Edgar Filing: HERCULES OFFSHORE, INC.

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Accelerated filer o

Non-accelerated filer o

Smaller reporting company þ

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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

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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

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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

_____________________________


(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.

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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			(14,876		)	n/m
Other, net	(39		)	(1,518		)	1,479			(97.4	)%
Loss before income taxes	(207,605		)	(37,753		)	(169,852		)	449.9	%
Income tax benefit (provision)	(8,505		)	10,944			(19,449		)	n/m
Loss from continuing operations	(216,110		)	(26,809		)	(189,301		)	706.1	%
Loss from discontinued operations, net of taxes	—			(41,308		)	41,308			n/m
Net loss	(216,110		)	(68,117		)	(147,993		)	217.3	%
Loss attributable to noncontrolling interest	—			39			(39		)	n/m
Net loss attributable to Hercules Offshore, Inc.	$	(216,110	)	$	(68,078	)	$	(148,032	)	217.4	%

_____________________________

"n/m" means not meaningful.

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



	Predecessor
	Year Ended December 31, 2014
	Operating Days	Available Days	Utilization		Average Revenue per Day		Average Operating Expense per Day
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

	Predecessor
	Year Ended December 31, 2013
	Operating Days	Available Days	Utilization		Average Revenue per Day		Average Operating Expense per Day
Domestic Offshore	5,930	6,649	89.2	%	$	88,146	$	34,917
International Offshore	1,572	2,177	72.2	%	121,104		66,904
International Liftboats	5,900	8,336	70.8	%	24,613		10,019

2014 Compared to 2013

Revenue

Consolidated. The increase in consolidated revenue is described below.

Domestic Offshore. Revenue decreased for our Domestic Offshore segment due to a decline in operating days in 2014 as compared to 2013, which contributed to a decrease in revenue of approximately $140 million primarily due to lower demand, several rigs undergoing scheduled regulatory surveys and repairs as well as Hercules 265 being out of service in 2014. Partially offsetting this decrease, our Domestic Offshore segment realized higher average dayrates in 2014 as compared to 2013, which contributed to an increase of approximately $115 million.

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


•	$35.9 million increase from Hercules Triumph primarily due to the rig commencing work in November 2013;


•	$32.1 million increase from Hercules Resilience primarily due to the rig commencing work in February 2014;


•	$20.9 million increase from Hercules 208 primarily driven by the rig being in the shipyard during 2013 for a special survey as well as higher utilization in 2014 and mobilization revenue recognized in 2014;


•	$14.3 million increase from Hercules 266 as the rig commenced work in April 2013;


•	$14.9 million increase from Hercules 267 as the rig commenced work in November 2013;


•	$11.1 million increase related to the Perisai management agreement; partially offset by:


•	$14.2 million decrease from Hercules 260 as it was ready stacked during a portion of 2014 as well as 2013 including revenue for the reimbursement of certain costs from our customer related to the rig's spudcan damage; and


•	$7.3 million decrease from Hercules 261 primarily driven by the rig being in the shipyard during a significant portion of 2014 for a special survey.

International Liftboats. The decrease in revenue from our International Liftboats segment resulted largely from a decrease in utilization of the majority of our vessels in West Africa. This decrease was partially offset by a $6.5 million increase in revenue from our vessels in the Middle East.

Operating Expenses

Consolidated. The increase in consolidated operating expenses is described below.

Domestic Offshore. The increase in operating expenses for our Domestic Offshore segment related primarily to the following:


•	$25.8 million increase from Hercules 265 due to a $31.6 million gain on insurance settlement in 2013 partially offset by a reduction in operating expenses in 2014 due to the rig being out of service;


•	$4.6 million increase in labor costs in 2014 as compared to 2013;

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•	$5.9 million increase to state sales and use taxes in 2014 as compared to 2013;


•	$3.8 million increase to workers' compensation; partially offset by:


•	$3.1 million decrease to repairs and maintenance; and


•	$9.6 million in additional net gains on asset sales in 2014 as compared to 2013.

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


•	$29.7 million increase from Hercules Resilience primarily due to the rig commencing operations in February 2014;


•	$27.2 million increase from Hercules Triumph primarily due to the rig commencing operations in November 2013 and incurring costs in 2014 of approximately $8 million to mobilize the rig from India to the North Sea;


•	$25.3 million increase from Hercules 267 primarily due to the rig being in the shipyard in 2013 preparing for a contract;


•	$5.6 million increase related to the Perisai management agreement;


•	$4.1 million increase from Hercules 261 primarily driven by the rig being in the shipyard during a significant portion of 2014 for a special survey;


•	$3.9 million increase from Hercules 266 as the rig began working in April 2013; partially offset by a:


•	$10.5 million gain on the sale of Hercules 258 in 2014;


•	$11.5 million decrease from Hercules 170 due to a loss on its sale in 2013; and


•	$7.4 million decrease from Hercules 260 in 2014 as compared to 2013 primarily due to repair costs in 2013 related to the rig's spudcan damage.

International Liftboats. The decrease in operating expenses for our International Liftboats segment is primarily due to a $4.8 million reduction in repairs and maintenance costs in 2014 as compared to 2013 and a $2.6 million write down of the Croaker to fair market value in 2013.

Asset Impairment

In 2013, we recorded a non-cash asset impairment charge of $114.2 million in our Domestic Offshore segment which includes the write-down of Hercules 153, Hercules 203, Hercules 206 and Hercules 250 to fair value based on a third-party estimate.

Depreciation and Amortization

The increase in depreciation and amortization is largely due to the additional depreciation for the Hercules Resilience, Hercules Triumph, Hercules 267, Hercules 266 and other capital projects, which contributed to increases of $8.2 million, $6.8 million, $5.9 million, $2.9 million and $15.5 million, respectively. These increases are partially offset by a reduction in depreciation of $15.2 million due to rigs impaired in 2013 and the third quarter of 2014 and $3.6 million due to the sale of Hercules 170 in 2013.

General and Administrative Expenses

The decrease in general and administrative expenses is primarily related to a $6.7 million decrease to labor costs, primarily in Corporate, and a $2.6 million decrease to professional fees, primarily in our International Offshore segment. These decreases are partially offset by a $5.0 million increase to bad debt provision in 2014 as compared to 2013 primarily related to a customer in our International Liftboat segment.

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Interest Expense

The increase in interest expense for 2014 is primarily due to $18.0 million in interest on our 8.75% Senior Notes due 2021 which were issued in July 2013 as well as a reduction in interest capitalization of $16.0 million in 2014 as compared to 2013. 2013 included interest capitalization on upgrade and reactivation projects and the Hercules Triumph project which were all completed in 2013, and the Hercules Resilience project which was completed in February 2014, while 2014 includes interest capitalization on the Hercules Resilience and Hercules Highlander projects. These increases in interest expense are partially offset by a $7.9 million reduction in interest expense associated with the redemption of our 10.5% Senior Notes and refinancing these notes with the issuance of our 7.5% Senior Notes in the fourth quarter of 2013.

Loss on Extinguishment of Debt

During the fourth quarter of 2013, we redeemed $300.0 million aggregate principal amount of our 10.5% Senior Notes and expensed $17.3 million for the call premium, as well as wrote off $4.2 million and $4.8 million in unamortized debt issuance costs and unamortized discount associated with these notes. Additionally, we expensed $3.0 million in bank fees related to the October 2013 refinancing of these notes with the issuance of the 7.5% Senior Notes.

Gain on Equity Investment

During 2013, we recognized a gain of $14.9 million as a result of remeasuring our 32% equity interest in Discovery at its fair value as of the acquisition date of a controlling interest in Discovery in June 2013.

Income Tax Benefit (Provision)

During 2014, we generated income tax expense from continuing operations of $8.5 million, compared to an income tax benefit from continuing operations of $10.9 million, during 2013. The change is primarily related to the $37.7 million tax benefit recorded in 2013 related to the tax attributes received from the Seahawk Transaction net of a valuation allowance. Additionally, the variation is due to the change to the US valuation allowance partially offset by the tax effect of the mix of earnings (losses) from different jurisdictions, and the impact of discrete items.

Discontinued Operations

In 2013, we had a loss from our former Inland and Domestic Liftboat operations of $37.0 million, net of taxes, and $4.3 million, net of taxes, respectively. These losses included a pre-tax non-cash asset impairment charge of $40.9 million and $3.5 million for the former Inland and Domestic Liftboat operations, respectively, to write down the assets to fair value less estimated costs to sell. Additionally, the loss from our former Inland operations includes a $4.8 million pre-tax gain on the sale of Hercules 27 in August 2013. The sale of these assets was completed in the third quarter of 2013.

Non-GAAP Financial Measures

Regulation G, General Rules Regarding Disclosure of Non-GAAP Financial Measures and other SEC regulations define and prescribe the conditions for use of certain Non-Generally Accepted Accounting Principles (“Non-GAAP”) financial measures. We use various Non-GAAP financial measures such as adjusted operating income (loss), adjusted income (loss) from continuing operations, adjusted diluted earnings (loss) per share from continuing operations, EBITDA and Adjusted EBITDA. EBITDA is defined as net income plus interest expense, income taxes, depreciation and amortization. We believe that in addition to GAAP based financial information, Non-GAAP amounts are meaningful disclosures for the following reasons: i) each are components of the measures used by our board of directors and management team to evaluate and analyze our operating performance and historical trends, ii) each are components of the measures used by our management team to make day-to-day operating decisions, iii) under certain scenarios the Predecessor Credit Agreement required us to maintain compliance with a maximum secured leverage ratio, which contained Non-GAAP adjustments as components, iv) the Successor Credit Agreement requires us to maintain compliance with a maximum senior secured first lien leverage ratio, which contains Non-GAAP adjustments as components, v) each are components of the measures used by our management to facilitate internal comparisons to competitors’ results and the shallow-water drilling and marine services industry in general, vi) results excluding certain costs and expenses provide useful information for the understanding of the ongoing operations without the impact of significant special items, and vii) the payment of certain bonuses to members of our management is contingent upon, among other things, the satisfaction by the Company of financial targets, which may contain Non-GAAP measures as components. We acknowledge that there are limitations when using Non-GAAP measures. The measures below are not recognized terms under GAAP and do not purport to be an alternative to income from continuing operations or net income as a measure of operating performance or to cash flows from operating activities as a measure of liquidity. EBITDA and Adjusted EBITDA are not intended to be a measure of free cash flow for management’s discretionary use, as it does not consider certain

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cash requirements such as tax payments and debt service requirements. Because all companies do not use identical calculations, the amounts below may not be comparable to other similarly titled measures of other companies.

The following tables present a reconciliation of the GAAP financial measures to the corresponding adjusted financial measures (in thousands, except per share amounts):



	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
Operating Income (Loss) attributable to Hercules Offshore, Inc.	$	(8,887	)	$	(175,629	)	$	(88,499	)	$	51,471
Adjustments:
Asset impairment	—			—			199,508			114,168
Net (gain) loss on sale of assets	—			3,564			(22,620		)	—
Gain on Hercules 265 insurance settlement	—			—			—			(31,600		)
Loss on sale of Hercules 170	—			—			—			11,498
Costs related to financing and restructuring activities	—			18,879			—			—
Loss on stock-based compensation due to bankruptcy	—			8,110			—			—
Gain on settlement of contractual dispute	—			(5,220		)	—			—
Total adjustments	—			25,333			176,888			94,066
Adjusted Operating Income (Loss)	$	(8,887	)	$	(150,296	)	$	88,389		$	145,537
Loss from Continuing Operations attributable to Hercules Offshore, Inc.	$	(23,669	)	$	(602,494	)	$	(216,110	)	$	(26,770	)
Adjustments:
Asset impairment	—			—			199,508			114,168
Net (gain) loss on sale of assets	—			3,564			(22,620		)	—
Gain on Hercules 265 insurance settlement	—			—			—			(31,600		)
Loss on sale of Hercules 170	—			—			—			11,498
Costs related to financing and restructuring activities	—			18,879			—			—
Loss on stock-based compensation due to bankruptcy	—			8,110			—			—
Gain on settlement of contractual dispute	—			(5,220		)	—			—
Reorganization items, net	1,330			357,050			—			—
Loss on extinguishment of debt	—			1,884			19,925			29,295
Gain on equity investment	—			—			—			(14,876		)
Tax benefit (a)	—			—			—			(37,729		)
Total adjustments	1,330			384,267			196,813			70,756
Adjusted Income (Loss) from Continuing Operations	$	(22,339	)	$	(218,227	)	$	(19,297	)	$	43,986
Diluted Loss per Share from Continuing Operations	$	(1.18	)	$	(3.73	)	$	(1.35	)	$	(0.17	)
Adjustments:
Asset impairment	—			—			1.24			0.71
Net (gain) loss on sale of assets	—			0.02			(0.14		)	—
Gain on Hercules 265 insurance settlement	—			—			—			(0.20		)
Loss on sale of Hercules 170	—			—			—			0.07
Costs related to financing and restructuring activities	—			0.12			—			—
Loss on stock-based compensation due to bankruptcy	—			0.05			—			—
Gain on settlement of contractual dispute	—			(0.03		)	—			—
Reorganization items, net	0.06			2.21			—			—
Loss on extinguishment of debt	—			0.01			0.13			0.18
Gain on equity investment	—			—			—			(0.09		)
Tax benefit (a)	—			—			—			(0.23		)
Total adjustments	0.06			2.38			1.23			0.44
Adjusted Diluted Earnings (Loss) per Share from Continuing Operations	$	(1.12	)	$	(1.35	)	$	(0.12	)	$	0.27

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	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
Loss from Continuing Operations attributable to Hercules Offshore, Inc.	$	(23,669	)	$	(602,494	)	$	(216,110	)	$	(26,770	)
Interest expense	7,939			61,173			99,142			73,248
Income tax provision (benefit)	728			7,042			8,505			(10,944		)
Depreciation and amortization	4,534			126,963			170,898			151,943
EBITDA	(10,468		)	(407,316		)	62,435			187,477
Adjustments:
Asset impairment	—			—			199,508			114,168
Net (gain) loss on sale of assets	—			3,564			(22,620		)	—
Gain on Hercules 265 insurance settlement	—			—			—			(31,600		)
Loss on sale of Hercules 170	—			—			—			11,498
Costs related to financing and restructuring activities	—			18,879			—			—
Loss on stock-based compensation due to bankruptcy	—			8,110			—			—
Gain on settlement of contractual dispute	—			(5,220		)	—			—
Reorganization items, net	1,330			357,050			—			—
Loss on extinguishment of debt	—			1,884			19,925			29,295
Gain on equity investment	—			—			—			(14,876		)
Total adjustments	1,330			384,267			196,813			108,485
Adjusted EBITDA	$	(9,138	)	$	(23,049	)	$	259,248		$	295,962

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(a) Tax benefit recognized of $37.7 million related to the change in characterization of the Seahawk acquisition for tax purposes from a purchase of assets to a reorganization.

Critical Accounting Policies

Critical accounting policies are those that are important to our results of operations, financial condition and cash flows and require management’s most difficult, subjective or complex judgments. Different amounts would be reported under alternative assumptions. We have evaluated the accounting policies used in the preparation of the consolidated financial statements and related notes appearing elsewhere in this annual report. We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with accounting principles generally accepted in the United States. We believe that our policies are generally consistent with those used by other companies in our industry. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates.

We periodically update the estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. Projected business and general economic environment are impacted by prices for crude oil and natural gas, which can at times be volatile, such as the recent decline in crude oil and natural gas prices. To the extent prices decline, coupled with the severity and duration of such decline, this may adversely impact the business of our customers, and in turn our business. This could result in changes to estimates used in preparing our financial statements, including the assessment of certain of our assets for impairment.

Our significant accounting policies are summarized in Note 2 to our consolidated financial statements. We believe that our more critical accounting policies include those related to property and equipment, revenue recognition, income taxes, stock-based compensation and accrued self-insurance reserves. Inherent in such policies are certain key assumptions and estimates.

Property and Equipment

Depreciation is computed using the straight-line method, after allowing for salvage value where applicable, over the useful life of the asset, which ranges from 10 to 30 years for our rigs and liftboats. The carrying value of long-lived assets, principally property and equipment, is reviewed for potential impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when reclassifications are made between property and equipment and assets held for sale. Factors that might indicate a potential impairment may include, but are not limited to, significant

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decreases in the market value of the long-lived asset, a significant change in the long-lived asset’s physical condition, a change in industry conditions or a substantial reduction in cash flows associated with the use of the long-lived asset. For property and equipment held for use, the determination of recoverability is made based upon the estimated undiscounted future net cash flows of the related asset or group of assets being evaluated. Actual impairment charges are recorded using an estimate of discounted future cash flows. This evaluation requires us to make judgments regarding long-term forecasts of future revenue and costs. In turn these forecasts are uncertain in that they require assumptions about demand for our services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. Given the nature of these evaluations and their application to specific asset groups and specific times, it is not possible to reasonably quantify the impact of changes in these assumptions.

Supply and demand are the key drivers of rig and vessel utilization and our ability to contract our rigs and vessels at economical rates. During periods of an oversupply, it is not uncommon for us to have rigs or vessels idled for extended periods of time, which could indicate that an asset group may be impaired. Our rigs and vessels are mobile units, equipped to operate in geographic regions throughout the world and, consequently, we may move rigs and vessels from an oversupplied region to one that is more lucrative and undersupplied when it is economical to do so. As such, our rigs and vessels are considered to be interchangeable within classes or asset groups and accordingly, we perform our impairment evaluation by asset group.

Our estimates, assumptions and judgments used in the application of our property and equipment accounting policies reflect both historical experience and expectations regarding future industry conditions and operations. Using different estimates, assumptions and judgments, especially those involving the useful lives and salvage values of our rigs and liftboats and expectations regarding future industry conditions and operations, would result in different carrying values of assets and results of operations. For example, a prolonged downturn in the drilling industry in which utilization and dayrates were significantly reduced could result in an impairment of the carrying value of our assets.

Useful lives of rigs and vessels are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. We evaluate the remaining useful lives of our rigs and vessels when certain events occur that directly impact our assessment of the remaining useful lives of the rigs and vessels and include changes in operating condition, functional capability and market and economic factors. We also consider major capital upgrades required to perform certain contracts and the long-term impact of those upgrades on the future marketability when assessing the useful lives and salvage values of individual rigs and vessels.

When analyzing our assets for impairment, we separate our marketable assets, those assets that are actively marketed and can be warm stacked or cold stacked for short periods of time depending on market conditions, from our non-marketable assets, those assets that have been cold stacked for an extended period of time or those assets that we currently do not reasonably expect to market in the foreseeable future.

Revenue Recognition

Revenue generated from our contracts is recognized as services are performed, as long as collectability is reasonably assured. For certain contracts, we may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one location to another are recognized as services are performed over the term of the related drilling contract. For certain contracts, we may receive fees from our customers for capital improvements to our rigs. Such fees are deferred and recognized as services are performed over the term of the related contract. We capitalize such capital improvements and depreciate them over the useful life of the asset. Certain of our contracts also allow us to recover additional direct costs, such as demobilization costs, additional labor and additional catering costs and under most of our liftboat contracts, we receive a variable rate for reimbursement of costs such as catering, oil, rental equipment and other items. Revenue for the recovery or reimbursement of these costs is recognized when the costs are incurred.

Accrued Self-Insurance Reserves

We are self-insured up to certain retention limits for maritime employer's liability claims and protection and indemnity claims. The amounts in excess of the self-insured levels are fully insured, up to a limit. Self-insurance reserves are based on estimates of (i) claims reported and (ii) loss amounts incurred but not reported. Reserves for reported claims are estimated by our internal risk department by evaluating the facts and circumstances of each claim and are adjusted from time to time based upon the status of each claim and our historical experience with similar claims. Reserves for loss amounts incurred but not reported are estimated by our third-party actuary and include provisions for expected development on claims reported due to information not yet received and expected development on claims to be reported in the future but which have occurred prior to the accounting date. As of December 31, 2015 and 2014, there was $18.5 million and $24.5 million in accrued self-insurance reserves, respectively, which is included in Accrued Liabilities on the Consolidated Balance Sheets. The actual outcome of any claim could differ significantly from estimated amounts.

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Income Taxes

Our net income tax expense or benefit is determined based on the mix of domestic and international pre-tax earnings or losses, respectively, as well as the tax jurisdictions in which we operate. We operate in multiple countries through various legal entities. As a result, we are subject to numerous domestic and foreign tax jurisdictions and are taxed on various bases: income before tax, deemed profits (which is generally determined using a percentage of revenue rather than profits), and withholding taxes based on revenue. The calculation of our tax liabilities involves consideration of uncertainties in the application and interpretation of complex tax regulations in our operating jurisdictions. Changes in tax laws, regulations, agreements and treaties, or our level of operations or profitability in each taxing jurisdiction could have an impact upon the amount of income taxes that we provide during any given year.

Stock-Based Compensation

We recognize compensation cost for all share-based payments awarded in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 718, Compensation — Stock Compensation (“ASC 718”) and in accordance with such we record the grant date fair value of time-based restricted stock awarded as compensation expense using a straight-line method over the requisite service period. Performance based awards were recognized using the accelerated method over the requisite service period. The fair value of our awards that are share settled are based on the closing price of our common stock on the date of grant. For those performance based grants that contained a market performance condition, the Monte Carlo simulation was used for valuation as of the date of grant. All of our cash settled awards were recorded as a liability at fair value, which was remeasured at the end of each reporting period, over the requisite service period. Our cash settled liability awards that contained market performance conditions were valued using a Monte Carlo simulation. We also estimate future forfeitures and related tax effects. Our estimate of compensation expense requires a number of assumptions and changes to those assumptions could result in different valuations for individual share awards. On the Effective Date, all share-based awards requiring share settlement that were granted under the Predecessor were canceled. Certain award agreements requiring cash settlement contained change of control provisions which provided for vesting. The Successor Company has only granted time-based restricted stock.

