HERCULES OFFSHORE, INC. - 10-K/A - 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").
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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
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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.
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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
Period from Period from
November 6, January 1,
2015 to 2015 to Year Ended
December 31, November 6, December 31,
(in millions) 2015 2015 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).
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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.
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RESULTS OF OPERATIONS
The following table sets forth financial information by operating segment and
other selected information for the periods indicated. The period from November 6
to December 31, 2015 (Successor Company) and the period from January 1 to
November 6, 2015 (Predecessor Company) are distinct reporting periods as a
result of our emergence from bankruptcy on November 6, 2015. References in these
results of operations to the change and the percentage change combine the
Successor Company and Predecessor Company results for the year ended December
31, 2015 in order to provide comparability of such information to the year ended
December 31, 2014. While this combined presentation is a non-GAAP presentation
for which there is no comparable GAAP measure, management believes that
providing this financial information is the most relevant and useful method for
making comparisons to the year ended December 31, 2014.
Successor Predecessor
(a) (b) (c) (a) + (b) - (c)
Period from Period from
November 6, January 1, Year
2015 to 2015 to Ended
December 31, November 6, December 31,
(Dollars in thousands) 2015 2015 2014 Change % Change
Domestic Offshore:
Number of rigs (as of end of
period) 18 18
24
Revenue $ 9,859 $ 131,308 $ 497,209 $ (356,042 ) (71.6 )%
Operating expenses 8,966 95,279 261,399 (157,154 ) (60.1 )%
Asset impairment - - 199,508 (199,508 ) n/m
Depreciation and amortization
expense 1,097 39,031 70,576 (30,448 ) (43.1 )%
General and administrative
expenses 404 5,462 6,314 (448 ) (7.1 )%
Operating loss $ (608 ) $ (8,464 ) $ (40,588 ) $ 31,516 (77.6 )%
International Offshore:
Number of rigs (as of end of
period) 9 9
9
Revenue $ 17,321 $ 113,438 $ 291,486 $ (160,727 ) (55.1 )%
Operating expenses 14,395 131,291 207,190 (61,504 ) (29.7 )%
Depreciation and amortization
expense 1,870 71,033 75,672 (2,769 ) (3.7 )%
General and administrative
expenses 2,691 6,225 8,322 594 7.1 %
Operating income (loss) $ (1,635 ) $ (95,111 ) $
302 $ (97,048 ) n/m
International Liftboats:
Number of liftboats (as of end
of period) 19 19
24
Revenue $ 5,262 $ 58,460 $ 111,556 $ (47,834 ) (42.9 )%
Operating expenses 6,314 45,418 74,647 (22,915 ) (30.7 )%
Depreciation and amortization
expense 1,567 14,599 20,763 (4,597 ) (22.1 )%
General and administrative
expenses 626 11,608 11,712 522 4.5 %
Operating income (loss) $ (3,245 ) $ (13,165 ) $ 4,434 $ (20,844 ) n/m
Total Company:
Revenue $ 32,442 $ 303,206 $ 900,251 $ (564,603 ) (62.7 )%
Operating expenses 29,675 271,988 543,236 (241,573 ) (44.5 )%
Asset impairment - - 199,508 (199,508 ) n/m
Depreciation and amortization
expense 4,534 126,963 170,898 (39,401 ) (23.1 )%
General and administrative
expenses 7,120 79,884 75,108 11,896 15.8 %
Operating loss (8,887 ) (175,629 ) (88,499 ) (96,017 ) 108.5 %
Interest expense (7,939 ) (61,173 ) (99,142 ) 30,030 (30.3 )%
Loss on extinguishment of debt - (1,884 ) (19,925 ) 18,041 n/m
Reorganization items, net (1,330 ) (357,050 ) - (358,380 ) n/m
Other, net (4,785 ) 284 (39 ) (4,462 ) n/m
Loss before income taxes (22,941 ) (595,452 ) (207,605 ) (410,788 ) 197.9 %
Income tax provision (728 ) (7,042 ) (8,505 ) 735 (8.6 )%
Loss from continuing operations (23,669 ) (602,494 ) (216,110 ) (410,053 ) 189.7 %
Loss from discontinued
operations, net of tax - - - - n/m
Net loss (23,669 ) (602,494 ) (216,110 ) (410,053 ) 189.7 %
Loss attributable to
noncontrolling interest - - - - n/m
Net loss attributable to Hercules Offshore, Inc $ (23,669 ) $ (602,494 ) $ (216,110 ) $ (410,053 ) 189.7 %
_____________________________
"n/m" means not meaningful.
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The following table sets forth selected operational data by operating segment
for the periods indicated:
Successor
Period from November 6, 2015 to December 31, 2015
Average
Average Operating
Operating Available Revenue Expense
Days Days Utilization(1) per Day(2) 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
Average
Average Operating
Operating Available Revenue Expense
Days Days Utilization(1) per Day(2) 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
Average
Average Operating
Operating Available Revenue Expense
Days Days Utilization(1) per Day(2) 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;
8
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• Hercules 266 experienced a reduction in dayrate during 2015;
• Hercules 267 experienced lower average dayrates and a decline in operating
days in 2015; and
• Hercules 262 experienced a reduction in dayrate and a decline in operating
days in 2015 and 2014 included mobilization revenue.
International Liftboats. The decrease in revenue from our International
Liftboats segment resulted from a decline in operating days and lower average
revenue per vessel per day.
Operating Expenses
Consolidated. The decrease in operating expenses is described below.
Domestic Offshore. Operating expenses for our Domestic Offshore segment
decreased across almost all expense categories. This decrease was partially
offset by net gains on asset sales in 2014.
International Offshore. The decrease in operating expenses for our International
Offshore segment is primarily due to the following:
• Hercules Resilience was ready stacked in 2015;
• Hercules Triumph was ready stacked most of 2015 and 2014 included costs to
mobilize the rig from
India
to the North Sea;
• Hercules 267 was ready and warm stacked during 2015, as compared to being
in the shipyard for repairs and maintenance a portion of 2014;
• Hercules 208 was ready and warm stacked a portion of 2015 which decreased
operating expenses. This decrease was partially offset by costs incurred
in 2015 for the rig's demobilization from
India
;
• Hercules 261 experienced cost reductions in 2015 and 2014 included
amortization of deferred contract preparation costs;
• Hercules 262 experienced cost reductions in 2015 and 2014 included
amortization of deferred contract preparation costs; partially offset by
increases in operating expenses due to:
• Hercules 258 gain on sale in April 2014; and
• Hercules 260 was in the shipyard preparing for a contract a portion of 2015.
International Liftboats. The decrease in operating expenses for our
International Liftboats segment is largely due to a reduction in the following
expenses: labor, equipment rentals, contract labor, catering and travel.
