10-K

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Accelerated filer o

Non-accelerated filer o

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10-K 1 a1231201510-k.htm 10-K 10-K

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

Commission file number: 001-37623

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 Market

Securities registered pursuant to Section 12(g) of the Act:

Title of Class

Warrants to Purchase Common Stock

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 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.

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, 2015, based on the closing price on the NASDAQ Global Select Market on such date, was approximately $36 million. As of such date, the registrant’s directors and executive officers were considered affiliates of the registrant for this purpose.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

Yes þ No ¨

As of March 24, 2016, there were 19,988,898 shares of the registrant’s common stock, par value $0.01 per share, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None.

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TABLE OF CONTENTS



		Page
	PART I
Item 1.	Business	1
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	27
Item 2.	Properties	27
Item 3.	Legal Proceedings	27
Item 4.	Mine Safety Disclosures	28

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
Item 6.	Selected Financial Data	31
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
	Forward-Looking Statements	60
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	61
Item 8.	Financial Statements and Supplementary Data	62
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	110
Item 9A.	Controls and Procedures	110
Item 9B.	Other Information	110

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	111
Item 11.	Executive Compensation	111
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	111
Item 13.	Certain Relationships and Related Transactions, and Director Independence	111
Item 14.	Principal Accountant Fees and Services	111

	PART IV
Item 15.	Exhibits, Financial Statement Schedules	111

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PART I

Item 1. Business

In this Annual Report on Form 10-K, we refer to Hercules Offshore, Inc. and its subsidiaries as “we,” the “Company” or “Hercules Offshore,” unless the context clearly indicates otherwise. Hercules Offshore, Inc. is a Delaware corporation formed in July 2004, with its principal executive offices located at 9 Greenway Plaza, Suite 2200, Houston, Texas 77046. Hercules Offshore’s telephone number at such address is (713) 350-5100 and our Internet address is www.herculesoffshore.com.

Overview

We 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 March 23, 2016, we operated a fleet of 27 jackup rigs (18 marketed, 9 cold stacked), including one rig under construction, and 19 liftboat vessels (18 marketed, 1 cold stacked). 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.

Recent Developments

We recently announced the formation of a special committee (the "Special Committee") comprised of all the independent members of our Board of Directors (the "Board") to consider and explore various strategic alternatives potentially available to us in order to maximize our value. The formation of the Special Committee is not in response to any proposal we have received or an approach by a third party.

The Special Committee is authorized to explore, review, and evaluate any potential strategic transaction and any alternatives thereto, including, but not limited to, the sale of the Company, a merger or share exchange involving the Company, the sale of some or all of the Company's assets, and a recapitalization of the Company (whether by issuance of equity or debt securities, incurrence of additional indebtedness, or issuance of derivative securities thereof). No decision has been made to engage in any particular transaction or transactions. There can be no assurance that the Special Committee or the Board will authorize the pursuit of any strategic alternative. Moreover, there can be no assurance with respect to the terms or the timing of any transaction, or whether any transaction will ultimately occur. Any potential transaction would be dependent upon a number of factors that may be beyond our control, including, among other factors, market conditions, industry trends, the interest of third parties in our business and the availability of financing to potential buyers on reasonable terms.

There can be no assurance that the process of reviewing strategic alternatives will not have an adverse impact on our business. Current market conditions, including commodity prices, are unfavorable for our business and may constrain our ability to move forward with any possible acquisitions or other strategic alternatives. There can be no assurances that we will be able to identify or complete any strategic transactions on commercially reasonable terms or at all, or that any such transaction would be favorable to our stockholders or lenders, or our business. Any such transaction would result in potential changes to our current business strategy and future operations and prospects. If we determine to pursue an alternative strategy or engage in a strategic transaction, our future business, prospects, financial position and operating results would likely be significantly different than those in historical periods or projected by our management. Additionally, any transaction we consummate may offer limited value for our stockholders and may not enhance stockholder value or provide the expected benefits.

Emergence from Voluntary Reorganization Under Chapter 11 Proceedings

On August 13, 2015 (the "Petition Date"), Hercules Offshore, Inc. and certain of its U.S. domestic direct and indirect subsidiaries (together with Hercules Offshore, Inc., the "Debtors") filed voluntary petitions (the "Bankruptcy Petitions") for reorganization ("Chapter 11 Cases") under Chapter 11 of the United States Bankruptcy Code (the "Bankruptcy Code") in the United States Bankruptcy Court for the District of Delaware (the "Court"). Through the Chapter 11 Cases, the Debtors implemented the pre-packaged plan of reorganization in accordance with the restructuring support agreement that the Debtors entered into with the Steering Group Members on June 17, 2015. The Chapter 11 Cases were jointly administered under the caption In re: Hercules Offshore, Inc., et al (Case No. 15-11685). The Company's foreign subsidiaries and one U.S. domestic subsidiary ("Non-Filing Entities") were not party to the Bankruptcy filing. After the petition date, the Debtors operated their business as "debtors-in-possession" under the jurisdiction of the Court and in accordance with applicable provisions of the Bankruptcy Code and orders of the Court until their emergence on November 6, 2015 from bankruptcy (See the information set forth in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview). The Non-Filing Entities continued to operate in the ordinary course of business.

Fresh-Start Accounting

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“Reorganizations” (“ASC 852”), which resulted in Hercules becoming a new entity for financial reporting purposes. As a result of the adoption of fresh-start reporting and the effects of the implementation of the pre-packaged plan of reorganization, our consolidated balance sheets and consolidated statements of operations subsequent to November 6, 2015 will not be comparable to our consolidated balance sheets and consolidated statements of operations prior to November 6, 2015.

References to “Successor” or “Successor Company” relate to Hercules on and subsequent to November 6, 2015. References to “Predecessor” or “Predecessor Company” refer to Hercules on and prior to November 6, 2015.

Drilling Contract Award and Rig Construction Contract

In May 2014, we signed a five-year drilling contract with Maersk Oil North Sea UK Limited ("Maersk") for a newbuild jackup rig, Hercules Highlander, that we will own and operate. Contract commencement is expected in mid-2016. In support of the drilling contract, in May 2014, we signed a rig construction contract with Jurong Shipyard Pte Ltd ("JSL") in Singapore. This High Specification, Harsh Environment (HSHE) newbuild rig is based on the Friede & Goldman JU-2000E design, with a 400 foot water depth rating and enhancements that will provide for greater load-bearing capabilities and operational flexibility. The shipyard cost of the rig is estimated at approximately $236 million. Including project management, spares, commissioning and other costs, total delivery cost is estimated at approximately $270 million, of which approximately $211 million remains to be spent at December 31, 2015. The total delivery cost estimate excludes any customer specific outfitting that is reimbursable to us, costs to mobilize the rig to the first well, as well as capitalized interest. We paid $23.6 million, or 10% of the shipyard cost, to JSL in May 2014 and made a second 10% payment in May 2015 with the final 80% of the shipyard payment due upon delivery of the rig, which is expected to be in the second quarter of 2016. $200.0 million of the proceeds from the Senior Secured Credit Facility were placed in an escrow account and are included in Restricted Cash on the Consolidated Balance Sheet as of December 31, 2015 to be used to finance the remaining installment payment on the Hercules Highlander and the expenses, costs and charges related to the construction and purchase of the Hercules Highlander.

Dayrate Reductions

On February 25, 2015, we received a notice from Saudi Arabian Oil Company ("Saudi Aramco") terminating for convenience our drilling contract for the Hercules 261, effective on or about March 27, 2015. We received subsequent notices from Saudi Aramco extending the effective date of termination to May 31, 2015. On June 1, 2015, we received notice from Saudi Aramco reinstating the drilling contract on the Hercules 261, in exchange for dayrate concessions on the Hercules 261, Hercules 262 and Hercules 266 from their existing contracted rates to $67,000 per day. These reduced dayrates were effective retroactively from January 1, 2015 through December 31, 2016 for the Hercules 261 and Hercules 262, and through the remaining contract term for the Hercules 266. However, on March 9, 2016, we received a notice from Saudi Aramco further reducing the dayrates under the contracts for the Hercules 261 and Hercules 262 from $67,000 per day to $63,650 per day. The reduced dayrates will apply retroactively from January 1, 2016, through December 31, 2016. The dayrate for the Hercules 266 was also reduced from $67,000 per day to $63,650 per day effective January 1, 2016, through the remaining term of its contract, or April 7, 2016.

Asset Dispositions

During 2015, we sold six rigs, Hercules 85, Hercules 153, Hercules 203, Hercules 206, Hercules 207 and Hercules 211, for gross proceeds of $4.5 million and recorded a net loss on the sales of $5.5 million for the year ended December 31, 2015.

Our Segments and Fleet

As of March 23, 2016, our business segments were Domestic Offshore, International Offshore, and International Liftboats, which included 18 jackup rigs, nine jackup rigs (including one jackup rig under construction) and 19 liftboats, respectively. Additionally in our International Offshore segment, we have an agreement with Perisai Drilling Sdn Bhd ("Perisai") whereby we agreed to market, manage and operate two Pacific Class 400 design new-build jackup drilling rigs, Perisai Pacific 101 and Perisai Pacific 102 ("Perisai Agreement"). In August 2014, Perisai Pacific 101 commenced work on a three-year drilling contract in Malaysia. Perisai Pacific 102 was scheduled to be delivered by the shipyard by mid-2015, but delivery has not yet occurred. It is our understanding that Perisai is in discussions with the shipyard to further delay delivery of the rig.

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. 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

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liftboat contracts, we receive a variable rate for reimbursement of costs such as catering, oil, rental equipment 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. Seventeen of our jackup rigs are mat-supported and ten are independent leg rigs.

Twenty-five 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. Two 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 March 23, 2016, seven of our jackup rigs were under contract ranging in duration from well-to-well to five 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.

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The following table contains information regarding our jackup rig fleet as of March 23, 2016.

