,861
)
 
(48,148
)
 
47.3
 %
Income tax benefit
23,005

 
35,341

 
(12,336
)
 
(34.9
)%
Loss from continuing operations
(127,004
)
 
(66,520
)
 
(60,484
)
 
90.9
 %
Loss from discontinued operations, net of taxes

 
(9,608
)
 
9,608

 
n/m

Net loss
$
(127,004
)
 
$
(76,128
)
 
$
(50,876
)
 
66.8
 %
  _____________________________
"n/m" means not meaningful.

The following table sets forth selected operational data by operating segment for the periods indicated:
 
Year Ended December 31, 2012
 
Operating
Days
 
Available
Days
 
Utilization(1)
 
Average
Revenue
per Day(2)
 
Average
Operating
Expense
per Day(3)
Domestic Offshore
5,760

 
6,588

 
87.4
%
 
$
61,764

 
$
36,229

International Offshore
1,331

 
2,336

 
57.0
%
 
101,463

 
28,315

Inland
880

 
1,098

 
80.1
%
 
31,835

 
23,839

Domestic Liftboats
7,315

 
11,941

 
61.3
%
 
8,726

 
3,354

International Liftboats
5,367

 
7,562

 
71.0
%
 
23,688

 
8,866