Asset Impairment
During 2014, we recorded non-cash asset impairment charges of $199.5 million in
our Domestic Offshore segment to write-down the Hercules 120, Hercules 200,
Hercules 202, Hercules 204, Hercules 212, Hercules 213, Hercules 214, Hercules
251 and Hercules 253 to fair value based on a third-party estimate.
Depreciation and Amortization
Upon our emergence from Chapter 11, we applied the provisions of fresh-start
accounting and revalued our property and equipment and drydocking asset to fair
value which resulted in a decrease in those values. The decrease in depreciation
and amortization is largely due to the reduction in asset values as a result of
fresh start accounting as well as the impact of rigs impaired in 2014. These
decreases are partially offset by additional depreciation related to capital
projects.
General and Administrative Expenses
The increase in general and administrative expense is largely due to
pre-petition costs related to financing and restructuring activities, partially
offset by a gain on the settlement of a contractual dispute relating to the sale
of certain of our assets in 2006.
Interest Expense
The decrease in interest expense is primarily due to the suspension of interest
on Predecessor debt subsequent to the Chapter 11 filing.
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Reorganization Items, Net
Reorganization items represent amounts incurred subsequent to the bankruptcy
filing as a direct result of the filing of the Chapter 11 Cases and are
comprised of the following:
Successor Predecessor
Period from Period from
November 6, January 1,
2015 to 2015 to
December 31, November 6,
(in thousands) 2015 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.
10
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The following table sets forth financial information by operating segment and other selected information for the periods indicated:
Predecessor
Year Ended December 31,
(Dollars in thousands) 2014 2013 Change % Change
Domestic Offshore:
Number of rigs (as of end of period) 24 28
Revenue $ 497,209 $ 522,705 $ (25,496 ) (4.9 )%
Operating expenses 261,399 232,166 29,233 12.6 %
Asset impairment 199,508 114,168 85,340 n/m
Depreciation and amortization expense 70,576 78,526 (7,950 ) (10.1 )%
General and administrative expenses 6,314 7,643 (1,329 ) (17.4 )%
Operating income (loss) $ (40,588 ) $ 90,202 $ (130,790 ) n/m
International Offshore:
Number of rigs (as of end of period) 9 10
Revenue $ 291,486 $ 190,376 $ 101,110 53.1 %
Operating expenses 207,190 145,650 61,540 42.3 %
Depreciation and amortization expense 75,672 51,759 23,913 46.2 %
General and administrative expenses 8,322 12,729 (4,407 ) (34.6 )%
Operating income (loss) $ 302 $ (19,762 ) $ 20,064 n/m
International Liftboats:
Number of liftboats (as of end of
period) 24 24
Revenue $ 111,556 $ 145,219 $ (33,663 ) (23.2 )%
Operating expenses 74,647 83,516 (8,869 ) (10.6 )%
Depreciation and amortization expense 20,763 18,627 2,136 11.5 %
General and administrative expenses 11,712 5,501 6,211 112.9 %
Operating income $ 4,434 $ 37,575 $ (33,141 ) (88.2 )%
Total Company:
Revenue $ 900,251 $ 858,300 $ 41,951 4.9 %
Operating expenses 543,236 461,332 81,904 17.8 %
Asset impairment 199,508 114,168 85,340 n/m
Depreciation and amortization expense 170,898 151,943 18,955 12.5 %
General and administrative expenses 75,108 79,425 (4,317 ) (5.4 )%
Operating income (loss) (88,499 ) 51,432 (139,931 ) n/m
Interest expense (99,142 ) (73,248 ) (25,894 ) 35.4 %
Loss on extinguishment of debt (19,925 ) (29,295 ) 9,370 n/m
Gain on equity investment - 14,876 (14,876 ) n/m
Other, net (39 ) (1,518 ) 1,479 (97.4 )%
Loss before income taxes (207,605 ) (37,753 ) (169,852 ) 449.9 %
Income tax benefit (provision) (8,505 ) 10,944 (19,449 ) n/m
Loss from continuing operations (216,110 ) (26,809 ) (189,301 ) 706.1 %
Loss from discontinued operations, net
of taxes - (41,308 ) 41,308 n/m
Net loss (216,110 ) (68,117 ) (147,993 ) 217.3 %
Loss attributable to noncontrolling
interest - 39 (39 ) n/m
Net loss attributable to Hercules
Offshore, Inc. $ (216,110 ) $ (68,078 ) $ (148,032 ) 217.4 %
_____________________________
"n/m" means not meaningful.
11
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The following table sets forth selected operational data by operating segment
for the periods indicated:
Predecessor
Year Ended December 31, 2014
Average
Average Operating
Operating Available Revenue Expense
Days Days Utilization per Day 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
Average
Average Operating
Operating Available Revenue Expense
Days Days Utilization per Day 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;
12
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• $5.9 million increase to state sales and use taxes in 2014 as compared to
2013;
• $3.8 million increase to workers' compensation; partially offset by:
• $3.1 million decrease to repairs and maintenance; and
• $9.6 million in additional net gains on asset sales in 2014 as compared to
2013.
International Offshore. The increase in operating expenses for our International Offshore segment is primarily due to the following: • $29.7 million increase from Hercules Resilience primarily due to the rig
commencing operations in February 2014;
• $27.2 million increase from Hercules Triumph primarily due to the rig
commencing operations in November 2013 and incurring costs in 2014 of
approximately $8 million to mobilize the rig from
India
to the North Sea;
• $25.3 million increase from Hercules 267 primarily due to the rig being in
the shipyard in 2013 preparing for a contract;
• $5.6 million increase related to the Perisai management agreement;
• $4.1 million increase from Hercules 261 primarily driven by the rig being
in the shipyard during a significant portion of 2014 for a special survey;
• $3.9 million increase from Hercules 266 as the rig began working in April
2013; partially offset by a:
• $10.5 million gain on the sale of Hercules 258 in 2014;
• $11.5 million decrease from Hercules 170 due to a loss on its sale in
2013; and
• $7.4 million decrease from Hercules 260 in 2014 as compared to 2013
primarily due to repair costs in 2013 related to the rig's spudcan damage.
International Liftboats. The decrease in operating expenses for our
International Liftboats segment is primarily due to a $4.8 million reduction in
repairs and maintenance costs in 2014 as compared to 2013 and a $2.6 million
write down of the Croaker to fair market value in 2013.
Asset Impairment
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.
In 2013, we recorded a non-cash asset impairment charge of $114.2 million in our
Domestic Offshore segment which includes the write-down of Hercules 153,
Hercules 203, Hercules 206 and Hercules 250 to fair value based on a third-party
estimate.