Rig Name

Type

Year

Built/

Upgraded (a)

Maximum/

Minimum

Water Depth

Rating

Rated

Drilling

Depth (b)

Location

Status(c)

(Feet)

Hercules 120

1958/1985

120/22

15,000

U.S. GOM

Cold Stacked

Hercules 150

ILC

1979

150/10

20,000

U.S. GOM

Warm Stacked

Hercules 173

1971

173/22

15,000

U.S. GOM

Warm Stacked

Hercules 200

1979

200/23

20,000

U.S. GOM

Cold Stacked

Hercules 201

1981

200/23

20,000

U.S. GOM

Warm Stacked

Hercules 202

1981

200/23

20,000

U.S. GOM

Cold Stacked

Hercules 204

1981

200/23

20,000

U.S. GOM

Cold Stacked

Hercules 205

1979/2003

200/23

20,000

U.S. GOM

Contracted

Hercules 208 (d)

1980/2008

200/22

20,000

Malaysia

Warm Stacked

Hercules 209

1981/2013

200/23

20,000

U.S. GOM

Warm Stacked

Hercules 212

1982

200/23

20,000

U.S. GOM

Cold Stacked

Hercules 213

1981/2002

200/23

20,000

U.S. GOM

Cold Stacked

Hercules 214

1982

200/23

20,000

U.S. GOM

Cold Stacked

Hercules 251

1978

250/24

20,000

U.S. GOM

Cold Stacked

Hercules 253

1982

250/24

20,000

U.S. GOM

Cold Stacked

Hercules 260

ILC

1979/2008

150/12

20,000

Congo

Contracted

Hercules 261

ILC

1979/2008

250/15

20,000

Saudi Arabia

Contracted

Hercules 262

ILC

1982/2008

250/15

20,000

Saudi Arabia

Contracted

Hercules 263

1982/2002

250/23

20,000

U.S. GOM

Warm Stacked

Hercules 264

1976/1998

250/23

25,000

U.S. GOM

Ready Stacked

Hercules 266

ILC

1978/2013

250/15

20,000

Saudi Arabia

Contracted

Hercules 267

ILC

1980/2006

250/15

20,000

Gabon

Warm Stacked

Hercules 300

1974/2000

300/25

20,000

U.S. GOM

Contracted

Hercules 350

ILC

1982

350/16

25,000

U.S. GOM

Ready Stacked

Hercules Resilience

ILC

2013

400/25

35,000

Gabon

Ready Stacked

Hercules Triumph

ILC

2013

400/25

35,000

Netherlands

Ready Stacked

Hercules Highlander

ILC

(e)

400/30

30,000

Singapore

(e)

_____________________________


(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 generally 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 while rigs described as "Ready Stacked" are not under contract, but generally are ready for service. 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, while 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.


(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)	Rig is currently under construction with an expected delivery in the second quarter of 2016 and contract commencement is expected in mid-2016.

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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;


•	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. Liftboats are typically moved to a port during severe weather to avoid the winds and waves they would be exposed to in open water.

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As of March 23, 2016, we owned 16 liftboats operating in West Africa and three liftboats operating in the Middle East. The following table contains information regarding the liftboats we operated as of March 23, 2016.



Liftboat Name (1)	Year Built/ Upgraded (2)	Leg Length (4)	Deck Area Total	Maximum Deck Load	Location	Gross Registered Tonnage
		(Feet)	(Square feet)	(Pounds)
Bull Ray	2008	280	11,000	1,000,000	Nigeria	2,559
Whale Shark (5)	2005/2009	260	8,170	1,010,000	U.A.E.	1,142
Tiger Shark (5)	2001	227	5,300	1,259,000	Nigeria	1,403
Kingfish	1996/2012	233	5,000	800,000	U.A.E	1,312
Blue Shark	1981	219	3,800	400,000	Nigeria	1,182
Amberjack (5)	1981	207	3,800	400,000	U.A.E.	417
Creole Fish	2001	200	5,000	798,000	Nigeria	761
Cutlassfish	2006	197	5,000	508,000	Nigeria	761
Black Jack	1997/2008	200	4,000	358,000	Nigeria	777
Oilfish (5)	1996	170	3,200	400,000	Nigeria	465
Bluefish	1984	150	2,600	200,000	Nigeria	407
Pilot Fish	1990	145	2,400	175,000	Nigeria	310
Rudderfish	1991	145	3,000	200,000	Nigeria	310
Scamp	1984	130	2,400	150,000	Nigeria	280
Solefish	1978	120	2,000	100,000	Nigeria	229
Triggerfish	1980	120	2,000	100,000	Nigeria	210
Bonefish (3)	1978	105	1,009	110,000	Nigeria	97
Gemfish	1978	105	2,000	100,000	Nigeria	223
Tapertail	1979	105	1,392	110,000	Nigeria	100

_____________________________


(1)	Names as printed on Flag registry document. All vessels are Nigeria, Panama, or Vanuatu Flag.


(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)	The Bonefish is currently cold stacked. All other liftboats are either available or operating.


(4)	Leg length measured from bottom of pad to top of the leg end cap.


(5)	Maximum deck load applicable at limited water depths.

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Competition

The shallow-water businesses in which we operate are highly competitive. Domestic drilling contracts are traditionally short term in nature, although we have in the past been awarded longer term domestic drilling contracts. 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. 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 from continuing operations in any of the past three years are as follows:



	Successor		Predecessor
	Period from November 6, 2015 to December 31, 2015		Period from January 1, 2015 to November 6, 2015		Year Ended December 31,
	Period from November 6, 2015 to December 31, 2015		Period from January 1, 2015 to November 6, 2015		2014		2013
Saudi Aramco (a)	34	%	21	%	12	%	12	%
Chevron Corporation (b)	10		19		15		15
Arena Energy (c)	10		16		10		5
Eni (d)	15		7		—		—
Linder Oil Company (c)	12		4		—		—
Cairn Energy (a)	—		3		11		2
Energy XXI (c) (e)	8		1		14		10

_____________________________


(a)	Revenue included in our International Offshore segment.


(b)	Revenue included in our Domestic Offshore, International Offshore and International Liftboats segments.


(c)	Revenue included in our Domestic Offshore segment.


(d)	Revenue included in our International Offshore and Domestic Offshore segment.


(e)	Includes EPL Oil and Gas since 2014 (Energy XXI acquired EPL Oil and Gas in 2014). 2013 includes only EPL Oil & Gas.

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

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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 five 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, oil, rental equipment and other items. Liftboat contracts generally are for shorter terms than are drilling contracts.

On larger drilling and liftboat 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 estimated 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 actual revenue 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 for our executed contracts by year as of March 23, 2016, including approximately $410.9 million related to the Maersk contract for the newbuild jackup rig, Hercules Highlander, and assuming that the dayrates on the Hercules 261 and Hercules 262 revert back to their originally contracted dayrates effective January 1, 2017:



	For the Years Ending December 31,
	Total		2016		2017		2018		Thereafter
	(in thousands)
Domestic Offshore	$	8,735	$	8,735	$	—	$	—	$	—
International Offshore	820,406		94,158		202,451		202,451		321,346
International Liftboats	—		—		—		—		—
Total	$	829,141	$	102,893	$	202,451	$	202,451	$	321,346

Employees

As of December 31, 2015, we had approximately 1,000 employees. We require skilled personnel to operate and provide technical services and support for our rigs and liftboats. As a result, we conduct extensive personnel 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 and Indemnity

Our drilling contracts provide for varying levels of indemnification from our customers, including for well control and subsurface risks, 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, and even if we are grossly negligent. However, some of our customers have been reluctant to extend their indemnity obligations in instances where we are grossly negligent. Our customers typically assume responsibility for and agree to indemnify us from any loss or liability resulting from pollution or contamination, including

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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 blowouts or cratering of the well (“Blowout Liability”). The customer’s assumption for Blowout Liability may, in certain circumstances, be contractually 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 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. Effective May 1, 2015, we completed the annual renewal of all of our key insurance policies. Our insurance policies typically consist of twelve-month policy periods, and the next renewal date for our insurance program is scheduled for May 1, 2016.

Primary Marine Package Coverage

Our primary marine package provides for hull and machinery coverage for substantially all of our rigs (excluding Hercules Triumph and Hercules Resilience which are covered under separate policies, discussed below) and liftboats up to a scheduled value of each asset. The marine package includes protection and indemnity and maritime employer’s liability coverage for marine crew personal injury and death and certain operational liabilities. The major coverages of this package include the following:



Events of Coverage		Coverage Amounts and Deductibles
- Total maximum amount of hull and machinery coverage;		- $753.3 million;
- Deductible for events that are not caused by a U.S. Gulf of Mexico named windstorm;		- $5.0 million and $1.0 million per occurrence for drilling rigs and liftboats, respectively;
- Deductible for events that are caused by a U.S. Gulf of Mexico named windstorm;		- $10.0 million;
- Maritime employer liability (crew liability);		- $5.0 million self-insured retention with excess liability coverage up to $200.0 million*;
- Personal injury and death of third parties;		- Primary coverage of $5.0 million per occurrence and $10.0 million annual aggregate with additional excess liability coverage up to $200.0 million*, subject to a $250,000 per occurrence deductible;
- Limitations for coverage for losses caused in U.S. Gulf of Mexico named windstorms; and		- Annual aggregate limit of liability of $25.0 million for property damage (except $50.0 million in respect to Hercules 300 and Hercules 350) and up to a total of $100.0 million* of liability coverage, including removal of wreck coverage; and
- Vessel pollution emanating from our vessels and drilling rigs.		- Primary limits of $5.0 million up to $17.1 million per occurrence and excess liability coverage up to $200.0 million*.

*Annual aggregate limit

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 $50.0 million primary liability coverage for well control costs, pollution and expenses incurred to redrill wild or lost wells, with excess liability coverage up to $200.0 million for pollution liability that is covered in the primary policy. Additionally, we carry a contractor's expense policy for the Hercules Triumph and Hercules Resilience with $50.0 million primary liability coverage for well control costs, pollution and expenses incurred to redrill wild or lost wells, with excess coverage up to $25.0 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, including the requirement for Company gross negligence or willful misconduct.

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Hercules Triumph and Hercules Resilience Marine Package Coverage

We have a separate primary marine package for Hercules Triumph and Hercules Resilience that provides the following:



Events of Coverage		Coverage Amounts and Deductibles
- Total maximum amount of hull and machinery coverage;		- $250.0 million per rig;
- Deductible;		- $2.5 million per occurrence per rig;
- Extended contractual liability, including subsea activities, property and personnel, clean up costs (primary coverage);		- $25.0 million per occurrence;
- Pollution-by-blowout coverage (primary coverage); and		-$10.0 million per occurrence; and
- Operational protection and indemnity coverage.		- $500.0 million per rig, subject to a $50,000 per occurrence deductible for claims originating outside the U.S. and a $250,000 per occurrence deductible for claims originating in the U.S.

Adequacy of Insurance Coverage

We are responsible 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.

Hercules 265 Incident and Settlement of Property Damage Insurance Claim

In July 2013, our jackup drilling rig, Hercules 265, a 250' mat-supported cantilevered unit operating in the U.S. Gulf of Mexico Outer Continental Shelf lease block South Timbalier 220, experienced a well control incident. The rig sustained substantial damage in the incident and our insurance underwriters determined that the rig was a constructive total loss. We received gross insurance proceeds of $50.0 million, the rig's insured value, in December 2013 from insurance underwriters and recorded a net insurance gain of $31.6 million, which is included in Operating Expenses on our Consolidated Statement of Operations for the year ended December 31, 2013, after writing off the rig's net book value of $18.4 million. The financial information for Hercules 265 has been reported as part of the Domestic Offshore segment. The cause of the incident is unknown. We have removal of wreck coverage for this incident up to a total amount of $110.0 million. During the second quarter of 2014, we received gross proceeds of $9.1 million from the insurance underwriters as reimbursement for a portion of the wreck removal and related costs incurred and, used $2.0 million to repurchase the Hercules 265 hull from the insurance underwriters, which is currently stacked in a Mississippi shipyard. During the period from January 1, 2015 to November 6, 2015, we received an additional $3.5 million in gross proceeds from the insurance underwriters as reimbursement for a portion of the wreck removal and related costs incurred to date. We and our insurance underwriters continue to negotiate the insurance recovery amounts for costs related to the salvage of the rig and certain other insured losses.