Our estimate of future expense relating to restricted stock awards granted through December 31, 2015 as well as the remaining vesting period over which the associated expense is to be recognized is presented in the table below; however, due to the uncertainty in the level of awards to be granted in the future, these amounts are estimates and subject to change.



	December 31, 2015
	Unrecognized Compensation Expense		Weighted Average Remaining Term
	(in thousands)		(in years)
Time-based Restricted Stock Awards	$	434	0.9

OUTLOOK

Offshore

Demand for our oilfield services is driven by our exploration and production ("E&P") customers' capital spending, which can experience significant fluctuations depending on current commodity prices and their expectations of future price levels, among other factors. Based on 2016 capital spending surveys, we expect both domestic and international focused exploration and production capital spending will decrease significantly from already declining 2015 levels.

Drilling activity levels in the shallow-water U.S. Gulf of Mexico are dependent on crude oil and natural gas prices, prospectivity of hydrocarbons, capital budgets of our customers as well as their ability to obtain necessary drilling permits to operate in the region.

The supply of marketed jackup rigs in the U.S. Gulf of Mexico has declined significantly since 2008, driven by events such as the financial crisis that began in late 2008, the imposition of new regulations after the Macondo incident in 2010, the consolidation of domestic customers that began in 2013 and continued in 2014, and the sharp decline in crude oil prices since mid-2014. Such events have led drilling contractors, including us, to cold stack, or no longer actively market, a number of rigs in the region. In other instances, rigs have been sold for conversion purposes, scrapped, or mobilized out of the U.S. Gulf of Mexico. As a result, the number of existing, actively marketed jackup rigs in the U.S. Gulf of Mexico, has declined from approximately 63 rigs in late 2008 to 21 rigs as of March 23, 2016, of which 9 are ours.

The fall in the price of crude oil, coupled with the consolidation of the domestic customer base, have negatively impacted demand for jackup rigs in the U.S. Gulf of Mexico. Jackup rig demand in the region, as defined by rigs under contract, has

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fallen from 31 rigs on July 21, 2014 to 6 rigs as of March 23, 2016. We expect the overall environment for rig demand to remain relatively soft through 2016, assuming commodity prices remain at or near current levels. Given these market conditions, we have executed a number of cost saving measures, including our decision to cold stack and warm stack over half of our domestic rigs since the fourth quarter of 2014. We currently believe that this is an appropriate step to reduce costs, better balance the market and support utilization on our marketed rigs. However, should we see indicators of stronger demand, we will have capacity ready to respond timely to these signals.

Demand for rigs in our International Offshore segment is primarily dependent on crude oil prices. Due to the sharp drop in crude oil prices, international capital spending budgets for 2016 is expected to be lower than prior years. This will have negative implications for jackup demand for all classes of rigs. In addition, new capacity that have entered the market over the past three years as well as new capacity growth expected over the next five years could put further pressure on the operating environment for the existing jackup rig fleet. The number of existing marketed jackup rigs, outside of the U.S. Gulf of Mexico, have increased from 394 rigs as of January 2, 2013 to 451 rigs as of March 23, 2016. Furthermore, as of March 23, 2016, there are approximately 124 jackup rigs under construction, on order and planned for delivery worldwide through 2020. One of the new rigs under construction is the Hercules Highlander. The Company has made significant progress on the construction of the Hercules Highlander, and the rig is scheduled to be delivered from the shipyard in Singapore during the second quarter 2016. Shortly after delivery of the Hercules Highlander, the rig will be mobilized to the U.K. North Sea, where it will commence operations under a five year contract with the customer Maersk Oil.

Liftboats

Demand for liftboats is typically a function of our customers' demand for offshore infrastructure construction, inspection and maintenance, well maintenance, well plugging and abandonment, and other related activities. Although activity levels for liftboats are not as closely correlated to commodity prices as our drilling segments, commodity prices are still a key driver of liftboat demand. Since early 2014, demand for liftboat services in West Africa has been weak. We believe this has been driven by budgetary constraints with major customers primarily in Nigeria, which we expect will continue through 2016. Additional supply of vessels mobilized into the region could also impact the utilization and pricing for our liftboat fleet. Utilization can and has been negatively impacted by local labor disputes, regional conflicts and other political events, particularly in West Africa. In the Middle East, we expect demand for liftboats to be a function of construction and well servicing activity levels. Due to the decline of oil prices, several construction projects previously planned in the region have been deferred to the latter part of 2016 or canceled. As a result, the Company expects activity levels in the Middle East to be weak through at least the first half of 2016.

Over the long term, we believe that international liftboat demand will benefit from (i) the aging offshore infrastructure and maturing offshore basins, (ii) desire by our customers to economically produce from these mature basins and service their infrastructure and (iii) the cost advantages of liftboats to perform these services relative to alternatives. Tempering this demand outlook is (i) the risk of a prolonged period of low oil prices impacting production-related activity, (ii) our expectation of increased competition from newly constructed liftboats and mobilizations of existing liftboats primarily from the U.S. Gulf of Mexico to international markets, (iii) the risk of recurring political, social and union unrest, principally in West Africa and (iv) increased pressure to have local ownership of assets, principally in Nigeria.

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LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

Sources and uses of cash are as follows (in millions):



	Successor			Predecessor
	Period from November 6, 2015 to December 31, 2015			Period from January 1, 2015 to November 6, 2015			Year Ended December 31, 2014
Net Cash Provided by (Used in) Operating Activities	$	(26.5	)	$	(9.6	)	$	114.7
Net Cash Provided by (Used in) Investing Activities:
Capital Expenditures	(5.1		)	(78.1		)	(147.5		)
Increase in Restricted Cash	—			(200.0		)	—
Insurance Proceeds Received	—			3.5			9.1
Proceeds from Sale of Assets, Net	0.1			9.7			35.1
Other	0.4			0.3			1.5
Total Cash Provided by (Used in) Investing Activities	(4.6		)	(264.6		)	(101.8		)
Net Cash Provided by (Used in) Financing Activities:
Long-term Debt Borrowings	—			436.5			300.0
Redemption of 7.125% Senior Secured Notes	—			—			(300.0		)
Payment of Debt Issuance Costs	—			(8.4		)	(3.9		)
Other	—			—			0.5
Total Cash Provided by (Used in) Financing Activities:	—			428.1			(3.4		)
Net Increase (Decrease) in Cash and Cash Equivalents	$	(31.1	)	$	153.9		$	9.5

Sources of Liquidity and Financing Arrangements

Our liquidity is comprised of cash on hand and cash from operations. We currently believe we will have adequate liquidity to fund our operations through at least December 31, 2016. However, to the extent we do not generate sufficient cash from operations we may need to raise additional funds through debt, equity offerings or the sale of assets. Furthermore, we may need to raise additional funds through debt or equity offerings or asset sales to refinance existing debt, to fund capital expenditures or for general corporate purposes.

Cash Requirements and Contractual Obligations

Our current debt structure is used to fund our business operations.

Senior Secured Credit Facility

On November 6, 2015 (the “Credit Agreement Closing Date”), we entered into a Credit Agreement (the “Credit Agreement”) that provides for a $450.0 million senior secured credit facility ("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 pursuant to an Escrow Agreement and will be released pursuant to the terms of such Agreement. The Escrowed Amount is 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 (See the information set forth in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview). The remaining proceeds of the loans are being used to consummate the Plan, fund fees and expenses in connection therewith, and to provide for working capital and other general corporate purposes of us and our subsidiaries. All loans under the Credit Agreement mature on May 6, 2020.

We may voluntarily prepay loans under the Credit Agreement, subject to customary notice requirements and minimum prepayment amounts, the payment of LIBOR breakage costs, if any, and (i) if such prepayment is made prior to the third anniversary of the Credit Agreement Closing Date, a prepayment premium of 3.0% of the principal amount of the loans being prepaid plus the present value of the sum of all required payments of interest on the aggregate principal amount of the loans being prepaid through the third anniversary of the Credit Agreement Closing Date, (ii) if such prepayment made after the third anniversary of the Credit Agreement Closing Date but on or prior to the fourth anniversary of the Credit Agreement Closing Date, a prepayment premium of 3.0% of the aggregate principal amount of the loans being prepaid and (iii) if such prepayment is made after the fourth anniversary of the Credit Agreement Closing Date, without premium or penalty.

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The Credit Agreement requires mandatory prepayments of amounts outstanding thereunder with (i) the net proceeds of certain asset sales and casualty events, subject to certain reinvestment rights, (ii) the net proceeds of certain equity issuances, subject to certain exceptions, including with respect to equity issuances used to finance acquisitions, (iii) the net proceeds of debt issuances not permitted by the Credit Agreement, (iv) any cancellation, termination or other fee received in connection with the cancellation or termination of the construction contract or drilling contract for the Hercules Highlander, and (v) the Escrowed Amount if the Escrow Conditions are not satisfied. No prepayment premium is payable in connection with any of these mandatory prepayments, unless the mandatory prepayment is a result of the issuance of debt not permitted by the Credit Agreement. In addition, if a change of control (as defined in the Credit Agreement) occurs, each lender will have the right to require us to prepay our loans at 101% of the principal amount of the loans requested to be prepaid.

Loans under the Credit Agreement bear interest, at our 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, we 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) in aggregate a total of $9.0 million, and we paid certain administrative and other fees to the Agent of $1.2 million.

The Credit Agreement contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to:

• incur indebtedness;

• create liens;

• enter into sale and leaseback transactions;

• 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);

• consolidate, merge or transfer all or substantially all of its assets;

• sell assets;

• engage in transactions with its affiliates;

• modify or terminate any material agreement;

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

• engage in any new line of business.

These covenants are subject to a number of important qualifications and limitations. In addition, we have to maintain compliance with (i) a maximum senior secured first lien leverage ratio (as defined in the Credit Agreement, being generally computed as the ratio of secured first lien debt to consolidated net income before interest, taxes, depreciation and amortization, which EBITDA amount will be annualized for any test period during 2017) commencing from the fiscal quarter ending March 31, 2017 and (ii) a minimum liquidity amount, consisting of unrestricted cash and cash equivalents, commencing from the Credit Agreement Closing Date. The maximum secured leverage ratio is 6.0 to 1.0 for the fiscal quarter ending March 31, 2017, 5.0 to 1.0 for the fiscal quarter ending June 30, 2017, 4.0 to 1.0 for the fiscal quarter ending September 30, 2017, and 3.5 to 1.0 for the fiscal quarter ending December 31, 2017 and thereafter. The minimum liquidity is $100.0 million for the period beginning on the Credit Agreement Closing Date and ending on June 30, 2016, $75.0 million for the period beginning July 1, 2016 and ending December 31, 2016, $50.0 million for the period beginning January 1, 2017 and ending June 30, 2017, and $25.0 million for the period beginning July 1, 2017 and thereafter. At December 31, 2015, we were in compliance with all covenants under our Senior Secured Credit Facility.

Our obligations under the Credit Agreement are guaranteed by substantially all of our domestic and foreign subsidiaries, and the obligations of us 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. Upon an event of default under the Credit Agreement, the Agent may, or at the direction of lenders holding a majority of the loans under the Credit Agreement shall, declare all amounts owing under the Credit Agreement to be due and payable. In addition, upon an event of default under the Credit Agreement the Agent is empowered to exercise all rights and remedies of a secured party and foreclose upon the collateral securing the Credit Agreement, in addition to all other rights and remedies under the security documents described in the Credit Agreement. Upon any acceleration of the loans under the Credit Agreement, the prepayment premiums described above that are otherwise applicable to voluntary prepayments shall become due and payable to the lenders.

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Embedded Derivative

We identified an embedded derivative related to a put option feature included in the Senior Secured Credit Facility, where, upon the occurrence of certain events of default and where we are not able to obtain a waiver from our lenders, the principal amount of our debt could be accelerated and 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. The accounting treatment of derivative financial instruments requires us to bifurcate and fair value the derivative as of the inception date of the Senior Secured Credit Facility and to fair value the derivative as of each subsequent reporting date.

Upon issuance of the Senior Secured Credit Facility on November 6, 2015, the Company received net proceeds of approximately $436.5 million, incurred debt issuance costs of approximately $11.0 million, and recognized a derivative financial instrument approximating $8.5 million. After these adjustments, the debt approximated $417.0 million.

In connection with fresh-start accounting, the debt was recorded at fair value of $428.0 million which was determined using an Income Approach, specifically the risk-neutral method. The difference between the $450.0 million face amount and the fair value recorded in fresh-start accounting is being amortized over 4.5 years, the current expected life of the debt.

Cancellation of Indebtedness

In accordance with the Plan, on the Effective Date all of the obligations of the Debtors with respect to the 8.75% Senior Notes, 7.5% Senior Notes, 6.75% Senior Notes, 10.25% Senior Notes, 3.375% Convertible Senior Notes and 7.375% Senior Notes were canceled (See the information set forth in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview).

Termination of Credit Facility

On April 3, 2012, we entered into a credit agreement which as amended on July 8, 2013 (the "Predecessor Credit Agreement") governed our senior secured revolving credit facility (the "Credit Facility"). The Predecessor Credit Agreement provided for a $150.0 million senior secured revolving credit facility.

In connection with the RSA, we terminated the Credit Facility effective June 22, 2015 (See the information set forth in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview). There were no amounts outstanding and no letters of credit issued under the Credit Facility at that time. Liens on our vessels that secured the Credit Facility have been released. We maintained compliance with all covenants under the Credit Facility through the termination date and have paid all fees in full.

8.75% Senior Notes due 2021

On July 8, 2013, we completed the issuance and sale of $400.0 million aggregate principal amount of senior notes at a coupon rate of 8.75% ("8.75% Senior Notes") with maturity in July 2021. These notes were sold at par and we received net proceeds from the offering of the notes of approximately $393.0 million after deducting the bank fees and estimated offering expenses. The net proceeds from this offering, together with cash on hand (including the proceeds of approximately $103.9 million we received from the sales of our inland barge rigs, domestic liftboats and related assets), were used to fund our acquisition of Discovery shares, the final shipyard payments totaling $333.9 million for Hercules Triumph and Hercules Resilience, related capital expenditures, as well as general corporate purposes. In accordance with the Plan, on the Effective Date all of the obligations of the Debtors with respect to the 8.75% Senior Notes were canceled (See the information set forth in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview).

7.5% Senior Notes due 2021

On October 1, 2013, we completed the issuance and sale of $300.0 million aggregate principal amount of senior notes at a coupon rate of 7.5% ("7.5% Senior Notes") with maturity in October 2021. These notes were sold at par and we received net proceeds from the offering of the notes of approximately $294.5 million after deducting the bank fees and estimated offering expenses. In accordance with the Plan, on the Effective Date all of the obligations of the Debtors with respect to the 7.5% Senior Notes were canceled (See the information set forth in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview).

6.75% Senior Notes due 2022

On March 26, 2014, we completed the issuance and sale of $300.0 million aggregate principal amount of senior notes at a coupon rate of 6.75% ("6.75% Senior Notes") with maturity in April 2022. These notes were sold at par and we received net proceeds from the offering of the notes of approximately $294.8 million after deducting bank fees and estimated offering expenses. In accordance with the Plan, on the Effective Date all of the obligations of the Debtors with respect to the 6.75% Senior Notes were canceled (See the information set forth in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview).

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10.25% Senior Notes due 2019

On April 3, 2012, we completed the issuance and sale of $200.0 million aggregate principal amount of senior notes at a coupon rate of 10.25% (“10.25% Senior Notes”) with maturity in April 2019. These notes were sold at par and we received net proceeds from the offering of the notes of $195.4 million after deducting the initial purchasers' discounts and offering expenses. In accordance with the Plan, on the Effective Date all of the obligations of the Debtors with respect to the 10.25% Senior Notes were canceled (See the information set forth in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview).

3.375% Convertible Senior Notes due 2038

In May 2012, we repurchased a portion of the 3.375% Convertible Senior Notes and in accordance with ASC 470-20 Debt - Debt with Conversion and Other Options, the settlement consideration was allocated to the extinguishment of the liability component in an amount equal to the fair value of that component immediately prior to extinguishment with the difference between this allocation and the net carrying amount of the liability component and unamortized debt issuance costs recognized as a gain or loss on debt extinguishment. If there would have been any remaining settlement consideration, it would have been allocated to the reacquisition of the equity component and recognized as a reduction of equity.

On May 1, 2013, we made an offer to purchase all of the outstanding notes in accordance with our repurchase obligation under the indenture and on June 1, 2013 repurchased $61.3 million aggregate principal amount of the 3.375% Convertible Senior Notes pursuant to the terms of the optional put repurchase offer. In accordance with the Plan, on the Effective Date all of the obligations of the Debtors with respect to the 3.375% Convertible Senior Notes were canceled (See the information set forth in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview).

Retirement of 10.5% Senior Notes

In 2009, we issued $300.0 million of senior notes at a coupon rate of 10.5% ("10.5% Senior Notes") with maturity in October 2017. On September 17, 2013, we commenced a cash tender offer (the "Tender offer") for any and all of the $300.0 million outstanding aggregate principal amount of our 10.5% Senior Notes. Senior notes totaling approximately $253.6 million were settled on October 1, 2013 for $268.5 million using a portion of the proceeds from the issuance of the 7.5% Senior Notes. Additionally, on November 4, 2013 we redeemed all $46.4 million of the remaining outstanding 10.5% Senior Notes for approximately $48.8 million using the remaining proceeds from the 7.5% Senior Notes offering, together with cash on hand.

Retirement of 7.125% Senior Secured Notes

In 2012, we issued $300.0 million of senior secured notes at a coupon rate of 7.125% ("7.125% Senior Secured Notes") with maturity in April 2017. On March 12, 2014 we commenced a cash tender offer (the "Tender offer") for any and all of the $300.0 million outstanding aggregate principal amount of our 7.125% Senior Secured Notes. Senior secured notes totaling approximately $220.1 million were settled on March 26, 2014 for $232.7 million using a portion of the proceeds from the issuance of the 6.75% Senior Notes. Additionally, on April 29, 2014, we redeemed all $79.9 million of the remaining outstanding 7.125% Senior Secured Notes for approximately $84.2 million using the remaining net proceeds from the 6.75% Senior Notes offering, together with cash on hand.

Loss on Extinguishment of Debt

During the period from January 1, 2015 to November 6, 2015 and the years ended December 31, 2014 and 2013, we incurred the following charges which are included in Loss on Extinguishment of Debt in the Consolidated Statements of Operations for their respective periods:


•	During the fourth quarter of 2013, we incurred a pretax charge of $29.3 million, consisting of a $17.3 million call premium, $4.8 million unamortized debt discount costs and $4.2 million unamortized debt issuance costs, all related to the redemption of the 10.5% Senior Notes, as well as approximately $3.0 million of bank fees related to the issuance of the 7.5% Senior Notes;


•	In March 2014, we incurred a pretax charge of $15.2 million, consisting of a $12.6 million call premium and $1.4 million of unamortized debt issuance costs related to the redemption of the 7.125% Senior Secured Notes, as well as $1.1 million of bank fees related to the issuance of the 6.75% Senior Notes;


•	In April 2014, we incurred a pretax charge of $4.8 million, consisting of a $4.3 million call premium and $0.5 million of unamortized debt issuance costs related to the redemption of the remaining 7.125% Senior Secured Notes; and


•	In June 2015, we incurred a pretax charge of $1.9 million consisting of $1.8 million of unamortized debt issuance costs and $0.1 million of associated professional fees related to the termination of the Credit Facility.

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The fair value of our Successor Company's Senior Secured Credit Facility is estimated using an Income Approach, specifically the risk-neutral method. The significant assumptions used in the valuation of the Senior Secured Credit Facility are: the expected recovery rate, the risk-neutral probability of default, and the risk-free rate (Level 2). The fair value of our Predecessor Company's 8.75% Senior Notes, 7.5% Senior Notes, 6.75% Senior Notes, 10.25% Senior Notes and 3.375% Convertible Senior Notes was estimated based on quoted prices in active markets. The fair value of our Predecessor Company's 7.375% Senior Notes was estimated based on discounted cash flows using inputs from quoted prices in active markets for similar debt instruments. The inputs used to determine fair value are considered Level 2 inputs.

The following table provides the carrying value and fair value of our long-term debt instruments:



	Successor				Predecessor
	December 31, 2015				December 31, 2014
(in millions)	Carrying Value		Fair Value		Carrying Value		Fair Value
Senior Secured Credit Facility, due May 2020	$	428.7	$	315.9	$	—	$	—
8.75% Senior Notes, due July 2021	—		—		400.0		191.0
7.5% Senior Notes, due October 2021	—		—		300.0		135.8
6.75% Senior Notes, due April 2022	—		—		300.0		132.8
10.25% Senior Notes, due April 2019	—		—		200.0		111.4
3.375% Convertible Senior Notes, due June 2038	—		—		7.4		6.5
7.375% Senior Notes, due April 2018	—		—		3.5		1.9

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 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.

Primary Marine Package Coverage

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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

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

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

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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.

Capital Expenditures

We currently expect total capital expenditures during 2016 to approximate $220.0 million to $250.0 million. Planned capital expenditures include the final shipyard payment, additional equipment, and commissioning expenditures for the Hercules Highlander (See the information set forth in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview), as well as items related to general maintenance, regulatory, refurbishment, upgrades and contract specific modifications to our other rigs and liftboats. Changes in timing of certain planned capital expenditure projects may result in a shift of spending levels beyond 2016.