Depreciation and Amortization
The increase in depreciation and amortization is largely due to the additional
depreciation for the Hercules Resilience, Hercules Triumph, Hercules 267,
Hercules 266 and other capital projects, which contributed to increases of $8.2
million, $6.8 million, $5.9 million, $2.9 million and $15.5 million,
respectively. These increases are partially offset by a reduction in
depreciation of $15.2 million due to rigs impaired in 2013 and the third quarter
of 2014 and $3.6 million due to the sale of Hercules 170 in 2013.
General and Administrative Expenses
The decrease in general and administrative expenses is primarily related to a
$6.7 million decrease to labor costs, primarily in Corporate, and a $2.6 million
decrease to professional fees, primarily in our International Offshore segment.
These decreases are partially offset by a $5.0 million increase to bad debt
provision in 2014 as compared to 2013 primarily related to a customer in our
International Liftboat segment.
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Interest Expense
The increase in interest expense for 2014 is primarily due to $18.0 million in
interest on our 8.75% Senior Notes due 2021 which were issued in July 2013 as
well as a reduction in interest capitalization of $16.0 million in 2014 as
compared to 2013. 2013 included interest capitalization on upgrade and
reactivation projects and the Hercules Triumph project which were all completed
in 2013, and the Hercules Resilience project which was completed in February
2014, while 2014 includes interest capitalization on the Hercules Resilience and
Hercules Highlander projects. These increases in interest expense are partially
offset by a $7.9 million reduction in interest expense associated with the
redemption of our 10.5% Senior Notes and refinancing these notes with the
issuance of our 7.5% Senior Notes in the fourth quarter of 2013.
Loss on Extinguishment of Debt
During 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.
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
14
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cash requirements such as tax payments and debt service requirements. Because
all companies do not use identical calculations, the amounts below may not be
comparable to other similarly titled measures of other companies.
The following tables present a reconciliation of the GAAP financial measures to
the corresponding adjusted financial measures (in thousands, except per share
amounts):
Successor Predecessor
Period from Period from
November 6, January 1, Year Ended December 31,
2015 to 2015 to
December 31, November 6,
2015 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
15
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Successor Predecessor
Period from Period from
November 6, January 1, Year Ended December 31,
2015 to 2015 to
December 31, November 6,
2015 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
16
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decreases in the market value of the long-lived asset, a significant change in
the long-lived asset's physical condition, a change in industry conditions or a
substantial reduction in cash flows associated with the use of the long-lived
asset. For property and equipment held for use, the determination of
recoverability is made based upon the estimated undiscounted future net cash
flows of the related asset or group of assets being evaluated. Actual impairment
charges are recorded using an estimate of discounted future cash flows. This
evaluation requires us to make judgments regarding long-term forecasts of future
revenue and costs. In turn these forecasts are uncertain in that they require
assumptions about demand for our services, future market conditions and
technological developments. Significant and unanticipated changes to these
assumptions could require a provision for impairment in a future period. Given
the nature of these evaluations and their application to specific asset groups
and specific times, it is not possible to reasonably quantify the impact of
changes in these assumptions.
Supply and demand are the key drivers of rig and vessel utilization and our
ability to contract our rigs and vessels at economical rates. During periods of
an oversupply, it is not uncommon for us to have rigs or vessels idled for
extended periods of time, which could indicate that an asset group may be
impaired. Our rigs and vessels are mobile units, equipped to operate in
geographic regions throughout the world and, consequently, we may move rigs and
vessels from an oversupplied region to one that is more lucrative and
undersupplied when it is economical to do so. As such, our rigs and vessels are
considered to be interchangeable within classes or asset groups and accordingly,
we perform our impairment evaluation by asset group.
Our estimates, assumptions and judgments used in the application of our property
and equipment accounting policies reflect both historical experience and
expectations regarding future industry conditions and operations. Using
different estimates, assumptions and judgments, especially those involving the
useful lives and salvage values of our rigs and liftboats and expectations
regarding future industry conditions and operations, would result in different
carrying values of assets and results of operations. For example, a prolonged
downturn in the drilling industry in which utilization and dayrates were
significantly reduced could result in an impairment of the carrying value of our
assets.
Useful lives of rigs and vessels are difficult to estimate due to a variety of
factors, including technological advances that impact the methods or cost of oil
and gas exploration and development, changes in market or economic conditions
and changes in laws or regulations affecting the drilling industry. We evaluate
the remaining useful lives of our rigs and vessels when certain events occur
that directly impact our assessment of the remaining useful lives of the rigs
and vessels and include changes in operating condition, functional capability
and market and economic factors. We also consider major capital upgrades
required to perform certain contracts and the long-term impact of those upgrades
on the future marketability when assessing the useful lives and salvage values
of individual rigs and vessels.
When analyzing our assets for impairment, we separate our marketable assets,
those assets that are actively marketed and can be warm stacked or cold stacked
for short periods of time depending on market conditions, from our
non-marketable assets, those assets that have been cold stacked for an extended
period of time or those assets that we currently do not reasonably expect to
market in the foreseeable future.
Revenue Recognition
Revenue generated from our contracts is recognized as services are performed, as
long as collectability is reasonably assured. For certain contracts, we may
receive lump-sum fees for the mobilization of equipment and personnel.
Mobilization fees received and costs incurred to mobilize a rig from one
location to another are recognized as services are performed over the term of
the related drilling contract. For certain contracts, we may receive fees from
our customers for capital improvements to our rigs. Such fees are deferred and
recognized as services are performed over the term of the related contract. We
capitalize such capital improvements and depreciate them over the useful life of
the asset. Certain of our contracts also allow us to recover additional direct
costs, such as demobilization costs, additional labor and additional catering
costs and under most of our liftboat contracts, we receive a variable rate for
reimbursement of costs such as catering, oil, rental equipment and other items.
Revenue for the recovery or reimbursement of these costs is recognized when the
costs are incurred.
Accrued Self-Insurance Reserves
We are self-insured up to certain retention limits for maritime employer's
liability claims and protection and indemnity claims. The amounts in excess of
the self-insured levels are fully insured, up to a limit. Self-insurance
reserves are based on estimates of (i) claims reported and (ii) loss amounts
incurred but not reported. Reserves for reported claims are estimated by our
internal risk department by evaluating the facts and circumstances of each claim
and are adjusted from time to time based upon the status of each claim and our
historical experience with similar claims. Reserves for loss amounts incurred
but not reported are estimated by our third-party actuary and include provisions
for expected development on claims reported due to information not yet received
and expected development on claims to be reported in the future but which have
occurred prior to the accounting date. As of December 31, 2015 and 2014, there
was $18.5 million and $24.5 million in accrued self-insurance reserves,
respectively, which is included in Accrued Liabilities on the Consolidated
Balance Sheets. The actual outcome of any claim could differ significantly from
estimated amounts.