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 Environmental Protection Agency ("EPA"), 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.

In the aftermath of the Macondo well blowout incident in April 2010, BSEE and BOEM have proposed and implemented regulations and requirements that add safety measures, increase permit scrutiny and add other requirements and policies such as contractor sanctions that could materially increase the cost of offshore drilling 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 Notices to Lessees have impacted and may continue to impact our operations. In addition, the federal government has considered legislation that could impose additional equipment and safety requirements on operators and drilling contractors in the U.S.

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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.

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 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 and have prepared Spill Prevention Control and Countermeasure Plans where appropriate. 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” are subject to certain specified liability limits. 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

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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.

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, prohibits deliberate emissions of ozone depleting substances and includes measures aimed at reducing greenhouse gases. 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. 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.

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. 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

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days during which, 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 17 of our Notes to Consolidated Financial Statements included in Item 8 of this annual report. Additional information about our segments is presented in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this annual report.

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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 dayrates. 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 supply of 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;


•	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, North Africa, West Africa, Asia, Eastern Europe 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 and the Middle East, where armed conflict, civil unrest and acts of terrorism are increasingly common occurrences.

Reduced demand for drilling and liftboat services has and could continue to 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, West Africa, Asia and Eastern Europe, 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. A decline in the United States or global economy could result in a decrease in energy consumption and commodity prices, 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 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, both of which we are currently experiencing, 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 we are currently experiencing.

An increase in supply of rigs or liftboats could adversely affect our financial condition and results of operations.

New construction of rigs and liftboats, mobilization of rigs to regions in which we operate, or reactivation of non-marketed rigs and liftboats, could result in excess supply in the regions in which we operate, and our dayrates and utilization could be reduced.

Construction of rigs, including high specification rigs such as Hercules Highlander, Hercules Triumph and Hercules Resilience, could result in excess supply in international regions, which could reduce our ability to secure new contracts for our

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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 could 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 and other mobile offshore drilling units into the U.S. Gulf of Mexico. Improved market conditions in any region worldwide could lead to increased construction of rigs and liftboats and upgrade programs by our competitors. Some of our competitors have already announced plans to build additional jackup rigs with higher specifications than most of our fleet. 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.

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, 2015, we had total outstanding debt of approximately $428.7 million. This debt represented approximately 43% of our total book capitalization. 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 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 service our debt, and to fund planned capital expenditures will depend on our ability to generate cash in the future, which is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. Our future cash flows may be insufficient to meet all of our debt obligations and other commitments, and any insufficiency could negatively impact our business. To the extent we are unable to make scheduled interest payments or 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 Board of Directors have formed a Special Committee to explore strategic alternatives. There can be no assurance with respect to the terms of timing of any transaction, or whether any transaction will ultimately occur, or will occur on terms favorable to our stockholders or lenders or to our business.

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be able to identify or complete any strategic transactions on commercially reasonable terms or at all, or that any such transaction would be favorable to our stockholders or lenders, or our business.

If we are unable to comply with the financial and other covenants in our Senior Secured Credit Facility, there could be a default, which could result in an acceleration of repayment of funds that we have borrowed.

Our Senior Secured Credit Facility includes financial covenants that require us to maintain a minimum amount of liquidity and, starting in the first quarter of 2017, the financial covenants will also require us to maintain a maximum ratio of debt relative to our EBITDA. Our ability to comply with these financial covenants can be affected by events beyond our control. Reduced activity levels in the oil and natural gas industry, such as we are currently experiencing, could adversely impact our ability to comply with such covenants in the future. Our failure to comply with the covenants in our Senior Secured Credit Facility would result in an event of default under the Senior Secured Credit Facility. An event of default could result in our having to immediately repay all amounts outstanding under the Senior Secured Credit Facility and in foreclosure of liens on our assets. As of December 31, 2015, we were in compliance with all covenants under our Senior Secured Credit Facility. However, we are currently projecting that we will violate the maximum ratio of debt relative to our EBITDA on March 31, 2017. If this occurs and we are not able to obtain a waiver from our lenders, the lenders could accelerate our debt obligations. In addition, we would be required to pay an additional premium of all interest that would accrue until November 6, 2018, plus a 3% premium, discounted to present value. Because of this applicable premium, it could be challenging for us to obtain a waiver, and further, given the current state of the drilling market, we do not currently believe refinancing would be a viable option. Our lenders may not support strategic alternatives considered by the Special Committee of our Board of Directors.

Our liquidity depends upon cash on hand and cash from operations.

Our liquidity depends upon cash on hand and cash from operations. Although we currently believe we have adequate liquidity to fund our operations through at least December 31, 2016, 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 existing indebtedness, 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 refinance our indebtedness, to fund capital expenditures or for general corporate purposes. There can be no guarantee that we will be able to access the capital markets when we need to or issue debt or equity on terms that are acceptable to us.

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 to transfer cash from our subsidiaries 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.

Many of our customer contracts are short term, and our customers may seek to terminate, renegotiate or decline to renew contracts when market conditions decline, which could result in reduced profitability.

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. 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, such as we are currently experiencing. Due to the short-term nature of most of our contracts, a decline in market conditions such as we are currently experiencing can quickly affect our business if customers reduce their levels of operations. Also, during these periods of 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 contracts or avoid their obligations, including their payment 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.

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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 such as we are currently experiencing. 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.

On February 25, 2015, we received a notice from Saudi Aramco terminating for convenience our drilling contract for the Hercules 261, effective on or about March 27, 2015. The Company received subsequent notices from Saudi Aramco extending the effective date of termination to May 31, 2015. On June 1, 2015, the Company received notice from Saudi Aramco reinstating the drilling contract on the Hercules 261, in exchange for dayrate concessions on the Hercules 261, Hercules 262 and Hercules 266 from their existing contracted rates to $67,000 per day. These reduced dayrates were effective retroactively from January 1, 2015 through December 31, 2016 for the Hercules 261 and Hercules 262, and through the remaining contract term for the Hercules 266. However, on March 9, 2016, we received a notice from Saudi Aramco further reducing the dayrates under the contracts for the Hercules 261 and Hercules 262 from $67,000 per day to $63,650 per day. The reduced dayrates will apply retroactively from January 1, 2016, through December 31, 2016. The dayrate for the Hercules 266 was also reduced from $67,000 per day to $63,650 per day effective January 1, 2016, through the remaining term of its contract, or April 7, 2016.

We can provide no assurance that our current backlog of contract revenue and receivables will be ultimately realized.

As of March 23, 2016, our total contract backlog for our Domestic Offshore, International Offshore and International Liftboats segments was approximately $829.1 million for our executed contracts, including approximately $410.9 million related to the Maersk contract for the newbuild jackup rig, Hercules Highlander, and accordingly, our financial prospects are significantly dependent upon our contract with Maersk. In addition, the total contract backlog assumes that the dayrates on the Hercules 261 and Hercules 262 revert back to their originally contracted dayrates effective January 1, 2017. 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. 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. In addition, we can provide no assurance that our customers will pay any or all of the revenues that we have earned from them for providing our drilling and liftboat services. 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.

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. In addition, the amount of natural gas production in the shallow-water U.S. Gulf of Mexico has declined over the last decade. Moreover, oil and natural gas companies may be unable to obtain financing necessary to drill prospects in this region. The decrease in the size of oil and natural gas prospects, the decrease in production or the failure to obtain such financing may result in reduced drilling activity in the U.S. Gulf of Mexico and reduced demand for our services.

Our industry is highly competitive, with intense price competition. Our inability to compete successfully may reduce our profitability.

Our industry is highly competitive. Our contracts are traditionally awarded on a competitive bid basis. Pricing is often the primary factor in determining which qualified contractor is awarded a job, 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 with excess capacity putting downward pressure on

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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 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 us.

Our financial prospects are significantly dependent on our drilling contract for our newbuild rig, Hercules Highlander, and we cannot guarantee the timely completion and delivery of the Hercules Highlander, which is being constructed at JSL and is currently scheduled for delivery in the second quarter of 2016.

We may be materially adversely affected if our newbuild rig, Hercules Highlander, to support the drilling contract for Maersk Oil North Sea UK Limited (the “Maersk Drilling Contract”) is not constructed or delivered on time in accordance with the agreed specifications. Delayed delivery beyond December 31, 2016 will, unless the delay is for certain reasons permitted under the Maersk Drilling Contract (including certain instances of force majeure), give Maersk the right to terminate the Maersk Drilling Contract.

Our rights under the construction contract may not protect us against the losses which may result if JSL is not able to deliver Hercules Highlander in accordance with the requirements of the construction contract and the Maersk Drilling Contract. We cannot give any assurance in respect of the yard’s ability to complete the construction of Hercules Highlander as contractually agreed. In the event of such a failure or delay, we may not be able to generate any income from the Maersk Drilling Contract, which might lead to deferred or lost revenue, which is likely to have a material adverse effect on our results of operations, cash flows and financial position. We could lose the Maersk Drilling Contract and/or receive potential liability claims from the customer as a result of such delays.

We may need to make changes to Hercules Highlander after delivery which could result in additional construction costs and additional capital needs for us in the future.

We cannot guarantee that Hercules Highlander will be completed or pass the acceptance tests.

Acceptance tests will be performed in connection with the delivery of Hercules Highlander. The construction of Hercules Highlander was agreed to be based on an enhanced JSL JU-2000E design, and in accordance with detailed specifications and the rules and regulations of the classification society, the American Bureau of Shipping, as well as the relevant laws, regulations and rules of the intended flag state, Liberia, and of the countries in which Hercules Highlander is expected to operate. Such compliance will be pre-tested prior to departure from the shipyard in Singapore in order to reduce the risk for not meeting the performance specifications set out in the construction contract. Hercules Highlander will not be delivered from the yard until it is in compliance with the performance specifications, which could cause delivery to be delayed.

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 or to fund capital expenditures. 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 Senior Secured 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 the maintenance of our assets, take advantage of business opportunities or respond to competitive pressures, any of which could harm our business.

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.

Asset sales have been an important component of our business strategy. 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 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. 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. Any such discussions and agreements to sell assets may or may not result in

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the consummation of an asset sale. We may not be able to identify buyers with access to financing or complete sales on acceptable terms. In addition, our Senior Secured Credit Facility imposes certain restrictions and requirements on us with respect to asset sales, including approval by our lenders of certain asset sales. We may not be able to obtain lender approvals required for asset sales that we believe to be desirable, or our lenders may favor different strategic alternatives.

Our Senior Secured Credit Facility imposes significant additional costs and operating and financial restrictions on us, which may prevent us from capitalizing on business opportunities and taking certain actions.