From time to time, we may review possible acquisitions of rigs, liftboats or businesses, joint ventures, mergers or other business combinations, and we may have outstanding from time to time bids to acquire certain assets from other companies. If we acquire additional assets, we would expect that our ongoing capital expenditures as a whole would increase in order to maintain our equipment in a competitive condition.

Our ability to fund capital expenditures beyond the current year would be adversely affected if conditions deteriorate further in our business.

Contractual Obligations

Our contractual obligations and commitments principally include obligations associated with our outstanding indebtedness, certain income tax liabilities, future minimum operating lease obligations, purchase commitments and management compensation obligations.

The following table summarizes our contractual obligations and contingent commitments by period as of December 31, 2015:



	Payments due by Period
Contractual Obligations and	Less than		1-3		4-5		After 5
Contingent Commitments (c)	1 Year		Years		Years		Years		Total
	(In thousands)
Long-term debt obligation	$	—	$	—	$	450,000	$	—	$	450,000
Interest on debt (a)	48,038		95,812		64,443		—		208,293
Purchase obligations (b)	11,554		—		—		—		11,554
Rig construction contract (d)	188,800		—		—		—		188,800
Management compensation obligations	4,100		—		—		—		4,100
Operating lease obligations	3,365		2,700		—		—		6,065
Total contractual obligations	$	255,857	$	98,512	$	514,443	$	—	$	868,812

_____________________________


(a)	Estimated interest is based on the indexed rate in effect at December 31, 2015. Interest is calculated at the LIBOR rate plus an applicable margin of 9.50% per annum. The LIBOR rate includes a floor of 1.0% per the terms of the Credit Agreement.

(b)

A “purchase obligation” is defined as an agreement to purchase goods or services that is enforceable and legally binding on the company and that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. These amounts are primarily comprised of open purchase order commitments to vendors and subcontractors.


(c)	Tax liabilities of $3.2 million have been excluded from the table above as a reasonably reliable estimate of the period of cash settlement cannot be made.

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(d)

$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 rig construction contract and the expenses, costs and charges related to the construction and purchase of the Hercules Highlander (See the information set forth in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview and Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources).

Off-Balance Sheet Arrangements

Guarantees

Accounting Pronouncements

In April 2014, the FASB issued ASU No. 2014-08, Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The amendments in this ASU require that a disposal representing a strategic shift that has (or will have) a major effect on an entity’s operations and financial results should be reported as discontinued operations. The amendments also expand the disclosure requirements for discontinued operations and add new disclosures for disposals of a significant part of an organization that does not qualify as discontinued operations. The amendments in this ASU are effective prospectively for annual periods beginning on or after December 15, 2014, and interim periods within those years. We adopted ASU 2014-08 as of January 1, 2015 with no material impact on our consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. This ASU is based on the principle that revenue is recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. Adoption is permitted under the ASU using either a full or modified retrospective application approach. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which defers the effective date of ASU No. 2014-09 for all entities by one year and makes it effective for public entities to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Early application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We are in the process of evaluating the impact on our consolidated financial statements.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. This ASU provides guidance on management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The ASU is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. We are in the process of evaluating the impact on our consolidated financial statements.

In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs . The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. The ASU is effective for financial statements issued for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years using a retrospective approach, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. Early adoption is permitted for financial statements that have not been previously issued. As of November 6, 2015, upon the adoption of fresh-start accounting, the Successor Company adopted ASU 2015-03 as a new accounting principle. As a result, we have not applied ASU 2015-03 to the Predecessor Company Balance Sheets.

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those annual periods. Early adoption is permitted. As of November 6, 2015, upon the adoption of fresh-start accounting, the Successor Company adopted ASU 2015-17 as a new accounting principle. As a result, we have not applied ASU 2015-17 to the Predecessor Company Balance Sheets.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). The FASB is issuing this Update to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The core principle of Topic 842 is that a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. Under previous GAAP, lessees did not recognize lease assets and lease liabilities for those leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption of this amendment is permitted. We are in the process of evaluating the impact of this accounting standard on our consolidated financial statements.

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FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended ("the Securities Act"), and Section 21E of the Exchange Act that are applicable to us and our business. All statements, other than statements of historical fact, included in this annual report, including statements that address outlook, activities, events or developments that we intend, contemplate, estimate, expect, project, believe or anticipate will or may occur in the future are forward-looking statements. These include such matters as:


•	our levels of indebtedness, debt service, covenant compliance and access to capital under current market conditions;


•	our ability to enter into new contracts for our rigs and liftboats, including the Hercules Triumph and Hercules Resilience, and future utilization rates and dayrates for the units;


•	our ability to maintain our contracts on current terms, to renew or extend our contracts, or enter into new contracts, when such contracts expire;


•	demand for our rigs and our liftboats;


•	activity levels of our customers and their expectations of future energy prices and ability to obtain drilling permits in an efficient manner or at all;


•	sufficiency and availability of funds for required capital expenditures, working capital and debt service;


•	our ability to close the sale and purchase of assets on time;


•	expected completion times for our repair, refurbishment and upgrade projects;


•	our ability to complete our shipyard projects incident free;


•	our ability to complete our shipyard projects on time to avoid cost overruns and contract penalties;


•	our ability to effectively reactivate rigs that we have stacked;


•	the timing and cost of shipyard projects and refurbishments and the return of idle rigs to work;


•	our plans to increase international operations;


•	expected useful lives of our rigs and liftboats;


•	future capital expenditures and refurbishment, reactivation, transportation, repair and upgrade costs;


•	liabilities and restrictions under applicable laws of the jurisdictions in which we operate and regulations protecting the environment;


•	expected outcomes of litigation, investigations, claims, disputes and tax audits and their expected effects on our financial condition and results of operations;


•	the existence of insurance coverage and the extent of recovery from our insurance underwriters for claims made under our insurance policies; and


•	expectations regarding offshore drilling and liftboat activity and dayrates, market conditions, demand for our rigs and liftboats, operating revenue, operating and maintenance expense, insurance coverage, insurance expense and deductibles, interest expense, debt levels and other matters with regard to outlook and future earnings.

We have based these statements on our assumptions and analyses in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Forward-looking statements by their nature involve substantial risks and uncertainties that could significantly affect expected results, and actual future results could differ materially from those described in such statements. Although it is not possible to identify all factors, we continue to face many risks and uncertainties. Among the factors that could cause actual future results to differ materially are the risks and uncertainties described under “Risk Factors” in Item 1A of this annual report and the following:


•	oil and natural gas prices and industry expectations about future prices;


•	levels of oil and gas exploration and production spending;


•	demand for and supply of offshore drilling rigs and liftboats;


•	our ability to enter into and the terms of future contracts;


•	compliance by our customers with the terms of our contracts, including the dayrate and payment obligations;


•	the adequacy and costs of sources of credit and liquidity;


•	our ability to collect receivables due from our customers;


•	the worldwide military and political environment, uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East, North Africa, West Africa, Asia, Eastern Europe and other significant oil and natural gas producing regions or acts of terrorism or piracy;

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•	the ability of our customers in the U.S. Gulf of Mexico to obtain drilling permits in an efficient manner or at all;


•	the impact of governmental laws and regulations, including laws and regulations in the U.S. Gulf of Mexico following the Macondo well incident;


•	our ability to obtain in a timely manner visas and work permits for our employees working in international jurisdictions;


•	the impact of local content and cabotage laws and regulations in international jurisdictions in which we operate, particularly Nigeria;


•	the impact of tax laws, regulations, interpretations and audits in jurisdictions where we conduct business;


•	uncertainties relating to the level of activity in offshore oil and natural gas exploration, development and production;


•	competition and market conditions in the contract drilling and liftboat industries;


•	the availability of skilled personnel and the rising cost of labor;


•	labor relations and work stoppages, particularly in the Nigerian labor environment;


•	operating hazards such as hurricanes, severe weather and seas, fires, cratering, blowouts and other well control incidents, war, terrorism and cancellation or unavailability of insurance coverage or insufficient insurance coverage;


•	the impact of public health outbreaks;


•	the enforceability and interpretations of indemnity and liability provisions contained in our drilling contracts, particularly in the U.S. Gulf of Mexico;


•	the effect of litigation, investigations, audits and contingencies; and


•	our inability to achieve our plans or carry out our strategy.

Many of these factors are beyond our ability to control or predict. Any of these factors, or a combination of these factors, could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. These forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements or present or prior earnings levels. In addition, each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward-looking statements except as required by applicable law.



Item 7A.	Quantitative and Qualitative Disclosures About Market Risk

We are currently exposed to market risk from changes in interest rates. From time to time, we may enter into derivative financial instrument transactions to manage or reduce our market risk, but we do not enter into derivative transactions for speculative purposes. A discussion of our market risk exposure in financial instruments follows.

Interest Rate Exposure

We are subject to interest rate risk on our variable-interest rate borrowings. Variable rate debt, where the interest rate fluctuates periodically, exposes us to short-term changes in market interest rates. As of December 31, 2015, the interest rate for the $450 million Senior Secured Credit Facility was 10.5%. If the interest rate averaged 1% more for 2016 than the rates as of December 31, 2015, annual interest expense would increase $4.5 million. This sensitivity analysis assumes there are no changes in our financial structure and excludes the impact of any interest related to the difference between the $450 million face amount and the carrying value due to discounts. The Fair Value of the amount outstanding on the Senior Secured Credit Facility at December 31, 2015 was $315.9 million.

Embedded Derivative

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Item 8.	Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and

Stockholders of Hercules Offshore, Inc.:

We have audited the accompanying consolidated balance sheets of Hercules Offshore, Inc. and subsidiaries as of December 31, 2015 (the "Successor Company" consolidated balance sheet) and 2014 (the "Predecessor Company" consolidated balance sheet), and the related consolidated statements of operations, equity and cash flows for the period from November 6, 2015 through December 31, 2015 (the Successor Company operations and cash flows), and for the period from January 1, 2015 through November 6, 2015, and each of the two years in the period ended December 31, 2014 (the Predecessor Company operations and cash flows). These financial statements and schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the Successor Company consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hercules Offshore, Inc. and subsidiaries as of December 31, 2015, and the results of their operations and their cash flows for the period from November 6, 2015 through December 31, 2015, in conformity with U.S. generally accepted accounting principles. Further, in our opinion, the Predecessor Company consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Predecessor Company as of December 31, 2014, and the results of their operations and their cash flows for the period from January 1, 2015 through November 6, 2015, and for each of the two years in the period ended December 31, 2014, in conformity with U.S generally accepted accounting principles in the United States of America.

As discussed in Note 4 to the consolidated financial statements, on September 24, 2015, the Bankruptcy Court entered an order confirming the plan of reorganization, which became effective on November 6, 2015. Accordingly, the accompanying consolidated financial statements have been prepared in conformity with Accounting Standards Codification 852-10, Reorganizations, for the Successor Company as a new entity with assets, liabilities and a capital structure having carrying amounts not comparable with prior periods as described in Note 1.

/s/ ERNST & YOUNG LLP

Houston, Texas

March 30, 2016

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except par value)



	Successor			Predecessor
	December 31,			December 31,
	2015			2014
ASSETS
Current Assets:
Cash and Cash Equivalents	$	330,780		$	207,937
Accounts Receivable, Net	63,668			166,359
Prepaids	11,740			19,585
Current Deferred Tax Asset	—			4,461
Other	4,015			5,955
	410,203			404,297
Property and Equipment, Net	465,497			1,574,749
Restricted Cash	200,000			—
Other Assets, Net	32,440			23,361
	$	1,108,140		$	2,002,407
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	43,616		$	52,952
Accrued Liabilities	49,108			66,090
Interest Payable	—			32,008
Other Current Liabilities	6,148			13,406
	98,872			164,456
Long-term Debt	428,715			1,210,919
Deferred Income Taxes	—			4,147
Other Liabilities	16,622			7,854
Commitments and Contingencies
Equity:
Predecessor Common Stock, $0.01 Par Value; 300,000 Shares Authorized, 163,540 Shares Issued and 160,818 Shares Outstanding	—			1,635
Predecessor Capital in Excess of Par Value	—			2,179,838
Predecessor Treasury Stock, at Cost, 2,722 Shares	—			(56,765		)
Successor Common Stock, $0.01 Par Value; 139,650 Shares Authorized, 20,000 Shares Issued and 19,989 Shares Outstanding	200			—
Successor Capital in Excess of Par Value	587,725			—
Successor Treasury Stock, at Cost, 11 Shares	(325		)	—
Retained Deficit	(23,669		)	(1,509,677		)
	563,931			615,031
	$	1,108,140		$	2,002,407

The accompanying notes are an integral part of these financial statements.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)



	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
Revenue	$	32,442		$	303,206		$	900,251		$	858,300
Costs and Expenses:
Operating Expenses	29,675			271,988			543,236			461,332
Asset Impairment	—			—			199,508			114,168
Depreciation and Amortization	4,534			126,963			170,898			151,943
General and Administrative	7,120			79,884			75,108			79,425
	41,329			478,835			988,750			806,868
Operating Income (Loss)	(8,887		)	(175,629		)	(88,499		)	51,432
Other Income (Expense):
Interest Expense	(7,939		)	(61,173		)	(99,142		)	(73,248		)
Loss on Extinguishment of Debt	—			(1,884		)	(19,925		)	(29,295		)
Gain on Equity Investment	—			—			—			14,876
Reorganization Items, Net	(1,330		)	(357,050		)	—			—
Other, Net	(4,785		)	284			(39		)	(1,518		)
Loss Before Income Taxes	(22,941		)	(595,452		)	(207,605		)	(37,753		)
Income Tax Benefit (Provision)	(728		)	(7,042		)	(8,505		)	10,944
Loss from Continuing Operations	(23,669		)	(602,494		)	(216,110		)	(26,809		)
Loss from Discontinued Operations, Net of Taxes	—			—			—			(41,308		)
Net Loss	(23,669		)	(602,494		)	(216,110		)	(68,117		)
Loss attributable to Noncontrolling Interest	—			—			—			39
Net Loss attributable to Hercules Offshore, Inc.	$	(23,669	)	$	(602,494	)	$	(216,110	)	$	(68,078	)

Net Loss attributable to Hercules Offshore, Inc. Per Share:
Basic and Diluted:
Loss from Continuing Operations	$	(1.18	)	$	(3.73	)	$	(1.35	)	$	(0.17	)
Loss from Discontinued Operations	—			—			—			(0.26		)
Net Loss	$	(1.18	)	$	(3.73	)	$	(1.35	)	$	(0.43	)
Basic and Diluted Weighted Average Shares Outstanding	19,989			161,430			160,598			159,501

The accompanying notes are an integral part of these financial statements.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(In thousands)



	Successor					Predecessor
	Period from November 6, 2015 to December 31, 2015					Period from January 1, 2015 to November 6, 2015					December 31, 2014					December 31, 2013
	Shares		Amount			Shares		Amount			Shares		Amount			Shares		Amount
Common Stock:
Balance at Beginning of Period	—		$	—		163,540		$	1,635		162,144		$	1,621		160,708		$	1,607
Issuance of Successor Company Equity	20,000		200			—		—			—		—			—		—
Other	—		—			1,084		11			1,396		14			1,436		14
Cancellation of Predecessor Company Equity	—		—			(164,624	)	(1,646		)	—		—			—		—
Balance at End of Period	20,000		200			—		—			163,540		1,635			162,144		1,621
Capital in Excess of Par Value:
Balance at Beginning of Period	—		—			—		2,179,838			—		2,170,811			—		2,159,744
Issuance of Successor Company Equity	—		587,699			—		—			—		—			—		—
Compensation Expense Recognized	—		26			—		6,922			—		8,348			—		9,960
Excess Tax Benefit From Stock-Based Arrangements, Net	—		—			—		—			—		548			—		825
Other	—		—			—		(11		)	—		131			—		282
Cancellation of Predecessor Company Equity	—		—			—		(2,186,749		)	—		—			—		—
Balance at End of Period	—		587,725			—		—			—		2,179,838			—		2,170,811
Treasury Stock:
Balance at Beginning of Period	—		—			(2,722	)	(56,765		)	(2,383	)	(55,165		)	(2,080	)	(53,100		)
Repurchase of Common Stock	(11	)	(325		)	(261	)	(178		)	(339	)	(1,600		)	(303	)	(2,065		)
Cancellation of Predecessor Company Equity	—		—			2,983		56,943			—		—			—		—
Balance at End of Period	(11	)	(325		)	—		—			(2,722	)	(56,765		)	(2,383	)	(55,165		)
Retained Deficit:
Balance at Beginning of Period	—		—			—		(1,509,677		)	—		(1,293,567		)	—		(1,225,489		)
Net Loss attributable to Hercules Offshore, Inc.	—		(23,669		)	—		(602,494		)	—		(216,110		)	—		(68,078		)
Cancellation of Predecessor Company Equity	—		—			—		2,112,171			—		—			—		—
Balance at End of Period	—		(23,669		)	—		—			—		(1,509,677		)	—		(1,293,567		)
Total Hercules Offshore, Inc. Stockholders’ Equity	19,989		563,931			—		—			160,818		615,031			159,761		823,700
Noncontrolling Interest:
Balance at Beginning of Period	—		—			—		—			—		—			—		—
Acquisition of Interest in Discovery	—		—			—		—			—		—			—		26,448
Acquisition of Noncontrolling Interest in Discovery	—		—			—		—			—		—			—		(26,409		)
Loss Attributable to Noncontrolling Interest	—		—			—		—			—		—			—		(39		)
Balance at End of Period	—		—			—		—			—		—			—		—
Total Equity	19,989		$	563,931		—		$	—		160,818		$	615,031		159,761		$	823,700

The accompanying notes are an integral part of these financial statements.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	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
Cash Flows from Operating Activities:
Net Loss	$	(23,669	)	$	(602,494	)	$	(216,110	)	$	(68,078	)
Adjustments to Reconcile Net Loss to Net Cash Provided by (Used in) Operating Activities:
Depreciation and Amortization	4,534			126,963			170,898			162,841
Stock-Based Compensation Expense	26			6,922			8,348			9,960
Deferred Income Taxes	16			1,931			(7,691		)	(30,940		)
Provision for Doubtful Accounts Receivable	1,855			7,665			5,627			642
(Gain) Loss on Disposal of Assets, Net	(28		)	970			(22,598		)	7,355
Asset Impairment	—			—			199,508			158,538
Gain on Equity Investment	—			—			—			(14,876		)
Gain on Insurance Settlement	—			(1,125		)	—			(31,600		)
Non-Cash Portion of Loss on Extinguishment of Debt	—			1,818			1,900			9,012
Non-Cash Reorganization Items, Net	—			344,231			—			—
Non-Cash Loss on Derivative	4,837			—			—			—
Other	342			1,453			2,910			8,319
(Increase) Decrease in Operating Assets -
Accounts Receivable	(1,278		)	94,449			48,153			(53,643		)
Prepaid Expenses and Other	3,875			8,860			2,323			15,214
Increase (Decrease) in Operating Liabilities -
Accounts Payable	(5,637		)	(12,027		)	(27,066		)	20,357
Insurance Notes Payable	—			—			(9,568		)	(31,462		)
Other Current Liabilities	(11,826		)	3,146			(36,317		)	17,753
Other Liabilities	494			7,637			(5,604		)	3,078
Net Cash Provided by (Used in) Operating Activities	(26,459		)	(9,601		)	114,713			182,470
Cash Flows from Investing Activities:
Acquisition of Assets, Net of Cash Acquired	—			—			—			(200,957		)
Capital Expenditures	(5,066		)	(78,097		)	(147,522		)	(544,987		)
(Increase) Decrease in Restricted Cash	—			(200,000		)	—			2,027
Insurance Proceeds Received	—			3,543			9,067			51,430
Proceeds from Sale of Assets, Net	78			9,697			35,135			117,350
Other	377			227			1,479			2,474
Net Cash Used in Investing Activities	(4,611		)	(264,630		)	(101,841		)	(572,663		)
Cash Flows from Financing Activities:
Long-term Debt Borrowings	—			436,500			300,000			700,000
Redemption of 7.125% Senior Secured Notes	—			—			(300,000		)	—
Redemption of 3.375% Convertible Senior Notes	—			—			—			(61,274		)
Redemption of 10.5% Senior Notes	—			—			—			(300,000		)
Payment of Debt Issuance Costs	—			(8,356		)	(3,914		)	(10,643		)
Other	—			—			573			1,323
Net Cash Provided by (Used in) Financing Activities	—			428,144			(3,341		)	329,406
Net Increase (Decrease) in Cash and Cash Equivalents	(31,070		)	153,913			9,531			(60,787		)
Cash and Cash Equivalents at Beginning of Period	361,850			207,937			198,406			259,193
Cash and Cash Equivalents at End of Period	$	330,780		$	361,850		$	207,937		$	198,406

The accompanying notes are an integral part of these financial statements.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Nature of Business

Organization

Hercules Offshore, Inc., a Delaware corporation, and its majority owned subsidiaries (the “Company”) provide shallow-water drilling and marine services to the oil and natural gas exploration and production industry globally through its Domestic Offshore, International Offshore and International Liftboats segments (See Note 17). At December 31, 2015, the Company 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). The Company’s 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.

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 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. Since 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. The Non-Filing Entities continued to operate in the ordinary course of business.

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. Upon adoption of fresh-start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh-start reporting date. The fair values of the Company’s assets and liabilities in conformance with ASC 805, “Business Combinations,” as of that date differed materially from the recorded values of its assets and liabilities as reflected in its historical consolidated financial statements. In addition, the Company’s adoption of fresh-start accounting may materially affect its results of operations following the fresh-start reporting dates, as the Company will have a new basis in its assets and liabilities. Consequently, the Company’s 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, the Company’s consolidated balance sheets and consolidated statements of operations subsequent to November 6, 2015 will not be comparable to its consolidated balance sheets and consolidated statements of operations prior to November 6, 2015 (See Note 5).