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Income Taxes
Our net income tax expense or benefit is determined based on the mix of domestic
and international pre-tax earnings or losses, respectively, as well as the tax
jurisdictions in which we operate. We operate in multiple countries through
various legal entities. As a result, we are subject to numerous domestic and
foreign tax jurisdictions and are taxed on various bases: income before tax,
deemed profits (which is generally determined using a percentage of revenue
rather than profits), and withholding taxes based on revenue. The calculation of
our tax liabilities involves consideration of uncertainties in the application
and interpretation of complex tax regulations in our operating jurisdictions.
Changes in tax laws, regulations, agreements and treaties, or our level of
operations or profitability in each taxing jurisdiction could have an impact
upon the amount of income taxes that we provide during any given year.
Stock-Based Compensation
We recognize compensation cost for all share-based payments awarded in
accordance with Financial Accounting Standards Board ("FASB") Accounting
Standards Codification ("ASC") 718, Compensation - Stock Compensation ("ASC
718") and in accordance with such we record the grant date fair value of
time-based restricted stock awarded as compensation expense using a
straight-line method over the requisite service period. Performance based awards
were recognized using the accelerated method over the requisite service period.
The fair value of our awards that are share settled are based on the closing
price of our common stock on the date of grant. For those performance based
grants that contained a market performance condition, the Monte Carlo simulation
was used for valuation as of the date of grant. All of our cash settled awards
were recorded as a liability at fair value, which was remeasured at the end of
each reporting period, over the requisite service period. Our cash settled
liability awards that contained market performance conditions were valued using
a Monte Carlo simulation. We also estimate future forfeitures and related tax
effects. Our estimate of compensation expense requires a number of assumptions
and changes to those assumptions could result in different valuations for
individual share awards. On the Effective Date, all share-based awards requiring
share settlement that were granted under the Predecessor were canceled. Certain
award agreements requiring cash settlement contained change of control
provisions which provided for vesting. The Successor Company has only granted
time-based restricted stock.
Our estimate of future expense relating to restricted stock awards granted
through December 31, 2015 as well as the remaining vesting period over which the
associated expense is to be recognized is presented in the table below; however,
due to the uncertainty in the level of awards to be granted in the future, these
amounts are estimates and subject to change.
December 31, 2015
Weighted
Unrecognized Average
Compensation Remaining
Expense Term
(in thousands) (in years)
Time-based Restricted Stock Awards $ 434 0.9
OUTLOOK
Offshore
Demand for our oilfield services is driven by our exploration and production
("E&P") customers' capital spending, which can experience significant
fluctuations depending on current commodity prices and their expectations of
future price levels, among other factors. Based on 2016 capital spending
surveys, we expect both domestic and international focused exploration and
production capital spending will decrease significantly from already declining
2015 levels.
Drilling activity levels in the shallow-water
U.S.
Gulf of Mexico are dependent
on crude oil and natural gas prices, prospectivity of hydrocarbons, capital
budgets of our customers as well as their ability to obtain necessary drilling
permits to operate in the region.
The supply of marketed jackup rigs in the
U.S.
Gulf of Mexico has declined
significantly since 2008, driven by events such as the financial crisis that
began in late 2008, the imposition of new regulations after the Macondo incident
in 2010, the consolidation of domestic customers that began in 2013 and
continued in 2014, and the sharp decline in crude oil prices since mid-2014.
Such events have led drilling contractors, including us, to cold stack, or no
longer actively market, a number of rigs in the region. In other instances, rigs
have been sold for conversion purposes, scrapped, or mobilized out of the
U.S.
Gulf of Mexico. As a result, the number of existing, actively marketed jackup
rigs in the
U.S.
Gulf of Mexico, has declined from approximately 63 rigs in late
2008 to 21 rigs as of March 23, 2016, of which 9 are ours.
The fall in the price of crude oil, coupled with the consolidation of the
domestic customer base, have negatively impacted demand for jackup rigs in the
U.S.
Gulf of Mexico. Jackup rig demand in the region, as defined by rigs under
contract, has
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fallen from 31 rigs on July 21, 2014 to 6 rigs as of March 23, 2016. We expect
the overall environment for rig demand to remain relatively soft through 2016,
assuming commodity prices remain at or near current levels. Given these market
conditions, we have executed a number of cost saving measures, including our
decision to cold stack and warm stack over half of our domestic rigs since the
fourth quarter of 2014. We currently believe that this is an appropriate step to
reduce costs, better balance the market and support utilization on our marketed
rigs. However, should we see indicators of stronger demand, we will have
capacity ready to respond timely to these signals.
Demand for rigs in our International Offshore segment is primarily dependent on
crude oil prices. Due to the sharp drop in crude oil prices, international
capital spending budgets for 2016 is expected to be lower than prior years. This
will have negative implications for jackup demand for all classes of rigs. In
addition, new capacity that have entered the market over the past three years as
well as new capacity growth expected over the next five years could put further
pressure on the operating environment for the existing jackup rig fleet. The
number of existing marketed jackup rigs, outside of the
U.S.
Gulf of Mexico,
have increased from 394 rigs as of January 2, 2013 to 451 rigs as of March 23,
2016. Furthermore, as of March 23, 2016, there are approximately 124 jackup rigs
under construction, on order and planned for delivery worldwide through 2020.
One of the new rigs under construction is the Hercules Highlander. The Company
has made significant progress on the construction of the Hercules Highlander,
and the rig is scheduled to be delivered from the shipyard in
Singapore
during
the second quarter 2016. Shortly after delivery of the Hercules Highlander, the
rig will be mobilized to the U.K. North Sea, where it will commence operations
under a five year contract with the customer Maersk Oil.
Liftboats
Demand for liftboats is typically a function of our customers' demand for
offshore infrastructure construction, inspection and maintenance, well
maintenance, well plugging and abandonment, and other related activities.
Although activity levels for liftboats are not as closely correlated to
commodity prices as our drilling segments, commodity prices are still a key
driver of liftboat demand. Since early 2014, demand for liftboat services in
West Africa
has been weak. We believe this has been driven by budgetary
constraints with major customers primarily in
Nigeria
, which we expect will
continue through 2016. Additional supply of vessels mobilized into the region
could also impact the utilization and pricing for our liftboat fleet.
Utilization can and has been negatively impacted by local labor disputes,
regional conflicts and other political events, particularly in
West Africa
. In
the
Middle East
, we expect demand for liftboats to be a function of construction
and well servicing activity levels. Due to the decline of oil prices, several
construction projects previously planned in the region have been deferred to the
latter part of 2016 or canceled. As a result, the Company expects activity
levels in the
Middle East
to be weak through at least the first half of 2016.