Our Senior Secured Credit Facility imposes significant additional costs and operating and financial restrictions on us. These restrictions limit our ability to, among other things:


•	incur indebtedness;


•	pay dividends or make other distributions to equity holders;


•	prepay subordinated debt or unsecured debt;


•	make other restricted payments or investments (including investments in subsidiaries that are not guarantors);


•	enter into sale and leaseback transactions;


•	sell assets;


•	create liens;


•	enter into agreements that restrict dividends or other transfers of assets by restricted subsidiaries;


•	engage in transactions with affiliates;


•	modify or terminate any material agreement;


•	engage in any new line of business; and


•	consolidate, merge or transfer all or substantially all of our assets.

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. Our lenders may not support strategic alternatives considered by the Special Committee of our Board of Directors, or our lenders may favor different strategic alternatives.

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, the Asia-Pacific region and the North Sea. We operate liftboats in West Africa, including Nigeria, and in the Middle East. We also operate drilling rigs in Saudi Arabia, West Africa and Southeast Asia. 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;


•	delays and potential prolonged disruption of operations associated with obtaining visas for our employees and other local procedural requirements and administrative matters;


•	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 Nigeria;


•	unexpected changes in regulatory requirements;

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•	wage and price controls;


•	imposition of trade barriers;


•	imposition or changes in enforcement of local content and cabotage 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. In certain countries, government rules and regulations also require that local citizens or entities be engaged as local representatives to support the operations of foreign contractors or to own a portion of the equity or assets of companies operating within their jurisdiction. These practices and legal requirements regarding the use of and potential company equity and asset ownership by local representatives might limit our business and operations, and occasions may arise when we have disagreements with our local representative, or the continuation of such relationship may become infeasible. Any such developments might disrupt our operations and continuity of our business in such jurisdictions. If we are unable to resolve issues with a local representative, we may decide to terminate the relationship with such local representative and seek another local representative or seek opportunities for our rigs and vessels elsewhere. Where local representative relationships require approval from the local government or other third parties we may be constrained in our ability to replace an existing local representative which may disrupt our operations and continuity of our business in such jurisdictions and require us to seek opportunities for our rigs and vessels elsewhere. In addition, if we experience delays or are unable to perform our obligations under our contracts, our customers may seek to cancel the contracts, which could adversely affect our financial condition, results of operations or cash flows.

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, 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 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. Our ability to compete in international markets may be adversely affected by these foreign governmental regulations and/or policies that favor the awarding of contracts to contractors in which nationals of those foreign countries have substantial ownership interests or by regulations requiring foreign contractors to employ, transfer ownership of equipment to, or purchase supplies from citizens of a particular jurisdiction.

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.

Many of 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 other than our three ultra-high specification rigs, including one under construction. In our existing fleet, 17 of our 27 jackup rigs are mat-supported, which are generally limited to geographic areas with soft bottom conditions like much of the Gulf of Mexico. In addition, the majority of new rigs under construction are of higher specification than our existing fleet, other than our three ultra-high specification rigs, including one under construction. Most of these 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 such as we are currently experiencing, higher specification rigs may be more likely to obtain contracts than lower specification jackup rigs such as ours. In the past, lower specification rigs typically 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

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of our rigs were designed specifically for drilling in the shallow-water of the U.S. Gulf of Mexico, our ability to move them to other regions in response to changes in market conditions is limited.

Furthermore, there is an increasing amount of exploration and production expenditures being 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.

A small number of customers account for a significant portion of our revenue and backlog, 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 and backlog from a few energy companies. Saudi Aramco, Chevron Corporation, Arena Energy and Eni accounted for 34%, 10%, 10% and 15%, respectively, of our successor revenue for the period November 6, 2015 to December 31, 2015 and 21%, 19%, 16% and 7%, respectively, of our predecessor revenue for the period January 1, 2015 to November 6, 2015. In addition, our financial prospects are significantly dependent on our five-year contract with Maersk, which is scheduled to commence in the second half of 2016 and is projected to account for a significant portion of our backlog. Our financial condition and results of operations will be materially adversely affected if any of these customers interrupt or curtail their activities, terminate or re-negotiate their contracts with us, fail to renew their existing contracts, refuse to award new contracts to us and we are unable to enter into contracts with new customers at comparable dayrates, or fail to pay for the revenues that we have earned providing our drilling and liftboat services. The loss of any of these or any other significant customer could adversely affect our financial condition and results of operations.

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, such as the well control incident experienced in July 2013 by our jackup drilling rig Hercules 265 in the U.S. Gulf of Mexico. 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. 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.

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, regardless of how the loss or damages may be caused. Typically, our customer agrees to indemnify us for these risks, even if we are grossly negligent. However, since the Macondo well blowout and resulting litigation, some of our customers have been reluctant to extend their indemnity obligations in instances where we are grossly negligent. 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.

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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.

Acquisitions and integrating such acquisitions create certain risk and may affect our operating results.

We have in the past completed acquisitions (including the acquisition of individual rigs and liftboats and our acquisitions of Seahawk in 2011 and Discovery Offshore S.A. in 2013), although we do not currently intend to pursue acquisitions. Acquisitions involve numerous risks and 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 and assets 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 obtain contracts or perform under 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. In addition, we may not be able to obtain, on terms we find acceptable, sufficient financing or funding that may be required to fund any such acquisition or investment and related capital expenditures.

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

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•	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. 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.

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.

Our operations are affected in varying degrees by governmental laws and regulations. We are also subject to the jurisdiction of the Coast Guard, the National Transportation Safety Board, the Customs and Border Protection, the Department of Interior, the Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement ("BSEE"), as well as private industry organizations such as the American Bureau of Shipping. 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 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. For example, the BSEE has extended its regulatory enforcement reach to include contractors, which exposes contractors to potential fines, sanctions and penalties for violations of law arising in the BSEE's jurisdictional area. 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 well 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. Governmental entities such as the U.S. Environmental Protection Agency and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and

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costly actions. For example, as an operator of mobile offshore drilling units in navigable U.S. waters and some offshore areas, we may be liable for damages and costs incurred in connection with oil spills or other unauthorized discharges of chemicals or wastes resulting from those operations. Additionally, the BSEE has extended its regulatory enforcement reach to include contractors which exposes contractors to potential fines, sanctions and penalties for violations of law arising in the BSEE's jurisdictional area. 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.

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.

We may not be able to maintain or replace our rigs and liftboats as they age.

The capital associated with the repair and maintenance of our fleet increases with age. We may not be able to maintain our fleet by extending the economic life of existing rigs and liftboats, and our financial resources may not be sufficient to enable us to make expenditures necessary for these purposes or to acquire or build replacement units.

Our operating and maintenance costs with respect to our rigs 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, including mobilizations to harsh environments where high specification rigs such as the Hercules Triumph, Hercules Resilience and Hercules Highlander generally operate, the labor and other operating and maintenance costs can increase 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;

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•	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, 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 in the past 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.

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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 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 any existing or future examinations by the Internal Revenue Service or other taxing authorities will not have an adverse effect on our operating results and financial condition.

Our ability to use net operating loss and credit carry-forwards to offset future taxable income for U.S. federal income tax purposes may be limited as a result of issuances of equity or other transactions.

In general, under Sections 382 and 383 of the Internal Revenue Code of 1986, as amended (the “Code”), a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change net operating losses (“NOLs”) and certain tax credits, to offset future taxable income and tax. In general, an ownership change occurs if the aggregate stock ownership of certain stockholders changes by more than 50 percentage points over such stockholders’ lowest percentage ownership during the testing period (generally three years).

The Debtors' emergence from Chapter 11 bankruptcy proceedings is considered a change in ownership for purposes of IRC Section 382. The ownership changes and resulting annual limitation will result in the expiration of an estimated $60 million of net operating losses generated prior to the emergence date. Net operating losses, alternative minimum tax credits and certain built-in losses generated prior to the emergence date will be limited to $7.5 million per year. The amount of consolidated U.S. NOLs available as of December 31, 2015 is approximately $146.8 million. Additionally, we have $19.5 million of alternative minimum tax credits. These NOLs will expire in the years 2029 through 2035.

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 existing indebtedness 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.

Our publicly-filed reports are reviewed from time to time by the SEC, and the audits of our financial statements are subject to review by the Public Company Accounting Oversight Board. Any significant changes or amendments required as a result of any such review may result in material liability to us and may have a material adverse impact on the trading price of our common stock.

The reports and other securities filings of publicly-traded companies are subject to review by the SEC from time to time for the purpose of assisting companies in complying with applicable disclosure requirements. The SEC is required, pursuant to the Sarbanes-Oxley Act of 2002, to undertake a comprehensive review of a company’s report at least once every three years, although an SEC review may be initiated at any time. Similarly, the Public Company Accounting Oversight Board (the “PCAOB”) periodically reviews selected audits performed by independent registered accounting firms. While we believe that our previously filed SEC reports comply, and we intend that all future reports, including our audited financials, will comply, in all material respects with the published rules and regulations of the SEC and that the audits of our financial statements have been performed in accordance with generally accepted auditing standards, we could be required to modify, amend or reformulate information contained in our public filings as a result of an SEC or PCAOB review, or we may be found to have a significant deficiency or material weakness in our internal controls over financial reporting. Any modification, amendment or reformulation of information contained in our public filings could be significant and could result in material liability to us and have a material adverse impact on the trading price of our common stock.

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We may not be able to maintain our listing on NASDAQ, which would adversely affect the price and liquidity of our common stock.

To maintain the listing of our common stock on NASDAQ we are required to meet certain listing requirements, including a minimum closing bid price of $1.00 per share. Companies traded on NASDAQ would receive a deficiency notice from NASDAQ if their common stock has traded below the $1.00 minimum bid price for 30 consecutive business days. Subsequent to December 31, 2015, our common stock traded below the $1.00 minimum bid price for 18 consecutive trading days, however, our stock price as of March 28, 2016 was $2.20 per share. If our common stock trades below the $1.00 minimum bid price for 30 consecutive business days, we would likely receive a deficiency notice. Following receipt of a deficiency notice, we expect we would have 180 calendar days to regain compliance by having our common stock trade over the $1.00 minimum bid price for at least a 10-day period. If we were to fail to meet the minimum bid price for at least 10 consecutive days during the grace period, our common stock could be delisted. Even if we are able to comply with the minimum bid requirement, there is no assurance that in the future we will continue to satisfy NASDAQ listing requirements, which could result in our common stock being delisted. Delisting of our common stock could materially adversely affect the market price and market liquidity of our common stock and our ability to raise necessary capital.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Our property consists primarily of jackup rigs, liftboats and ancillary equipment, substantially all of which we own. All of our vessels (including Hercules Highlander when it is delivered) and substantially all of our other personal property are pledged to collateralize our Senior Secured Credit Facility.