The audited consolidated financial statements included in this Annual Report on Form 10-K have been prepared assuming that the Company 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, the Company’s ability to continue as a going concern, was contingent 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Current Market Environment

Demand for the Company’s oilfield services is driven by its exploration and production customers’ capital spending, which can experience significant fluctuation depending on current commodity prices and their expectations of future price levels, among other factors. The decline in the price of crude oil that began in mid-2014 and extending into 2016 has severely impacted dayrates and demand for the Company’s services. In addition to the oil price decline, the consolidation of the domestic customer base has negatively impacted demand for jackup rigs in the U.S. Gulf of Mexico. Internationally, the new capacity growth expected over the next three years could put further pressure on the operating environment for the existing jackup rig fleet. Although activity levels for liftboats are not as closely correlated to commodity prices as the Company’s drilling segments, commodity prices are still a key driver of liftboat demand. Demand for liftboat services in West Africa has been weak, which the Company believes has been driven by budgetary constraints with major customers primarily in Nigeria.

The Company has taken numerous actions to mitigate the effects of the decline in activity levels, including but not limited to: (i) cold stacking nine rigs and warm stacking seven rigs since the fourth quarter of 2014 to significantly reduce operating expenses, (ii) significantly reducing its capital expenditures in 2015 and the amount planned for 2016 and (iii) significantly reducing its workforce, both onshore and offshore. The Company continues to monitor its operating environment and will respond to further activity level declines as appropriate.

Although the Company is exploring all strategic alternatives, the Company does not believe that there is substantial doubt about the Company’s ability to continue as a going concern through 2016. As part of that assessment, based on facts known to the Company as of the filing of this Form 10K, the Company does not believe it is more likely than not that a bankruptcy filing will occur during 2016. Further, the Company does not intend to pursue any strategic action that results in an event of default under the Credit Agreement during 2016. The Company is currently projecting, however, that they will violate the Maximum Senior Secured First Lien Leverage Ratio on March 31, 2017. If this occurs and the Company is not able to obtain a waiver from its lenders, the lenders could accelerate these debt obligations. In addition, the Company 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 ("Applicable Premium"). Because of this Applicable Premium, it could be challenging for the Company to obtain a waiver, and further, given the current state of the drilling market, the Company does not believe refinancing would be a viable option.

Any strategic transaction we may pursue 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.

Dayrate Reductions

On February 25, 2015, the Company received a notice from Saudi Aramco terminating for convenience its 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2. Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements of the Company include the accounts of the Company and its wholly owned subsidiaries from the date a majority controlling interest was acquired (See Note 8). All intercompany account balances and transactions have been eliminated.

Use of Estimates

In preparing financial statements in conformity with accounting principles generally accepted in the United States, management makes estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenue and expenses during the reporting period. On an ongoing basis, the Company evaluates its estimates, including those related to bad debts, property and equipment, income taxes, insurance, employment benefits and contingent liabilities. The Company bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand deposits with banks and investments in highly liquid investments with original maturities of three months or less.

Revenue Recognition

Revenue generated from the Company’s contracts is recognized as services are performed, as long as collectability is reasonably assured. For certain contracts, the Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one location to another are recognized as services are performed over the term of the related drilling contract. For certain contracts, the Company may receive fees from its customers for capital improvements to its rigs. Such fees are deferred and recognized as services are performed over the term of the related contract. The Company capitalizes such capital improvements and depreciates them over the useful life of the asset. Certain of the Company's contracts also allow us to recover additional direct costs, such as demobilization costs, additional labor and additional catering costs and under most of our liftboat contracts, we receive a variable rate for reimbursement of costs such as catering, oil, rental equipment and other items. Revenue for the recovery or reimbursement of these costs is recognized when the costs are incurred.

Stock-Based Compensation

The Company recognizes compensation cost for all share-based payments awarded in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 718, Compensation — Stock Compensation (“ASC 718”) and in accordance with such the Company records the grant date fair value of time-based restricted stock awarded as compensation expense using a straight-line method over the requisite service period. Performance based awards were recognized using the accelerated method over the requisite service period. The fair value of the Company’s awards that are share settled are based on the closing price of the Company’s common stock on the date of grant. For those performance based grants that contained a market performance condition, the Monte Carlo simulation was used for valuation as of the date of grant. All of the Company’s cash settled awards were recorded as a liability at fair value, which was remeasured at the end of each reporting period, over the requisite service period. The Company’s cash settled liability awards that contained market performance conditions were valued using a Monte Carlo simulation. The Company also estimates future forfeitures and related tax effects. The Company’s estimate of compensation expense requires a number of assumptions and changes to those assumptions could result in different valuations for individual share awards. On November 6, 2015, the date the Plan became effective pursuant to its terms and the Debtors emerged from Chapter 11, all share-based awards requiring share settlement that were granted under the Predecessor were canceled. Certain award agreements requiring cash settlement contained change of control provisions which provided for vesting (See Note 10). The Successor Company has only granted time-based restricted stock (See Note 10).

Due to the uncertainty in the level of awards to be granted in the future, the Company's estimate of future expense relating to restricted stock granted through December 31, 2015 as well as the remaining vesting period over which the associated expense is to be recognized are estimates and subject to change.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are stated at the historical carrying amount net of write-offs and the allowance for doubtful accounts. The Company monitors the accounts receivable from its customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. The Company establishes an allowance for doubtful accounts based on the actual amount it believes is not collectable. During the period January 1, 2015 to November 6, 2015, the Predecessor Company's allowance for doubtful accounts increased $7.7 million primarily due to an uncollectable receivable identified in its International Liftboats segment. In connection with the application of fresh-start accounting on November 6, 2015, the carrying value of accounts receivable was adjusted to fair value, eliminating the allowance for doubtful accounts. The Successor Company's allowance for doubtful accounts increased $1.9 million, primarily due to a disputed receivable balance identified in its International Offshore segment. The Company had an allowance of $1.9 million and $5.7 million at December 31, 2015 and 2014, respectively.

Business Combinations

The Company accounted for the 2013 acquisition of Discovery as a business combination (See Note 8).

Property and Equipment and Impairment of Long-lived Assets

Property and equipment are recorded at cost, less accumulated depreciation. In connection with fresh-start accounting, property and equipment were adjusted to their estimated fair value and depreciable lives were revised as of November 6, 2015. Expenditures for property and equipment and items that substantially increase the useful lives of existing assets are capitalized at cost and depreciated. Routine expenditures for repairs and maintenance are expensed as incurred.

Depreciation is computed using the straight-line method, after allowing for salvage value where applicable, over the useful lives of the assets. Depreciation of leasehold improvements is computed utilizing the straight-line method over the lease term or life of the asset, whichever is shorter.

The useful lives of property and equipment for the purposes of computing depreciation are as follows:



	Years
Drilling rigs and marine equipment (salvage value of 5%) *	10–30
Drilling machinery and equipment	2–12
Other	3–20

* Salvage value for predecessor was 10%.

The carrying value of long-lived assets, principally property and equipment, is reviewed for potential impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable or when reclassifications are made between property and equipment and assets held for sale. Factors that might indicate a potential impairment may include, but are not limited to, significant decreases in the market value of the long-lived asset, a significant change in the long-lived asset’s physical condition, a change in industry conditions or a substantial reduction in cash flows associated with the use of the long-lived asset. For property and equipment held for use, the determination of recoverability is made based upon the estimated undiscounted future net cash flows of the related asset or group of assets being evaluated. Actual impairment charges are recorded using an estimate of discounted future cash flows. This evaluation requires the Company to make judgments regarding long-term forecasts of future revenue and costs. In turn these forecasts are uncertain in that they require assumptions about demand for the Company’s services, future market conditions and technological developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. Given the nature of these evaluations and their application to specific asset groups and specific times, it is not possible to reasonably quantify the impact of changes in these assumptions.

Supply and demand are the key drivers of rig and vessel utilization and the Company’s ability to contract its rigs and vessels at economical rates. During periods of an oversupply, it is not uncommon for the Company to have rigs or vessels idled for extended periods of time, which could indicate that an asset group may be impaired. The Company’s rigs and vessels are mobile units, equipped to operate in geographic regions throughout the world and, consequently, the Company may move rigs and vessels from an oversupplied region to one that is more lucrative and undersupplied when it is economical to do so. As such, the Company’s rigs and vessels are considered to be interchangeable within classes or asset groups and accordingly, the Company performs its impairment evaluation by asset group.

The Company’s estimates, assumptions and judgments used in the application of its property and equipment accounting policies reflect both historical experience and expectations regarding future industry conditions and operations. Using different

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

estimates, assumptions and judgments, especially those involving the useful lives and salvage values of the Company’s rigs and liftboats and expectations regarding future industry conditions and operations, would result in different carrying values of assets and results of operations. For example, a prolonged downturn in the drilling industry in which utilization and dayrates were significantly reduced could result in an impairment of the carrying value of the Company’s assets.

Useful lives of rigs and vessels are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. The Company evaluates the remaining useful lives of its rigs and vessels when certain events occur that directly impact its assessment of the remaining useful lives of the rigs and vessels and include changes in operating condition, functional capability and market and economic factors. The Company also considers major capital upgrades required to perform certain contracts and the long-term impact of those upgrades on the future marketability when assessing the useful lives and salvage values of individual rigs and vessels.

When analyzing its assets for impairment, the Company separates its marketable assets, those assets that are actively marketed and can be warm stacked or cold stacked for short periods of time depending on market conditions, from its non-marketable assets, those assets that have been cold stacked for an extended period of time or those assets that the Company currently does not reasonably expect to market in the foreseeable future.

Other Intangible Assets

In connection with the application of fresh-start accounting on November 6, 2015, the Company recorded intangible assets of $25.3 million related to the fair value of certain customer contracts and $1.2 million related to our corporate office lease which was favorable relative to available market terms at November 6, 2015. The intangible assets related to the customer contracts are being amortized on a straight-line basis over the life of the contracts once those contracts have commenced, which in the case of one of the customer contracts commencement is not expected until mid-2016. The intangible asset related to our corporate office lease is being amortized on a straight-line basis to rental expense over the remaining lease term. Amortization expense related to intangible assets was $0.2 million for the period November 6, 2015 to December 31, 2015. Intangible assets are included in Other Assets, Net on the Consolidated Balance Sheet at December 31, 2015.



	Successor
	December 31, 2015
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Net		Weighted-Average Amortization Period
Customer Contracts	$	25,300	$	117	$	25,183	4.9 years
Corporate Office Lease Intangible	1,178		91		1,087		2.2 years
Total	$	26,478	$	208	$	26,270

Future estimated amortization expense for the carrying amount of intangible assets as of December 31, 2015 is expected to be as follows (in thousands):



2016	$	3,177
2017	5,463
2018	4,920
2019	4,920
2020	4,920
Thereafter	2,870
Total	$	26,270

Restricted Cash

Restricted cash at December 31, 2015 is $200.0 million held in 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 (See Note 18). The Company includes any changes in restricted cash for the purpose of financing or purchasing property and equipment to be held and used in providing services as Cash flows from investing activities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Accrued Self-Insurance Reserves

The Company is self-insured up to certain retention limits for maritime employer's liability claims and protection and indemnity claims. The amounts in excess of the self-insured levels are fully insured, up to a limit. Self-insurance reserves are based on estimates of (i) claims reported and (ii) loss amounts incurred but not reported. Reserves for reported claims are estimated by the Company's internal risk department by evaluating the facts and circumstances of each claim and are adjusted from time to time based upon the status of each claim and the Company's historical experience with similar claims. Reserves for loss amounts incurred but not reported are estimated by the Company's third-party actuary and include provisions for expected development on claims reported due to information not yet received and expected development on claims to be reported in the future but which have occurred prior to the accounting date. As of December 31, 2015 and 2014, there was $18.5 million and $24.5 million in accrued self-insurance reserves, respectively, which is included in Accrued Liabilities on the Consolidated Balance Sheets. The actual outcome of any claim could differ significantly from estimated amounts.

Income Taxes

The Company uses the liability method for determining its income taxes. The Company’s income tax provision is based upon the tax laws and rates in effect in the countries in which the Company’s operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these jurisdictions vary substantially. The Company’s effective tax rate is expected to fluctuate from year to year as operations are conducted in different taxing jurisdictions and the amount of pre-tax income fluctuates. Current income tax expense reflects an estimate of the Company’s income tax liability for the current year, withholding taxes, changes in prior year tax estimates as returns are filed, or from tax audit adjustments, while the net deferred tax expense or benefit represents the changes in the balance of deferred tax assets and liabilities as reported on the balance sheet.

Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized in the future.

The Company considers estimated future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for a valuation allowance. Changes in these estimates and assumptions, as well as changes in tax laws, could require the Company to adjust the valuation allowance for deferred taxes in the future. The adjustments to the valuation allowance impact the Company’s income tax provision in the period in which such adjustments are identified and recorded.

Certain of the Company’s international rigs and liftboats are owned or operated, directly or indirectly, by the Company’s wholly owned Cayman Islands subsidiaries. U.S. Federal deferred tax liabilities are recorded for the unremitted earnings of foreign subsidiaries that are not permanently reinvested; otherwise, no U.S. Federal deferred taxes are provided on foreign subsidiaries. In certain circumstances, management expects that, due to the changing demands of the offshore drilling and liftboat markets and the ability to redeploy the Company’s offshore units, certain of such units will not reside in a location long enough to give rise to future tax consequences in that location. As a result, no deferred tax asset or liability has been recognized in these circumstances. Should management’s expectations change regarding the length of time an offshore drilling unit will be used in a given location, the Company would adjust deferred taxes accordingly.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Earnings Per Share

The reconciliation of the numerators and denominators used for the computation of basic and diluted earnings per share is 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,
(in thousands)	Period from November 6, 2015 to December 31, 2015			Period from January 1, 2015 to November 6, 2015			2014			2013
Numerator:
Loss from continuing operations	$	(23,669	)	$	(602,494	)	$	(216,110	)	$	(26,809	)
Less: Loss attributable to noncontrolling interest	—			—			—			39
Adjusted loss from continuing operations	(23,669		)	(602,494		)	(216,110		)	(26,770		)
Loss from discontinued operations, net of taxes	—			—			—			(41,308		)
Net loss attributable to Hercules Offshore, Inc.	$	(23,669	)	$	(602,494	)	$	(216,110	)	$	(68,078	)
Denominator:
Weighted average basic and diluted shares outstanding	19,989			161,430			160,598			159,501

The Company calculates basic earnings per share by dividing both income (loss) from continuing operations and net income (loss) attributable to Hercules Offshore, Inc. by the weighted average number of shares outstanding. Diluted earnings per share is computed by dividing both income from continuing operations and net income attributable to Hercules Offshore, Inc. by the weighted average number of shares outstanding during the period as adjusted for the dilutive effect of the Company’s stock equivalents, which for the Predecessor included stock option, time-based restricted stock and performance-based restricted stock awards and for the Successor included time-based restricted stock awards and warrants. The effect of stock equivalents is not included in the computation for periods in which a net loss occurs, because to do so would be anti-dilutive. The Company's diluted earnings per share calculation 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 excludes 5.1 million, 5.6 million, 6.4 million and 6.3 million stock equivalents, respectively, that would have potentially been included if the Company had generated income from continuing operations and net income attributable to Hercules Offshore, Inc. for the respective period, but are excluded as the Company generated a loss from continuing operations and net loss during the respective period. For the Predecessor, there were no stock equivalents to exclude from the calculation of the dilutive effect of stock equivalents for the diluted earnings per share calculations for the period January 1, 2015 to November 6, 2015 and the years ended December 31, 2014 and 2013 related to the assumed conversion of the 3.375% Convertible Senior Notes as there was no excess of conversion value in any of these periods.

3. Accounting Pronouncements

In April 2014, the FASB issued ASU No. 2014-08, Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The amendments in this ASU require that a disposal representing a strategic shift that has (or will have) a major effect on an entity’s operations and financial results should be reported as discontinued operations. The amendments also expand the disclosure requirements for discontinued operations and add new disclosures for disposals of a significant part of an organization that does not qualify as discontinued operations. The amendments in this ASU are effective prospectively for annual periods beginning on or after December 15, 2014, and interim periods within those years. The Company adopted ASU 2014-08 as of January 1, 2015 with no material impact on its consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. This ASU is based on the principle that revenue is recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. Adoption is permitted under the ASU using either a full or modified retrospective application approach. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which defers the effective date of ASU No. 2014-09 for all entities by one year and makes it effective for public entities to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period.

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Early application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. The Company is in the process of evaluating the impact on its consolidated financial statements.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. This ASU provides guidance on management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The ASU is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Company is in the process of evaluating the impact on its consolidated financial statements.

In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. The ASU is effective for financial statements issued for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years using a retrospective approach, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. Early adoption is permitted for financial statements that have not been previously issued. As of November 6, 2015, upon the adoption of fresh-start accounting, the Successor Company adopted ASU 2015-03 as a new accounting principle. As a result, the Company has not applied ASU 2015-03 to the Predecessor Company Balance Sheets.

In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. The amendments in this ASU require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendments in this ASU. The ASU is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted. As of November 6, 2015, upon the adoption of fresh-start accounting, the Successor Company adopted ASU 2015-17 as a new accounting principle. As a result, the Company has not applied ASU 2015-17 to the Predecessor Company Balance Sheets.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). The FASB is issuing this Update to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The core principle of Topic 842 is that a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. Under previous GAAP, lessees did not recognize lease assets and lease liabilities for those leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption of this amendment is permitted. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements.

4. Bankruptcy, Emergence from Voluntary Reorganization under Chapter 11 Proceedings and Related Events

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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.

•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 would receive 3.1% of the New Common Stock and would also receive 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 will be 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

•The Successor Company entered into a Credit Agreement (See Note 13) 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.

5. Fresh-Start Accounting

In connection with the Company’s emergence from Chapter 11, the Company applied the provisions of fresh-start accounting, pursuant to Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852, Reorganizations, ("ASC 852"), to its financial statements as (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the emerging entity and (ii) the reorganization value of the Company's assets immediately prior to confirmation was less than the post-petition liabilities and allowed claims. The Company applied

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fresh-start accounting as of November 6, 2015. Adopting fresh-start reporting results in a new reporting entity with no beginning retained earnings or deficit. The cancellation of all existing shares outstanding on the Effective Date and issuance of new shares of the reorganized entity caused a related change of control of the Company under ASC 852.

Upon the application of fresh-start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values. Reorganization value represents the fair value of the Successor Company’s assets before considering liabilities.

Reorganization Value

In support of the Plan, the enterprise value of the Successor Company was estimated to be in the range of $535 million to $725 million. The Company estimated the enterprise value of the Successor Company to be $653.7 million .

To estimate reorganization value, the Company utilized the discounted cash flow method. The Company established an estimate of future cash flows for the period ranging from November 6, 2015 to December 31, 2022 and discounted the estimated future cash flows to present value. The expected cash flows for the period November 6, 2015 to December 31, 2022 were derived from earnings forecasts and assumptions regarding growth and margin projections, as applicable. A terminal value was included, calculated using the constant growth method, based on the cash flows of the final year of the forecast period.

The discount rate of 20.9% was estimated based on an after-tax weighted average cost of capital (“WACC”) reflecting the rate of return that would be expected by a market participant. The WACC also takes into consideration a company specific risk premium reflecting the risk associated with the overall uncertainty of the financial projections used to estimate future cash flows.

The following table reconciles the enterprise value to the estimated fair value of Successor common stock as of the Effective Date:



(in thousands, except per share value)
Enterprise value	$	653,720
Plus: Cash and cash equivalents	361,850
Less: Fair value of debt	427,996
Less: Fair value of warrants	1,433
Fair value of Successor common stock	$	586,141
Shares outstanding at November 6, 2015	19,989
Per share value	$29.32

The Company identified an embedded derivative related to a put option feature included in the Senior Secured Credit Facility, where, upon the occurrence of certain events of default and where the Company was not able to obtain a waiver from our lenders, the principal amount of the Company's debt could be accelerated and the Company 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. The accounting treatment of derivative financial instruments requires the Company to bifurcate and fair value the derivative as of the inception date of the Senior Secured Credit Facility and to fair value the derivative as of each subsequent reporting date.

The fair value of the warrants was estimated using a Black-Scholes pricing model with the following assumptions: stock price of $10.27; strike price of $70.50; expected volatility of 40%; expected dividend rate of 0.0%; risk free interest rate of 1.91%; expiration date of six years. The fair value of these warrants was estimated using Level 2 inputs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date:



(in thousands)
Enterprise value	$	653,720
Plus: Cash and cash equivalents	361,850
Plus: Fair value of non-debt liabilities	127,576
Reorganization value of Successor assets	$	1,143,146

The fair value of non-debt liabilities represents total liabilities of the Successor Company on the Effective Date less long-term debt.

Consolidated Balance Sheet

The adjustments set forth in the following consolidated Balance Sheet reflect the effect of the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh-start accounting (reflected in the column “Fresh-Start Adjustments”). The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions.