Over the long term, we believe that international liftboat demand will benefit
from (i) the aging offshore infrastructure and maturing offshore basins, (ii)
desire by our customers to economically produce from these mature basins and
service their infrastructure and (iii) the cost advantages of liftboats to
perform these services relative to alternatives. Tempering this demand outlook
is (i) the risk of a prolonged period of low oil prices impacting
production-related activity, (ii) our expectation of increased competition from
newly constructed liftboats and mobilizations of existing liftboats primarily
from the
U.S.
Gulf of Mexico to international markets, (iii) the risk of
recurring political, social and union unrest, principally in
West Africa
and
(iv) increased pressure to have local ownership of assets, principally in
Nigeria
.
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LIQUIDITY AND CAPITAL RESOURCES
Sources and Uses of Cash
Sources and uses of cash are as follows (in millions):
Successor Predecessor
Period from Period from
November 6, January 1,
2015 to 2015 to
December 31, November 6, Year Ended
2015 2015 December 31, 2014
Net Cash Provided by (Used in) Operating
Activities $ (26.5 ) $ (9.6 ) $ 114.7
Net Cash Provided by (Used in) Investing
Activities:
Capital Expenditures (5.1 ) (78.1 ) (147.5 )
Increase in Restricted Cash - (200.0 ) -
Insurance Proceeds Received - 3.5 9.1
Proceeds from Sale of Assets, Net 0.1 9.7 35.1
Other 0.4 0.3 1.5
Total Cash Provided by (Used in) Investing
Activities (4.6 ) (264.6 ) (101.8 )
Net Cash Provided by (Used in) Financing
Activities:
Long-term Debt Borrowings - 436.5 300.0
Redemption of 7.125% Senior Secured Notes - - (300.0 )
Payment of Debt Issuance Costs - (8.4 ) (3.9 )
Other - - 0.5
Total Cash Provided by (Used in) Financing
Activities: - 428.1 (3.4 )
Net Increase (Decrease) in Cash and Cash
Equivalents $ (31.1 ) $
153.9 $ 9.5
Sources of Liquidity and Financing Arrangements
Our liquidity is comprised of cash on hand and cash from operations. We
currently believe we will have adequate liquidity to fund our operations through
at least December 31, 2016. However, to the extent we do not generate sufficient
cash from operations we may need to raise additional funds through debt, equity
offerings or the sale of assets. Furthermore, we may need to raise additional
funds through debt or equity offerings or asset sales to refinance existing
debt, to fund capital expenditures or for general corporate purposes.
Cash Requirements and Contractual Obligations
Our current debt structure is used to fund our business operations.
Senior Secured Credit Facility
On November 6, 2015 (the "Credit Agreement Closing Date"), we entered into a
Credit Agreement (the "Credit Agreement") that provides for a $450.0 million
senior secured credit facility ("Senior Secured Credit Facility") consisting
entirely of term loans. The loans were issued with 3.0% original issue discount,
and $200.0 million (the "Escrowed Amount") of the proceeds were placed into an
escrow account pursuant to an Escrow Agreement and will be released pursuant to
the terms of such Agreement. The Escrowed Amount is to be used to finance the
remaining installment payment on the Hercules Highlander and the expenses, costs
and charges related to the construction and purchase of the Hercules Highlander
(See the information set forth in Part II, Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations - Overview). The
remaining proceeds of the loans are being used to consummate the Plan, fund fees
and expenses in connection therewith, and to provide for working capital and
other general corporate purposes of us and our subsidiaries. All loans under the
Credit Agreement mature on May 6, 2020.
We may voluntarily prepay loans under the Credit Agreement, subject to customary
notice requirements and minimum prepayment amounts, the payment of LIBOR
breakage costs, if any, and (i) if such prepayment is made prior to the third
anniversary of the Credit Agreement Closing Date, a prepayment premium of 3.0%
of the principal amount of the loans being prepaid plus the present value of the
sum of all required payments of interest on the aggregate principal amount of
the loans being prepaid through the third anniversary of the Credit Agreement
Closing Date, (ii) if such prepayment made after the third anniversary of the
Credit Agreement Closing Date but on or prior to the fourth anniversary of the
Credit Agreement Closing Date, a prepayment premium of 3.0% of the aggregate
principal amount of the loans being prepaid and (iii) if such prepayment is made
after the fourth anniversary of the Credit Agreement Closing Date, without
premium or penalty.
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The Credit Agreement requires mandatory prepayments of amounts outstanding
thereunder with (i) the net proceeds of certain asset sales and casualty events,
subject to certain reinvestment rights, (ii) the net proceeds of certain equity
issuances, subject to certain exceptions, including with respect to equity
issuances used to finance acquisitions, (iii) the net proceeds of debt issuances
not permitted by the Credit Agreement, (iv) any cancellation, termination or
other fee received in connection with the cancellation or termination of the
construction contract or drilling contract for the Hercules Highlander, and (v)
the Escrowed Amount if the Escrow Conditions are not satisfied. No prepayment
premium is payable in connection with any of these mandatory prepayments, unless
the mandatory prepayment is a result of the issuance of debt not permitted by
the Credit Agreement. In addition, if a change of control (as defined in the
Credit Agreement) occurs, each lender will have the right to require us to
prepay our loans at 101% of the principal amount of the loans requested to be
prepaid.
Loans under the Credit Agreement bear interest, at our option, at either (i) the
ABR (the highest of the prime rate, the federal funds rate plus 0.5%, the
one-month LIBOR rate plus 1.0%, and 2.0%), plus an applicable margin of 8.50%,
or (ii) the LIBOR rate plus an applicable margin of 9.50% per annum. The LIBOR
rate includes a floor of 1.0%. In connection with entering into the Credit
Agreement, we paid to the original commitment parties a put option premium equal
to 2.0% of each such commitment party's commitment (one half of such fee was
paid upon execution of the commitment letter, and the remaining half of such fee
was paid on the Credit Agreement Closing Date) in aggregate a total of $9.0
million, and we paid certain administrative and other fees to the Agent of $1.2
million.
The Credit Agreement contains covenants that, among other things, limit our
ability and the ability of our restricted subsidiaries to:
• incur indebtedness;
• create liens;
• enter into sale and leaseback transactions;
• pay dividends or make other distributions to equity holders;
• prepay subordinated debt or unsecured debt;
• make other restricted payments or investments (including investments in
subsidiaries that are not guarantors);
• consolidate, merge or transfer all or substantially all of its assets;
• sell assets;
• engage in transactions with its affiliates;
• modify or terminate any material agreement;
• enter into agreements that restrict dividends or other transfers of assets by
restricted subsidiaries; and
• engage in any new line of business.