We maintain offices, a maintenance facility, yard facilities, warehouses, a waterfront dock as well as residential premises in various countries, including the United States, United Kingdom, Nigeria, Singapore, Saudi Arabia, United Arab Emirates, Malaysia, Congo and Bahrain. All of these properties are leased except for an office and a warehouse in the United Kingdom. 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

We are involved in various claims and lawsuits in the normal course of business. As of December 31, 2015, management did not believe any accruals were necessary in accordance with FASB ASC 450-20, Contingencies - Loss Contingencies.

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. On June 11, 2012, the plaintiff in the Harris County action voluntarily dismissed his action. On March 14, 2013, our and the other defendants' motions to dismiss the Delaware federal action were granted. The motions to dismiss the Texas federal action are pending.

We do not expect the ultimate outcome of the shareholder derivative lawsuit to have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Hercules 265 Litigation

In January 2015, Cameron International Corporation (“Cameron”), and Axon Pressure Products, Inc. and Axon EP, Inc. (collectively “Axon”) filed third-party complaints against us in a subrogation action that Walter Oil & Gas Corporation

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("Walter") and its underwriters, together with Walter’s working interest partners, Tana Exploration Company, LLC and Helis Oil & Gas Company, LLC, filed against Cameron and Axon, among others, to recover an undisclosed amount of damages relating to the well control incident at South Timbalier 220 involving the Hercules 265. In response to Cameron and Axon's third-party complaints, we filed counterclaims against Cameron and Axon pursuing contribution and related claims. Subsequently, Walter dismissed Cameron from the subrogation action. Separately, Cameron and Axon have filed answers and claims in a limitation of liability action that we filed relating to the incident. In response, we filed counterclaims against Axon and Cameron pursuing contribution and related claims. After Walter and the other plaintiffs in the subrogation matter dismissed Cameron, Hercules and Cameron mutually dismissed all claims against each other in both the limitation of liability and subrogation actions. We have tendered defense and indemnity to Walter for the remaining claims asserted by Axon and other costs and/or liabilities arising from the incident, pursuant to the terms of the drilling contract between us and Walter. Until such time as Walter accepts the tender, we will vigorously defend the claims.

Settlement of Contractual Dispute

In August 2015, we agreed to a settlement of a contractual dispute relating to the sale of certain of our assets in 2006, pursuant to which settlement we received a $5.2 million payment in October 2015 and recorded a gain of the same amount, which is included in General and Administrative on the Consolidated Statement of Operations for the period January 1, 2015 to November 6, 2015.

We and our subsidiaries are involved in a number of other lawsuits, all of which have arisen in the ordinary course of business. We do not believe that the ultimate liability, if any, resulting from any such other pending litigation will have a material adverse effect on our business or consolidated financial statements.

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

In connection with the Company's emergence from Chapter 11, all shares of common stock of the Company outstanding prior to emergence were canceled on November 6, 2015. The emerged company ("Emerged Company") issued 20.0 million shares of new common stock, par value $0.01 per share (the "New Common Stock").

The Company's common stock was delisted from NASDAQ and its last day to trade on the NASDAQ Global Select Market was August 21, 2015. On August 24, 2015, the Company's common stock began trading on the OTC Market Group Inc.’s OTC Pink market. On November 6, 2015, the Emerged Company listed its common stock on the NASDAQ under the symbol "HERO" and it commenced trading on the NASDAQ Global Market on November 9, 2015. Upon listing on the NASDAQ, the common stock ceased to be listed on the OTC market. As of March 24, 2016, there were 65 stockholders of record. On March 24, 2016, the closing price of our common stock as reported by NASDAQ was $2.03 per share. The following table sets forth, for the period indicated, the range of high and low sales prices for our common stock:



	Price
	High		Low
2015
Period from November 9, 2015 to December 31, 2015	$	14.50	$	2.05

We have not paid any cash dividends on our common stock 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 restricts our ability to pay dividends or other distributions on our equity securities.

Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities

In connection with the Company's emergence from Chapter 11, the Emerged Company issued 20.0 million shares of New Common Stock, par value $0.01 per share, of which 96.9%, or 19.4 million shares, were distributed to the holders of the Outstanding Notes of the pre-emerged company ("Pre-emerged Company") and 3.1%, or 0.6 million shares, were distributed to equity holders of the Pre-emerged Company. Additionally, the Emerged Company also issued 5.0 million warrants, which were distributed to equity holders of the Pre-emerged Company, exercisable until the Expiration Date, to purchase up to an aggregate of 5.0 million shares of New Common Stock at an initial exercise price of $70.50 per share, subject to adjustment as provided in the Warrant Agreement. Warrants are exercisable on a cashless basis at the election of the warrant holder. All unexercised Warrants shall expire, and the rights of Initial Beneficial Holders of such Warrants to purchase New Common Stock shall terminate at the close of business on the first to occur of (i) November 8, 2021 or (ii) the date of completion of (A) any Affiliated Asset Sale or (B) a Change of Control (as defined in the warrant agreement). Warrant holders will not have any rights as stockholders until a holder of Warrants becomes a holder of record of shares of Common Stock issued upon settlement of Warrants.

The issuance of the 20.0 million shares of common stock and the 5.0 million warrants to purchase 5.0 million shares of common stock were issued in exchange for debt and equity of the Debtors and were exempt from registration under the Securities Act of 1933, as amended, because they were issued under section 1145 of the Bankruptcy Code (Title 11 of the U.S. Code).

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Issuer Purchases of Equity Securities

The following table sets forth for the periods indicated certain information with respect to our purchases of our common stock:



Period	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of a Publicly Announced Plan (2)	Maximum Number of Shares That May Yet Be Purchased Under the Plan (2)
October 1 - 31, 2015	255	$	0.06	N/A	N/A
November 1 - 30, 2015	—	N/A		N/A	N/A
December 1 - 31, 2015	—	N/A		N/A	N/A
Total	255	0.06		N/A	N/A

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(1)	Represents the surrender of shares of our common stock to satisfy tax withholding obligations in connection with the vesting of restricted stock issued to employees under our stockholder-approved 2004 Amended and Restated Long-Term Incentive Plan.


(2)	We did not have at any time during 2015, 2014 or 2013, and currently do not have, a share repurchase program in place.

There were eleven thousand shares held in treasury at November 6, 2015 that were valued at a per share price of $29.32 in connection with reorganization.

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Item 6.	Selected Financial Data

We have derived the following condensed consolidated financial information as of December 31, 2015 and 2014 and for the periods November 6, 2015 to December 31, 2015 and January 1, 2015 to November 6, 2015 and the years ended December 31, 2014 and 2013 from our audited consolidated financial statements included in Item 8 of this report. The condensed consolidated financial information as of December 31, 2013 and for the year ended December 31, 2012 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, 2014. The condensed consolidated financial information as of December 31, 2012 and for the year ended December 31, 2011 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, 2013. The condensed consolidated financial information as of December 31, 2011 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, 2012, as amended by our current report on Form 8-K filed on August 23, 2013.

We were formed in July 2004 and commenced operations in August 2004. From our formation to December 31, 2015, we completed our (i) acquisition of the remaining 68% interest in Discovery Offshore S.A. ("Discovery") (52% on June 24, 2013 ("Acquisition Date")), and the remaining interest to reach 100% in the third quarter of 2013), which includes Hercules Triumph and Hercules Resilience; ii) 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; iii) acquisition of TODCO and iv) acquisition of several other significant assets. Our financial results reflect the consolidation of Discovery's results as of the Acquisition Date, 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.

In 2013, we closed on the sale of the majority of the Inland barges as well as our U.S. Gulf of Mexico Liftboats and related assets. The results of operations of the Inland segment and Domestic Liftboats segment are reflected in the Consolidated Statements of Operations for all periods presented as discontinued operations. The remaining assets of the Inland segment, which included spare equipment, one cold stacked barge and a barge that was used as a training rig, were transferred to the Domestic Offshore segment and the historical results of Domestic Offshore were recast to include the operating results of these remaining assets. Additionally, in 2009 (4 vessels) and 2012 (1 vessel), we transferred certain assets from our Domestic Liftboats segment to our International Liftboats segment. The historical results generated by these assets that were previously reported in the Domestic Liftboats segment are reported in the International Liftboats segment.

Upon the Company’s emergence from Chapter 11 on November 6, 2015, the Company adopted fresh-start accounting in accordance with provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852, “Reorganizations” (“ASC 852”), which resulted in Hercules' becoming a new entity for financial reporting purposes. As a result of the adoption of fresh-start reporting and the effects of the implementation of the Plan, the Company’s consolidated financial statements subsequent to November 6, 2015 will not be comparable to our consolidated financial statements prior to November 6, 2015.

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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.



	Successor			Predecessor
(In thousands, except per share data)	Period from November 6, 2015 to December 31, 2015 (a)			Period from January 1, 2015 to November 6, 2015 (b)			Year Ended December 31, 2014 (c)			Year Ended December 31, 2013 (d)			Year Ended December 31, 2012 (e)			Year Ended December 31, 2011
Statement of Operations Data:
Revenue	$	32,442		$	303,206		$	900,251		$	858,300		$	618,225		$	574,571
Operating income (loss) attributable to Hercules Offshore, Inc.	(8,887		)	(175,629		)	(88,499		)	51,471			(59,727		)	(6,412		)
Loss from continuing operations attributable to Hercules Offshore, Inc.	(23,669		)	(602,494		)	(216,110		)	(26,770		)	(121,000		)	(54,750		)
Loss per share from continuing operations attributable to Hercules Offshore, Inc.:
Basic and Diluted	$	(1.18	)	$	(3.73	)	$	(1.35	)	$	(0.17	)	$	(0.79	)	$	(0.42	)
Balance Sheet Data (as of end of period):
Cash and cash equivalents	$	330,780		N/A			$	207,937		$	198,406		$	259,193		$	134,351
Working capital	311,331			N/A			239,841			227,291			217,184			174,598
Total assets	1,108,140			N/A			2,002,407			2,301,448			2,016,630			2,006,704
Long-term debt, net of current portion	428,715			N/A			1,210,919			1,210,676			798,013			818,146
Total equity	563,931			N/A			615,031			832,700			882,762			908,553
Cash dividends per share	—			—			—			—			—			—

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(a)	Includes a $1.3 million charge for reorganization items ($1.3 million net of tax or $0.06 per diluted share).

(b)

Includes a $357.1 million charge for reorganization items ($357.1 million net of tax or $2.21 per diluted share). In addition, 2015 includes $18.9 million of costs related to financing and restructuring activities ($18.9 million net of tax or $0.12 per diluted share), an $8.1 million charge on stock-based compensation due to bankruptcy ($8.1 million net of tax or $0.05 per diluted share), a $5.2 million gain on the settlement of a contractual dispute ($5.2 million net of tax or $0.03 per diluted share) and a $1.9 million charge related to the termination of the Predecessor Credit Facility ($1.9 million net of tax or $0.01 per diluted share).