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(in thousands)	Predecessor Company November 6, 2015			Reorganization Adjustments				Fresh-Start Adjustments				Successor Company November 6, 2015
ASSETS
Current Assets:
Cash and Cash Equivalents	$	133,706		$	228,144		(1)	$	—			$	361,850
Accounts Receivable, Net	64,245			—				—				64,245
Prepaids	15,074			—				—				15,074
Other	4,489			—				—				4,489
	217,514			228,144				—				445,658
Property and Equipment, Net	1,514,798			—				(1,049,537		)	(12)	465,261
Restricted Cash	—			200,000			(2)	—				200,000
Other Assets, Net	7,675			(147		)	(3)	24,699			(13)	32,227
	$	1,739,987		$	427,997			$	(1,024,838	)		$	1,143,146
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	49,253		$	—			$	—			$	49,253
Accrued Liabilities	55,762			2,643			(4)	—				58,405
Other Current Liabilities	13,081			—				(4,454		)	(14)	8,627
	118,096			2,643				(4,454		)		116,285
Long-term Debt	—			416,998			(5)	10,998			(15)	427,996
Deferred Income Taxes	—			39,546			(6)	(39,546		)	(16)	—
Other Liabilities	15,062			8,503			(7)	(12,274		)	(17)	11,291
Liabilities Subject to Compromise	1,254,845			(1,254,845		)	(8)	—				—
Commitments and Contingencies
Equity:
Predecessor Common Stock, $0.01 Par Value; 300,000 Shares Authorized, 164,624 Shares Issued and 161,641 Shares Outstanding	1,646			(1,646		)	(9)	—				—
Predecessor Capital in Excess of Par Value	2,186,749			(2,186,749		)	(9)	—				—
Predecessor Treasury Stock, at Cost, 2,983 Shares	(56,943		)	56,943			(9)	—				—
Successor Common Stock, $0.01 Par Value; 139,650 Shares Authorized, 20,000 Shares Issued and 19,989 Shares Outstanding	—			200			(10)	—				200
Successor Capital in Excess of Par Value	—			587,699			(10)	—				587,699
Successor Treasury Stock, at Cost, 11 Shares	—			(325		)	(10)	—				(325		)
Retained Deficit	(1,779,468		)	2,759,030			(11)	(979,562		)	(18)	—
	351,984			1,215,152				(979,562		)		587,574
	$	1,739,987		$	427,997			$	(1,024,838	)		$	1,143,146

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Reorganization Adjustments


1.	Reflects the net cash payments recorded as of the Effective Date from implementation of the Plan:



(in thousands)
Sources:
Net proceeds from Senior Secured Credit Facility*	$	436,500
Total sources	436,500
Uses:
Funding of escrow account	200,000
Debt issuance costs	8,356
Total uses	208,356
Net Sources	$	228,144

*$450 million Senior Secured Credit Facility issued at a discount of 3%


2.	Reflects the funding of $200 million to an escrow account 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.


3.	Reflects the reduction of tax attributes and corresponding change to the valuation allowance as a result of the Debtor's emergence from Chapter 11 bankruptcy proceedings (See Note 16).


4.	Represents debt issuance costs related to the Senior Secured Credit Facility expected to be settled in cash.


5.	Upon issuance of the Senior Secured Credit Facility, the Company received net proceeds of approximately $436.5 million, incurred debt issuance costs of approximately $11.0 million, and recognized a derivative financial instrument approximating $8.5 million.


6.	Reflects the reduction of tax attributes and corresponding change to the valuation allowance as a result of the Debtor's emergence from Chapter 11 bankruptcy proceedings (See Note 16).


7.	Reflects the recording of the embedded put option derivative.


8.	Liabilities subject to compromise were settled as follows in accordance with the Plan:



(in thousands)
8.75% Senior Notes, due July 2021	$	400,000
7.5% Senior Notes, due October 2021	300,000
6.75% Senior Notes, due April 2022	300,000
10.25% Senior Notes, due April 2019	200,000
3.375% Convertible Senior Notes, due June 2038	7,565
7.375% Senior Notes, due April 2018	3,508
Accrued Interest	43,772
Liabilities subject to compromise of the Predecessor Company (LSTC)	1,254,845
Fair value of equity issued to holders of the Senior Notes of the Predecessor	(568,286		)
Gain on settlement of liabilities subject to compromise (debt forgiveness)	$	686,559

Refer to 10. below as explanation for the determination of fair value for equity issued to holders of the Senior Notes of the Predecessor.


9.	Reflects the cancellation of Predecessor Company equity to retained earnings.

10.

Reflects the issuance of 19.4 million shares of common stock at a per share price of $29.32 to the holders of the Senior Notes of the Predecessor and 0.6 million shares of common stock at a per share price of $29.32 to the stockholders of the Predecessor Company as well as the repurchase of eleven thousand shares into treasury at a per share price of $29.32. Additionally, this amount reflects the issuance of 5.0 million warrants valued at $0.29 to the stockholders of the Predecessor Company.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


11.	Reflects the cumulative impact of the reorganization adjustments discussed above:



(in thousands)
Gain on settlement of liabilities subject to compromise	$	686,559
Net gain on reorganization adjustments	686,559
Fair value of shares issued to stockholders	(18,180		)
Fair value of shares purchased back to treasury	325
Fair value of warrants issued to stockholders	(1,433		)
Cancellation of Predecessor Company equity	2,131,452
Tax impact on reorganization adjustments	(39,693		)
Net impact to retained earnings (deficit)	$	2,759,030

The net gain on reorganization adjustments has been included in Reorganization Items, Net in the Consolidated Statement of Operations.

Fresh-Start Adjustments


12.	An adjustment of $1.0 billion was recorded to decrease the net book value of property and equipment to estimated fair value. Fair value was determined as follows:

•We utilized the income and cost approach for drilling rigs and marine equipment.The discounted cash flow method under the Income approach estimates the future cash flow that a business or asset is expected to generate. Future cash flow is converted to a present value equivalent using an estimated discount rate such as the cost of equity or the weighted average cost of capital ("WACC" or "discount rate"), based on the type of cash flows being discounted. The Cost approach considers the amount required to construct or purchase a new asset of equal utility at current prices, with adjustments in value for physical deterioration, and functional and economic obsolescence. Physical deterioration is an adjustment made in the cost approach to reflect the real operating age of an asset with regard to wear and tear, decay and deterioration that is not prevented by maintenance. Functional obsolescence is the loss in value or usefulness of an asset caused by inefficiencies or inadequacies of the asset, as compared to a more efficient or less costly replacement asset with newer technology. Economic obsolescence is the loss in value or usefulness of an asset due to factors external to the asset, such as the economics of the industry, reduced demand, increased competition or similar factors.

•We utilized the market, sales comparison or trended cost approach for drilling machinery and equipment. This approach relies upon recent sales and offerings of similar assets to arrive at a probable selling price.

•For the land and building, included in Other below, we considered the market rents for the property and the subject property's specific characteristics as well as current market conditions and demand.

The following table summarizes the components of property and equipment, net as of November 6, 2015, and the fair value at November 6, 2015:



	Predecessor		Successor
(in thousands)	November 6, 2015		November 6, 2015
Drilling rigs and marine equipment	$	1,485,420	$	447,571
Drilling machinery and equipment	17,365		12,609
Other	12,013		5,081
Total	$	1,514,798	$	465,261

For property and equipment owned at November 6, 2015, the depreciable lives were revised to reflect the remaining estimated useful lives (See Note 2).


13.	The net adjustment of $24.7 million reflects the write-off of existing deferred drydock of $1.9 million, $0.1 million for the recording of a valuation allowance on the federal benefit of a foreign deferred tax asset and an adjustment of $26.5 million to record the fair value of intangibles, determined as follows:


a.	Customer contract related intangibles of $25.3 million were valued using the income approach.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


b.	In addition, the Company recorded the fair value of other intangibles of $1.2 million related to the corporate office lease which was favorable relative to available market terms.


14.	Represents the revaluation of liabilities related to a previous acquisition of $2.8 million as well as the revaluation of the current portion of deferred revenues to fair value as the Company has no related future performance obligations of $1.4 million and the revaluation of a tenant allowance of $0.3 million.


15.	Represents the adjustment to record the Senior Secured Credit Facility at fair value.


16.	Reflects the change from a deferred tax liability to a deferred tax asset associated with adjustments to fresh-start accounting and the corresponding change to the valuation allowance (See Note 16).


17.	Represents the revaluation of deferred revenues to fair value as the Company has no related future performance obligations of $12.0 million and the revaluation of the long-term portion of a tenant allowance of $0.3 million.


18.	Reflects the cumulative impact of fresh-start adjustments as discussed above.



(in thousands)
Establishment of Successor intangibles	$	26,478
Property and equipment fair value adjustment	(1,049,537		)
Long-term debt fair value adjustment	(10,998		)
Other assets and liabilities adjustment	14,802
Net loss on fresh-start adjustments	(1,019,255		)
Tax impact on fresh-start adjustments	39,693
Net impact on retained earnings (deficit)	$	(979,562	)

The net loss on fresh-start adjustments has been included in Reorganization Items, Net in the Consolidated Statement of Operations.

6. 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.

For the periods November 6, 2015 to December 31, 2015 and January 1, 2015 to November 6, 2015, cash payments for reorganization items totaled $1.4 million and $3.9 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

7. Property and Equipment, Net

The following is a summary of property and equipment, less accumulated depreciation:



	Successor			Predecessor
	December 31,			December 31,
(in thousands)	2015			2014
Drilling rigs and marine equipment	$	451,841		$	2,098,651
Drilling machinery and equipment	12,937			42,317
Other	5,081			38,195
	469,859			2,179,163
Less accumulated depreciation	(4,362		)	(604,414		)
Total property and equipment, net	$	465,497		$	1,574,749

In connection with the application of fresh-start accounting as of November 6, 2015, Hercules recorded fair value adjustments and therefore eliminated accumulated depreciation as of that date (See Note 5).

Depreciation expense was $4.3 million, $124.4 million, $164.9 million and $155.0 million 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, respectively, of which, $7.1 million related to discontinued operations for the year ended December 31, 2013 is included in Loss from Discontinued Operations, Net of Taxes on the Consolidated Statement of Operations.

8. Business Combinations and Asset Acquisitions

Predecessor

Prior to June 24, 2013 the Company held a 32% equity investment in Discovery, which was a development stage company whose purpose was to own new ultra high-specification jackup drilling rigs. Historically, the Company accounted for its investment in Discovery under the equity method of accounting. On June 24, 2013 ("Acquisition Date"), the Company acquired an additional 52% interest to bring the total interest held to 84%, for cash consideration, net of cash acquired of $77.7 million ("Discovery Transaction") and began consolidating Discovery's results of operations from that date. The Discovery Transaction allowed the Company to enter into the high-specification jackup rig market, significantly expanded its service offerings and opened new international markets that had growing needs for assets of this caliber. As of December 31, 2013, the Company held a 100% interest in Discovery as a result of additional purchases of Discovery common stock shares at 15 Norwegian Kroner ("NOK") per share (USD $26.3 million in total).

The acquisition date fair value of the Company's previously held equity interest in Discovery was $52.0 million based on the price the Company paid for additional Discovery shares on June 24, 2013 of 15 NOK per share. The Company recognized a $14.9 million gain, included in Gain on Equity Investment in the Consolidated Statement of Operations for the year ended December 31, 2013, as a result of remeasuring its 32% equity interest in Discovery at its fair value as of the Acquisition Date in accordance with FASB Accounting Standards Codification ("ASC") Topic 805, Business Combinations.

In connection with the Discovery Transaction, the Company settled certain pre-existing relationships including a receivable from Discovery, warrants to purchase 5 million Discovery shares (see Note 15), as well as deferred revenue in the amounts of $14.3 million, $3.5 million, and $5.6 million, respectively, at the Acquisition Date.

The Company valued the noncontrolling interest at the Acquisition Date of 15 NOK per share or $26.4 million in total.

The components of the consideration transferred on June 24, 2013 were as follows (in thousands):



Cash Paid, Net of Cash Acquired	$	77,658
Elimination of Related Party Balances	12,283
Fair Value of Discovery Equity Investment	51,959
Noncontrolling Interest	26,448
	$	168,348

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The unaudited pro forma financial information set forth below has been compiled from historical financial statements and other information, but is not necessarily indicative of the results that actually would have been achieved had the transactions occurred on the dates indicated or that may be achieved in the future:



	Year Ended
(in millions, except per share data)	December 31, 2013
Revenue	$	850.2
Loss from Continuing Operations	$	(40.4	)
Loss from Discontinued Operations, Net of Taxes	(41.3		)
Net Loss	(81.7		)
Loss attributable to Noncontrolling Interest	—
Net Loss attributable to Hercules Offshore, Inc.	$	(81.7	)
Net Loss attributable to Hercules Offshore, Inc. Per share:
Basic and Diluted:
Loss from Continuing Operations	$	(0.25	)
Loss from Discontinued Operations	(0.26		)
Net Loss	$	(0.51	)

The Company incurred transaction costs in the amount of $3.3 million for the year ended December 31, 2013 related to the Discovery Transaction which is included in General and Administrative in the Consolidated Statement of Operations.

The amount of revenue and net income of Discovery included in the Company's Consolidated Statement of Operations for the year ended December 31, 2013 is as follows:



	Predecessor
(in millions)	June 24, 2013 through December 31, 2013
Revenue	$	17.3
Net Income	2.5

In March 2013, the Company acquired the offshore drilling rig Hercules 267 for $55.0 million and the liftboat Bull Ray for $42.0 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

9. Dispositions and Discontinued Operations

From time to time the Company enters into agreements to sell assets. The following table provides information related to the sale of several of the Company’s assets, excluding other miscellaneous asset sales that occur in the normal course of business, during the years ended December 31, 2015, 2014 and 2013:



				Predecessor
Asset		Segment	Period of Sale	Proceeds		Gain/(Loss)
				(in thousands)
Period from January 1, 2015 to November 6, 2015:
	Hercules 85 (a)	Domestic Offshore	May 2015	$	250	$	(2,606	)
	Hercules 153 (a)	Domestic Offshore	May 2015	250		(1,039		)
	Hercules 203 (a)	Domestic Offshore	May 2015	250		(1,050		)
	Hercules 206 (a)	Domestic Offshore	May 2015	250		(1,039		)
	Hercules 207 (a)	Domestic Offshore	June 2015	1,750		(43		)
	Hercules 211 (a)	Domestic Offshore	June 2015	1,750		292
				$	4,500	$	(5,485	)
2014:
	Hercules 258 (a)	International Offshore	April 2014	$	12,000	$	10,526
	Hercules 2002 (a)	Domestic Offshore	April 2014	1,750		470
	Hercules 250 (a)	Domestic Offshore	June 2014	8,450		6,883
	Hercules 2003 (a)	Domestic Offshore	August 2014	1,750		500
	Hercules 2500 (a)	Domestic Offshore	August 2014	6,000		4,680
	Hercules 156 (a)	International Offshore	September 2014	3,100		(439		)
				$	33,050	$	22,620
2013:
	Various (b) (c)	Domestic Liftboats	July 2013	$	54,447	$	—
	Various (b) (d)	Inland	July 2013	44,331		—
	Hercules 27 (b)	Inland	August 2013	5,149		4,834
	Hercules 170 (a)	International Offshore	December 2013	8,300		(11,498		)
				$	112,227	$	(6,664	)

_____________________


(a)	These gains (losses) are included in Operating Expenses on the Consolidated Statements of Operations.


(b)	These gains (losses) have been reflected in the Consolidated Statements of Operations as discontinued operations.


(c)	The Company completed the sale of its U.S. Gulf of Mexico liftboats and related assets.


(d)	The Company completed the sale of eleven inland barge rigs and related assets.

Discontinued Operations

In 2013, the Company sold its U.S. Gulf of Mexico liftboats and related assets and additionally sold twelve of its inland barge rigs and related assets, comprising the majority of the Inland segment fleet. These long-lived assets, excluding the Hercules 27, were written down to their fair value less estimated cost to sell, resulting in non-cash impairment charges (See Note 15).

Interest charges have been allocated, based on a pro rata calculation of the net assets sold as compared to the Company’s consolidated net assets, to the Inland and Domestic Liftboats segments. Interest allocated to discontinued operations of the Inland and Domestic Liftboats segments was $1.4 million and $1.2 million for the year ended December 31, 2013, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Operating results included in discontinued operations were as follows:



	Predecessor
(in thousands)	Year Ended December 31, 2013
Inland:
Revenue	$	15,782
Loss Before Income Taxes	$	(39,585	)
Income Tax Benefit	2,587
Loss from Discontinued Operations, Net of Taxes	$	(36,998	)
Domestic Liftboats:
Revenue	$	29,625
Loss Before Income Taxes	$	(4,310	)
Income Tax Provision	—
Loss from Discontinued Operations, Net of Taxes	$	(4,310	)
Total:
Revenue	$	45,407
Loss Before Income Taxes	$	(43,895	)
Income Tax Benefit	2,587
Loss from Discontinued Operations, Net of Taxes	$	(41,308	)

10. Long-Term Incentive Awards

Predecessor

Stock-based Compensation

The Company’s 2014 Long-Term Incentive Plan (the “2014 Plan”), provided for the granting of stock options, stock appreciation rights, restricted stock, restricted stock units, dividend equivalents, performance awards and other stock-based awards to selected employees and non-employee directors of the Company. The 2014 Plan and any shares that were available for grant or award under such were canceled on the Effective Date pursuant to the Plan. The Company's 2004 Amended and Restated Long-Term Incentive Plan (the "2004 Plan") remained in effect after the approval of the 2014 Plan only as it related to outstanding awards previously granted under such 2004 Plan, but was canceled on the Effective Date pursuant to the Plan. The Compensation Committee of the Company’s Board of Directors selected participants from time to time and, subject to the terms and conditions of the 2014 Plan, determined all terms and conditions of awards. The Company issued originally issued shares upon exercise of stock options and for restricted stock grants. On the Effective Date, all share-based awards requiring share settlement that were granted under the Predecessor were canceled pursuant to the Plan. Certain award agreements requiring cash settlement contained change of control provisions which provided for vesting. The amount of liability for predecessor liability-based awards requiring cash settlement was $4.1 million and $2.0 million at November 6, 2015 and December 31, 2015, respectively. Cash payment related to these liability-based awards during the period November 6, 2015 to December 31, 2015 was $2.1 million.

The Company had the following equity award grants:

•

Time-based awards The Company granted time-based restricted stock awards to its employees which vest 1/3 per year and previously to Directors which vested on the date of the Company's annual meeting of stockholders that followed the grant date. The grant-date fair value per share for these time-based restricted stock awards was equal to the closing price of the Company's stock on the grant date. Additionally, the Company previously granted stock options which vested 1/3 per year and had a maximum contractual term of 10 years.

•

Objective-based awards The Company granted compensation awards to its employees that were based on the Company's achievement of certain Company-based performance objectives as well as the Company's achievement of certain market-based objectives. The awards granted in 2015 were to cliff vest three years from the date of grant and were payable in cash, subject to vesting requirements, after the completion of all performance periods with 20% of the award being achievable based on a one-year performance period, 30% being achievable based on a two-year performance period, and the remaining 50% being achievable based upon a three-year performance period. The CEO’s

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

award also contains an equity component that is earned, in addition to the cash, up to a total amount of 400,000 shares if minimum levels of performance were achieved. The awards granted in 2014 and 2013, which were to cliff vest on the third anniversary of the grant date, are payable in shares at target levels when combined and in cash for the amount above target up to maximum, as defined by the agreements. For the Chief Executive Officer ("CEO"), the portion of these awards payable in cash was based on the achievement of certain market-based and Company-based performance objectives being met at certain levels below target when combined. Additionally, for the awards granted in 2014, if either the market-based or Company-based performance objectives were met at threshold or above, but the other was not, the CEO was entitled to a cash award for that objective if it was met at target or above. For 2012, a portion of the awards were payable in shares of the Company's common stock which vest 1/3 per year. For 2012, if the highest market-based and Company-based performance objectives were met, a portion of these awards were payable in cash and cliff vested at the first anniversary of the grant date. In addition, the Company granted certain awards to its CEO in 2011 that were based upon the Company's achievement of certain market-based objectives and were paid in cash at the end of the vesting periods at March 31, 2014 and December 31, 2013 ("Performance Retention Awards"). Additionally, a retention award, granted in 2011, outside of the 2004 Plan was paid in cash at December 31, 2013, the end of a three-year vesting period.

The Company recognized a $4.0 million expense, a $0.4 million benefit and a $3.4 million expense for employee compensation during the period January 1, 2015 to November 6, 2015 and the years ended December 31, 2014 and 2013, respectively, for all liability-based awards. The expense for the period January 1, 2015 to November 6, 2015 includes $3.7 million of expense related to change of control provisions. For these awards, there was no related income tax benefit in the period January 1, 2015 to November 6, 2015 and the years ended December 31, 2014 and 2013, respectively. The Company recognized $6.9 million, $8.3 million and $10.0 million in employee stock-based compensation expense for all share-settled awards during the period January 1, 2015 to November 6, 2015 and the years ended December 31, 2014 and 2013, respectively. The expense for the period January 1, 2015 to November 6, 2015 includes $4.4 million of expense related to the cancellation of awards pursuant to the Plan, which under ASC 718 requires that any unrecognized cost on the cancellation date be recognized. For these awards, there was no related income tax benefit in the period January 1, 2015 to November 6, 2015 and the years ended December 31, 2014 and 2013, respectively. The Company classified $0.4 million and $1.0 million in excess tax benefits as a financing cash inflow for the years ended December 31, 2014 and 2013, respectively. There were no excess tax benefits to classify as financing cash inflow for the period January 1, 2015 to November 6, 2015.

The Company used various assumptions to estimate the fair value of its objective-based awards. The risk-free interest rate assumptions were based on observed interest rates consistent with the approximate vesting periods. For the Performance Retention Awards in 2013, the Company used the historical volatility of its common stock to estimate volatility and the dividend yield assumption was based on the historical and anticipated dividend payouts of the Company. For the 2015, 2014 and 2013 objective-based awards, the Company used the historical volatility of its common stock, as well as that of certain peer groups, as defined in the award agreements to estimate volatility and the dividend yield assumptions were based on historical and anticipated dividend payouts of the Company, as well as that of certain peer groups, as defined in the award agreements.