These covenants are subject to a number of important qualifications and
limitations. In addition, we have to maintain compliance with (i) a maximum
senior secured first lien leverage ratio (as defined in the Credit Agreement,
being generally computed as the ratio of secured first lien debt to consolidated
net income before interest, taxes, depreciation and amortization, which EBITDA
amount will be annualized for any test period during 2017) commencing from the
fiscal quarter ending March 31, 2017 and (ii) a minimum liquidity amount,
consisting of unrestricted cash and cash equivalents, commencing from the Credit
Agreement Closing Date. The maximum secured leverage ratio is 6.0 to 1.0 for the
fiscal quarter ending March 31, 2017, 5.0 to 1.0 for the fiscal quarter ending
June 30, 2017, 4.0 to 1.0 for the fiscal quarter ending September 30, 2017, and
3.5 to 1.0 for the fiscal quarter ending December 31, 2017 and thereafter. The
minimum liquidity is $100.0 million for the period beginning on the Credit
Agreement Closing Date and ending on June 30, 2016, $75.0 million for the period
beginning July 1, 2016 and ending December 31, 2016, $50.0 million for the
period beginning January 1, 2017 and ending June 30, 2017, and $25.0 million for
the period beginning July 1, 2017 and thereafter. At December 31, 2015, we were
in compliance with all covenants under our Senior Secured Credit Facility.
Our obligations under the Credit Agreement are guaranteed by substantially all
of our domestic and foreign subsidiaries, and the obligations of us and the
guarantors are secured by liens on substantially all of their respective assets,
including their current and future vessels (including the Hercules Highlander
when it is delivered), bank accounts, accounts receivable, and equity interests
in subsidiaries. Upon an event of default under the Credit Agreement, the Agent
may, or at the direction of lenders holding a majority of the loans under the
Credit Agreement shall, declare all amounts owing under the Credit Agreement to
be due and payable. In addition, upon an event of default under the Credit
Agreement the Agent is empowered to exercise all rights and remedies of a
secured party and foreclose upon the collateral securing the Credit Agreement,
in addition to all other rights and remedies under the security documents
described in the Credit Agreement. Upon any acceleration of the loans under the
Credit Agreement, the prepayment premiums described above that are otherwise
applicable to voluntary prepayments shall become due and payable to the lenders.
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Embedded Derivative
We identified an embedded derivative related to a put option feature included in
the Senior Secured Credit Facility, where, upon the occurrence of certain events
of default and where we are not able to obtain a waiver from our lenders, the
principal amount of our debt could be accelerated and we would be required to
pay an additional premium of all interest that would accrue until November 6,
2018, plus a 3% premium, discounted to present value. The accounting treatment
of derivative financial instruments requires us to bifurcate and fair value the
derivative as of the inception date of the Senior Secured Credit Facility and to
fair value the derivative as of each subsequent reporting date.
Upon issuance of the Senior Secured Credit Facility on November 6, 2015, the
Company received net proceeds of approximately $436.5 million, incurred debt
issuance costs of approximately $11.0 million, and recognized a derivative
financial instrument approximating $8.5 million. After these adjustments, the
debt approximated $417.0 million.
In connection with fresh-start accounting, the debt was recorded at fair value
of $428.0 million which was determined using an Income Approach, specifically
the risk-neutral method. The difference between the $450.0 million face amount
and the fair value recorded in fresh-start accounting is being amortized over
4.5 years, the current expected life of the debt.
Cancellation of Indebtedness
In accordance with the Plan, on the Effective Date all of the obligations of the
Debtors with respect to the 8.75% Senior Notes, 7.5% Senior Notes, 6.75% Senior
Notes, 10.25% Senior Notes, 3.375% Convertible Senior Notes and 7.375% Senior
Notes were canceled (See the information set forth in Part II, Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations - Overview).
Termination of Credit Facility
On April 3, 2012, we entered into a credit agreement which as amended on July 8,
2013 (the "Predecessor Credit Agreement") governed our senior secured revolving
credit facility (the "Credit Facility"). The Predecessor Credit Agreement
provided for a $150.0 million senior secured revolving credit facility.
In connection with the RSA, we terminated the Credit Facility effective June 22,
2015 (See the information set forth in Part II, Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations - Overview). There
were no amounts outstanding and no letters of credit issued under the Credit
Facility at that time. Liens on our vessels that secured the Credit Facility
have been released. We maintained compliance with all covenants under the Credit
Facility through the termination date and have paid all fees in full.
8.75% Senior Notes due 2021
On July 8, 2013, we completed the issuance and sale of $400.0 million aggregate
principal amount of senior notes at a coupon rate of 8.75% ("8.75% Senior
Notes") with maturity in July 2021. These notes were sold at par and we received
net proceeds from the offering of the notes of approximately $393.0 million
after deducting the bank fees and estimated offering expenses. The net proceeds
from this offering, together with cash on hand (including the proceeds of
approximately $103.9 million we received from the sales of our inland barge
rigs, domestic liftboats and related assets), were used to fund our acquisition
of Discovery shares, the final shipyard payments totaling $333.9 million for
Hercules Triumph and Hercules Resilience, related capital expenditures, as well
as general corporate purposes. In accordance with the Plan, on the Effective
Date all of the obligations of the Debtors with respect to the 8.75% Senior
Notes were canceled (See the information set forth in Part II, Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations - Overview).
7.5% Senior Notes due 2021
On October 1, 2013, we completed the issuance and sale of $300.0 million
aggregate principal amount of senior notes at a coupon rate of 7.5% ("7.5%
Senior Notes") with maturity in October 2021. These notes were sold at par and
we received net proceeds from the offering of the notes of approximately $294.5
million after deducting the bank fees and estimated offering expenses. In
accordance with the Plan, on the Effective Date all of the obligations of the
Debtors with respect to the 7.5% Senior Notes were canceled (See the information
set forth in Part II, Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - Overview).
6.75% Senior Notes due 2022
On March 26, 2014, we completed the issuance and sale of $300.0 million
aggregate principal amount of senior notes at a coupon rate of 6.75% ("6.75%
Senior Notes") with maturity in April 2022. These notes were sold at par and we
received net proceeds from the offering of the notes of approximately $294.8
million after deducting bank fees and estimated offering expenses. In accordance
with the Plan, on the Effective Date all of the obligations of the Debtors with
respect to the 6.75% Senior Notes were canceled (See the information set forth
in Part II, Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations - Overview).
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10.25% Senior Notes due 2019
On April 3, 2012, we completed the issuance and sale of $200.0 million aggregate
principal amount of senior notes at a coupon rate of 10.25% ("10.25% Senior
Notes") with maturity in April 2019. These notes were sold at par and we
received net proceeds from the offering of the notes of $195.4 million after
deducting the initial purchasers' discounts and offering expenses. In accordance
with the Plan, on the Effective Date all of the obligations of the Debtors with
respect to the 10.25% Senior Notes were canceled (See the information set forth
in Part II, Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations - Overview).
