Edgar Filing: HERCULES OFFSHORE, INC.

Large accelerated filer o

Accelerated filer o

Non-accelerated filer o

Smaller reporting company þ

(Do not check if a smaller reporting company)

10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A

AMENDMENT NO. 1

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.

EXPLANATORY NOTE

We are filing this Amendment No. 1 (the “Amendment”) on Form 10-K/A to our Annual Report on Form 10-K for the year ended December 31, 2015, which was filed with the Securities and Exchange Commission on March 30, 2016 (the “Original Filing”), in order to amend disclosure in the Management’s Discussion and Analysis of Financial Condition and Results of Operations.

New certifications by our principal executive officer and principal financial officer are filed as exhibits to this Amendment under Item 15 of Part IV hereof. Except for the foregoing amended information, this Amendment does not alter or update any other information contained in the Original Filing. This Amendment does not reflect events that may have occurred subsequent to the Original Filing.

PART II



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

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.

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.

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.

•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 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 10-K, management and a majority of the members of our board of directors 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.

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.

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, 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

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.

Segments

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 (See the information set forth in Part I, Item 1. Business - Our Segments and Fleet).

Our drilling rigs are used primarily for exploration and development drilling in shallow waters. Under most of our contracts, we are paid a fixed daily rental rate called a “dayrate,” and we are required to pay all costs associated with our own crews as well as the upkeep and insurance of the rig and equipment.

Our liftboats are self-propelled, self-elevating vessels with a large open deck space, which provides a versatile, mobile and stable platform to support a broad range of offshore maintenance and construction services throughout the life of an oil or natural gas well. Under most of our liftboat contracts, we are paid a fixed dayrate for the rental of the vessel, which typically 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.

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.

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

_____________________________

(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;


•	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.

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.

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.

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;


•	$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.

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

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



	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

_____________________________

(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

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.

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

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.

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.

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.

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).

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.

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.

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.

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.

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.

(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.

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, 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.

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K, as amended, 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;


•	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.

PART IV



Item 15.	Exhibits, Financial Statement Schedules

(b) Exhibits

The exhibits listed below are required by Item 601 of Regulation S-K.



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 (incorporated by reference to Exhibit 3.2 to Hercules' Annual Report on Form 10-K for the year ended December 31, 2015) (File No. 1-37623).
4.1	—	Form of specimen common stock certificate (incorporated by reference to Exhibit 4.1 to Hercules' Annual Report on Form 10-K for the year ended December 31, 2015) (File No. 1-37623)
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 (incorporated by reference to Exhibit 10.5 to Hercules' Annual Report on Form 10-K for the year ended December 31, 2015) (File No. 1-37623).
†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).



Exhibit Number		Description
†10.7	—	Form of Restricted Stock Unit Award Agreement for Directors (incorporated by reference to Exhibit 10.7 to Hercules' Annual Report on Form 10-K for the year ended December 31, 2015) (File No. 1-37623).
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)).
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 (incorporated by reference to Exhibit 21.1 to Hercules' Annual Report on Form 10-K for the year ended December 31, 2015) (File No. 1-37623).
23.1	—	Consent of Ernst & Young LLP (incorporated by reference to Exhibit 23.1 to Hercules' Annual Report on Form 10-K for the year ended December 31, 2015) (File No. 1-37623).
*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 (incorporated by reference to Exhibit 101.INS to Hercules' Annual Report on Form 10-K for the year ended December 31, 2015) (File No. 1-37623)
101.SCH		XBRL Schema Document (incorporated by reference to Exhibit 101.SCH to Hercules' Annual Report on Form 10-K for the year ended December 31, 2015) (File No. 1-37623).
101.CAL		XBRL Calculation Linkbase Document (incorporated by reference to Exhibit 101.CAL to Hercules' Annual Report on Form 10-K for the year ended December 31, 2015) (File No. 1-37623).
101.DEF		XBRL Definition Linkbase Document (incorporated by reference to Exhibit 101.DEF to Hercules' Annual Report on Form 10-K for the year ended December 31, 2015) (File No. 1-37623).
101.LAB		XBRL Label Linkbase Document (incorporated by reference to Exhibit 101.LAB to Hercules' Annual Report on Form 10-K for the year ended December 31, 2015) (File No. 1-37623).
101.PRE		XBRL Presentation Linkbase Document (incorporated by reference to Exhibit 101.PRE to Hercules' Annual Report on Form 10-K for the year ended December 31, 2015) (File No. 1-37623).



*	Filed herewith.



†	Compensatory plan, contract or arrangement.

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 April 5, 2016.



HERCULES OFFSHORE, INC.

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