(c)

Includes $199.5 million ($199.5 million, net of taxes or $1.24 per diluted share) in non-cash asset impairment charges. In addition, 2014 includes a $22.6 million ($22.6 million, net of taxes or $0.14 per diluted share) net gain on sale of cold stacked drilling rigs and a $19.9 million charge ($19.9 million, net of taxes or $0.12 per diluted share) related to retirement of the 7.125% Senior Secured Notes and issuance of the 6.75% Senior Notes.

(d)

Includes $114.2 million ($114.2 million, net of taxes or $0.72 per diluted share) in non-cash asset impairment charges. 2013 includes an $11.5 million loss ($11.5 million, net of taxes or $0.07 per diluted share) on the sale of Hercules 170 and a $31.6 million gain ($31.6 million, net of taxes or $0.20 per diluted share) for the Hercules 265 insurance settlement. In addition, 2013 includes a $14.9 million gain ($14.9 million, net of taxes or $0.09 per diluted share) on equity investment, a $29.3 million charge ($29.3 million, net of taxes or $0.18 per diluted share) related to the redemption of the 10.5% Senior Notes and issuance of the 7.5% Senior Notes and a $37.7 million tax benefit ($0.24 per diluted share) recognized related to the change in characterization of the Seahawk Acquisition for tax purposes from a purchase of assets to a reorganization.


(e)	Includes $108.2 million ($82.7 million, net of taxes or $0.54 per diluted share) in non-cash 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.

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	Successor			Predecessor
(In thousands)	Period from November 6, 2015 to December 31, 2015			Period from January 1, 2015 to November 6, 2015			Year Ended December 31, 2014			Year Ended December 31, 2013 (a)			Year Ended December 31, 2012			Year Ended December 31, 2011
Other Financial Data:
Net cash provided by (used in):
Operating activities	$	(26,459	)	$	(9,601	)	$	114,713		$	182,470		$	68,363		$	52,025
Investing activities	(4,611		)	(264,630		)	(101,841		)	(572,663		)	(52,269		)	(32,520		)
Financing activities	—			428,144			(3,341		)	329,406			108,748			(21,820		)
Capital expenditures	5,066			78,097			147,522			544,987			138,605			55,222

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(a) 2013 Capital expenditures includes a $166.9 million final shipyard installment payment for each of Hercules Triumph and Hercules Resilience.



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, 2015 and 2014, and for the periods November 6, 2015 to December 31, 2015 and January 1, 2015 to November 6, 2015 and the years ended December 31, 2014 and 2013, 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

On June 17, 2015, Hercules Offshore, Inc. and certain of its U.S. domestic direct and indirect subsidiaries (together with Hercules Offshore, Inc., the “Debtors”) entered into an agreement (the “Restructuring Support Agreement” or "RSA") with certain holders (the “Steering Group Members”) collectively owning or controlling in excess of 66 2/3% of the aggregate outstanding principal amount of the Company’s 10.25% senior notes due 2019, 8.75% senior notes due 2021, 7.5% senior notes due 2021 and 6.75% senior notes due 2022 (the “Outstanding Senior Notes”).

The RSA set forth, subject to certain conditions, the commitment to and obligations of, on the one hand, the Debtors, and on the other hand, the Steering Group Members (and any successors or permitted assigns that become party thereto) in connection with a restructuring of the Outstanding Senior Notes, the Company’s 3.375% convertible senior notes due 2038 (the “Convertible Notes”), the Company’s 7.375% senior notes due 2018 (the “Legacy Notes”) (collectively all the "Outstanding Notes") and the Company's common stock, par value $0.01 per share (the “Existing Common Stock”) (the “Restructuring Transaction”) pursuant to a pre-packaged or pre-negotiated plan of reorganization (the “Plan”) filed under Chapter 11 ("Chapter 11") of the United States Bankruptcy Code.

Pursuant to the terms of the RSA, the Steering Group Members agreed, among other things, and subject to certain conditions: (a) not to support any restructuring, reorganization, plan or sale process that is inconsistent with the RSA, and (b) not to instruct an agent or indenture trustee for any of the Outstanding Notes to take any action that is inconsistent with the terms and conditions of the RSA, including, without limitation, the declaration of an event of default, or acceleration of the Outstanding Notes arising from, relating to, or in connection with the execution of the RSA; and at the request of the Company, to waive or agree to forbear from exercising any right to take action in respect of any default or acceleration that may occur automatically without action of any as a result of the operation of the indentures governing the Outstanding Notes.

The Company agreed, among other things, and subject to certain conditions: (a) to take no action that was materially inconsistent with the RSA, the Term Sheet or the Plan; and (b) not to support any alternative plan or transaction other than the Plan.

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The Plan contemplated that the Debtors would reorganize as a going concern and continue their day-to-day operations substantially as currently conducted. Specifically, the material terms of the Plan were expected to effect, among other things, subject to certain conditions and as more particularly set forth in the Plan, upon the effective date of the Plan, a substantial reduction in the Debtors’ funded debt obligations (including $1.2 billion of face amount of the Outstanding Notes). Certain principal terms of the Plan are outlined below.

•New capital raise of first lien debt with a maturity of 4.5 years and bearing interest at LIBOR plus 9.5% per annum (1.0% LIBOR Floor), payable in cash, issued at a price equal to 97% of the principal amount. The first lien debt will consist of $450 million for general corporate use and to finance the remaining construction cost of the Company’s newbuild rig, the Hercules Highlander, and will be guaranteed by substantially all of the Company’s U.S. domestic and international subsidiaries and secured by liens on substantially all of the Company’s domestic and foreign assets. The first lien debt will include financial covenants and other terms and conditions.

•Exchange of the Outstanding Notes for 96.9% of the Company’s common stock issued in the reorganization (“New Common Stock”).

As the Plan was consummated as contemplated, holders of the Company’s Existing Common Stock received 3.1% of the New Common Stock and also received warrants to purchase New Common Stock on a pro rata basis (the “Warrants”). The Warrants are exercisable at any time until their expiration date for a per share price based upon a $1.55 billion total enterprise value. The expiration date for the Warrants is six years from the effective date of the reorganization, subject to the earlier expiration upon the occurrence of certain extraordinary events. If the terms for exercise of the Warrants are not met before the applicable expiration date, then holders of the Company’s Existing Common Stock will receive only 3.1% of the New Common Stock and will not realize any value under the terms of the Warrants.

The entry into the RSA or the matters contemplated thereby may have been deemed to have constituted an event of default with respect to the Credit Facility and the Outstanding Notes. In connection with the RSA, the Company terminated its Credit Facility effective June 22, 2015. There were no amounts outstanding and no letters of credit issued under the Credit Facility at that time. The obligations under the Credit Facility were jointly and severally guaranteed by substantially all of the Company’s domestic subsidiaries. Liens on the Company's vessels that secured the Credit Facility have been released. The Company maintained compliance with all covenants under the Credit Facility through the termination date and has paid all fees in full (See the information set forth in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources).

On August 13, 2015, the Debtors filed voluntary petitions (the "Bankruptcy Petitions") for reorganization ("Chapter 11 Cases") under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Court”). Through the Chapter 11 Cases, the Debtors implemented the Plan in accordance with the RSA that the Debtors entered into with the Steering Group Members. The Chapter 11 Cases were jointly administered under the caption In re: Hercules Offshore, Inc., et al (Case No. 15-11685). The Company's foreign subsidiaries and one U.S. domestic subsidiary ("Non-Filing Entities") were not party to the Bankruptcy filing. After the petition date, the Debtors operated their business as "debtors-in-possession" under the jurisdiction of the Court and in accordance with applicable provisions of the Bankruptcy Code and orders of the Court. Under the Chapter 11 Cases, which required Court approval, the Company’s trade creditors and vendors were paid in full in the ordinary course of business, and all of the Company’s contracts remained in effect in accordance with their terms preserving the rights of all parties. The Non-Filing Entities operated in the ordinary course of business.

The filing of the Chapter 11 Cases constituted an event of default with respect to the Company’s Outstanding Notes. Pursuant to the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically stayed most actions against the Debtors, including most actions to collect indebtedness incurred prior to the filing of the Bankruptcy Petitions or to exercise control over the Debtors’ property. Accordingly, although the Bankruptcy Petitions triggered defaults under the Outstanding Notes, creditors were generally stayed from taking action as a result of these defaults.

On September 24, 2015, the Bankruptcy Court entered an order confirming the Plan (the "Confirmation Order") and such order became final on October 8, 2015. On November 6, 2015 (the “Effective Date”) the Plan became effective pursuant to its terms and the Debtors emerged from Chapter 11.

On the Effective Date, the following items related to the Plan occurred:

•The obligations of the Debtors with respect to the Predecessor Company Outstanding Notes were canceled.

•Hero equity interests in the Predecessor Company were canceled.

•The Successor Company issued 20.0 million shares of new common stock, par value $0.01 per share (the "New Common Stock"), of which 96.9%, or 19.4 million shares, were distributed to the holders of the Outstanding Notes of the Predecessor Company and 3.1%, or 0.6 million shares, were distributed to equity holders of the Predecessor Company.

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•The Successor Company also issued 5.0 million warrants, which were distributed to equity holders of the Predecessor Company, exercisable until the Expiration Date, to purchase up to an aggregate of 5.0 million shares of New Common Stock at an initial exercise price of $70.50 per share, subject to adjustment as provided in the Warrant Agreement. Warrants are exercisable on a cashless basis at the election of the warrant holder. All unexercised Warrants shall expire, and the rights of Initial Beneficial Holders of such Warrants to purchase New Common Stock shall terminate at the close of business on the first to occur of (i) November 8, 2021 or (ii) the date of completion of (A) any Affiliated Asset Sale or (B) a Change of Control (as defined in the warrant agreement). Warrant holders will not have any rights as stockholders until a holder of Warrants becomes a holder of record of shares of Common Stock issued upon settlement of Warrants. The number of shares of Common Stock for which a Warrant is exercisable, and the exercise price per share of such Warrant are subject to adjustment from time to time upon the occurrence of certain events, including the issuance of a dividend to all holders of Common Shares, the payment in respect to any tender offer or exchange offer by the Company for shares of Common Stock, or the occurrence of a Reorganization event defined in the Warrant Agreement as the occurrence of certain events constituting a Fundamental Equity Change (other than a Non-Affiliate Combination) or a reorganization, recapitalization, reclassification, consolidation, merger or similar event as a result of which the Common Stock would be converted into, changed into or exchanged for, stock, other securities, other property or assets (including Cash or any combination thereof), each holder of a Warrant will have the right to receive, upon exercise of a Warrant, an amount of securities, Cash or other property received in connection with such event with respect to or in exchange for the number of shares of Common Stock for which such Warrant is exercisable immediately prior to such event.