3.375% Convertible Senior Notes due 2038
In May 2012, we repurchased a portion of the 3.375% Convertible Senior Notes and
in accordance with ASC 470-20 Debt - Debt with Conversion and Other Options, the
settlement consideration was allocated to the extinguishment of the liability
component in an amount equal to the fair value of that component immediately
prior to extinguishment with the difference between this allocation and the net
carrying amount of the liability component and unamortized debt issuance costs
recognized as a gain or loss on debt extinguishment. If there would have been
any remaining settlement consideration, it would have been allocated to the
reacquisition of the equity component and recognized as a reduction of equity.
On May 1, 2013, we made an offer to purchase all of the outstanding notes in
accordance with our repurchase obligation under the indenture and on June 1,
2013 repurchased $61.3 million aggregate principal amount of the 3.375%
Convertible Senior Notes pursuant to the terms of the optional put repurchase
offer. In accordance with the Plan, on the Effective Date all of the obligations
of the Debtors with respect to the 3.375% Convertible Senior Notes were canceled
(See the information set forth in Part II, Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations - Overview).
Retirement of 10.5% Senior Notes
In 2009, we issued $300.0 million of senior notes at a coupon rate of 10.5%
("10.5% Senior Notes") with maturity in October 2017. On September 17, 2013, we
commenced a cash tender offer (the "Tender offer") for any and all of the $300.0
million outstanding aggregate principal amount of our 10.5% Senior Notes. Senior
notes totaling approximately $253.6 million were settled on October 1, 2013 for
$268.5 million using a portion of the proceeds from the issuance of the 7.5%
Senior Notes. Additionally, on November 4, 2013 we redeemed all $46.4 million of
the remaining outstanding 10.5% Senior Notes for approximately $48.8 million
using the remaining proceeds from the 7.5% Senior Notes offering, together with
cash on hand.
Retirement of 7.125% Senior Secured Notes
In 2012, we issued $300.0 million of senior secured notes at a coupon rate of
7.125% ("7.125% Senior Secured Notes") with maturity in April 2017. On March 12,
2014 we commenced a cash tender offer (the "Tender offer") for any and all of
the $300.0 million outstanding aggregate principal amount of our 7.125% Senior
Secured Notes. Senior secured notes totaling approximately $220.1 million were
settled on March 26, 2014 for $232.7 million using a portion of the proceeds
from the issuance of the 6.75% Senior Notes. Additionally, on April 29, 2014, we
redeemed all $79.9 million of the remaining outstanding 7.125% Senior Secured
Notes for approximately $84.2 million using the remaining net proceeds from the
6.75% Senior Notes offering, together with cash on hand.
Loss on Extinguishment of Debt
During the period from January 1, 2015 to November 6, 2015 and the years ended
December 31, 2014 and 2013, we incurred the following charges which are included
in Loss on Extinguishment of Debt in the Consolidated Statements of Operations
for their respective periods:
• During the fourth quarter of 2013, we incurred a pretax charge of $29.3
million, consisting of a $17.3 million call premium, $4.8 million
unamortized debt discount costs and $4.2 million unamortized debt issuance
costs, all related to the redemption of the 10.5% Senior Notes, as well as
approximately $3.0 million of bank fees related to the issuance of the
7.5% Senior Notes;
• In March 2014, we incurred a pretax charge of $15.2 million, consisting of
a $12.6 million call premium and $1.4 million of unamortized debt issuance
costs related to the redemption of the 7.125% Senior Secured Notes, as
well as $1.1 million of bank fees related to the issuance of the 6.75%
Senior Notes;
• In April 2014, we incurred a pretax charge of $4.8 million, consisting of
a $4.3 million call premium and $0.5 million of unamortized debt issuance
costs related to the redemption of the remaining 7.125% Senior Secured
Notes; and
• In June 2015, we incurred a pretax charge of $1.9 million consisting of
$1.8 million of unamortized debt issuance costs and $0.1 million of
associated professional fees related to the termination of the Credit
Facility.
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The fair value of our Successor Company's Senior Secured Credit Facility is
estimated using an Income Approach, specifically the risk-neutral method. The
significant assumptions used in the valuation of the Senior Secured Credit
Facility are: the expected recovery rate, the risk-neutral probability of
default, and the risk-free rate (Level 2). The fair value of our Predecessor
Company's 8.75% Senior Notes, 7.5% Senior Notes, 6.75% Senior Notes, 10.25%
Senior Notes and 3.375% Convertible Senior Notes was estimated based on quoted
prices in active markets. The fair value of our Predecessor Company's 7.375%
Senior Notes was estimated based on discounted cash flows using inputs from
quoted prices in active markets for similar debt instruments. The inputs used to
determine fair value are considered Level 2 inputs.
The following table provides the carrying value and fair value of our long-term
debt instruments:
Successor Predecessor
December 31, 2015 December 31, 2014
Carrying Fair Carrying Fair
(in millions) Value Value Value Value
Senior Secured Credit Facility, due May 2020$ 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:
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Events of Coverage Coverage Amounts and
Deductibles
- Total maximum amount of hull and - $753.3 million;
machinery coverage;
- Deductible for events that are not - $5.0 million and $1.0 million per
caused by a
U.S.
Gulf of Mexico named occurrence for drilling rigs and
windstorm; liftboats, respectively;
- Deductible for events that are caused - $10.0 million;
by a
U.S.
Gulf of Mexico named
windstorm;
- Maritime employer liability (crew - $5.0 million self-insured retention
liability); with excess liability coverage up
to
$200.0 million*;
- Personal injury and death of third - Primary coverage of $5.0 million per
parties; 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 - Annual aggregate limit of liability
caused in
U.S.
Gulf of Mexico named of $25.0 million for property damage
windstorms; and (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 - Primary limits of $5.0 million up to
vessels and drilling rigs. $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 - $250.0 million per rig; machinery coverage; - Deductible;
- $2.5 million per occurrence per
rig;
- Extended contractual liability, - $25.0 million per occurrence;
including subsea activities, property
and personnel, clean up costs (primary
coverage);
- Pollution-by-blowout coverage -$10.0 million per occurrence;
and
(primary coverage); and
- Operational protection and indemnity - $500.0 million per rig, subject to a
coverage. $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
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substantial damage in the incident and our insurance underwriters determined
that the rig was a constructive total loss. We received gross insurance proceeds
of $50.0 million, the rig's insured value, in December 2013 from insurance
underwriters and recorded a net insurance gain of $31.6 million, which is
included in Operating Expenses on our Consolidated Statement of Operations for
the year ended December 31, 2013, after writing off the rig's net book value of
$18.4 million. The financial information for Hercules 265 has been reported as
part of the Domestic Offshore segment. The cause of the incident is unknown. We
have removal of wreck coverage for this incident up to a total amount of $110.0
million. During the second quarter of 2014, we received gross proceeds of $9.1
million from the insurance underwriters as reimbursement for a portion of the
wreck removal and related costs incurred and, used $2.0 million to repurchase
the Hercules 265 hull from the insurance underwriters, which is currently
stacked in a
Mississippi
shipyard. During the period from January 1, 2015 to
November 6, 2015, we received an additional $3.5 million in gross proceeds from
the insurance underwriters as reimbursement for a portion of the wreck removal
and related costs incurred to date. We and our insurance underwriters continue
to negotiate the insurance recovery amounts for costs related to the salvage of
the rig and certain other insured losses.