Objective-based Awards (cash settled)

The Company accounts for awards or the portion of the awards requiring cash settlement under stock-compensation principles of accounting as liability instruments. The fair value of all liability instruments are being remeasured based on the awards' estimated fair value at the end of each reporting period and are being recorded to expense over the vesting period. The awards that are based on the Company's achievement of market-based objectives related to its stock price performance as compared to certain peer groups, as defined in the award agreements, are valued using a Monte Carlo simulation. The following are the assumptions for the Company:



	December 31, 2014			December 31, 2013
	Restricted Stock Market-Based			Performance Retention Awards			Restricted Stock Market-Based
Dividend yield	—			—			—
Expected price volatility	54.4		%	65.0		%	44.1		%
Risk-free interest rate	0.5		%	0.1		%	0.4		%
Stock price (a)	$	1.00		$	6.52		$	6.52
Fair value	$	0.05		$	4.19		$	6.19

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_____________________________

(a) The stock price represents the closing price of the Company's common stock at the valuation date.

Stock Option Awards

The following table summarizes stock option activity as of November 6, 2015 and changes during the period then ended:



Stock Options	Shares		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term	Aggregate Intrinsic Value
						(in thousands)
Outstanding at January 1, 2015	3,005,480		$	8.91	3.87	$	—
Granted	—		—
Exercised	—		—
Cancelled	(1,809,358	)	7.50
Expired	(1,196,122	)	11.04
Outstanding at November 6, 2015	—		—		0.00	—
Vested or Expected to Vest at November 6, 2015	—		—		0.00	—
Exercisable at November 6, 2015	—		—		0.00	—

The intrinsic value of stock options exercised during 2014 and 2013 was $0.2 million and $0.4 million, respectively. Cash received from stock option exercises was $0.1 million and $0.3 million during the years ended December 31, 2014 and 2013, respectively. There were no stock option exercises during the period January 1, 2015 through November 6, 2015.

Objective-based Awards (share settled)

The fair value of all awards requiring share settlement were measured at the fair value on the date of grant. These awards that were based on the Company's achievement of market-based objectives related to its stock price performance as compared to certain peer groups, as defined in the award agreements, were valued at the date of grant using a Monte Carlo simulation. The following are the assumptions for the Company:



	March 2, 2015			February 19, 2014			February 28, 2013
Dividend yield	—			—			—
Expected price volatility	71.7		%	54.4		%	64.7		%
Risk-free interest rate	0.7		%	0.6		%	0.3		%
Stock price (a)	$	0.55		$	4.71		$	6.78
Fair value	$	0.55		$	3.63		$	7.78

_____________________________


(a)	The stock price represents the closing price of the Company's common stock at March 2, 2015, February 19, 2014 and February 28, 2013, the respective grant dates.

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The following table summarizes information about objective-based restricted stock outstanding as of November 6, 2015 and changes during the period then ended:



	Objective-Based Restricted Stock		Weighted- Average Grant Date Fair Value
Non-Vested at January 1, 2015	2,125,870		$	5.36
Granted (a)	400,000		0.55
Vested	(176,211	)	5.94
Canceled	(1,718,226	)	4.22
Forfeited	(631,433	)	5.23
Non-Vested at November 6, 2015	—		—

_____________________________


(a)	The number of objective-based restricted stock shown reflects the shares that would be granted if the maximum level of performance is achieved. The number of shares actually issued may range from zero to 400,000.

The weighted-average grant date fair value of objective-based restricted stock granted during the period January 1, 2015 to November 6, 2015 and the years ended December 31, 2014 and 2013 was $0.55, $4.17 and $7.16, respectively. The total fair value of objective-based restricted stock that vested during the period January 1, 2015 to November 6, 2015 and the years ended December 31, 2014 and 2013 was $0.1 million, $2.0 million and $3.1 million, respectively.

Time-based Restricted Stock Awards

The following table summarizes information about time-based restricted stock outstanding as of November 6, 2015 and changes during the period then ended:



	Time-Based Restricted Stock		Weighted- Average Grant Date Fair Value
Non-Vested at January 1, 2015	1,849,525		$	5.08
Granted	1,600,000		0.55
Vested	(908,186	)	5.18
Canceled	(1,928,505	)	1.97
Forfeited	(612,834	)	2.90
Non-Vested at November 6, 2015	—		—

The weighted-average grant date fair value of time-based restricted stock granted during the period January 1, 2015 to November 6, 2015 and the years ended December 31, 2014 and 2013 was $0.55, $4.59 and $6.86, respectively. The total fair value of time-based restricted stock that vested during the period January 1, 2015 to November 6, 2015 and the years ended December 31, 2014 and 2013 was $0.7 million, $4.1 million and $6.1 million, respectively.

Successor

On December 11, 2015, the Company's Board of Directors adopted the Hercules Offshore, Inc. 2015 Long-Term Incentive Plan (the "2015 LTIP") which subject to adjustment in accordance with the 2015 LTIP, provides that 2.0 million shares of our common stock will be available for issuance pursuant to awards under the 2015 LTIP. The 2015 LTIP provides for the granting of stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards and other stock-based awards. There were 1.8 million shares available for grant at December 31, 2015. The 2015 LTIP is administered by a committee of the Company's board of directors consisting of at least two outside directors, which is referred to herein as the "committee," except in the event the Company's board of directors choses to administer the 2015 LTIP. The committee, subject to the terms and conditions of the 2015 LTIP, determines all terms and conditions of awards, including who is eligible to receive awards.

The Company granted time-based restricted stock awards to its Directors which vest in full on the one-year anniversary of the Grant Date. Vested shares will be delivered to the Director upon a change of control of the Company or such Director's

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departure from the Board. The grant-date fair value per share for these time-based restricted stock awards is equal to the closing price of the Company's stock on the grant date.

The Company recognized twenty-six thousand dollars in stock-based compensation for the time-based restricted stock awards granted to the Company's Directors during the period of November 6, 2015 to December 31, 2015.

Time-based Restricted Stock Awards

The following table summarizes information about time-based restricted stock outstanding as of December 31, 2015 and changes during the period November 6, 2015 to December 31, 2015:



	Time-Based Restricted Stock	Weighted- Average Grant Date Fair Value
Non-Vested at November 6, 2015	—	$	—
Granted	164,286	2.80
Vested	—	—
Forfeited	—	—
Non-Vested at December 31, 2015	164,286	2.80

The Company's estimate of future expense relating to the Successor Company's restricted stock awards granted through December 31, 2015 as well as the remaining vesting period over which the associated expense is to be recognized is $0.4 million and 0.9 years, respectively.

11. Supplemental Financial Information

Consolidated Balance Sheet Information

Accrued liabilities consisted of the following:



	Successor		Predecessor
	December 31,		December 31,
(in thousands)	2015		2014
Accrued Liabilities:
Taxes other than Income	$	12,617	$	15,262
Accrued Payroll and Employee Benefits	17,062		25,460
Accrued Self-Insurance Reserves	18,532		24,514
Other	897		854
	$	49,108	$	66,090

Other current liabilities consisted of the following:



	Successor		Predecessor
	December 31,		December 31,
(in thousands)	2015		2014
Other Current Liabilities:
Deferred Revenue-Current Portion	$	—	$	9,439
Other	6,148		3,967
	$	6,148	$	13,406

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Supplemental Cash Flow Information



	Successor		Predecessor
	Period from November 6, 2015 to December 31, 2015		Period from January 1, 2015 to November 6, 2015		Year Ended December 31,
(in thousands)	Period from November 6, 2015 to December 31, 2015		Period from January 1, 2015 to November 6, 2015		2014		2013
Cash paid, net during the period for:
Interest, net of capitalized interest	$	7,219	$	47,728	$	97,304	$	55,094
Income taxes	505		1,562		21,147		15,658

Capitalized interest was $2.4 million, $4.4 million and $20.4 million for the period January 1, 2015 to November 6, 2015 and the years ended December 31, 2014 and 2013, respectively. There was no capitalized interest for the period November 6, 2015 to December 31, 2015.

Concentration of Credit Risk

The Company maintains its cash and cash equivalents in bank deposit accounts at high credit quality financial institutions or in highly rated liquid investments with maturities of three months or less. The balances, at many times, exceed federally insured limits.

The Company provides services to a diversified group of customers in the oil and natural gas exploration and production industry. Credit is extended based on an evaluation of each customer’s financial condition. The Company maintains an allowance for doubtful accounts receivable based on expected collectability and establishes a reserve when payment is unlikely to occur.

Sales to Major Customers

The Company’s 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 the Company’s 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 the Company’s International Offshore segment.


(b)	Revenue included in the Company's Domestic Offshore, International Offshore and International Liftboats segments.


(c)	Revenue included in the Company's Domestic Offshore segment.


(d)	Revenue included in the Company’s International Offshore and Domestic Offshore segments.


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

12. Benefit Plan

The Company currently has a 401(k) plan in which substantially all U.S. employees are eligible to participate. Effective April 1, 2013, the Company increased the Company match of participant contributions equal to 6% from 3% of a participant's eligible compensation and effective March 15, 2015 the Company eliminated the match of participant contributions. The

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Company incurred expense related to matching contributions of $1.1 million, $6.8 million and $5.7 million for the period January 1, 2015 to November 6, 2015 and the years ended December 31, 2014 and 2013, respectively.

13. Debt

Debt is comprised of the following:



	Successor		Predecessor
(in thousands)	December 31, 2015		December 31, 2014
Senior Secured Credit Facility, due May 2020	$	428,715	$	—
8.75% Senior Notes, due July 2021	—		400,000
7.5% Senior Notes, due October 2021	—		300,000
6.75% Senior Notes, due April 2022	—		300,000
10.25% Senior Notes, due April 2019	—		200,000
3.375% Convertible Senior Notes, due June 2038*	—		7,410
7.375% Senior Notes, due April 2018	—		3,509
Total Long-term Debt	$	428,715	$	1,210,919

* The carrying amount of the equity component was $30.1 million at December 31, 2014.

The following is a summary of scheduled long-term debt maturities by year (in thousands):



2016	$	—
2017	—
2018	—
2019	—
2020	428,715
Thereafter	—
	$	428,715

The Senior Secured Credit Facility accretes to the $450.0 million aggregate principal over 4.5 years, the current expected life of the debt.



	Successor
	Period from November 6, 2015 to December 31, 2015
(in millions)	Contractual Interest		Accreted Interest		Total Interest		Effective Rate
Senior Secured Credit Facility, due May 2020	$	7.2	$	0.7	$	7.9	11.6	%

The unamortized discount of the 10.5% Senior Notes was amortized to interest expense over the original expected life of the debt instrument. The unamortized discount of the 3.375% Convertible Senior Notes was amortized to interest expense over the original expected life of the debt, which was determined to be June 1, 2013, the earliest date the holders of the notes had the right to require the Company to repurchase the notes.



	Predecessor
	Year Ended December 31, 2013
(in millions)	Coupon Interest		Discount Amortization		Total Interest		Effective Rate
10.5% Senior Notes, due October 2017	$	24.1	$	0.7	$	24.8	11.00	%
3.375% Convertible Senior Notes, due June 2038	1.1		1.2		2.3		7.27

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Successor

Senior Secured Credit Facility

On November 6, 2015 (the "Credit Agreement Closing Date"), the Company entered into a Credit Agreement (the "Credit Agreement") that provides for a $450.0 million senior secured credit facility ("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 pursuant to an Escrow Agreement and will be released pursuant to the terms of such Agreement. The Escrowed Amount is 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 (See Note 18). The remaining proceeds of the loans are being 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. All loans under the Credit Agreement mature on May 6, 2020.

The Company may voluntarily prepay loans under the Credit Agreement, subject to customary notice requirements and minimum prepayment amounts, the payment of LIBOR breakage costs, if any, and (i) if such prepayment is made prior to the third anniversary of the Credit Agreement Closing Date, a prepayment premium of 3.0% of the principal amount of the loans being prepaid plus the present value of the sum of all required payments of interest on the aggregate principal amount of the loans being prepaid through the third anniversary of the Credit Agreement Closing Date, (ii) if such prepayment made after the third anniversary of the Credit Agreement Closing Date but on or prior to the fourth anniversary of the Credit Agreement Closing Date, a prepayment premium of 3.0% of the aggregate principal amount of the loans being prepaid and (iii) if such prepayment is made after the fourth anniversary of the Credit Agreement Closing Date, without premium or penalty.

The Credit Agreement requires mandatory prepayments of amounts outstanding thereunder with (i) the net proceeds of certain asset sales and casualty events, subject to certain reinvestment rights, (ii) the net proceeds of certain equity issuances, subject to certain exceptions, including with respect to equity issuances used to finance acquisitions, (iii) the net proceeds of debt issuances not permitted by the Credit Agreement, (iv) any cancellation, termination or other fee received in connection with the cancellation or termination of the construction contract or drilling contract for the Hercules Highlander, and (v) the Escrowed Amount if the Escrow Conditions are not satisfied. No prepayment premium is payable in connection with any of these mandatory prepayments, unless the mandatory prepayment is a result of the issuance of debt not permitted by the Credit Agreement. In addition, if a change of control (as defined in the Credit Agreement) occurs, each lender will have the right to require the Company to prepay its loans at 101% of the principal amount of the loans requested to be prepaid.

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) in aggregate a total of $9.0 million, and the Company paid certain administrative and other fees to the Agent of $1.2 million.

The Credit Agreement contains covenants that, among other things, limit the Company’s ability and the ability of the Company’s restricted subsidiaries to:

• incur indebtedness;

• create liens;

• enter into sale and leaseback transactions;

• 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);

• consolidate, merge or transfer all or substantially all of its assets;

• sell assets;

• engage in transactions with its affiliates;

• modify or terminate any material agreement;

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

• engage in any new line of business.

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These covenants are subject to a number of important qualifications and limitations. In addition, the Company has to maintain compliance with (i) a maximum senior secured first lien leverage ratio (as defined in the Credit Agreement, being generally computed as the ratio of secured first lien debt to consolidated net income before interest, taxes, depreciation and amortization, which EBITDA amount will be annualized for any test period during 2017) commencing from the fiscal quarter ending March 31, 2017 and (ii) a minimum liquidity amount, consisting of unrestricted cash and cash equivalents, commencing from the Credit Agreement Closing Date. The maximum secured leverage ratio is 6.0 to 1.0 for the fiscal quarter ending March 31, 2017, 5.0 to 1.0 for the fiscal quarter ending June 30, 2017, 4.0 to 1.0 for the fiscal quarter ending September 30, 2017, and 3.5 to 1.0 for the fiscal quarter ending December 31, 2017 and thereafter. The minimum liquidity is $100.0 million for the period beginning on the Credit Agreement Closing Date and ending on June 30, 2016, $75.0 million for the period beginning July 1, 2016 and ending December 31, 2016, $50.0 million for the period beginning January 1, 2017 and ending June 30, 2017, and $25.0 million for the period beginning July 1, 2017 and thereafter. At December 31, 2015, the Company was in compliance with all covenants under our Senior Secured Credit Facility.

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. Upon an event of default under the Credit Agreement, the Agent may, or at the direction of lenders holding a majority of the loans under the Credit Agreement shall, declare all amounts owing under the Credit Agreement to be due and payable. In addition, upon an event of default under the Credit Agreement the Agent is empowered to exercise all rights and remedies of a secured party and foreclose upon the collateral securing the Credit Agreement, in addition to all other rights and remedies under the security documents described in the Credit Agreement. Upon any acceleration of the loans under the Credit Agreement, the prepayment premiums described above that are otherwise applicable to voluntary prepayments shall become due and payable to the lenders.

Embedded Derivative

Predecessor

Cancellation of Indebtedness

Termination of Credit Facility

On April 3, 2012, the Company entered into a credit agreement which as amended on July 8, 2013 (the "Predecessor Credit Agreement") governed its senior secured revolving credit facility (the "Credit Facility"). The Predecessor Credit Agreement provided for a $150.0 million senior secured revolving credit facility.

In connection with the RSA, the Company terminated the Credit Facility effective June 22, 2015 (See Note 4). There were no amounts outstanding and no letters of credit issued under the Credit Facility at that time. 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.

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8.75% Senior Notes due 2021

On July 8, 2013, the Company completed the issuance and sale of $400.0 million aggregate principal amount of senior notes at a coupon rate of 8.75% ("8.75% Senior Notes") with maturity in July 2021. These notes were sold at par and the Company received net proceeds from the offering of the notes of approximately $393.0 million after deducting the bank fees and estimated offering expenses. The net proceeds from this offering, together with cash on hand (including the proceeds of approximately $103.9 million the Company received from the sales of its inland barge rigs, domestic liftboats and related assets), were used to fund its acquisition of Discovery shares, the final shipyard payments totaling $333.9 million for Hercules Triumph and Hercules Resilience, related capital expenditures, as well as general corporate purposes. In accordance with the Plan, on the Effective Date all of the obligations of the Debtors with respect to the 8.75% Senior Notes were canceled (See Notes 4 and 5).

7.5% Senior Notes due 2021

On October 1, 2013, the Company completed the issuance and sale of $300.0 million aggregate principal amount of senior notes at a coupon rate of 7.5% ("7.5% Senior Notes") with maturity in October 2021. These notes were sold at par and the Company received net proceeds from the offering of the notes of approximately $294.5 million after deducting the bank fees and estimated offering expenses. In accordance with the Plan, on the Effective Date all of the obligations of the Debtors with respect to the 7.5% Senior Notes were canceled (See Notes 4 and 5).

6.75% Senior Notes due 2022

On March 26, 2014, the Company completed the issuance and sale of $300.0 million aggregate principal amount of senior notes at a coupon rate of 6.75% ("6.75% Senior Notes") with maturity in April 2022. These notes were sold at par and the Company received net proceeds from the offering of the notes of approximately $294.8 million after deducting bank fees and estimated offering expenses. In accordance with the Plan, on the Effective Date all of the obligations of the Debtors with respect to the 6.75% Senior Notes were canceled (See Notes 4 and 5).

10.25% Senior Notes due 2019

On April 3, 2012 the Company completed the issuance and sale of $200.0 million aggregate principal amount of senior notes at a coupon rate of 10.25% ("10.25% Senior Notes") with maturity in April 2019. These notes were sold at par and the Company received net proceeds from the offering of the notes of $195.4 million after deducting the initial purchasers' discounts and offering expenses. In accordance with the Plan, on the Effective Date all of the obligations of the Debtors with respect to the 10.25% Senior Notes were canceled (See Notes 4 and 5).

3.375% Convertible Senior Notes due 2038

In May 2012, the Company repurchased a portion of the 3.375% Convertible Senior Notes and in accordance with ASC 470-20 Debt - Debt with Conversion and Other Options, the settlement consideration was allocated to the extinguishment of the liability component in an amount equal to the fair value of that component immediately prior to extinguishment with the difference between this allocation and the net carrying amount of the liability component and unamortized debt issuance costs recognized as a gain or loss on debt extinguishment. If there would have been any remaining settlement consideration, it would have been allocated to the reacquisition of the equity component and recognized as a reduction of equity.

On May 1, 2013, the Company made an offer to purchase all of the outstanding notes in accordance with its repurchase obligation under the indenture and on June 1, 2013 repurchased $61.3 million aggregate principal amount of the 3.375% Convertible Senior Notes pursuant to the terms of the optional put repurchase offer. In accordance with the Plan, on the Effective Date all of the obligations of the Debtors with respect to the 3.375% Convertible Senior Notes were canceled (See Notes 4 and 5).

Retirement of 10.5% Senior Notes

In 2009, the Company issued $300.0 million of senior notes at a coupon rate of 10.5% ("10.5% Senior Notes") with maturity in October 2017. On September 17, 2013, the Company commenced a cash tender offer (the "Tender offer") for any and all of the $300.0 million outstanding aggregate principal amount of its 10.5% Senior Notes. Senior notes totaling approximately $253.6 million were settled on October 1, 2013 for $268.5 million using a portion of the proceeds from the issuance of the 7.5% Senior Notes. Additionally, on November 4, 2013 the Company redeemed all $46.4 million of the remaining outstanding 10.5% Senior Notes for approximately $48.8 million using the remaining proceeds from the 7.5% Senior Notes offering, together with cash on hand.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Retirement of 7.125% Senior Secured Notes

In 2012, the Company issued $300.0 million of senior secured notes at a coupon rate of 7.125% ("7.125% Senior Secured Notes") with maturity in April 2017. On March 12, 2014 the Company commenced a cash tender offer (the "Tender offer") for any and all of the $300.0 million outstanding aggregate principal amount of its 7.125% Senior Secured Notes. Senior secured notes totaling approximately $220.1 million were settled on March 26, 2014 for $232.7 million using a portion of the proceeds from the issuance of the 6.75% Senior Notes. Additionally, on April 29, 2014, the Company redeemed all $79.9 million of the remaining outstanding 7.125% Senior Secured Notes for approximately $84.2 million using the remaining net proceeds from the 6.75% Senior Notes offering, together with cash on hand.

Loss on Extinguishment of Debt

During the period January 1, 2015 to November 6, 2015 and the years ended December 31, 2014 and 2013, the Company incurred the following charges which are included in Loss on Extinguishment of Debt in the Consolidated Statements of Operations for their respective periods:


•	During the fourth quarter of 2013, the Company incurred a pretax charge of $29.3 million, consisting of a $17.3 million call premium, $4.8 million unamortized debt discount costs and $4.2 million unamortized debt issuance costs, all related to the redemption of the 10.5% Senior Notes, as well as approximately $3.0 million of bank fees related to the issuance of the 7.5% Senior Notes;


•	In March 2014, the Company incurred a pretax charge of $15.2 million, consisting of a $12.6 million call premium and $1.4 million of unamortized debt issuance costs related to the redemption of the 7.125% Senior Secured Notes, as well as $1.1 million of bank fees related to the issuance of the 6.75% Senior Notes;


•	In April 2014, the Company incurred a pretax charge of $4.8 million, consisting of a $4.3 million call premium and $0.5 million of unamortized debt issuance costs related to the redemption of the remaining 7.125% Senior Secured Notes; and


•	In June 2015, the Company incurred a pretax charge of $1.9 million consisting of $1.8 million of unamortized debt issuance costs and $0.1 million of associated professional fees related to the termination of the Credit Facility.