•The Successor Company entered into a Credit Agreement (See the information set forth in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources) that provides for a $450.0 million senior secured credit facility consisting entirely of term loans. The loans were issued with 3.0% original issue discount, and $200.0 million (the “Escrowed Amount”) of the proceeds were placed into an escrow account to be used to finance the remaining installment payment on the Hercules Highlander and the expenses, costs and charges related to the construction and purchase of the Hercules Highlander. The remaining proceeds of the loans were to be used to consummate the Plan, fund fees and expenses in connection therewith, and to provide for working capital and other general corporate purposes of the Company and its subsidiaries. The Company’s obligations under the Credit Agreement are guaranteed by substantially all of its domestic and foreign subsidiaries, and the obligations of the Company and the guarantors are secured by liens on substantially all of their respective assets, including their current and future vessels (including the Hercules Highlander when it is delivered), bank accounts, accounts receivable, and equity interests in subsidiaries. Loans under the Credit Agreement bear interest, at the Company’s option, at either (i) the ABR (the highest of the prime rate, the federal funds rate plus 0.5%, the one-month LIBOR rate plus 1.0%, and 2.0%), plus an applicable margin of 8.50%, or (ii) the LIBOR rate plus an applicable margin of 9.50% per annum. The LIBOR rate includes a floor of 1.0%. In connection with entering into the Credit Agreement, the Company paid to the original commitment parties a put option premium equal to 2.0% of each such commitment party’s commitment (one half of such fee was paid upon execution of the commitment letter, and the remaining half of such fee was paid on the Credit Agreement Closing Date), and the Company paid certain administrative and other fees to the Agent.

Fresh-Start Accounting

Upon our emergence from Chapter 11 on November 6, 2015, we adopted fresh-start accounting in accordance with provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852, “Reorganizations” (“ASC 852”) which resulted in Hercules becoming a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. The fair values of our assets and liabilities in conformance with ASC 805, “Business Combinations,” as of that date differed materially from the recorded values of our assets and liabilities as reflected in its historical consolidated financial statements. In addition, our adoption of fresh-start accounting may materially affect its results of operations following the fresh-start reporting dates, as we will have a new basis in our assets and liabilities. Consequently, our historical financial statements may not be reliable indicators of its financial condition and results of operations for any period after it adopted fresh-start reporting. As a result of the adoption of fresh-start reporting and the effects of the implementation of the Plan, our consolidated balance sheets and consolidated statements of operations subsequent to November 6, 2015 will not be comparable to our consolidated balance sheets and consolidated statements of operations prior to November 6, 2015.

Subsequent to the Petition Date, expenses, realized gains and losses, and provisions for losses that can be directly associated with the reorganization of the business are reported as Reorganization Items, Net in the accompanying Consolidated Statement of Operations.

The audited consolidated financial statements included in this Annual Report on Form 10-K have been prepared assuming we will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the ordinary course of business. During the Chapter 11 proceedings, our ability to continue as a going concern was contingent

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upon, among other factors, the Debtors’ ability to satisfy the remaining conditions to effectiveness contemplated under the Plan and to implement such plan of reorganization, including obtaining any exit financing.

Although we are exploring all strategic alternatives, we do not believe that there is substantial doubt about our ability to continue as a going concern through 2016. As part of that assessment, based on facts known to us as of the filing of our Form 10K, we do not believe it is more likely than not that a bankruptcy filing will occur during 2016. Further, we do not intend to pursue any strategic action that results in an event of default under the Credit Agreement during 2016. We are currently projecting, however, that we will violate the Maximum Senior Secured First Lien Leverage Ratio on March 31, 2017. If this occurs and we are not able to obtain a waiver from our lenders, the lenders could accelerate these debt obligations. In addition, we would be required to pay an additional premium of all interest that would accrue until November 6, 2018, plus a 3% premium, discounted to present value. Because of this applicable premium, it could be challenging for us to obtain a waiver, and further, given the current state of the drilling market, we do not currently believe refinancing would be a viable option.

Drilling Contract Award and Rig Construction Contract

In May 2014, we signed a five-year drilling contract with Maersk Oil North Sea UK Limited ("Maersk") for a newbuild jackup rig, Hercules Highlander, that we will own and operate. Contract commencement is expected in mid-2016. In support of the drilling contract, in May 2014, we signed a rig construction contract with Jurong Shipyard Pte Ltd ("JSL") in Singapore. This High Specification, Harsh Environment (HSHE) newbuild rig is based on the Friede & Goldman JU-2000E design, with a 400 foot water depth rating and enhancements that will provide for greater load-bearing capabilities and operational flexibility. The shipyard cost of the rig is estimated at approximately $236 million. Including project management, spares, commissioning and other costs, total delivery cost is estimated at approximately $270 million of which approximately $211 million remains to be spent at December 31, 2015. The total delivery cost estimate excludes any customer specific outfitting that is reimbursable to us, costs to mobilize the rig to the first well, as well as capitalized interest. We paid $23.6 million, or 10% of the shipyard cost, to JSL in May 2014 and made a second 10% payment in May 2015 with the final 80% of the shipyard payment due upon delivery of the rig, which is expected to be in the second quarter of 2016. $200.0 million of the proceeds from the Senior Secured Credit Facility were placed in an escrow account and are included in Restricted Cash on the Consolidated Balance Sheet as of December 31, 2015 to be used to finance the remaining installment payment on the Hercules Highlander and the expenses, costs and charges related to the construction and purchase of the Hercules Highlander.

Perisai Management Contract

In November 2013, we entered into an agreement with Perisai Drilling Sdn Bhd ("Perisai") whereby we agreed to market, manage and operate two Pacific Class 400 design new-build jackup drilling rigs, Perisai Pacific 101 and Perisai Pacific 102 ("Perisai Agreement"). Pursuant to the terms of the agreement, Hercules is reimbursed for all operating expenses and Perisai pays for all capital expenditures. We receive a daily management fee for the rig and a daily operational fee equal to 12% of the rig-based EBITDA, as defined in the Perisai Agreement. In August 2014, Perisai Pacific 101 commenced work on a three-year drilling contract in Malaysia. Perisai Pacific 102 was scheduled to be delivered by the shipyard by mid-2015, but delivery has not yet occurred. It is our understanding that Perisai is in discussions with the shipyard to further delay delivery of the rig.

Specific to the Perisai Agreement, we recognized the following results in our International Offshore segment:



	Successor		Predecessor
(in millions)	Period from November 6, 2015 to December 31, 2015		Period from January 1, 2015 to November 6, 2015		Year Ended December 31, 2014
Revenue	$	1.3	$	12.1	$	11.1
Operating Expenses	0.8		6.3		5.6

Dayrate Reductions

On February 25, 2015, we received a notice from Saudi Aramco terminating for convenience our drilling contract for the Hercules 261, effective on or about March 27, 2015. We received subsequent notices from Saudi Aramco extending the effective date of termination to May 31, 2015. On June 1, 2015, we received notice from Saudi Aramco reinstating the drilling contract on the Hercules 261, in exchange for dayrate concessions on the Hercules 261, Hercules 262 and Hercules 266 from their existing contracted rates to $67,000 per day. These reduced dayrates were effective retroactively from January 1, 2015 through December 31, 2016 for the Hercules 261 and Hercules 262, and through the remaining contract term for the Hercules 266. However, on March 9, 2016, we received a notice from Saudi Aramco further reducing the dayrates under the contracts for the Hercules 261 and Hercules 262 from $67,000 per day to $63,650 per day. The reduced dayrates will apply retroactively from January 1, 2016,

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through December 31, 2016. The dayrate for the Hercules 266 was also reduced from $67,000 per day to $63,650 per day effective January 1, 2016, through the remaining term of its contract, or April 7, 2016.

Asset Dispositions and Impairment

Segments

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 includes the costs of a small crew of five to ten employees, and we also receive a variable rate for reimbursement of other operating costs such as catering, rental equipment 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 and International Offshore 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 International Liftboats segment are the wages paid to crews, maintenance, insurance and repairs to the vessels and the amortization of regulatory drydocking costs. Unlike our Domestic Offshore and International Offshore 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, oil, rental equipment 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.

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RESULTS OF OPERATIONS

The following table sets forth financial information by operating segment and other selected information for the periods indicated. The period from November 6 to December 31, 2015 (Successor Company) and the period from January 1 to November 6, 2015 (Predecessor Company) are distinct reporting periods as a result of our emergence from bankruptcy on November 6, 2015. References in these results of operations to the change and the percentage change combine the Successor Company and Predecessor Company results for the year ended December 31, 2015 in order to provide comparability of such information to the year ended December 31, 2014. While this combined presentation is a non-GAAP presentation for which there is no comparable GAAP measure, management believes that providing this financial information is the most relevant and useful method for making comparisons to the year ended December 31, 2014.



	Successor			Predecessor
	(a)			(b)			(c)			(a) + (b) - (c)
(Dollars in thousands)	Period from November 6, 2015 to December 31, 2015			Period from January 1, 2015 to November 6, 2015			Year Ended December 31, 2014			Change			% Change
Domestic Offshore:
Number of rigs (as of end of period)	18			18			24
Revenue	$	9,859		$	131,308		$	497,209		$	(356,042	)	(71.6	)%
Operating expenses	8,966			95,279			261,399			(157,154		)	(60.1	)%
Asset impairment	—			—			199,508			(199,508		)	n/m
Depreciation and amortization expense	1,097			39,031			70,576			(30,448		)	(43.1	)%
General and administrative expenses	404			5,462			6,314			(448		)	(7.1	)%
Operating loss	$	(608	)	$	(8,464	)	$	(40,588	)	$	31,516		(77.6	)%
International Offshore:
Number of rigs (as of end of period)	9			9			9
Revenue	$	17,321		$	113,438		$	291,486		$	(160,727	)	(55.1	)%
Operating expenses	14,395			131,291			207,190			(61,504		)	(29.7	)%
Depreciation and amortization expense	1,870			71,033			75,672			(2,769		)	(3.7	)%
General and administrative expenses	2,691			6,225			8,322			594			7.1	%
Operating income (loss)	$	(1,635	)	$	(95,111	)	$	302		$	(97,048	)	n/m
International Liftboats:
Number of liftboats (as of end of period)	19			19			24
Revenue	$	5,262		$	58,460		$	111,556		$	(47,834	)	(42.9	)%
Operating expenses	6,314			45,418			74,647			(22,915		)	(30.7	)%
Depreciation and amortization expense	1,567			14,599			20,763			(4,597		)	(22.1	)%
General and administrative expenses	626			11,608			11,712			522			4.5	%
Operating income (loss)	$	(3,245	)	$	(13,165	)	$	4,434		$	(20,844	)	n/m
Total Company:
Revenue	$	32,442		$	303,206		$	900,251		$	(564,603	)	(62.7	)%
Operating expenses	29,675			271,988			543,236			(241,573		)	(44.5	)%
Asset impairment	—			—			199,508			(199,508		)	n/m
Depreciation and amortization expense	4,534			126,963			170,898			(39,401		)	(23.1	)%
General and administrative expenses	7,120			79,884			75,108			11,896			15.8	%
Operating loss	(8,887		)	(175,629		)	(88,499		)	(96,017		)	108.5	%
Interest expense	(7,939		)	(61,173		)	(99,142		)	30,030			(30.3	)%
Loss on extinguishment of debt	—			(1,884		)	(19,925		)	18,041			n/m
Reorganization items, net	(1,330		)	(357,050		)	—			(358,380		)	n/m
Other, net	(4,785		)	284			(39		)	(4,462		)	n/m
Loss before income taxes	(22,941		)	(595,452		)	(207,605		)	(410,788		)	197.9	%
Income tax provision	(728		)	(7,042		)	(8,505		)	735			(8.6	)%
Loss from continuing operations	(23,669		)	(602,494		)	(216,110		)	(410,053		)	189.7	%
Loss from discontinued operations, net of tax	—			—			—			—			n/m
Net loss	(23,669		)	(602,494		)	(216,110		)	(410,053		)	189.7	%
Loss attributable to noncontrolling interest	—			—			—			—			n/m
Net loss attributable to Hercules Offshore, Inc	$	(23,669	)	$	(602,494	)	$	(216,110	)	$	(410,053	)	189.7	%

_____________________________

"n/m" means not meaningful.