Capital Expenditures
We currently expect total capital expenditures during 2016 to approximate $220.0
million to $250.0 million. Planned capital expenditures include the final
shipyard payment, additional equipment, and commissioning expenditures for the
Hercules Highlander (See the information set forth in Part II, Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations - Overview), as well as items related to general maintenance,
regulatory, refurbishment, upgrades and contract specific modifications to our
other rigs and liftboats. Changes in timing of certain planned capital
expenditure projects may result in a shift of spending levels beyond 2016.
From time to time, we may review possible acquisitions of rigs, liftboats or
businesses, joint ventures, mergers or other business combinations, and we may
have outstanding from time to time bids to acquire certain assets from other
companies. If we acquire additional assets, we would expect that our ongoing
capital expenditures as a whole would increase in order to maintain our
equipment in a competitive condition.
Our ability to fund capital expenditures beyond the current year would be
adversely affected if conditions deteriorate further in our business.
Contractual Obligations
Our contractual obligations and commitments principally include obligations
associated with our outstanding indebtedness, certain income tax liabilities,
future minimum operating lease obligations, purchase commitments and management
compensation obligations.
The following table summarizes our contractual obligations and contingent
commitments by period as of December 31, 2015:
Payments due by Period
Contractual Obligations and Less than 1-3 4-5 After 5
Contingent Commitments (c) 1 Year Years Years Years Total
(In thousands)
Long-term debt obligation $ - $ - $ 450,000 $ - $ 450,000
Interest on debt (a) 48,038 95,812 64,443 - 208,293
Purchase obligations (b) 11,554 - - - 11,554
Rig construction contract
(d) 188,800 - - - 188,800
Management compensation
obligations 4,100 - - - 4,100
Operating lease obligations 3,365 2,700 - - 6,065
Total contractual
obligations $ 255,857 $ 98,512 $ 514,443 $ - $ 868,812
_____________________________
(a) Estimated interest is based on the indexed rate in effect at December 31,
2015. Interest is calculated at the LIBOR rate plus an applicable margin of
9.50% per annum. The LIBOR rate includes a floor of 1.0% per the terms of the
Credit Agreement.
(b) A "purchase obligation" is defined as an agreement to purchase goods or
services that is enforceable and legally binding on the company and that
specifies all significant terms, including: fixed or minimum quantities to be
purchased; fixed, minimum or variable price provisions; and the approximate
timing of the transaction. These amounts are primarily comprised of open
purchase order commitments to vendors and subcontractors.
(c) Tax liabilities of $3.2 million have been excluded from the table above as a
reasonably reliable estimate of the period of cash settlement cannot be made.
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(d) $200.0 million of the proceeds from the Senior Secured Credit Facility were
placed in an escrow account and are included in Restricted Cash on the
Consolidated Balance Sheet as of December 31, 2015 to be used to finance the
remaining installment payment on the Hercules Highlander rig construction
contract and the expenses, costs and charges related to the construction and
purchase of the Hercules Highlander (See the information set forth in Part
II, Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations - Overview and Part II, Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources).
Off-Balance Sheet Arrangements
Guarantees
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.
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
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those annual periods. Early adoption is permitted. As of November 6, 2015, upon
the adoption of fresh-start accounting, the Successor Company adopted ASU
2015-17 as a new accounting principle. As a result, we have not applied ASU
2015-17 to the Predecessor Company Balance Sheets.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). The FASB
is issuing this Update to increase transparency and comparability among
organizations by recognizing lease assets and lease liabilities on the balance
sheet and disclosing key information about leasing arrangements. The core
principle of Topic 842 is that a lessee should recognize in the statement of
financial position a liability to make lease payments (the lease liability) and
a right-of-use asset representing its right to use the underlying asset for the
lease term. Under previous GAAP, lessees did not recognize lease assets and
lease liabilities for those leases classified as operating leases. The ASU is
effective for fiscal years beginning after December 15, 2018, including interim
periods within those fiscal years. Early adoption of this amendment is
permitted. We are in the process of evaluating the impact of this accounting
standard on our consolidated financial statements.
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FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K, 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;
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• the ability of our customers in the
U.S.
Gulf of Mexico to obtain
drilling permits in an efficient manner or at all;
• the impact of governmental laws and regulations, including laws and
regulations in the
U.S.
Gulf of Mexico following the Macondo well
incident;
• our ability to obtain in a timely manner visas and work permits for our
employees working in international jurisdictions;
• the impact of local content and cabotage laws and regulations in
international jurisdictions in which we operate, particularly
Nigeria
;
• the impact of tax laws, regulations, interpretations and audits in
jurisdictions where we conduct business;
• uncertainties relating to the level of activity in offshore oil and
natural gas exploration, development and production;
• competition and market conditions in the contract drilling and liftboat
industries;
• the availability of skilled personnel and the rising cost of labor;
• labor relations and work stoppages, particularly in the Nigerian labor
environment;
• operating hazards such as hurricanes, severe weather and seas, fires,
cratering, blowouts and other well control incidents, war, terrorism and
cancellation or unavailability of insurance coverage or insufficient
insurance coverage;
• the impact of public health outbreaks;
• the enforceability and interpretations of indemnity and liability
provisions contained in our drilling contracts, particularly in the
U.S.
Gulf of Mexico;
• the effect of litigation, investigations, audits and contingencies; and
• our inability to achieve our plans or carry out our strategy.
Many of these factors are beyond our ability to control or predict. Any of these
factors, or a combination of these factors, could materially affect our future
financial condition or results of operations and the ultimate accuracy of the
forward-looking statements. These forward-looking statements are not guarantees
of our future performance, and our actual results and future developments may
differ materially from those projected in the forward-looking statements.
Management cautions against putting undue reliance on forward-looking statements
or projecting any future results based on such statements or present or prior
earnings levels. In addition, each forward-looking statement speaks only as of
the date of the particular statement, and we undertake no obligation to publicly
update or revise any forward-looking statements except as required by applicable
law.
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