14. Derivative Instrument

Embedded Derivative

Bifurcated embedded derivatives are initially recorded at fair value and are then revalued at each reporting date with changes in the fair value reported as non-operating income or expense. The fair value of the embedded put option derivative was determined using the "With" and "Without" method (See Note 5 and 15).

The following table provides the fair value of the Company’s derivative:



	Successor
	Fair Value
Balance Sheet Classification	December 31, 2015
	(in thousands)
Derivative:
Embedded Put Option Derivative	$	13,340
Other Liabilities	$	13,340

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table provides the effect of the Company’s derivative on the Consolidated Statements of Operations:



I.	Classification of Gain (Loss) Recognized in Income (Loss) on Derivative



II.	Amount of Gain (Loss) Recognized in Income (Loss) on Derivative

15. Fair Value Measurements

Fair value measurements are generally based upon observable and unobservable inputs. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect the Company’s view of market assumptions in the absence of observable market information. The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company uses the fair value hierarchy included in FASB ASC Topic 820-10, Fair Value Measurements and Disclosure, which is intended to increase consistency and comparability in fair value measurements and related disclosures. The fair value hierarchy consists of the following three levels:

Level 1 — Inputs are quoted prices in active markets for identical assets or liabilities.

Level 2 — Inputs are quoted prices for similar assets or liabilities in an active market, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable and market-corroborated inputs which are derived principally from or corroborated by observable market data.

Level 3 — Inputs are derived from valuation techniques in which one or more significant inputs or value drivers are unobservable.

2013 Discovery Warrants (Predecessor)

The fair value of the settlement of the warrants issued by Discovery (See Note 8) was determined using a Monte Carlo simulation based on the following assumptions:



	Predecessor
	June 24, 2013
Strike Price (NOK)	11.50
Target Price (NOK)	23.00
Stock Value (NOK)	15.00
Expected Volatility (%)	40.0	%
Risk-Free Interest Rate (%)	1.42	%
Expected Life of Warrants (5 years at inception)	2.6
Number of Warrants	5,000,000

The Company used the historical volatility of companies similar to that of Discovery to estimate volatility. The risk-free interest rate assumption was based on observed interest rates consistent with the approximate life of the warrants. The stock price represents the closing stock price of Discovery stock at June 24, 2013. The strike price, target price, expected life and number of warrants are all contractual based on the terms of the warrant agreement. On June 24, 2013, the derivative asset was adjusted to a fair value of $3.5 million, measured using Level 2 inputs, and was included as a purchase adjustment in connection with the purchase of a controlling interest in Discovery.

Embedded Derivative (Successor)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The fair value of the embedded put option derivative was estimated using the “with” and “without” method. Using this methodology, the Senior Secured Credit Facility is first valued with the embedded derivative (the “with” scenario) and subsequently valued without the embedded derivative (the “without” scenario). The fair value of the embedded put option derivative is estimated as the difference between the fair value of the Senior Secured Credit Facility in the “with” and “without” scenarios. The fair value of the Senior Secured Credit Facility in the “with” and “without” scenarios was estimated using an Income Approach. Specifically, to estimate the fair value of the Senior Secured Credit Facility, the expected cash flows were modeled over the life of the debt. The significant assumptions used in the valuation of the embedded put option derivative are: the fair value of the Senior Secured Credit Facility, the expected recovery rate, the risk-neutral probability of default, and the risk-free rate (Level 3). The initial measurement of fair value for this derivative liability was at November 6, 2015, the date the Company entered into the Senior Secured Credit Facility (See Note 5 and 13).

The following table represents the Company’s derivative liability measured at fair value on a recurring basis as of December 31, 2015:



	Successor
(in thousands)	Total Fair Value Measurement		Quoted Prices in Active Markets for Identical Asset or Liability (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Embedded Put Option Derivative	$	13,340	$	—	$	—	$	13,340

2014 Asset Impairments (Predecessor)

The following table represents the Company’s assets measured at fair value on a non-recurring basis for which an impairment measurement was made during the year ended December 31, 2014:



	Predecessor
(in thousands)	Total Fair Value Measurement		Quoted Prices in Active Markets for Identical Asset or Liability (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Gain (Loss)
Property and Equipment, Net (a)	$	6,000	$	—	$	—	$	6,000	$	(82,507	)
Property and Equipment, Net (b)	7,500		—		—		7,500		(117,001		)


(a)	This represents a non-recurring fair value measurement made at September 30, 2014 for Hercules 202, Hercules 204, Hercules 212 and Hercules 213.


(b)	This represents a non-recurring fair value measurement made at December 31, 2014 for Hercules 120, Hercules 200, Hercules 214, Hercules 251 and Hercules 253.

The Company made the decision to remove the Hercules 120, Hercules 200, Hercules 202, Hercules 204, Hercules 212, Hercules 213, Hercules 214, Hercules 251 and Hercules 253 from its marketable assets into its non-marketable assets as the Company did not reasonably expect to market these rigs in the foreseeable future. This decision resulted in a non-cash impairment charge of approximately $199.5 million ($199.5 million, net of tax), which is included in Asset Impairment on the Consolidated Statement of Operations for the year ended December 31, 2014, to write the rigs down to fair value based on a third-party estimate. The financial information for these rigs has been reported as part of the Domestic Offshore segment.

2013 Asset Impairments (Predecessor)

Long-lived assets held for sale at June 30, 2013 were written down to their fair value (level 2) less estimated cost to sell, resulting in non-cash impairment charges of $40.9 million ($40.7 million net of tax) and $3.5 million ($3.5 million, net of tax) for the discontinued operations of the former Inland and Domestic Liftboats segments, respectively. The impairment charges are included in Discontinued Operations on the Consolidated Statement of Operations for the year ended December 31, 2013 (See Note 9).

During December 2013, the Company made the decision to remove the Hercules 153, Hercules 203, Hercules 206 and Hercules 250 from its marketable assets into its non-marketable assets as the Company did not reasonably expect to market these rigs in the foreseeable future. This decision resulted in a non-cash impairment charge of approximately $114.2 million

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

($114.2 million, net of tax), which is included in Asset Impairment on the Consolidated Statement of Operations for the year ended December 31, 2013, to write the rigs down to fair value based on a third-party estimate (Level 3). The financial information for these rigs has been reported as part of the Domestic Offshore segment.

Fair Value of Financial Instruments

The carrying amounts of the Company’s financial instruments, which include cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities and other current liabilities, approximate fair values because of the short-term nature of the instruments. The fair value of the Company's cash equivalents are Level 1.

The fair value of the Successor Company’s Senior Secured Credit Facility is estimated using an Income Approach, specifically the risk-neutral method. The significant assumptions used in the valuation of the Senior Secured Credit Facility are: the expected recovery rate, the risk-neutral probability of default, and the risk-free rate (Level 2). The fair value of the Predecessor Company's 8.75% Senior Notes, 7.5% Senior Notes, 6.75% Senior Notes, 10.25% Senior Notes and 3.375% Convertible Senior Notes was estimated based on quoted prices in active markets. The fair value of the Predecessor Company’s 7.375% Senior Notes was estimated based on discounted cash flows using inputs from quoted prices in active markets for similar debt instruments. The inputs used to determine fair value are considered Level 2 inputs.

The following table provides the carrying value and fair value of the Company’s long-term debt instruments:



	Successor				Predecessor
	December 31, 2015				December 31, 2014
(in millions)	Carrying Value		Fair Value		Carrying Value		Fair Value
Senior Secured Credit Facility, due May 2020	$	428.7	$	315.9	$	—	$	—
8.75% Senior Notes, due July 2021	—		—		400.0		191.0
7.5% Senior Notes, due October 2021	—		—		300.0		135.8
6.75% Senior Notes, due April 2022	—		—		300.0		132.8
10.25% Senior Notes, due April 2019	—		—		200.0		111.4
3.375% Convertible Senior Notes, due June 2038	—		—		7.4		6.5
7.375% Senior Notes, due April 2018	—		—		3.5		1.9

Fresh-Start Accounting

Upon the Company’s emergence from Chapter 11, Hercules applied the provisions of fresh-start accounting to its financial statements, including the allocation of the reorganization value to its individual assets based on their estimated fair values (See Note 5).

16. Income Taxes

Income (loss) from continuing operations before income taxes consisted of the following:



	Successor			Predecessor
	Period from November 6, 2015 to December 31, 2015			Period from January 1, 2015 to November 6, 2015			Year Ended December 31,
(in thousands)	Period from November 6, 2015 to December 31, 2015			Period from January 1, 2015 to November 6, 2015			2014			2013
United States	$	(18,053	)	$	327,414		$	(211,186	)	$	(68,080	)
Foreign	(4,888		)	(922,866		)	3,581			30,327
Total	$	(22,941	)	$	(595,452	)	$	(207,605	)	$	(37,753	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The income tax (benefit) provision consisted of the following:



	Successor		Predecessor
	Period from November 6, 2015 to December 31, 2015		Period from January 1, 2015 to November 6, 2015		Year Ended December 31,
(in thousands)	Period from November 6, 2015 to December 31, 2015		Period from January 1, 2015 to November 6, 2015		2014			2013
Current-United States	$	—	$	161	$	642		$	2,776
Current-foreign	514		4,858		15,611			14,539
Current-state	198		92		(57		)	(114		)
Current income tax provision	712		5,111		16,196			17,201
Deferred-United States	—		—		548			(30,124		)
Deferred-foreign	16		1,675		(4,407		)	1,341
Deferred-state	—		256		(3,832		)	638
Deferred income tax (benefit) provision	16		1,931		(7,691		)	(28,145		)
Total income tax (benefit) provision	$	728	$	7,042	$	8,505		$	(10,944	)

A reconciliation of statutory and effective income tax rates is as shown below:



	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
Statutory rate	35.0	%	35.0	%	35.0	%	35.0	%
Effect of:
Taxes on foreign earnings at greater than the U.S. statutory rate	(25.4	)	(48.5	)	(13.3	)	(23.6	)
Discharge of debt and other reorganization related items	—		10.8		—		—
Officer's compensation	—		—		(0.1	)	(3.3	)
Seahawk tax attributes	—		—		—		152.5
Valuation allowance	(11.1	)	3.4		(30.4	)	(125.9	)
Uncertain tax positions	—		0.1		2.4		(0.5	)
State income taxes	(0.8	)	—		3.1		(1.5	)
Other	(0.9	)	(2.0	)	(0.8	)	(3.7	)
Effective rate	(3.2	)%	(1.2	)%	(4.1	)%	29.0	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The components of and changes in the net deferred taxes were as follows:



	Successor			Predecessor
	December 31,			December 31,
(in thousands)	2015			2014
Deferred tax assets:
Net operating loss carryforward (Federal, State & Foreign)	$	51,566		$	155,649
Fixed assets	28,940			—
Credit carryforwards	19,529			35,596
Accrued expenses	11,356			13,026
Unearned income	—			664
Intangibles	6,102			3,638
Stock-based compensation	703			5,628
Deferred expenses	4,436			5,215
Valuation allowance	(107,213		)	(125,021		)
Deferred tax assets	15,419			94,395
Deferred tax liabilities:
Fixed assets	—			(89,463		)
Unearned income	(6,327		)	—
Convertible notes	—			(947		)
Debt	(4,474		)	—
Unremitted foreign earnings	(3,986		)	—
Other	(228		)	(1,636		)
Deferred tax liabilities	(15,015		)	(92,046		)
Net deferred tax assets	$	404		$	2,349

Under the Plan, a substantial portion of the Company’s pre-petition debt securities were extinguished. Absent an exception, a debtor recognizes cancellation of indebtedness income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The Internal Revenue Code of 1986, as amended (“IRC”), provides that a debtor in a bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. As a result of the market value of equity upon emergence from Chapter 11 bankruptcy proceedings, the estimated amount of U.S. CODI is approximately $939 million, which will reduce the value of the Company’s U.S. net operating losses, alternative minimum tax credits and other assets. The actual reduction in tax attributes does not occur until the first day of the Company’s tax year subsequent to the date of emergence, or January 1, 2016.

IRC Sections 382 and 383 provide an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future U.S. taxable income in the event of a change in ownership. The Debtors’ emergence from Chapter 11 bankruptcy proceedings is considered a change in ownership for purposes of IRC Section 382. The limitation under the IRC is based on the value of the corporation as of the emergence date. 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. The expiration of these tax attributes was fully offset by a corresponding decrease in the Company’s U.S. valuation allowance, which results in no net tax provision.

The amount of consolidated U.S. net operating losses (“NOLs”) available as of December 31, 2015 is approximately $146.8 million. This differs from the NOL reported in the Company's financial statements by $4.5 million which represents the unrealized tax benefits associated with equity compensation and uncertain tax position in accordance with FASB ASC 718, Stock Compensation and FASB ASC 740, Income Taxes. These NOLs will expire in the years 2029 through 2035. The amount of foreign NOL’s available as of December 31, 2015 is $8.9 million which have an indefinite life carry-forward period. In addition, the Company has $19.5 million of non-expiring alternative minimum tax credits.

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During 2015, the Company concluded that the undistributed earnings of its foreign subsidiaries would no longer be considered permanently reinvested. The Company recorded a deferred tax liability of $4.0 million for the year ended December 31, 2015. This deferred tax liability was fully offset by the U.S. valuation allowance. In accordance with FASB ASC 740, the Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The Company recorded interest and penalties expense (benefit) of $(0.3) million, $(1.8) million and $0.2 million through the Income Tax Benefit (Provision) line of the Consolidated Statements of Operations for the period January 1, 2015 to November 6, 2015 and and the years ended December 31, 2014 and 2013, respectively. There was no interest and penalties expense (benefit) for the period November 6, 2015 to December 31, 2015.

The Company, directly or through its subsidiaries, files income tax returns in the United States, and multiple state and foreign jurisdictions. The Company’s tax returns for 2008 through 2014 remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed. Although the Company believes that its estimates are reasonable, the final outcome in the event that the Company is subjected to an audit could be different from that which is reflected in its historical income tax provision and accruals. Such differences could have a material effect on the Company’s income tax provision and net income in the period in which such determination is made. In addition TODCO income tax obligations from periods prior to its initial public offering in 2004 are indemnified by Transocean, the former owner of TODCO, under the tax sharing agreement, except for the Trinidad and Tobago jurisdiction.

In accordance with FASB ASC 740, the Company evaluates its deferred tax assets, including net operating losses and credits, to determine if a valuation allowance should be recognized on the consideration of all available evidence using a "more likely than not" standard. Based on the analysis of all factors management concluded that due to the uncertainty regarding the future realization of the net deferred tax asset, a valuation allowance should be recorded. As of December 31, 2015 and 2014, the Company had a valuation allowance of $107.2 million and $125.0 million, respectively.

The following table presents the reconciliation of the total amounts of unrecognized tax benefits that, if recognized, would impact the effective income tax rate:



	Successor		Predecessor
	Period from November 6, 2015 to December 31, 2015		Period from January 1, 2015 to November 6, 2015			Year Ended December 31,
(in thousands)	Period from November 6, 2015 to December 31, 2015		Period from January 1, 2015 to November 6, 2015			2014			2013
Balance, beginning of period	$	3,062	$	3,605		$	5,533		$	5,533
Gross increases — tax positions in prior periods	—		—			713			—
Lapse of statute of limitation	—		(543		)	(2,641		)	—
Balance, end of period	$	3,062	$	3,062		$	3,605		$	5,533

The unrecognized tax benefits may change due to the settlement of audits and the expiration of statutes of limitation in the next twelve months. The Company recognized $0.9 million of tax benefit, including accrued interest and penalties of $0.3 million, during the year ended December 31, 2015 as a result of the tolling of statutes of limitations in foreign jurisdictions.

From time to time, the Company’s tax returns are subject to review and examination by various tax authorities within the jurisdictions in which the Company operates or has operated. The Company is currently contesting tax assessments in Venezuela, and may contest future assessments where the Company believes the assessments are meritless.

In January 2014, the Federal Inland Revenue Service of Nigeria notified the Company that it will initiate an audit including calendar years 2007 through 2011, which was completed in the first quarter of 2015. In February 2015, the Federal Inland Revenue Service of Nigeria notified the Company that it will examine calendar year 2012 and 2013 corporate income tax returns. While the Company cannot predict or provide assurance regarding the outcome of these proceedings, the Company does not expect the ultimate liability to have a material effect on its consolidated financial statements.

17. Segments

The Company currently reports its business activities in three business segments: (1) Domestic Offshore, (2) International Offshore, and (3) International Liftboats. The Company eliminates inter-segment revenue and expenses, if any.

The results of operations of the former Domestic Liftboats and Inland segments are reflected in the Consolidated Statement of Operations for the year ended December 31, 2013 as discontinued operations (See Note 9). The financial information of the Company's discontinued operations is not included in the results of operations presented for the Company's reporting segments.

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The following describes the Company's reporting segments as of December 31, 2015:

Domestic Offshore - includes 18 jackup rigs in the U.S. Gulf of Mexico that can drill in maximum water depths ranging from 120 to 350 feet. Nine of the jackup rigs are either under contract or available for contracts and nine are cold stacked.

International Offshore — includes nine jackup rigs outside of the U.S. Gulf of Mexico. The Company has three jackup rigs contracted offshore in Saudi Arabia, one jackup rig contracted offshore in Congo, one jackup rig ready stacked and one jackup rig warm stacked in Gabon, one jackup ready stacked in the Netherlands and one jackup rig warm stacked in Malaysia. Additionally, the Company has one newbuild jackup rig under construction in Singapore that is expected to be delivered in the second quarter of 2016.

International Liftboats — includes 19 liftboats. Fifteen are operating or available for contracts offshore West Africa, one is cold stacked offshore West Africa and three are operating or available for contracts in the Middle East region.

The Company’s jackup rigs are used primarily for exploration and development drilling in shallow waters. The Company’s 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.

In November 2013, the Company entered into an agreement with Perisai Drilling Sdn Bhd ("Perisai") whereby the Company 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. The Company receives 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 the Company's understanding that Perisai is in discussions with the shipyard to further delay delivery of the rig.

Specific to the Perisai Agreement, the Company recognized the following results in its 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

Information regarding the Company's reportable segments is as follows:



	Successor							Predecessor
	Period from November 6, 2015 to December 31, 2015							Period from January 1, 2015 to November 6, 2015
(in thousands)	Revenue		Income (Loss) from Operations			Depreciation and Amortization		Revenue		Income (Loss) from Operations			Depreciation and Amortization
Domestic Offshore	$	9,859	$	(608	)	$	1,097	$	131,308	$	(8,464	)	$	39,031
International Offshore	17,321		(1,635		)	1,870		113,438		(95,111		)	71,033
International Liftboats	5,262		(3,245		)	1,567		58,460		(13,165		)	14,599
	$	32,442	$	(5,488	)	$	4,534	$	303,206	$	(116,740	)	$	124,663
Corporate	—		(3,399		)	—		—		(58,889		)	2,300
Total Company	$	32,442	$	(8,887	)	$	4,534	$	303,206	$	(175,629	)	$	126,963

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	Predecessor
	Year Ended December 31, 2014							Year Ended December 31, 2013
(in thousands)	Revenue		Income (Loss) from Operations			Depreciation and Amortization		Revenue		Income (Loss) from Operations			Depreciation and Amortization
Domestic Offshore	$	497,209	$	(40,588	)	$	70,576	$	522,705	$	90,202		$	78,526
International Offshore	291,486		302			75,672		190,376		(19,762		)	51,759
International Liftboats	111,556		4,434			20,763		145,219		37,575			18,627
	$	900,251	$	(35,852	)	$	167,011	$	858,300	$	108,015		$	148,912
Corporate	—		(52,647		)	3,887		—		(56,583		)	3,031
Total Company	$	900,251	$	(88,499	)	$	170,898	$	858,300	$	51,432		$	151,943



	Successor		Predecessor
	December 31,		December 31,
(in thousands)	2015		2014
Total Assets:
Domestic Offshore	$	298,813	$	511,804
International Offshore	353,600		1,228,247
International Liftboats	164,814		227,776
Corporate	290,913		34,580
Total Company	$	1,108,140	$	2,002,407



	Successor		Predecessor
	Period from November 6, 2015 to December 31, 2015		Period from January 1, 2015 to November 6, 2015		Year Ended December 31,
(in thousands)	Period from November 6, 2015 to December 31, 2015		Period from January 1, 2015 to November 6, 2015		2014		2013
Capital Expenditures:
Domestic Offshore	$	571	$	3,197	$	54,082	$	63,344
International Offshore (a)	3,937		67,564		83,777		459,685
Inland	—		—		—		396
Domestic Liftboats	—		—		—		5,678
International Liftboats	558		7,336		9,037		12,407
Corporate	—		—		626		3,477
Total Company	$	5,066	$	78,097	$	147,522	$	544,987

_____________________________


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

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A substantial portion of the Company’s assets are mobile. Asset locations at the end of the period are not necessarily indicative of the geographic distribution of the revenue generated by such assets during the periods. The following tables present revenue and long-lived assets by country based on the location of the service provided:



	Successor		Predecessor
	Period from November 6, 2015 to December 31, 2015		Period from January 1, 2015 to November 6, 2015		Year Ended December 31,
(in thousands)	Period from November 6, 2015 to December 31, 2015		Period from January 1, 2015 to November 6, 2015		2014		2013
Operating Revenue:
United States	$	10,213	$	135,063	$	503,626	$	522,705
Saudi Arabia	11,146		74,974		114,171		114,364
Nigeria	3,148		37,165		75,183		115,314
Gabon	4,897		13,158		64,537		—
India	—		9,832		96,198		17,319
Other (a)	3,038		33,014		46,536		88,598
Total Non-U.S. Countries	22,229		168,143		396,625		335,595
Total Company	$	32,442	$	303,206	$	900,251	$	858,300



	Successor		Predecessor
	December 31,		December 31,
(in thousands)	2015		2014
Long-Lived Assets:
United States	$	38,523	$	356,656
Saudi Arabia	92,139		322,004
Nigeria	70,204		112,428
Gabon	126,151		442,192
India	—		45,296
Netherlands	68,682		272,488
Other (a)	75,968		47,046
Total Non-U.S. Countries	433,144		1,241,454
Total Company	$	471,667	$	1,598,110

_____________________________


(a)	Other represents countries in which the Company operates that individually had operating revenue or long-lived assets representing less than 10% of total operating revenue or total long-lived assets.