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The following table sets forth selected operational data by operating segment for the periods indicated:



	Successor
	Period from November 6, 2015 to December 31, 2015
	Operating Days	Available Days	Utilization(1)		Average Revenue per Day(2)		Average Operating Expense per Day(3)
Domestic Offshore	159	495	32.1	%	$	62,006	$	18,113
International Offshore	220	440	50.0	%	78,732		32,716
International Liftboats	298	990	30.1	%	17,658		6,378

	Predecessor
	Period from January 1, 2015 to November 6, 2015
	Operating Days	Available Days	Utilization(1)		Average Revenue per Day(2)		Average Operating Expense per Day(3)
Domestic Offshore	1,497	2,867	52.2	%	$	87,714	$	33,233
International Offshore	1,221	2,480	49.2	%	92,906		52,940
International Liftboats	2,776	6,686	41.5	%	21,059		6,793

	Predecessor
	Year Ended December 31, 2014
	Operating Days	Available Days	Utilization(1)		Average Revenue per Day(2)		Average Operating Expense per Day(3)
Domestic Offshore	4,624	6,243	74.1	%	$	107,528	$	41,871
International Offshore	2,025	2,875	70.4	%	143,944		72,066
International Liftboats	4,332	8,395	51.6	%	25,752		8,892

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(1)

Utilization is defined as the total number of days our rigs or liftboats, as applicable, were under contract, known as operating days, in the period as a percentage of the total number of available days in the period. Days during which our rigs and liftboats were undergoing major refurbishments, upgrades or construction, and days during which our rigs and liftboats are cold stacked, are not counted as available days. Days during which our liftboats are in the shipyard undergoing drydocking or inspection are considered available days for the purposes of calculating utilization.


(2)	Average revenue per rig or liftboat per day is defined as revenue earned by our rigs or liftboats, as applicable, in the period divided by the total number of operating days for our rigs or liftboats, as applicable, in the period.

(3)

Average operating expense per rig or liftboat per day is defined as operating expenses, excluding depreciation and amortization, incurred by our rigs or liftboats, as applicable, in the period divided by the total number of available days in the period. We use available days to calculate average operating expense per rig or liftboat per day rather than operating days, which are used to calculate average revenue per rig or liftboat per day, because we incur operating expenses on our rigs and liftboats even when they are not under contract and earning a dayrate.

2015 Compared to 2014

Revenue

Consolidated. The decrease in revenue is described below.

Domestic Offshore. Revenue decreased for our Domestic Offshore segment due to a decline in operating days and lower average dayrates.

International Offshore. Revenue for our International Offshore segment decreased primarily due to the following:


•	Hercules Triumph did not work in 2015 as it was in the shipyard in early 2015 preparing for North Sea operations and ready stacked the remainder of 2015;


•	Hercules Resilience was ready stacked during 2015;


•	Hercules 208 experienced lower utilization in 2015;

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•	Hercules 266 experienced a reduction in dayrate during 2015;


•	Hercules 267 experienced lower average dayrates and a decline in operating days in 2015; and


•	Hercules 262 experienced a reduction in dayrate and a decline in operating days in 2015 and 2014 included mobilization revenue.

International Liftboats. The decrease in revenue from our International Liftboats segment resulted from a decline in operating days and lower average revenue per vessel per day.

Operating Expenses

Consolidated. The decrease in operating expenses is described below.

Domestic Offshore. Operating expenses for our Domestic Offshore segment decreased across almost all expense categories. This decrease was partially offset by net gains on asset sales in 2014.

International Offshore. The decrease in operating expenses for our International Offshore segment is primarily due to the following:


•	Hercules Resilience was ready stacked in 2015;


•	Hercules Triumph was ready stacked most of 2015 and 2014 included costs to mobilize the rig from India to the North Sea;


•	Hercules 267 was ready and warm stacked during 2015, as compared to being in the shipyard for repairs and maintenance a portion of 2014;


•	Hercules 208 was ready and warm stacked a portion of 2015 which decreased operating expenses. This decrease was partially offset by costs incurred in 2015 for the rig's demobilization from India;


•	Hercules 261 experienced cost reductions in 2015 and 2014 included amortization of deferred contract preparation costs;


•	Hercules 262 experienced cost reductions in 2015 and 2014 included amortization of deferred contract preparation costs; partially offset by increases in operating expenses due to:


•	Hercules 258 gain on sale in April 2014; and


•	Hercules 260 was in the shipyard preparing for a contract a portion of 2015.

International Liftboats. The decrease in operating expenses for our International Liftboats segment is largely due to a reduction in the following expenses: labor, equipment rentals, contract labor, catering and travel.

Asset Impairment

During 2014, we recorded non-cash asset impairment charges of $199.5 million in our Domestic Offshore segment to write-down the Hercules 120, Hercules 200, Hercules 202, Hercules 204, Hercules 212, Hercules 213, Hercules 214, Hercules 251 and Hercules 253 to fair value based on a third-party estimate.

Depreciation and Amortization

Upon our emergence from Chapter 11, we applied the provisions of fresh-start accounting and revalued our property and equipment and drydocking asset to fair value which resulted in a decrease in those values. The decrease in depreciation and amortization is largely due to the reduction in asset values as a result of fresh start accounting as well as the impact of rigs impaired in 2014. These decreases are partially offset by additional depreciation related to capital projects.

General and Administrative Expenses

The increase in general and administrative expense is largely due to pre-petition costs related to financing and restructuring activities, partially offset by a gain on the settlement of a contractual dispute relating to the sale of certain of our assets in 2006.

Interest Expense

The decrease in interest expense is primarily due to the suspension of interest on Predecessor debt subsequent to the Chapter 11 filing.

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Reorganization Items, Net

Reorganization items represent amounts incurred subsequent to the bankruptcy filing as a direct result of the filing of the Chapter 11 Cases and are comprised of the following:



	Successor		Predecessor
(in thousands)	Period from November 6, 2015 to December 31, 2015		Period from January 1, 2015 to November 6, 2015
Professional Fees	$	1,330	$	12,819
Net Gain on Reorganization Adjustments	—		(686,559		)
Net Loss on Fresh-Start Adjustments	—		1,019,255
Non-Cash Expense for Write-off of Debt Issuance Costs Related to Predecessor Senior Notes (a)	—		11,535
Reorganization Items, Net	$	1,330	$	357,050

_____________________


(a)	The carrying value of debt that was subject to compromise was adjusted to include the related unamortized debt issuance costs; this adjusted debt amount was compared to the probable amount of claim allowed, which resulted in a non-cash expense of $11.5 million during the quarter ended September 30, 2015.

Other, Net

The Increase in other expense, net is primarily related to the loss on the embedded put option derivative due to the change in the fair market value from November 6, 2015 to December 31, 2015.

Loss on Extinguishment of Debt

During the Predecessor period January 1, 2015 to November 6, 2015, we terminated our Credit Facility and wrote off $1.8 million in associated unamortized debt issuance costs, as well as expensed $0.1 million in associated professional fees.

During 2014, we redeemed $300.0 million aggregate principal amount of our 7.125% Senior Secured Notes and expensed $16.9 million for the call premium and wrote off $1.9 million in unamortized debt issuance costs associated with these notes. In addition, we expensed $1.1 million in bank fees related to the issuance of the 6.75% Senior Notes.

Income Tax Provision

During 2015 income tax expense decreased by $0.7 million. Foreign income tax decreased due to a reduction in operations in foreign jurisdictions in 2015. The Predecessor period January 1, 2015 to November 6, 2015 includes a $0.9 million tax benefit related to an expiration of the statute of limitations of an unrecognized tax benefit. 2014 includes a $5.7 million tax benefit related to an expiration of the statute of limitations of an unrecognized tax benefit.

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The following table sets forth financial information by operating segment and other selected information for the periods indicated:



	Predecessor
	Year Ended December 31,
(Dollars in thousands)	2014			2013			Change			% Change
Domestic Offshore:
Number of rigs (as of end of period)	24			28
Revenue	$	497,209		$	522,705		$	(25,496	)	(4.9	)%
Operating expenses	261,399			232,166			29,233			12.6	%
Asset impairment	199,508			114,168			85,340			n/m
Depreciation and amortization expense	70,576			78,526			(7,950		)	(10.1	)%
General and administrative expenses	6,314			7,643			(1,329		)	(17.4	)%
Operating income (loss)	$	(40,588	)	$	90,202		$	(130,790	)	n/m
International Offshore:
Number of rigs (as of end of period)	9			10
Revenue	$	291,486		$	190,376		$	101,110		53.1	%
Operating expenses	207,190			145,650			61,540			42.3	%
Depreciation and amortization expense	75,672			51,759			23,913			46.2	%
General and administrative expenses	8,322			12,729			(4,407		)	(34.6	)%
Operating income (loss)	$	302		$	(19,762	)	$	20,064		n/m
International Liftboats:
Number of liftboats (as of end of period)	24			24
Revenue	$	111,556		$	145,219		$	(33,663	)	(23.2	)%
Operating expenses	74,647			83,516			(8,869		)	(10.6	)%
Depreciation and amortization expense	20,763			18,627			2,136			11.5	%
General and administrative expenses	11,712			5,501			6,211			112.9	%
Operating income	$	4,434		$	37,575		$	(33,141	)	(88.2	)%
Total Company:
Revenue	$	900,251		$	858,300		$	41,951		4.9	%
Operating expenses	543,236			461,332			81,904			17.8	%
Asset impairment	199,508			114,168			85,340			n/m
Depreciation and amortization expense	170,898			151,943			18,955			12.5	%
General and administrative expenses	75,108			79,425			(4,317		)	(5.4	)%
Operating income (loss)	(88,499		)	51,432			(139,931		)	n/m
Interest expense	(99,142		)	(73,248		)	(25,894		)	35.4	%
Loss on extinguishment of debt	(19,925		)	(29,295		)	9,370			n/m
Gain on equity investment	—			14,876