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HERCULES OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

18. Commitments and Contingencies

Operating Leases

The Company has non-cancellable operating lease commitments that expire at various dates through 2017. As of December 31, 2015, future minimum lease payments related to non-cancellable operating leases were as follows (in thousands):



Years Ended December 31,
2016	$	3,365
2017	2,700
2018	—
2019	—
2020	—
Thereafter	—
Total	$	6,065

Rental expense for all operating leases was $2.5 million, $12.1 million, $16.9 million and $15.1 million 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, respectively, of which $0.4 million related to discontinued operations is included in Loss from Discontinued Operations, Net of Taxes on the Consolidated Statement of Operations for the year ended December 31, 2013.

Rig Construction Contract

In May 2014, the Company signed a rig construction contract with Jurong Shipyard Pte Ltd ("JSL") in Singapore to build a High Specification, Harsh Environment rig, Hercules Highlander, which is expected to be delivered in the second quarter of 2016. 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 the Company, costs to mobilize the rig to the first well as well as capitalized interest. The Company 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. $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.

Legal Proceedings

The Company is 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 the Company’s behalf in response to its failure to receive a majority advisory “say-on-pay” vote in favor of the Company’s 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 the Company as a nominal defendant and certain of its officers and directors, as well as the Company’s Compensation Committee’s consultant, as defendants. Plaintiffs allege that the Company’s 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 the Company’s behalf from the officer and director defendants, certain corporate governance actions, and an award of their costs and attorney’s fees. The Company and the other defendants have filed motions to dismiss these cases for failure to make demand upon the Company’s 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, the Company's and the other defendants' motions to dismiss the Delaware federal action were granted. The motions to dismiss the Texas federal action are pending.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company does not expect the ultimate outcome of the shareholder derivative lawsuit to have a material adverse effect on its 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 the Company in a subrogation action that Walter Oil & Gas Corporation ("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, the Company 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 the Company filed relating to the incident. In response, the Company 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. The Company has 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 the Company and Walter. Until such time as Walter accepts the tender, the Company will vigorously defend the claims.

Settlement of Contractual Dispute

In August 2015, the Company agreed to a settlement of a contractual dispute relating to the sale of certain of our assets in 2006, pursuant to which settlement the Company 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.

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

The Company 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 the Company’s belief or expectations as to the outcome or effect of any lawsuit or other litigation matter will prove correct, and the eventual outcome of these matters could materially differ from management’s current estimates.

Insurance and Indemnity

The Company maintains 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, the Company completed the annual renewal of all of its key insurance policies. The Company’s insurance policies typically consist of twelve-month policy periods, and the next renewal date for its insurance program is scheduled for May 1, 2016.

The Company’s drilling contracts provide for varying levels of indemnification from its customers, including for well control and subsurface risks, and in most cases, may require the Company to indemnify its customers for certain liabilities. Under the Company’s drilling contracts, liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that the Company and its customers assume liability for their respective personnel and property, regardless of how the loss or damage to the personnel and property may be caused, and even if the Company is grossly negligent. However, some of the Company's customers have been reluctant to extend their indemnity obligations in instances where the Company is grossly negligent. The Company’s customers typically assume responsibility for and agree to indemnify the Company from any loss or liability resulting from pollution or contamination, including clean-up and removal and third-party damages arising from operations under the contract and originating below the surface of the water, including as a result of 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 the Company’s gross negligence, willful misconduct or other egregious conduct. In addition, the Company may not be indemnified for statutory penalties and punitive damages relating to such pollution or contamination events. The Company generally indemnifies the customer for the consequences of spills of industrial waste or other liquids originating solely above the surface of the water and emanating from its rigs or vessels.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

coverage up to $200.0 million for pollution liability that is covered in the primary policy. Additionally, the Company carries 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.

Adequacy of Insurance Coverage

The Company is responsible for the deductible portion of its insurance coverage. Management believes adequate accruals have been made on known and estimated exposures up to the deductible portion of the Company’s insurance coverage. Management believes that claims and liabilities in excess of the amounts accrued are adequately insured. However, the Company’s insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect the Company against liability from all potential consequences. In addition, there is no assurance of renewal or the ability to obtain coverage acceptable to the Company.

Hercules 265 Incident and Settlement of Property Damage Insurance Claim

In July 2013, the Company's 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 the Company's insurance underwriters determined that the rig was a constructive total loss. The Company 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 the 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. The Company has removal of wreck coverage for this incident up to a total amount of $110.0 million. During the second quarter of 2014, the Company 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, the Company 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. The Company and its insurance underwriters continue to negotiate the insurance recovery amounts for costs related to the salvage of the rig and certain other insured losses.

Sales and Use Tax Audits

Certain of the Company’s legal entities are under audit by various taxing authorities for several prior-year periods. These audits are ongoing and the Company is working to resolve all relevant issues. The Company has an accrual of $10.0 million and $6.3 million related to these sales and use tax matters, which is included in Accrued Liabilities on the Consolidated Balance Sheets as of December 31, 2015 and 2014, respectively.

19. Unaudited Interim Financial Data

Unaudited interim financial information for the years ended December 31, 2015 and 2014 is as follows:



	Predecessor												Successor
	Quarter Ended									Period from October 1 to November 6 (c)			Period from November 6 to December 31 (d)
(in thousands, except per share amounts)	March 31			June 30 (a)			September 30 (b)			Period from October 1 to November 6 (c)			Period from November 6 to December 31 (d)
2015
Revenue	$	122,619		$	79,249		$	73,804		$	27,534		$	32,442
Operating Loss	(29,958		)	(60,183		)	(68,534		)	(16,954		)	(8,887		)
Net Loss	(57,115		)	(88,250		)	(95,351		)	(361,778		)	(23,669		)
Loss attributable to Noncontrolling Interest	—			—			—			—			—
Net Loss attributable to Hercules Offshore, Inc.	$	(57,115	)	$	(88,250	)	$	(95,351	)	$	(361,778	)	$	(23,669	)
Net Loss attributable to Hercules Offshore, Inc. Per Share:
Basic and Diluted	$	(0.35	)	$	(0.55	)	$	(0.59	)	$	(2.24	)	$	(1.18	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



	Predecessor
	Quarter Ended
(in thousands, except per share amounts)	March 31 (e)		June 30 (f)		September 30 (g)			December 31 (h)
2014
Revenue	$	256,734	$	242,963	$	221,884		$	178,670
Operating Income (Loss)	57,672		50,049		(70,898		)	(125,322		)
Net Income (Loss)	19,916		6,646		(88,553		)	(154,119		)
Loss attributable to Noncontrolling Interest	—		—		—			—
Net Income (Loss) attributable to Hercules Offshore, Inc.	$	19,916	$	6,646	$	(88,553	)	$	(154,119	)
Net Income (Loss) attributable to Hercules Offshore, Inc. Per Share:
Basic	$	0.12	$	0.04	$	(0.55	)	$	(0.96	)
Diluted	$	0.12	$	0.04	$	(0.55	)	$	(0.96	)

_____________________________

(a)

Includes a $13.4 million revenue adjustment related to retroactive dayrate concessions on the Hercules 261, Hercules 262 and Hercules 266, $10.6 million of costs related to financing and restructuring activities, a $3.6 million net loss on the sale of assets, including six cold-stacked drilling rigs and a $1.9 million charge related to the termination of the Predecessor Credit Facility (See Notes 1 and 13).


(b)	Includes a $7.6 million bad debt provision in our International Liftboats segment, $8.3 million of costs related to financing and restructuring activities and a $14.3 million charge for reorganization items (See Note 6).


(c)	Includes a $342.7 million charge for reorganization items, an $8.1 million loss on stock-based compensation due to bankruptcy and a $5.2 million gain on settlement of a contractual dispute (See Notes 6, 10 and 18).


(d)	Includes a $1.3 million charge for reorganization items (See Note 6).


(e)	Includes a $15.2 million charge related to the retirement of a portion of the 7.125% Senior Secured Notes and the issuance of the 6.75% Senior Notes (See Note 13).


(f)	Includes a $17.9 million gain on the sale of three cold-stacked drilling rigs and a $4.8 million charge related to the retirement of the remaining portion of the 7.125% Senior Secured Notes (See Notes 9 and 13).


(g)	Includes a $4.7 million net gain on the sale of three cold-stacked drilling rigs and $82.5 million in non-cash asset impairment charges (See Notes 9 and 15).


(h)	Includes $117.0 million in non-cash asset impairment charges (See Note 15).

20. Related Parties

The Company engages in transactions in the ordinary course of business with entities with whom certain of the Company's directors or members of management have a relationship. The Company has determined that these transactions were carried out on an arm’s-length basis and are not material individually or in the aggregate. All of these transactions were approved in accordance with the Company’s Policy on Covered Transactions with Related Persons. The following provides a brief description of these relationships.


•	The Company’s former Chairman of the Board of Directors was serving as a member of the Board of Directors of Global Energy Services, which included the Southwest Oilfield Products division, an oilfield equipment manufacturing company.


•	A former member of the Company’s Board of Directors was serving as a member of the Board of Directors of HCC Insurance Holdings, Inc., a specialty insurance group.


•	A former member of the Company's Board of Directors was serving as a member of the Board of Directors of Technip, a provider of project management, engineering and construction for the energy industry.


•	The Company holds a three percent ownership in each of Hall-Houston Exploration II, L.P., Hall-Houston Exploration III, L.P. and Hall-Houston Exploration IV, L.P., exploration and production funds.

•

As of December 31, 2012, the Company had an investment in approximately 32% of the total outstanding equity of Discovery. In 2013, through additional purchases of shares of Discovery's common stock, the Company acquired a 100% interest in Discovery (See Note 8). Two former officers of the Company served on the Board of Directors of Discovery Offshore prior to it becoming a wholly owned subsidiary.

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Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.



Item 9A.	Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and our chief financial officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Our chief executive officer and chief financial officer evaluated whether our disclosure controls and procedures as of the end of the period covered by this report were designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (2) accumulated and communicated to our management, including our chief executive officer and our chief financial officer, as appropriate to allow timely decisions regarding required disclosure. Based on their evaluation, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective to achieve the foregoing objectives as of the end of the period covered by this report.

There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) under the U.S. Securities Exchange Act of 1934. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2015. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013 framework). Based on our assessment, we have concluded that, as of December 31, 2015, our internal control over financial reporting is effective based on those criteria.



Item 9B.	Other Information

None.

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PART III



Item 10.	Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated by reference to our Form 10-K/A, which is to be filed with the SEC pursuant to the Securities Exchange Act of 1934 within 120 days after the end of our fiscal year on December 31, 2015.

Code of Business Conduct and Ethical Practices

We have adopted a Code of Conduct, which applies to, among others, our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. We have posted a copy of the code in the “Corporate Governance” section of our internet website at www.herculesoffshore.com. Copies of the code may be obtained free of charge on our website or by requesting a copy in writing from our Corporate Secretary at 9 Greenway Plaza, Suite 2200, Houston, Texas 77046. Any waivers of the code must be approved by our board of directors or a designated board committee. Any amendments to, or waivers from, the code that apply to our executive officers and directors will be posted in the “Corporate Governance” section of our internet website at www.herculesoffshore.com.



Item 11.	Executive Compensation

The information required by this item is incorporated by reference to our Form 10-K/A, which is to be filed with the SEC pursuant to the Exchange Act within 120 days after the end of our fiscal year on December 31, 2015.



Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters



Item 13.	Certain Relationships and Related Transactions, and Director Independence



Item 14.	Principal Accountant Fees and Services

PART IV



Item 15.	Exhibits, Financial Statement Schedules

(a) The following documents are included as part of this report:

(1) Financial Statements

(2) Consolidated Financial Statement Schedule on page 114 of this Report.

(3) The Exhibits of the Company listed below in Item 15(b)

(b) Exhibits

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Exhibit Number		Description
2.1	—	Asset Purchase Agreement, dated February 11, 2011, by and between Hercules Offshore, Inc., SD Drilling LLC and Seahawk Drilling, Inc., Seahawk Global Holdings LLC, Seahawk Mexico Holdings LLC, Seahawk Drilling Management LLC, Seahawk Drilling LLC, Seahawk Offshore Management LLC, Energy Supply International LLC and Seahawk Drilling USA, LLC (incorporated by reference to Exhibit 2.1 to Hercules’ Current Report on Form 8-K/A dated February 15, 2011 (File No. 0-51582)).
2.2	—	Plan of Conversion (incorporated by reference to Exhibit 2.1 to Hercules’ Registration Statement on Form S-1 (Registration No. 333-126457), as amended (the “S-1 Registration Statement”), originally filed on July 8, 2005).
2.3	—	Amended and Restated Agreement and Plan of Merger, dated effective as of March 18, 2007, by and among Hercules, THE Hercules Offshore Drilling Company LLC and TODCO (incorporated by reference to Annex A to the Joint Proxy/Statement Prospectus included in Part I of Hercules’ Registration Statement on Form S-4 (Registration No. 333-142314), as amended (the “S-4 Registration Statement”), originally filed April 24, 2007).
2.4	—	Confirmation Order for Joint Prepackaged Plan of Reorganization (incorporated by reference to Exhibit 2.1 to Hercules' Current Report on Form 8-K filed October 9, 2015) (File No. 0-51582).
2.5	—	Solicitation and Disclosure Statement, including Joint Prepackaged Plan of Reorganization under Chapter 11 of the Bankruptcy Code (incorporated by reference to Exhibit 99.1 to Hercules' Current Report on Form 8-K filed July 14, 2015) (File No. 0-51582).
3.1	—	Second Amended and Restated Certificate of Incorporation of Hercules Offshore, Inc. dated November 6, 2015 (incorporated by reference to Exhibit 3.1 to Hercules' Current Report on Form 8-A filed November 6, 2015) (File No. 1-37623).
*3.2	—	Second Amended and Restated By-Laws of Hercules Offshore, Inc. dated December 11, 2015.
*4.1	—	Form of specimen common stock certificate.
4.2	—	Warrant Agreement between Hercules Offshore, Inc. and American Stock Transfer & Trust Company, LLC, as Warrant Agent, dated as of November 6, 2015 2015 (incorporated by reference to Exhibit 4.1 to From 8-A filed November 6, 2015) (File No. 0-51582).
†10.1	—	Amended and Restated Executive Employment Agreement, dated February 28, 2012, between the Company and John T. Rynd (incorporated by reference to Exhibit 10.5 to Hercules' Current Report on Form 8-K dated March 2, 2012 (the "March 2012 8-K")) (File No. 0-51582).
†10.2	—	Amended and Restated Executive Employment Agreement, dated February 28, 2012, between the Company and Troy L. Carson (incorporated by reference to Exhibit 10.6 to the March 2012 8-K) (File No. 0-51582).
†10.3	—	Hercules Offshore, Inc. Amended and Restated Deferred Compensation Plan (incorporated by reference to Exhibit 10.18 to Hercules’ Annual Report on Form 10-K for the year ended December 31, 2008 (File No. 0-51582)).
†10.4	—	Special Retention Award Agreement, dated January 1, 2011, between Hercules and John T. Rynd (incorporated by reference to Exhibit 10.29 to the 2010 Form 10-K) (File No. 0-51582).
†*10.5	—	Hercules Offshore, Inc. 2015 Long-Term Incentive Plan.
†10.6	—	Hercules Offshore, Inc. HERO Annual Performance Bonus Plan effective January 1, 2012 (incorporated by reference to Exhibit 10.1 to Hercules' Current Report on Form 8-K dated December 15, 2011) (File No. 0-51582).
†*10.7	—	Form of Restricted Stock Unit Award Agreement for Directors
10.8	—	Asset Purchase Agreement, dated April 3, 2006, by and between Hercules Liftboat Company, LLC and Laborde Marine Lifts, Inc. (incorporated by reference to Exhibit 10.1 to Hercules’ Current Report on Form 8-K dated April 3, 2006 (File No. 0-51582)).
10.9	—	Asset Purchase Agreement, dated as of August 23, 2006, by and among Hercules International Holdings, Ltd., Halliburton West Africa Ltd. and Halliburton Energy Services Nigeria Limited (incorporated by reference to Exhibit 10.1 to Hercules’ Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 0-51582)).
10.10	—	First Amendment to Asset Purchase Agreement, dated as of November 1, 2006, by and among Hercules International Holdings, Ltd., Hercules Oilfield Services Ltd., Halliburton West Africa Ltd. and Halliburton Energy Services Nigeria Limited (incorporated by reference to Exhibit 10.2 to Hercules’ Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 0-51582)).

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Exhibit Number		Description
10.11	—	Earnout Agreement, dated November 7, 2006, by and among Hercules Oilfield Services, Ltd., Halliburton West Africa Ltd. and Halliburton Energy Services Nigeria Limited (incorporated by reference to Exhibit 10.3 to Hercules’ Current Report on Form 8-K dated November 7, 2006 (File No. 0-51582)).
10.12	—	Credit Agreement dated as of November 6, 2015, among Hercules Offshore, Inc., the Subsidiary Guarantors, the Lenders, and Jefferies Finance LLC, as administrative agent for the Lenders and as collateral agent for the Secured Parties (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed November 6, 2015) (File No. 1-37623).
*21.1	—	Subsidiaries of Hercules.
*23.1	—	Consent of Ernst & Young LLP.
*31.1	—	Certification of Chief Executive Officer of Hercules pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	—	Certification of Chief Financial Officer of Hercules pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	—	Certification of the Chief Executive Officer and the Chief Financial Officer of Hercules pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS		XBRL Instance Document
*101.SCH		XBRL Schema Document
*101.CAL		XBRL Calculation Linkbase Document
*101.DEF		XBRL Definition Linkbase Document
*101.LAB		XBRL Label Linkbase Document
*101.PRE		XBRL Presentation Linkbase Document



*	Filed herewith.



†	Compensatory plan, contract or arrangement.

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(1) Valuation and Qualifying Accounts and Allowances

SCHEDULE II

HERCULES OFFSHORE, INC. AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS AND ALLOWANCES



			Additions
Description	Balance at Beginning of Period		Charged to Expense, Net			Charged to Other Accounts				Deductions				Balance at End of Period
	(in thousands)
Successor
Period from November 6, 2015 to December 31, 2015
Allowance for doubtful accounts receivable	$	—	$	1,855		$	—			$	—			$	1,855
Valuation allowance of deferred tax assets	$	104,679	$	2,534		$	—			$	—			$	107,213

Predecessor
Period from January 1, 2015 to November 6, 2015
Allowance for doubtful accounts receivable	$	5,677	$	7,665		$	—			$	(13,342	)	(a)	$	—
Valuation allowance of deferred tax assets	$	125,021	$	(20,342	)	$	—			$	—			$	104,679
Year Ended December 31, 2014:
Allowance for doubtful accounts receivable	$	891	$	5,627		$	—			$	(841	)		$	5,677
Valuation allowance of deferred tax assets	61,913		62,721			387			(b)	—				125,021
Year Ended December 31, 2013:
Allowance for doubtful accounts receivable	$	788	$	642		$	—			$	(539	)		$	891
Valuation allowance of deferred tax assets	—		63,732			(1,819		)	(c)	—				61,913

_____________________________


(a)	Includes a fresh-start accounting adjustment of $13.2 million to adjust the carrying value of accounts receivable to fair value, eliminating the allowance for doubtful accounts (see Note 2).


(b)	Adjustment to unrecognized tax benefit recorded net of valuation allowance.


(c)	Adjustment to unrecognized tax balance in foreign jurisdiction to recognize impact of federal valuation allowance.

All other financial statement schedules have been omitted because they are not applicable or not required, or the information required thereby is included in the consolidated financial statements or the notes thereto included in this annual report.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on March 30, 2016.



HERCULES OFFSHORE, INC.

By:	/S/ JOHN T. RYND
	John T. Rynd
	Chief Executive Officer, President and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on March 30, 2016.



Signatures		Title

/S/ JOHN T. RYND		Chief Executive Officer, President and Director (Principal Executive Officer)
John T. Rynd

/S/ TROY L. CARSON		Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
Troy L. Carson

/S/ LAWRENCE DICKERSON		Chairman of the Board
Lawrence Dickerson

/S/ DAVID BROWN		Director
David Brown

/S/ JON COLE		Director
Jon Cole

/S/ EUGENE DAVIS		Director
Eugene Davis

/S/ GARY HANNA		Director
Gary Hanna

/S/ TARIQ OSMAN		Director
Tariq Osman

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